Plains All American Pipeline, L.P. and Plains GP Holdings Report Fourth-Quarter and Full-Year 2017 Results

PAA Also Furnishes 2018 Full-Year Guidance

HOUSTON--()--Plains All American Pipeline, L.P. (NYSE: PAA) and Plains GP Holdings (NYSE: PAGP) today reported fourth-quarter and full-year 2017 results.

“We are pleased to report that PAA finished the year on a strong note, having made significant progress on the plans we outlined in August of 2017”

Fourth-Quarter and Full-Year 2017 Highlights

  • Delivered operating and financial performance in line with to slightly ahead of 4Q17 expectations;
  • Reduced total debt by $1.5 billion during 4Q17; exited 2017 with $3.0 billion of liquidity
  • Retired $950 million of senior notes
  • Reduced short-term/inventory debt by ~$200 million compared to September 30, 2017 (~$375 million relative to the June 30, 2017 balance);
  • Completed ~$1.1 billion in targeted asset sales (~$700 million since August 2017); advancing efforts on additional 2018 sales;
  • Completed construction and placed the new Diamond and STACK JV pipelines into service and completed capacity expansions for the Cactus I and BridgeTex pipelines, adding over 275,000 barrels per day to PAA’s net transportation capacity; and
  • Obtained long-term minimum volume commitments (“MVCs”) to sanction construction of the Cactus II pipeline and the extension/looping of the Sunrise pipeline system.

“We are pleased to report that PAA finished the year on a strong note, having made significant progress on the plans we outlined in August of 2017,” stated Willie Chiang, Executive Vice President and Chief Operating Officer of Plains All American Pipeline.

“We remain on track to achieve our deleveraging objectives and targeted credit metrics by early 2019 while maintaining substantial distribution coverage underpinned by predominantly fee-based cash flow. Additionally, execution of our capital program, which includes several recently announced Permian projects, and robust Permian fundamentals will drive momentum for PAA’s continued growth in 2018 and beyond.”

 

Plains All American Pipeline, L.P.

 

Summary Financial Information (unaudited)

(in millions, except per unit data)

 
         

Three Months Ended

December 31,

    %    

Twelve Months Ended

December 31,

    %
GAAP Results         2017     2016 Change 2017     2016 Change
Net income attributable to PAA $ 191 $ 126 52 % $ 856 $ 726 18 %
Diluted net income per common unit $ 0.19 $ 0.14 36 % $ 0.95 $ 0.43 121 %
Diluted weighted average common units outstanding 726   662   10 % 718   466   54 %
Distribution per common unit declared for the period $ 0.30   $ 0.55   (45 )% $ 1.70   $ 2.50   (32 )%
 
 

Three Months Ended

December 31,

%

Twelve Months Ended

December 31,

%
Non-GAAP Results (1)         2017 2016 Change 2017 2016 Change
Adjusted net income attributable to PAA $ 241 $ 278 (13 )% $ 849 $ 1,062 (20 )%
Diluted adjusted net income per common unit $ 0.26 $ 0.37 (30 )% $ 0.94 $ 1.14 (18 )%
Adjusted EBITDA $ 631 $ 600 5 % $ 2,082 $ 2,169 (4 )%
 

_____________________________

(1)   See the section of this release entitled “Non-GAAP Financial Measures and Selected Items Impacting Comparability” and the tables attached hereto for information regarding certain selected items that PAA believes impact comparability of financial results between reporting periods, as well as for information regarding non-GAAP financial measures (such as adjusted EBITDA) and their reconciliation to the most directly comparable measures as reported in accordance with GAAP.
 

Segment adjusted EBITDA for the fourth quarter and full year of 2017 and 2016 is presented below:

 

Summary of Selected Financial Data by Segment (unaudited)

(in millions)

 
        Three Months Ended
December 31, 2017
    Three Months Ended
December 31, 2016
Transportation     Facilities    

Supply and

Logistics

Transportation     Facilities    

Supply and

Logistics

Segment adjusted EBITDA $ 354   $ 184   $ 92   $ 278   $ 171   $ 151

Percentage change in segment

  adjusted EBITDA versus 2016

  period

27 % 8 % (39 )%
 
 
Twelve Months Ended
December 31, 2017
Twelve Months Ended
December 31, 2016
Transportation Facilities

Supply and

Logistics

Transportation Facilities

Supply and

Logistics

Segment adjusted EBITDA $ 1,287   $ 734   $ 60   $ 1,141   $ 667   $ 359

Percentage change in segment

  adjusted EBITDA versus 2016

  period

13 % 10 % (83 )%
 

Fourth-quarter 2017 Transportation segment adjusted EBITDA increased by 27% versus comparable 2016 results. This increase was primarily driven by increased volume on our Permian Basin systems, in addition to contributions from our Eagle Ford JV system, which receives Permian volumes from our Cactus pipeline. This increase was partially offset by a one-time contract settlement in the fourth quarter and the sale of non-core assets in our Rocky Mountain region.

Fourth-quarter 2017 Facilities segment adjusted EBITDA increased by 8% versus comparable 2016 results. This increase was primarily driven by increased NGL storage and fractionation services and higher throughput fees and additional storage capacity at Cushing and Patoka. These increases were partially offset by decreased rail terminal revenue and the impact of a natural gas storage asset sale completed in June 2017.

Fourth-quarter 2017 Supply and Logistics segment adjusted EBITDA decreased by 39% versus comparable 2016 results due to crude oil and NGL margin compression and reduced arbitrage opportunities.

 

2018 Full-Year Guidance

 

The table below presents our full-year 2018 financial and operating guidance:

 

Financial and Operating Guidance (unaudited)

(in millions, except per unit and per barrel data)

 
        Twelve Months Ended December 31,
2016     2017     2018 (G)
+ / -
Segment Adjusted EBITDA
Transportation $ 1,141 $ 1,287 $ 1,535
Facilities 667   734   665  
Fee-based $ 1,808 $ 2,021 $ 2,200
Supply and Logistics 359 60 100
Other income/(expense), net 2   1    
Adjusted EBITDA (1) $ 2,169   $ 2,082   $ 2,300  
Interest expense, net (2) (451 ) (483 ) (425 )
Maintenance capital (186 ) (247 ) (215 )
Current income tax expense (85 ) (28 ) (30 )
Other (33 )   (12 )   5  
Implied DCF (1) $ 1,414 $ 1,312 $ 1,635
Preferred unit cash distributions paid (3) (5 ) (160 )
General partner cash distributions (565 )      
Implied DCF Available to Common Unitholders $ 849   $ 1,307   $ 1,475  
 
Implied DCF per Common Unit (1) $ 1.83 $ 1.82 $ 2.03
Implied DCF per Common Unit and Common Equivalent Unit (1) $ 1.63 $ 1.67 $ 1.99
 
Distributions per Common Unit (4) $ 2.65 $ 1.95 $ 1.20
Common Unit Distribution Coverage Ratio 0.87x 0.94x 1.70x
 
Operating Data
Transportation
Average daily volumes (MBbls/d) 4,637 5,186 5,925
Segment Adjusted EBITDA per barrel $ 0.67 $ 0.68 $ 0.71
 
Facilities
Average capacity (MMBbls/Mo) 127 130 125
Segment Adjusted EBITDA per barrel $ 0.44 $ 0.47 $ 0.44
 
Supply and Logistics
Average daily volumes (MBbls/d) 1,153 1,219 1,275
Segment Adjusted EBITDA per barrel $ 0.85 $ 0.13 $ 0.21
 
Expansion Capital $ 1,405 $ 1,135 $ 1,400
 
First-Quarter Adjusted EBITDA as Percentage of Full Year 29 % 25 % 25 %
 

_____________________________

(G)   2018 Guidance forecasts are intended to be + / - amounts.
 
(1) See the section of this release entitled “Non-GAAP Financial Measures and Selected Items Impacting Comparability” and the Non-GAAP Reconciliation tables attached hereto for information regarding non-GAAP financial measures and, for the historical 2016 and 2017 periods, their reconciliation to the most directly comparable measures as reported in accordance with GAAP. We do not provide a reconciliation of non-GAAP financial measures to the equivalent GAAP financial measures on a forward-looking basis as it is impractical to forecast certain items that we have defined as “Selected Items Impacting Comparability” without unreasonable effort, due to the uncertainty and inherent difficulty of predicting the occurrence and financial impact of and the periods in which such items may be recognized. Thus, a reconciliation of non-GAAP financial measures to the equivalent GAAP financial measures could result in disclosure that could be imprecise or potentially misleading.
 
(2) Excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps.
 
(3) Cash distributions paid to our preferred unitholders during the year presented. The distribution requirement of our Series A preferred units was paid-in-kind for all 2016 and 2017 quarterly distributions. Distributions on our Series A preferred units must be paid in cash beginning with the May 2018 quarterly distribution. The distribution requirement of our Series B preferred units, which were issued in October 2017, is payable semi-annually in arrears on May 15 and November 15. A pro-rated initial distribution on the Series B preferred units was paid on November 15, 2017.
 
(4) Cash distributions per common unit paid during 2016 and 2017. 2018(G) reflects the current distribution rate held constant.
 

Plains GP Holdings

PAGP owns an indirect non-economic controlling interest in PAA’s general partner and an indirect limited partner interest in PAA. As the control entity of PAA, PAGP consolidates PAA’s results into its financial statements, which is reflected in the condensed consolidating balance sheet and income statement tables included at the end of this release. Information regarding PAGP’s distributions is reflected below:

 
        Q4 2017     Q3 2017     Q4 2016

Distribution per Class A share declared for the period

$ 0.30 $ 0.30   $ 0.55  
Q4 2017 distribution percentage change from prior periods % (45 )%
 

Additionally, following the enactment of the Tax Cuts and Jobs Act of 2017 and the resulting decrease in the federal income tax rate from 35% to 21%, in the fourth quarter of 2017 PAGP re-measured its deferred tax asset and recorded deferred income tax expense of $823 million. This re-measurement is non-cash and does not affect the timing of when PAGP is expected to pay taxes, which we do not currently expect to occur within the next 10 years.

Conference Call

PAA and PAGP will hold a conference call at 10:00 a.m. CT on Wednesday, February 7, 2018 to discuss the following items:

1. PAA’s fourth-quarter 2017 and full-year 2017 performance;

2. Financial and operating guidance for the full year of 2018;

3. Capitalization and liquidity; and

4. PAA’s and PAGP’s outlook for the future.

Conference Call Webcast Instructions

To access the internet webcast please go to https://event.webcasts.com/starthere.jsp?ei=1176062&tp.

Alternatively, the webcast can be accessed at www.plainsallamerican.com, under the Investor Relations section of the website (Navigate to: Investor Relations / either PAA or PAGP / News & Events / Quarterly Earnings). Following the live webcast, an audio replay in MP3 format will be available on the website within two hours after the end of the call and will be accessible for a period of 365 days.

Non-GAAP Financial Measures and Selected Items Impacting Comparability

To supplement our financial information presented in accordance with GAAP, management uses additional measures known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the future. The primary additional measures used by management are earnings before interest, taxes, depreciation and amortization (including our proportionate share of depreciation and amortization and gains or losses on significant asset sales of unconsolidated entities) and adjusted for certain selected items impacting comparability (“Adjusted EBITDA”) and implied distributable cash flow (“DCF”).

Management believes that the presentation of such additional financial measures provides useful information to investors regarding our performance and results of operations because these measures, when used to supplement related GAAP financial measures, (i) provide additional information about our core operating performance and ability to fund distributions to our unitholders through cash generated by our operations and (ii) provide investors with the same financial analytical framework upon which management bases financial, operational, compensation and planning/budgeting decisions. We also present these and additional non-GAAP financial measures, including adjusted net income attributable to PAA; basic and diluted adjusted net income per common unit; implied DCF available to common unitholders; implied DCF per common unit; and implied DCF per common unit and common equivalent unit, as they are measurements that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations. These non-GAAP measures may exclude, for example, (i) charges for obligations that are expected to be settled with the issuance of equity instruments, (ii) gains or losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), the mark-to-market related to our Preferred Distribution Rate Reset Option, gains and losses on derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable, (iii) long-term inventory costing adjustments, (iv) items that are not indicative of our core operating results and business outlook and/or (v) other items that we believe should be excluded in understanding our core operating performance. These measures may further be adjusted to include amounts related to deficiencies associated with minimum volume commitments whereby we have billed the counterparties for their deficiency obligation and such amounts are recognized as deferred revenue in “Accounts payable and accrued liabilities” on our Consolidated Financial Statements. Such amounts are presented net of applicable amounts subsequently recognized into revenue. Furthermore, the calculation of these measures contemplates tax effects as a separate reconciling item, where applicable. We have defined all such items as “selected items impacting comparability.” Due to the nature of the selected items, certain selected items impacting comparability may impact certain non-GAAP financial measures, referred to as adjusted results, but not impact other non-GAAP financial measures. We do not necessarily consider all of our selected items impacting comparability to be non-recurring, infrequent or unusual, but we believe that an understanding of these selected items impacting comparability is material to the evaluation of our operating results and prospects.

Although we present selected items impacting comparability that management considers in evaluating our performance, you should also be aware that the items presented do not represent all items that affect comparability between the periods presented. Variations in our operating results are also caused by changes in volumes, prices, exchange rates, mechanical interruptions, acquisitions, expansion projects and numerous other factors. These types of variations are not separately identified in this release, but will be discussed, as applicable, in management’s discussion and analysis of operating results in our Annual Report on Form 10-K.

Our definition and calculation of certain non-GAAP financial measures may not be comparable to similarly-titled measures of other companies. Adjusted EBITDA, Implied DCF and other non-GAAP financial performance measures are reconciled to Net Income (the most directly comparable measure as reported in accordance with GAAP) for the historical periods presented in the tables attached to this release, and should be viewed in addition to, and not in lieu of, our Consolidated Financial Statements and notes thereto. In addition, we encourage you to visit our website at www.plainsallamerican.com (in particular the section under “Financial Information” entitled “Non-GAAP Reconciliations” within the Investor Relations tab), which presents a reconciliation of our commonly used non-GAAP and supplemental financial measures.

Forward-Looking Statements

Except for the historical information contained herein, the matters discussed in this release consist of forward-looking statements that involve certain risks and uncertainties that could cause actual results or outcomes to differ materially from results or outcomes anticipated in the forward-looking statements. These risks and uncertainties include, among other things, declines in the actual or expected volume of crude oil and NGL shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of our assets, whether due to declines in production from existing oil and gas reserves, reduced demand, failure to develop or slowdown in the development of additional oil and gas reserves, whether from reduced cash flow to fund drilling or the inability to access capital, or other factors; the effects of competition; market distortions caused by producer over-commitments to infrastructure projects, which impacts volumes, margins, returns and overall earnings; unanticipated changes in crude oil and NGL market structure, grade differentials and volatility (or lack thereof); maintenance of our credit rating and ability to receive open credit from our suppliers and trade counterparties; environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves; fluctuations in refinery capacity in areas supplied by our mainlines and other factors affecting demand for various grades of crude oil and natural gas and resulting changes in pricing conditions or transportation throughput requirements; the occurrence of a natural disaster, catastrophe, terrorist attack (including eco-terrorist attacks) or other event, including attacks on our electronic and computer systems; failure to implement or capitalize, or delays in implementing or capitalizing, on expansion projects, whether due to permitting delays, permitting withdrawals or other factors; tightened capital markets or other factors that increase our cost of capital or limit our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, expansion projects, working capital requirements and the repayment or refinancing of indebtedness; the successful integration and future performance of acquired assets or businesses and the risks associated with operating in lines of business that are distinct and separate from our historical operations; the failure to consummate, or significant delay in consummating, sales of assets or interests as a part of our strategic divestiture program; the impact of current and future laws, rulings, governmental regulations, accounting standards and statements, and related interpretations; the currency exchange rate of the Canadian dollar; continued creditworthiness of, and performance by, our counterparties, including financial institutions and trading companies with which we do business; inability to recognize current revenue attributable to deficiency payments received from customers who fail to ship or move more than minimum contracted volumes until the related credits expire or are used; non-utilization of our assets and facilities; increased costs, or lack of availability, of insurance; weather interference with business operations or project construction, including the impact of extreme weather events or conditions; the availability of, and our ability to consummate, acquisition or combination opportunities; the effectiveness of our risk management activities; shortages or cost increases of supplies, materials or labor; fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our long-term incentive plans; risks related to the development and operation of our assets, including our ability to satisfy our contractual obligations to our customers; factors affecting demand for natural gas and natural gas storage services and rates; general economic, market or business conditions and the amplification of other risks caused by volatile financial markets, capital constraints and pervasive liquidity concerns; and other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil, as well as in the storage of natural gas and the processing, transportation, fractionation, storage and marketing of natural gas liquids as discussed in the Partnerships’ filings with the Securities and Exchange Commission.

Plains All American Pipeline, L.P. is a publicly traded master limited partnership that owns and operates midstream energy infrastructure and provides logistics services for crude oil, natural gas liquids (“NGL”) and natural gas. PAA owns an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins and transportation corridors and at major market hubs in the United States and Canada. On average, PAA handles over 5 million barrels per day of crude oil and NGL in its Transportation segment. PAA is headquartered in Houston, Texas. More information is available at www.plainsallamerican.com.

Plains GP Holdings is a publicly traded entity that owns an indirect, non-economic controlling general partner interest in PAA and an indirect limited partner interest in PAA, one of the largest energy infrastructure and logistics companies in North America. PAGP is headquartered in Houston, Texas. More information is available at www.plainsallamerican.com.

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 
 

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per unit data)

 
       

Three Months Ended

December 31,

     

Twelve Months Ended

December 31,

2017       2016 2017       2016
REVENUES $ 7,605 $ 5,952 $ 26,223 $ 20,182
 
COSTS AND EXPENSES
Purchases and related costs 6,746 5,234 22,985 17,233
Field operating costs 307 289 1,183 1,182
General and administrative expenses 66 68 276 279
Depreciation and amortization 225   143   626   494  
Total costs and expenses 7,344 5,734 25,070 19,188
 
OPERATING INCOME 261 218 1,153 994
 
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities 90 61 290 195
Interest expense, net (120 ) (127 ) (510 ) (467 )
Other income/(expense), net (26 ) (14 ) (31 ) 33  
 
INCOME BEFORE TAX 205 138 902 755
Current income tax expense (19 ) (41 ) (28 ) (85 )
Deferred income tax benefit/(expense) 5   30   (16 ) 60  
 
NET INCOME 191 127 858 730
Net income attributable to noncontrolling interests   (1 ) (2 ) (4 )
NET INCOME ATTRIBUTABLE TO PAA $ 191   $ 126   $ 856   $ 726  
 
NET INCOME PER COMMON UNIT:
Net income allocated to common unitholders — Basic $ 138 $ 91 $ 685 $ 200
Basic weighted average common units outstanding 725 660 717 464
Basic net income per common unit $ 0.19   $ 0.14   $ 0.96   $ 0.43  
 
Net income allocated to common unitholders — Diluted $ 138 $ 91 $ 685 $ 200
Diluted weighted average common units outstanding 726 662 718 466
Diluted net income per common unit $ 0.19   $ 0.14   $ 0.95   $ 0.43  
 
 

NON-GAAP ADJUSTED RESULTS

(in millions, except per unit data)

 

Three Months Ended

December 31,

Twelve Months Ended

December 31,

2017 2016 2017 2016
Adjusted net income attributable to PAA $ 241   $ 278   $ 849   $ 1,062  
 
Diluted adjusted net income per common unit $ 0.26   $ 0.37   $ 0.94   $ 1.14  
 
Adjusted EBITDA $ 631   $ 600   $ 2,082   $ 2,169  
 
 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 

 

CONDENSED CONSOLIDATED BALANCE SHEET DATA

(in millions)

 
       

December 31,

2017

     

December 31,

2016

ASSETS
Current assets $ 4,000 $ 4,272
Property and equipment, net 14,089 13,872
Goodwill 2,566 2,344
Investments in unconsolidated entities 2,756 2,343
Linefill and base gas 872

896

Long-term inventory 164 193
Other long-term assets, net 904   290
Total assets $ 25,351   $ 24,210
 
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities $ 4,531 $ 4,664
Senior notes, net of unamortized discounts and debt issuance costs 8,933 9,874
Other long-term debt 250 250
Other long-term liabilities and deferred credits 679   606
Total liabilities $ 14,393 $ 15,394
 
Partners' capital excluding noncontrolling interests 10,958 8,759
Noncontrolling interests   57
Total partners' capital 10,958   8,816
Total liabilities and partners' capital $ 25,351   $ 24,210
 

DEBT CAPITALIZATION RATIOS

(in millions)

 

December 31,

2017

December 31,

2016

Short-term debt (1) $ 737 $ 1,715
Long-term debt 9,183   10,124  
Total debt $ 9,920   $ 11,839  
 
Long-term debt $ 9,183 $ 10,124
Partners' capital 10,958   8,816  
Total book capitalization $ 20,141   $ 18,940  
Total book capitalization, including short-term debt $ 20,878   $ 20,655  
 
Long-term debt-to-total book capitalization 46 % 53 %
Total debt-to-total book capitalization, including short-term debt 48 % 57 %
 

_____________________________

(1)   As of December 31, 2017 and 2016, short-term debt includes borrowings of approximately $523 million and $1,303 million, respectively, for short-term hedged inventory purchases and borrowings of approximately $212 million and $410 million, respectively, for cash margin deposits with our clearing brokers, which are associated with financial derivatives used for hedging purposes.
 
 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 
 

OPERATING DATA (1)

       

Three Months Ended

December 31,

   

Twelve Months Ended

December 31,

2017     2016 2017     2016
Transportation segment (average daily volumes in thousands of barrels per day):
Tariff activities volumes
Crude oil pipelines (by region):
Permian Basin (2) 3,219 2,197 2,855 2,146
South Texas / Eagle Ford (2) 418 284 360 284
Central (2) 424 397 420 394
Gulf Coast 312 373 349 497
Rocky Mountain (2) 317 454 393 449
Western 179 171 184 188
Canada 330   374   352   381
Crude oil pipelines 5,199 4,250 4,913 4,339
NGL pipelines 172   190   170   184
Tariff activities total volumes 5,371 4,440 5,083 4,523
Trucking volumes 106   118   103   114
Transportation segment total volumes 5,477   4,558   5,186   4,637
 
Facilities segment (average monthly volumes):
Liquids storage (average monthly capacity in millions of barrels) 114   110   112   107
Natural gas storage (average monthly working capacity in billions of cubic feet) 67   97   82   97
NGL fractionation (average volumes in thousands of barrels per day) 127   122   126   115
Facilities segment total volumes (average monthly volumes in millions of barrels) (3) 129   129   130   127
 
Supply and Logistics segment (average daily volumes in thousands of barrels per day):
Crude oil lease gathering purchases 994 895 945 894
NGL sales 335   346   274   259
Supply and Logistics segment total volumes 1,329   1,241   1,219   1,153
 

_____________________________

(1)   Average volumes are calculated as total volumes for the period (attributable to our interest) divided by the number of days or months in the period.
 
(2) Region includes volumes (attributable to our interest) from pipelines owned by unconsolidated entities.
 
(3) Facilities segment total volumes is calculated as the sum of: (i) liquids storage capacity; (ii) natural gas storage working capacity divided by 6 to account for the 6:1 mcf of natural gas to crude Btu equivalent ratio and further divided by 1,000 to convert to monthly volumes in millions; and (iii) NGL fractionation volumes multiplied by the number of days in the period and divided by the number of months in the period.
 
 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 
 

COMPUTATION OF BASIC AND DILUTED NET INCOME PER COMMON UNIT (1)

(in millions, except per unit data)

 
       

Three Months Ended

December 31,

   

Twelve Months Ended

December 31,

2017     2016 2017     2016
Basic Net Income per Common Unit
Net income attributable to PAA $ 191 $ 126 $ 856 $ 726
Distributions to Series A preferred unitholders (37 ) (34 ) (142 ) (122 )
Distributions to Series B preferred unitholders (11 ) (11 )
Distributions to general partner (412 )
Other (5 ) (1 ) (18 ) 8  
Net income allocated to common unitholders $ 138   $ 91   $ 685   $ 200  
 
Basic weighted average common units outstanding 725 660 717 464
 
Basic net income per common unit $ 0.19   $ 0.14   $ 0.96   $ 0.43  
 
Diluted Net Income per Common Unit
Net income attributable to PAA $ 191 $ 126 $ 856 $ 726
Distributions to Series A preferred unitholders (37 ) (34 ) (142 ) (122 )
Distributions to Series B preferred unitholders (11 ) (11 )
Distributions to general partner (412 )
Other (5 ) (1 ) (18 ) 8  
Net income allocated to common unitholders $ 138   $ 91   $ 685   $ 200  
 
Basic weighted average common units outstanding 725 660 717 464
Effect of dilutive securities:
LTIP units (2) 1   2   1   2  
Diluted weighted average common units outstanding 726   662   718   466  
 
Diluted net income per common unit (3) $ 0.19   $ 0.14   $ 0.95   $ 0.43  
 

_____________________________

(1)   We calculate net income allocated to common unitholders based on the distributions pertaining to the current period’s net income (whether paid in cash or in-kind). After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings (“undistributed loss”), if any, are allocated to the general partner (for periods prior to the Simplification Transactions), common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method. The Simplification Transactions, which closed on November 15, 2016, simplified our governance structure and permanently eliminated our IDRs and the economic rights associated with our 2% general partner interest. As such, beginning with the distribution pertaining to the fourth quarter of 2016, our general partner is no longer entitled to receive distributions on these interests.
 
(2) Our Long-term Incentive Plan (“LTIP”) awards that contemplate the issuance of common units are considered dilutive unless (i) vesting occurs only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards that are deemed to be dilutive are reduced by a hypothetical unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB.
 
(3) The possible conversion of our Series A preferred units was excluded from the calculation of diluted net income per common unit for the three and twelve months ended December 31, 2017 and 2016 as the effect was antidilutive.
 
 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 
 

SELECTED FINANCIAL DATA BY SEGMENT

(in millions)

 
        Three Months Ended
December 31, 2017
    Three Months Ended
December 31, 2016
Transportation     Facilities    

Supply and

Logistics

Transportation     Facilities    

Supply and

Logistics

Revenues (1) $ 458 $ 299 $ 7,308 $ 396 $ 290 $ 5,665
Purchases and related costs (1) (48 ) (4 ) (7,151 ) (25 ) (9 ) (5,596 )
Field operating costs (1) (2) (158 ) (91 ) (61 ) (136 ) (91 ) (65 )

Segment general and administrative expenses (2) (3)

(24 ) (18 ) (24 ) (25 ) (16 ) (27 )

Equity earnings in unconsolidated entities

90 61
 
Adjustments: (4)

Depreciation and amortization of unconsolidated entities

13 13

(Gains)/losses from derivative activities net of inventory valuation adjustments

40 (2 ) 217

Long-term inventory costing adjustments

(22 ) (51 )

Deficiencies under minimum volume commitments, net

(3 ) (11 ) (3 )

Equity-indexed compensation expense

3 1 1 5 2 3

Net loss on foreign currency revaluation

1 5
Line 901 incident 20            
Segment adjusted EBITDA $ 354   $ 184   $ 92   $ 278   $ 171   $ 151  
 
Maintenance capital $ 31   $ 20   $ 2   $ 35   $ 23   $  
 

_____________________________

(1)   Includes intersegment amounts.
 
(2) Field operating costs and Segment general and administrative expenses include equity-indexed compensation expense.
 
(3) Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.
 
(4) Represents adjustments utilized by our Chief Operating Decision Maker (“CODM”) in the evaluation of segment results. Many of these adjustments are also considered selected items impacting comparability when calculating consolidated non-GAAP financial measures such as Adjusted EBITDA. See the “Selected Items Impacting Comparability” table for additional discussion.
 
 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 
 

SELECTED FINANCIAL DATA BY SEGMENT

(in millions)

 
        Twelve Months Ended
December 31, 2017
    Twelve Months Ended
December 31, 2016
Transportation     Facilities    

Supply and

Logistics

Transportation     Facilities    

Supply and

Logistics

Revenues (1) $ 1,718 $ 1,173 $ 25,065 $ 1,584 $ 1,107 $ 19,018
Purchases and related costs (1) (123 ) (24 ) (24,557 ) (94 ) (26 ) (18,627 )
Field operating costs (1) (2) (593 ) (350 ) (254 ) (551 ) (352 ) (292 )
Segment general and administrative expenses (2) (3) (101 ) (73 ) (102 ) (103 ) (68 ) (108 )
Equity earnings in unconsolidated entities 290 195
 
Adjustments: (4)
Depreciation and amortization of unconsolidated entities 45 50
(Gains)/losses from derivative activities net of inventory valuation adjustments 4 (50 ) (2 ) 406
Long-term inventory costing adjustments (24 ) (58 )
Deficiencies under minimum volume commitments, net 2 44 2
Equity-indexed compensation expense 11 4 8 16 7 10
Net (gain)/loss on foreign currency revaluation (26 ) (1 ) 10
Line 901 incident 32
Significant acquisition-related expenses 6            
Segment adjusted EBITDA $ 1,287   $ 734   $ 60   $ 1,141   $ 667   $ 359  
 
Maintenance capital $ 120   $ 114   $ 13   $ 121   $ 55   $ 10  
 

_____________________________

(1)   Includes intersegment amounts.
 
(2) Field operating costs and Segment general and administrative expenses include equity-indexed compensation expense.
 
(3) Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.
 
(4) Represents adjustments utilized by our CODM in the evaluation of segment results. Many of these adjustments are also considered selected items impacting comparability when calculating consolidated non-GAAP financial measures such as Adjusted EBITDA. See the “Selected Items Impacting Comparability” table for additional discussion.
 
 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 
 

SELECTED ITEMS IMPACTING COMPARABILITY

(in millions)

       

Three Months Ended

December 31,

   

Twelve Months Ended

December 31,

2017     2016 2017     2016
Selected Items Impacting Comparability: (1)
Gains/(losses) from derivative activities net of inventory valuation adjustments (2) $ (28 ) $ (227 ) $ 59 $ (374 )
Long-term inventory costing adjustments (3) 22 51 24 58
Deficiencies under minimum volume commitments, net (4) 3 14 (2 ) (46 )
Equity-indexed compensation expense (5) (5 ) (10 ) (23 ) (33 )
Net gain/(loss) on foreign currency revaluation (6) (7 ) 21 (8 )
Line 901 incident (7) (20 ) (32 )
Significant acquisition-related expenses (8) (6 )
Net loss on early repayment of senior notes (9) (40 )   (40 )  
Selected items impacting comparability - Adjusted EBITDA $ (68 ) $ (179 ) $ 1 $ (403 )
Losses from derivative activities (2) (10 )
Tax effect on selected items impacting comparability 18   27   16   67  
Selected items impacting comparability - Adjusted net income attributable to PAA $ (50 ) $ (152 ) $ 7   $ (336 )
 

_____________________________

(1)   Certain of our non-GAAP financial measures may not be impacted by each of the selected items impacting comparability.
 
(2) We use derivative instruments for risk management purposes and our related processes include specific identification of hedging instruments to an underlying hedged transaction. Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction. In the course of evaluating our results of operations, we identify the earnings that were recognized during the period related to derivative instruments for which the identified underlying transaction does not occur in the current period and exclude the related gains and losses in determining adjusted results. In addition, we exclude gains and losses on derivatives that are related to investing activities, such as the purchase of linefill. We also exclude the impact of corresponding inventory valuation adjustments, as applicable, as well as the mark-to-market adjustment related to our Preferred Distribution Rate Reset Option.
 
(3) We carry crude oil and NGL inventory comprised of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets). We treat the impact of changes in the average cost of the long-term inventory (that result from fluctuations in market prices) and writedowns of such inventory that result from price declines as a selected item impacting comparability.
 
(4) We have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. Substantially all of such agreements were entered into with counterparties to economically support the return on our capital expenditure necessary to construct the related asset. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue, as a selected item impacting comparability. We believe the inclusion of the contractually committed revenues associated with that period is meaningful to investors as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results.
 
(5) Our total equity-indexed compensation expense includes expense associated with awards that will or may be settled in units and awards that will or may be settled in cash. The awards that will or may be settled in units are included in our diluted net income per unit calculation when the applicable performance criteria have been met. We consider the compensation expense associated with these awards as a selected item impacting comparability as the dilutive impact of the outstanding awards is included in our diluted net income per unit calculation and the majority of the awards are expected to be settled in units. The portion of compensation expense associated with awards that are certain to be settled in cash is not considered a selected item impacting comparability.
 
(6) During the periods presented, there were fluctuations in the value of the Canadian dollar to the U.S. dollar, resulting in gains and losses that were not related to our core operating results for the period and were thus classified as a selected item impacting comparability.
 
(7) Includes costs recognized during the period related to the Line 901 incident that occurred in May 2015, net of amounts we believe are probable of recovery from insurance.
 
(8) Includes acquisition-related expenses associated with the Alpha Crude Connector acquisition.
 
(9) Includes net losses incurred in connection with the early redemption of our (i) $600 million, 6.50% senior notes due May 2018 and (ii) $350 million, 8.75% senior notes due May 2019.
 
 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 
 

NON-GAAP RECONCILIATIONS

(in millions, except per unit data)

 
       

Three Months Ended

December 31,

   

Twelve Months Ended

December 31,

2017     2016 2017     2016
Net Income to Adjusted EBITDA and Implied DCF Reconciliation
Net Income $ 191 $ 127 $ 858 $ 730
Interest expense, net 120 127 510 467
Income tax expense 14 11 44 25
Depreciation and amortization 225 143 626 494
Depreciation and amortization of unconsolidated entities (1) 13 13 45 50
Selected items impacting comparability - Adjusted EBITDA (2) 68   179   (1 ) 403  
Adjusted EBITDA $ 631   $ 600   $ 2,082   $ 2,169  
Interest expense, net (3) (116 ) (123 ) (483 ) (451 )
Maintenance capital (53 ) (58 ) (247 ) (186 )
Current income tax expense (19 ) (41 ) (28 ) (85 )
Adjusted equity earnings in unconsolidated entities, net of distributions (4) (19 ) (9 ) (10 ) (29 )
Distributions to noncontrolling interests   (1 ) (2 ) (4 )
Implied DCF (5) $ 424 $ 368 $ 1,312 $ 1,414
Preferred unit cash distributions (6) (5 ) (5 )
General partner cash distributions (7)   (101 )   (565 )
Implied DCF Available to Common Unitholders $ 419   $ 267   $ 1,307   $ 849  
 
Implied DCF per Common Unit (8) $ 0.58 $ 0.40 $ 1.82 $ 1.83
Implied DCF per Common Unit and Common Equivalent Unit (9) $ 0.53 $ 0.37 $ 1.67 $ 1.63
 
Cash Distribution Paid per Common Unit $ 0.30 $ 0.55 $ 1.95 $ 2.65
Common Unit Cash Distributions (10) $ 218 $ 328 $ 1,386 $ 1,627
Common Unit Distribution Coverage Ratio 1.92x 1.12x 0.94x 0.87x
 
Implied DCF Excess / (Shortage) $ 201 $ 40 $ (79 ) $ (213 )
 

_____________________________

(1)   Adjustment to add back our proportionate share of depreciation and amortization expense and gains or losses on significant asset sales of unconsolidated entities.
 
(2) Certain of our non-GAAP financial measures may not be impacted by each of the selected items impacting comparability.
 
(3) Excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps.
 
(4) Represents the difference between non-cash equity earnings in unconsolidated entities (adjusted for our proportionate share of depreciation and amortization and gains or losses on significant asset sales) and cash distributions received from such entities.
 
(5) Including net costs recognized during the periods related to the Line 901 incident that occurred in May 2015, Implied DCF would have been $404 million and $1,280 million for the three and twelve months ended December 31, 2017, respectively.
 
(6) Cash distributions paid to our preferred unitholders during the period presented. The $0.5250 quarterly ($2.10 annualized) per unit distribution requirement of our Series A preferred units has been paid-in-kind for each quarterly distribution since their issuance; as such, no Series A preferred unit distributions are included for any periods presented. Distributions on our Series A preferred units must be paid in cash beginning with the May 2018 quarterly distribution. The $61.25 per unit annual distribution requirement of our Series B preferred units, which were issued in October 2017, is payable semi-annually in arrears on May 15 and November 15. A pro-rated initial distribution on the Series B preferred units was paid on November 15, 2017.
 
(7) The Simplification Transactions, which closed on November 15, 2016, simplified our governance structure and permanently eliminated our incentive distribution rights (IDRs) and the economic rights associated with our 2% general partner interest.
 
(8) Implied DCF Available to Common Unitholders for the period divided by the weighted average common units outstanding for the periods of 725 million, 660 million, 717 million and 464 million, respectively.
 
(9) Implied DCF Available to Common Unitholders for the period, adjusted for Series A preferred unit cash distributions paid (if any), divided by the weighted average common units and common equivalent units outstanding for the periods of 794 million, 724 million, 784 million and 522 million, respectively. Our Series A preferred units are convertible into common units, generally on a one-for-one basis and subject to customary anti-dilution adjustments, at any time after January 28, 2018, in whole or in part, subject to certain minimum conversion amounts.
 
(10) Cash distributions paid during the period presented. For the three and twelve months ended December 31, 2016, includes $101 million and $565 million, respectively, of cash distributions paid to the general partner during the period.
 
 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 
 

NON-GAAP RECONCILIATIONS (continued)

       

Three Months Ended

December 31,

   

Twelve Months Ended

December 31,

2017     2016 2017     2016

Net Income Per Common Unit to Implied DCF Per Common Unit

  and Common Equivalent Unit Reconciliation

Basic net income per common unit $ 0.19 $ 0.14 $ 0.96 $ 0.43
Reconciling items per common unit (1) (2) 0.39   0.26   0.86   1.40
Implied DCF per common unit $ 0.58   $ 0.40   $ 1.82   $ 1.83
 
Basic net income per common unit $ 0.19 $ 0.14 $ 0.96 $ 0.43
Reconciling items per common unit and common equivalent unit (1) (3) 0.34   0.23   0.71   1.20
Implied DCF per common unit and common equivalent unit $ 0.53   $ 0.37   $ 1.67   $ 1.63
 

_____________________________

(1)   Represents adjustments to Net Income to calculate Implied DCF Available to Common Unitholders. See the “Net Income to Adjusted EBITDA and Implied DCF Reconciliation” table for additional information.
 
(2) Based on weighted average common units outstanding for the period of 725 million, 660 million, 717 million and 464 million, respectively.
 
(3) Based on weighted average common units outstanding for the period, as well as weighted average Series A preferred units outstanding for the period of 69 million, 64 million, 67 million and 58 million, respectively.
 
 
       

Three Months Ended

December 31,

   

Twelve Months Ended

December 31,

2017     2016 2017     2016

Net Income Per Common Unit to Adjusted Net Income Per

  Common Unit Reconciliation

Basic net income per common unit $ 0.19 $ 0.14 $ 0.96 $ 0.43
Selected items impacting comparability per common unit (1) 0.07   0.23   (0.01 ) 0.72
Basic adjusted net income per common unit $ 0.26   $ 0.37   $ 0.95   $ 1.15
 
Diluted net income per common unit $ 0.19 $ 0.14 $ 0.95 $ 0.43
Selected items impacting comparability per common unit (1) 0.07   0.23   (0.01 ) 0.71
Diluted adjusted net income per common unit $ 0.26   $ 0.37   $ 0.94   $ 1.14
 

_____________________________

(1)   See the “Selected Items Impacting Comparability” and the “Computation of Basic and Diluted Adjusted Net Income Per Common Unit” tables for additional information.
 
 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 
 

COMPUTATION OF BASIC AND DILUTED ADJUSTED NET INCOME PER COMMON UNIT (1)

(in millions, except per unit data)

       

Three Months Ended

December 31,

   

Twelve Months Ended

December 31,

2017     2016 2017     2016
Basic Adjusted Net Income per Common Unit
Net income attributable to PAA $ 191 $ 126 $ 856 $ 726
Selected items impacting comparability - Adjusted net income attributable to PAA (2) 50   152   (7 ) 336  
Adjusted net income attributable to PAA $ 241 $ 278 $ 849 $ 1,062
Distributions to Series A preferred unitholders (37 ) (34 ) (142 ) (122 )
Distributions to Series B preferred unitholders (11 ) (11 )
Distributions to general partner (412 )
Other (5 ) (1 ) (17 ) 5  
Adjusted net income allocated to common unitholders $ 188   $ 243   $ 679   $ 533  
 
Basic weighted average common units outstanding 725 660 717 464
 
Basic adjusted net income per common unit $ 0.26   $ 0.37   $ 0.95   $ 1.15  
 
Diluted Adjusted Net Income per Common Unit
Net income attributable to PAA $ 191 $ 126 $ 856 $ 726
Selected items impacting comparability - Adjusted net income attributable to PAA (2) 50   152   (7 ) 336  
Adjusted net income attributable to PAA $ 241 $ 278 $ 849 $ 1,062
Distributions to Series A preferred unitholders (37 ) (34 ) (142 ) (122 )
Distributions to Series B preferred unitholders (11 ) (11 )
Distributions to general partner (412 )
Other (5 ) (1 ) (17 ) 5  
Adjusted net income allocated to common unitholders $ 188   $ 243   $ 679   $ 533  
 
Basic weighted average common units outstanding 725 660 717 464
Effect of dilutive securities:
LTIP units (3) 1   2   1   2  
Diluted weighted average common units outstanding 726   662   718   466  
 
Diluted adjusted net income per common unit (4) $ 0.26   $ 0.37   $ 0.94   $ 1.14  
 

_____________________________

(1)   We calculate adjusted net income allocated to common unitholders based on the distributions pertaining to the current period’s net income (whether paid in cash or in-kind). After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings (“undistributed loss”), if any, are allocated to the general partner (for periods prior to the Simplification Transactions), common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method. The Simplification Transactions, which closed on November 15, 2016, simplified our governance structure and permanently eliminated our IDRs and the economic rights associated with our 2% general partner interest. As such, beginning with the distribution pertaining to the fourth quarter of 2016, our general partner is no longer entitled to receive distributions from these interests.
 
(2) Certain of our non-GAAP financial measures may not be impacted by each of the selected items impacting comparability.
 
(3) Our LTIP awards that contemplate the issuance of common units are considered dilutive unless (i) vesting occurs only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards that are deemed to be dilutive are reduced by a hypothetical unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB.
 
(4) The possible conversion of our Series A preferred units was excluded from the calculation of diluted adjusted net income per common unit for the three and twelve months ended December 31, 2017 and 2016 as the effect was antidilutive.
 
       

PLAINS GP HOLDINGS AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

             
 

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(in millions, except per share data)

 

Three Months Ended
December 31, 2017

Three Months Ended
December 31, 2016
  Consolidating     Consolidating  
PAA Adjustments (1) PAGP PAA Adjustments (1) PAGP
REVENUES $ 7,605 $ $ 7,605 $ 5,952 $ $ 5,952
 
COSTS AND EXPENSES
Purchases and related costs 6,746 6,746 5,234 5,234
Field operating costs 307 307 289 289
General and administrative expenses 66 1 67 68 1 69
Depreciation and amortization 225     225   143     143  
Total costs and expenses 7,344 1 7,345 5,734 1 5,735
 
OPERATING INCOME 261 (1 ) 260 218 (1 ) 217
 
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities 90 90 61 61
Interest expense, net (120 ) (120 ) (127 ) (3 ) (130 )
Other expense, net (26 )   (26 ) (14 )   (14 )
 
INCOME BEFORE TAX 205 (1 ) 204 138 (4 ) 134
Current income tax expense (19 ) (19 ) (41 ) (41 )
Deferred income tax benefit/(expense) 5   (837 ) (832 ) 30   (1 ) 29  
 
NET INCOME/(LOSS) 191 (838 ) (647 ) 127 (5 ) 122
Net income attributable to noncontrolling interests   (153 ) (153 ) (1 ) (129 ) (130 )
NET INCOME/(LOSS) ATTRIBUTABLE TO PAGP $ 191   $ (991 ) $ (800 ) $ 126   $ (134 ) $ (8 )
 
BASIC AND DILUTED NET INCOME/(LOSS) PER CLASS A SHARE $ (5.16 ) $ (0.08 )
 
BASIC AND DILUTED WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING 155   101  

_____________________________

(1)

 

Represents the aggregate consolidating adjustments necessary to produce consolidated financial statements for PAGP.

 
       

PLAINS GP HOLDINGS AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 
 

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(in millions, except per share data)

 
Twelve Months Ended
December 31, 2017
Twelve Months Ended
December 31, 2016
  Consolidating     Consolidating  
PAA Adjustments (1) PAGP PAA Adjustments (1) PAGP
REVENUES $ 26,223 $ $ 26,223 $ 20,182 $ $ 20,182
 
COSTS AND EXPENSES
Purchases and related costs 22,985 22,985 17,233 17,233
Field operating costs 1,183 1,183 1,182 1,182
General and administrative expenses 276 4 280 279 3 282
Depreciation and amortization 626   2   628   494   1   495  
Total costs and expenses 25,070 6 25,076 19,188 4 19,192
 
OPERATING INCOME 1,153 (6 ) 1,147 994 (4 ) 990
 
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities 290 290 195 195
Interest expense, net (510 ) (510 ) (467 ) (13 ) (480 )
Other income/(expense), net (31 )   (31 ) 33     33  
 
INCOME BEFORE TAX 902 (6 ) 896 755 (17 ) 738
Current income tax expense (28 ) (28 ) (85 ) (85 )
Deferred income tax benefit/(expense) (16 ) (893 ) (909 ) 60   (53 ) 7  
 
NET INCOME/(LOSS) 858 (899 ) (41 ) 730 (70 ) 660
Net income attributable to noncontrolling interests (2 ) (688 ) (690 ) (4 ) (562 ) (566 )
NET INCOME/(LOSS) ATTRIBUTABLE TO PAGP $ 856   $ (1,587 ) $ (731 ) $ 726   $ (632 ) $ 94  
 
BASIC AND DILUTED NET INCOME/(LOSS) PER CLASS A SHARE $ (5.03 ) $ 0.94  
 
BASIC AND DILUTED WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING 145   99  

_____________________________

(1)

 

Represents the aggregate consolidating adjustments necessary to produce consolidated financial statements for PAGP.

 
       

PLAINS GP HOLDINGS AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 
 

CONDENSED CONSOLIDATING BALANCE SHEET DATA

(in millions)

 
December 31, 2017 December 31, 2016
  Consolidating     Consolidating  
PAA Adjustments (1) PAGP PAA Adjustments (1) PAGP
ASSETS
Current assets $ 4,000 $ 3 $ 4,003 $ 4,272 $ 3 $ 4,275
Property and equipment, net 14,089 16 14,105 13,872 18 13,890
Goodwill 2,566 2,566 2,344 2,344
Investments in unconsolidated entities 2,756 2,756 2,343 2,343
Deferred tax asset 1,386 1,386 1,876 1,876
Linefill and base gas 872 872 896 896
Long-term inventory 164 164 193 193
Other long-term assets, net 904   (3 ) 901   290   (4 ) 286

Total assets

$ 25,351   $ 1,402   $ 26,753   $ 24,210   $ 1,893   $ 26,103
 
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities $ 4,531 $ 2 $ 4,533 $ 4,664 $ 2 $ 4,666
Senior notes, net of unamortized discounts and debt issuance costs 8,933 8,933 9,874 9,874
Other long-term debt 250 250 250 250
Other long-term liabilities and deferred credits 679     679   606     606
Total liabilities $ 14,393 $ 2 $ 14,395 $ 15,394 $ 2 $ 15,396
 
Partners' capital excluding noncontrolling interests 10,958 (9,263 ) 1,695 8,759 (7,022 ) 1,737
Noncontrolling interests   10,663   10,663   57   8,913   8,970
Total partners' capital 10,958   1,400   12,358   8,816   1,891   10,707
Total liabilities and partners' capital $ 25,351   $ 1,402   $ 26,753   $ 24,210   $ 1,893   $ 26,103

_____________________________

(1)

 

Represents the aggregate consolidating adjustments necessary to produce consolidated financial statements for PAGP.

 
     

PLAINS GP HOLDINGS AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 
 

COMPUTATION OF BASIC AND DILUTED NET INCOME/(LOSS) PER CLASS A SHARE

(in millions, except per share data)

 

Three Months Ended
December 31,

Twelve Months Ended
December 31,

2017   2016 2017   2016
Basic and Diluted Net Income/(Loss) per Class A Share
Net income/(loss) attributable to PAGP $ (800 ) $ (8 ) $ (731 ) $ 94
Basic and diluted weighted average Class A shares outstanding 155 101 145 99
 
Basic and diluted net income/(loss) per Class A share (1) $ (5.16 ) $ (0.08 ) $ (5.03 ) $ 0.94

_____________________________

(1)

 

For the three and twelve months ended December 31, 2017 and 2016, the possible exchange of any AAP units and certain AAP Management Units would not have had a dilutive effect on basic net income/(loss) per Class A share.

 

Contacts

Plains All American Pipeline, L.P. and Plains GP Holdings
Roy Lamoreaux, 866-809-1291
Vice President, Investor Relations & Communications
or
Brett Magill, 866-809-1291
Manager, Investor Relations

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