PAA Plains All American Pipeline

PAA Also Furnishes 2017 Full-Year Guidance

Plains All American Pipeline, L.P. (NYSE: PAA) and Plains GP Holdings (NYSE: PAGP) today reported fourth-quarter and full-year 2016 results.

 

Plains All American Pipeline, L.P.

 

Summary Financial Information (unaudited)

(in millions, except per unit data)           Three Months Ended         Twelve Months Ended     December 31, December 31, GAAP Results         2016     2015 %

Change

2016     2015 %

Change

Net income attributable to PAA $ 126 $ 247 (49 )% $ 726 $ 903 (20 )% Diluted net income per common unit $ 0.14 $ 0.24 (42 )% $ 0.43 $ 0.77 (44 )% Diluted weighted average common units outstanding           662   399 66 %

 

466

  396 18 % Distribution per common unit declared for the period         $ 0.55 $ 0.70 (21.4 )%

$

2.50

$

2.78

(10.1

)%

      Three Months Ended Twelve Months Ended December 31, December 31, Non-GAAP Results (1)         2016 2015 %

Change

2016 2015 %

Change

Adjusted net income attributable to PAA $ 278 $ 304 (9 )% $ 1,062 $ 1,191 (11 )% Diluted adjusted net income per common unit $ 0.37 $ 0.38 (3 )% $ 1.14 $ 1.48 (23 )% Adjusted EBITDA (2) $ 600 $ 575 4 % $ 2,169 $ 2,213 (2 )%

________________________

 

(1)

 

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

 

(2)

During the fourth quarter of 2016, we modified our definition of adjusted EBITDA to exclude depreciation and amortization expense associated with equity method investments. Prior period amounts have been recast to reflect this change.

 

“PAA reported fourth-quarter 2016 adjusted EBITDA of $600 million which was essentially in line with the fourth-quarter guidance furnished last November and full-year 2016 adjusted EBITDA of $2.169 billion,” said Greg Armstrong, Chairman and CEO of Plains All American.

“Looking forward, we are encouraged by the significant increase in drilling and completion activities in the Permian Basin observed over the latter half of 2016 and continuing into 2017. These activity levels have increased our conviction in significant Permian Basin production growth in 2017 and beyond as we discussed on our acquisition related conference call on January 25th.”

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

 

Summary of Selected Financial Data by Segment(1)(unaudited)

(in millions)           Three Months Ended     Three Months Ended December 31, 2016 December 31, 2015 Transportation   Facilities   Supply and

Logistics

Transportation   Facilities   Supply and

Logistics

Segment adjusted EBITDA $ 278     $ 171   $ 151     $ 268   $ 150 $ 157 Percentage change in segment adjusted EBITDA versus 2015 period   4 %     14 %   (4 )%       Twelve Months Ended Twelve Months Ended December 31, 2016 December 31, 2015 Transportation Facilities Supply and

Logistics

Transportation Facilities Supply and

Logistics

Segment adjusted EBITDA $ 1,141     $ 667   $ 359     $ 1,056   $ 588 $ 568 Percentage change in segment adjusted EBITDA versus 2015 period   8 %     13 %   (37 )%    

________________________

 

(1)

 

During the fourth quarter of 2016, we modified our primary segment performance measure to segment adjusted EBITDA from segment profit. Prior period segment amounts have been recast to reflect this change. See additional discussion below.

 

Fourth-quarter 2016 Transportation segment adjusted EBITDA increased by 4% versus comparable 2015 results. This increase was primarily driven by increased volumes and margins on certain of our Permian Basin pipelines, earnings from our 40% interest in the Saddlehorn pipeline which was placed in service in the third quarter of 2016 and lower operating expenses, partially offset by the sale of certain of our Gulf Coast pipelines in early 2016.

Fourth-quarter 2016 Facilities segment adjusted EBITDA increased by 14% versus comparable 2015 results. This increase was primarily due to contributions from the Western Canada NGL assets acquired in August 2016 and contributions from ongoing projects at our Fort Saskatchewan facility as well as lower operating expenses.

Fourth-quarter 2016 Supply and Logistics segment adjusted EBITDA decreased by 4% relative to comparable 2015 results. This decrease was primarily driven by lower volumes and margins associated with our U.S. crude oil lease gathering activities due to less favorable market conditions as a result of increased competition and lower crude oil production in certain regions.

During the fourth quarter of 2016, we modified our primary segment performance measure to segment adjusted EBITDA from segment profit. Segment adjusted EBITDA forms the basis of our internal financial reporting and is the primary measure used by our Chief Operating Decision Maker (“CODM”) in assessing performance and allocating resources among our operating segments. In conjunction with this change, we modified our adjusted EBITDA metric to exclude depreciation and amortization expense associated with equity method investments. Prior period amounts have been recast to reflect this change. The 2016 fourth quarter and full year impact of this modification increased adjusted EBITDA by $13 million and $50 million, respectively, and the 2015 fourth quarter and full year impact of this modification increased adjusted EBITDA by $12 million and $45 million, respectively, within the Transportation segment.

2017 Full-Year Guidance

Full-year 2017 financial and operating guidance is presented below:

 

FINANCIAL AND OPERATING GUIDANCE (unaudited)

(in millions, except per barrel data)         Twelve Months Ended December 31,       2015       2016       2017 (G) 2017 vs 2016 + / - Segment Adjusted EBITDA Transportation $ 1,056 $ 1,141 $

1,315

15

% Facilities 588 667

680

2

% Supply and Logistics 568 359

365

2

%

Other Income/(Expense), Net

  1     2     -    

 

 

Adjusted EBITDA (1) $ 2,213   $ 2,169   $ 2,360     9 % Interest expense, net (2) (417 ) (451 ) (500 ) 11 % Maintenance capital (220 ) (186 ) (180 ) (3 )% Current income tax expense (84 ) (85 ) (70 ) (18 )% Other   (18 )   (33 )   (10 )   (70 )% Implied DCF (1) $ 1,474   $ 1,414   $ 1,600     13 %   Operating Data Transportation Average Daily Volumes (MBbls/d) 4,453 4,637

5,250

13

% Segment Adjusted EBITDA per Barrel $ 0.65 $ 0.67 $

0.69

3

%   Facilities Average Capacity (MMBbls/Mo) 126 129 130 1 % Segment Adjusted EBITDA per Barrel $ 0.39 $ 0.43 $

0.44

2

%   Supply and Logistics Average Daily Volumes (MBbls/d) 1,168 1,160 1,250 8 % Segment Adjusted EBITDA per Barrel $ 1.33 $ 0.85 $

0.80

(6

)%   Expansion Capital $ 2,170 $ 1,405 $ 800 $ (605 )   First Quarter Adjusted EBITDA as Percentage of Full Year 29 % 29 % 23 %  

________________________

 

(G)

 

2017 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 Financial Data Reconciliations table attached hereto for information regarding non-GAAP financial measures and, for the 2015 and 2016 periods, their reconciliation to the most directly comparable measures as reported in accordance with GAAP. We do not provide a reconciliation of non-GAAP financial measures to the equivalent GAAP financial measures on a forward-looking basis as it is impractical to forecast certain items that we have defined as “Selected Items Impacting Comparability” without unreasonable effort, due to the uncertainty and inherent difficulty of predicting the occurrence and financial impact of and the periods in which such items may be recognized. Thus, a reconciliation of non-GAAP financial measures to the equivalent GAAP financial measures could result in disclosure that could be imprecise or potentially misleading.

 

(2)

Excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps.

 

Plains GP Holdings

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

            Q4 2016     Q3 2016     Q4 2015

Distribution per Class A share declared for the period (1)

$ 0.55 $ 0.55   $ 0.62   Q4 2016 distribution percentage change from prior periods   - %   (11.3 )%  

________________________

 

(1)

 

A reverse split of PAGP's Class A shares was completed on November 15, 2016. The effect of the reverse split has been retroactively applied to all per-share amounts presented.

 

Conference Call

PAA and PAGP will hold a conference call at 11:00 a.m. ET on Wednesday, February 8, 2017 to discuss the following items:

1. PAA's fourth-quarter and full-year 2016 performance;

2. Financial and operating guidance for 2017;

3. An update on major capital expansion projects;

4. Capitalization and liquidity; and

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

Prior to the conference call, PAA will furnish a current report on Form 8-K that will include material in this earnings release. A copy of the 8-K and a slide presentation for the conference call will be available at www.plainsallamerican.com, where PAA and PAGP routinely post important information.

Conference Call Webcast Instructions

To access the internet webcast of the conference call, please go to 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 of unconsolidated entities) and adjusted for certain selected items impacting comparability (“adjusted EBITDA”) and implied distributable cash flow (“DCF”).

Management believes that the presentation of such additional financial measures provides useful information to investors regarding our performance and results of operations because these measures, when used to supplement related GAAP financial measures, (i) provide additional information about our core operating performance and ability to fund distributions to our unitholders through cash generated by our operations and (ii) provide investors with the same financial analytical framework upon which management bases financial, operational, compensation and planning/budgeting decisions. We also present these and additional non-GAAP financial measures, including adjusted net income attributable to PAA and basic and diluted adjusted net income per common unit, as they are measurements that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations. These non-GAAP measures may exclude, for example, (i) charges for obligations that are expected to be settled with the issuance of equity instruments, (ii) the mark-to-market of 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 volume of crude oil, refined product and NGL shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of our assets, whether due to declines in production from existing oil and gas reserves, reduced demand, failure to develop or slowdown in the development of additional oil and gas reserves, whether from reduced cash flow to fund drilling or the inability to access capital, or other factors; the effects of competition; market distortions caused by producer over-commitments to new or recently constructed infrastructure projects, which impacts volumes, margins, returns and overall earnings; unanticipated changes in crude oil market structure, grade differentials and volatility (or lack thereof); environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves; maintenance of our credit rating and ability to receive open credit from our suppliers and trade counterparties; fluctuations in refinery capacity in areas supplied by our mainlines and other factors affecting demand for various grades of crude oil, refined products and natural gas and resulting changes in pricing conditions or transportation throughput requirements; the occurrence of a natural disaster, catastrophe, terrorist attack (including eco-terrorist attacks) or other event, including attacks on our electronic and computer systems; failure to implement or capitalize, or delays in implementing or capitalizing, on expansion projects, whether due to permitting delays, permitting withdrawals or other factors; tightened capital markets or other factors that increase our cost of capital or limit our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, expansion projects, working capital requirements and the repayment or refinancing of indebtedness; the successful integration and future performance of acquired assets or businesses and the risks associated with operating in lines of business that are distinct and separate from our historical operations; the currency exchange rate of the Canadian dollar; continued creditworthiness of, and performance by, our counterparties, including financial institutions and trading companies with which we do business; inability to recognize current revenue attributable to deficiency payments received from customers who fail to ship or move more than minimum contracted volumes until the related credits expire or are used; non-utilization of our assets and facilities; increased costs, or lack of availability, of insurance; weather interference with business operations or project construction, including the impact of extreme weather events or conditions; the availability of, and our ability to consummate, acquisition or combination opportunities; the effectiveness of our risk management activities; shortages or cost increases of supplies, materials or labor; the impact of current and future laws, rulings, governmental regulations, accounting standards and statements and related interpretations; fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our long-term incentive plans; risks related to the development and operation of our assets, including our ability to satisfy our contractual obligations to our customers; factors affecting demand for natural gas and natural gas storage services and rates; general economic, market or business conditions and the amplification of other risks caused by volatile financial markets, capital constraints and pervasive liquidity concerns; and other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil and refined products, as well as in the storage of natural gas and the processing, transportation, fractionation, storage and marketing of natural gas liquids as discussed in the Partnerships' filings with the Securities and Exchange Commission.

Plains All American Pipeline, L.P. is a publicly traded master limited partnership that owns and operates midstream energy infrastructure and provides logistics services for crude oil, NGLs, natural gas and refined products. PAA owns an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins and transportation corridors and at major market hubs in the United States and Canada. On average, PAA handles over 4.6 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.

  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       Twelve Months Ended December 31, December 31, 2016       2015 2016       2015   REVENUES $ 5,952 $ 4,996 $ 20,182 $ 23,152   COSTS AND EXPENSES Purchases and related costs 5,234 4,135 17,233 19,726 Field operating costs 289 343 1,182 1,454 General and administrative expenses 68 61 279 278 Depreciation and amortization   143     113     494     432   Total costs and expenses 5,734 4,652 19,188 21,890   OPERATING INCOME 218 344 994 1,262   OTHER INCOME/(EXPENSE) Equity earnings in unconsolidated entities 61 49 195 183 Interest expense, net (127 ) (111 ) (467 ) (432 ) Other income/(expense), net   (14 )   -     33     (7 )   INCOME BEFORE TAX 138 282 755 1,006 Current income tax expense (41 ) (12 ) (85 ) (84 ) Deferred income tax benefit/(expense)   30     (22 )   60     (16 )   NET INCOME 127 248 730 906 Net income attributable to noncontrolling interests   (1 )   (1 )   (4 )   (3 ) NET INCOME ATTRIBUTABLE TO PAA $ 126   $ 247   $ 726   $ 903     NET INCOME PER COMMON UNIT: Net income allocated to common unitholders — Basic $ 91 $ 95 $ 200 $ 305 Basic weighted average common units outstanding 660 398 464 394 Basic net income per common unit $ 0.14   $ 0.24   $ 0.43   $ 0.78     Net income allocated to common unitholders — Diluted $ 91 $ 95 $ 200 $ 305 Diluted weighted average common units outstanding 662 399 466 396 Diluted net income per common unit $ 0.14   $ 0.24   $ 0.43   $ 0.77      

NON-GAAP ADJUSTED RESULTS

(in millions, except per unit data) Three Months Ended Twelve Months Ended December 31, December 31, 2016 2015 2016 2015   Adjusted net income attributable to PAA $ 278   $ 304   $ 1,062   $ 1,191     Diluted adjusted net income per common unit $ 0.37   $ 0.38   $ 1.14   $ 1.48     Adjusted EBITDA $ 600   $ 575   $ 2,169   $ 2,213       PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited)  

CONDENSED CONSOLIDATED BALANCE SHEET DATA

(in millions)         December 31,       December 31, 2016   2015 ASSETS Current assets $ 4,272 $ 2,969 Property and equipment, net 13,872 13,474 Goodwill 2,344 2,405 Investments in unconsolidated entities 2,343 2,027 Linefill and base gas 896 898 Long-term inventory 193 129 Other long-term assets, net   290     386   Total assets $ 24,210   $ 22,288     LIABILITIES AND PARTNERS' CAPITAL Current liabilities $ 4,664 $ 3,407 Senior notes, net of unamortized discounts and debt issuance costs 9,874 9,698 Other long-term debt 250 677 Other long-term liabilities and deferred credits   606     567   Total liabilities 15,394 14,349   Partners' capital excluding noncontrolling interests 8,759 7,881 Noncontrolling interests   57     58   Total partners' capital   8,816     7,939   Total liabilities and partners' capital $ 24,210   $ 22,288    

DEBT CAPITALIZATION RATIOS

(in millions) December 31, December 31, 2016 2015 Short-term debt (1) $ 1,715 $ 999 Long-term debt   10,124     10,375   Total debt $ 11,839   $ 11,374     Long-term debt $ 10,124 $ 10,375 Partners' capital   8,816     7,939   Total book capitalization $ 18,940   $ 18,314   Total book capitalization, including short-term debt $ 20,655   $ 19,313     Long-term debt-to-total book capitalization 53 % 57 % Total debt-to-total book capitalization, including short-term debt 57 % 59 %  

________________________

 

(1)

 

At December 31, 2016, short-term debt includes borrowings of approximately $1,303 million for short-term hedged inventory purchases and borrowings of approximately $410 million 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     Twelve Months Ended December 31, December 31, 2016   2015 2016   2015   Transportation segment (average daily volumes in thousands of barrels per day): Tariff activities volumes Crude oil pipelines (by region): Permian Basin (2) 2,197 1,963 2,146 1,849 South Texas / Eagle Ford (2) 284 331 284 306 Western 171 190 188 215 Rocky Mountain (2) 454 433 449 440 Gulf Coast 373 537 497 532 Central (2) 397 362 394 413 Canada 374 377 381 392 Crude oil pipelines 4,250 4,193 4,339 4,147 NGL pipelines 190 189 184 193 Tariff activities total volumes 4,440 4,382 4,523 4,340 Trucking 118 109 114 113 Transportation segment total volumes 4,558 4,491 4,637 4,453  

Facilities segment (average monthly volumes):

Crude oil, refined products and NGL terminalling and storage

  (average monthly capacity in millions of barrels)

110 103 107 100

Rail load / unload volumes

  (average volumes in thousands of barrels per day)

42 172 83 210

Natural gas storage

  (average monthly working capacity in billions of cubic feet)

97 97 97 97

NGL fractionation

  (average volumes in thousands of barrels per day)

122 111 115 103

Facilities segment total volumes

  (average monthly volumes in millions of barrels) (3)

131 128 129 126   Supply and Logistics segment (average daily volumes in thousands of barrels per day): Crude oil lease gathering purchases 895 899 894 943 NGL sales 346 266 259 223 Waterborne cargos 7 2 7 2 Supply and Logistics segment total volumes 1,248 1,167 1,160 1,168  

________________________

 

(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 is calculated as the sum of: (i) crude oil, refined products and NGL terminalling and storage capacity; (ii) rail load and unload volumes multiplied by the number of days in the period and divided by the number of months in the period; (iii) natural gas storage working capacity divided by 6 to account for the 6:1 mcf of natural gas to crude Btu equivalent ratio and further divided by 1,000 to convert to monthly volumes in millions; and (iv) NGL fractionation volumes multiplied by the number of days in the period and divided by the number of months in the period.

    PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited)  

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

(in millions, except per unit data)         Three Months Ended     Twelve Months Ended December 31, December 31, 2016     2015 2016     2015 Basic Net Income per Common Unit Net income attributable to PAA $ 126 $ 247 $ 726 $ 903 Distributions to Series A preferred units (34 ) - (122 ) - Distributions to general partner - (155 ) (412 ) (608 ) Distributions to participating securities - (1 ) (4 ) (6 ) Undistributed loss allocated to general partner - 4 14 16 Other   (1 )   -     (2 )   -   Net income allocated to common unitholders in accordance with application of the two-class method $ 91   $ 95   $ 200   $ 305     Basic weighted average common units outstanding (2) 660 398 464 394   Basic net income per common unit $ 0.14   $ 0.24   $ 0.43   $ 0.78     Diluted Net Income per Common Unit Net income attributable to PAA $ 126 $ 247 $ 726 $ 903 Distributions to Series A preferred units (34 ) - (122 ) - Distributions to general partner - (155 ) (412 ) (608 ) Distributions to participating securities - (1 ) (4 ) (6 ) Undistributed loss allocated to general partner - 4 14 16 Other   (1 )   -     (2 )   -   Net income allocated to common unitholders in accordance with application of the two-class method $ 91   $ 95   $ 200   $ 305     Basic weighted average common units outstanding (2) 660 398 464 394 Effect of dilutive securities: Weighted average LTIP units (3)   2     1     2     2   Diluted weighted average common units outstanding   662     399     466     396     Diluted net income per common unit (4) $ 0.14   $ 0.24   $ 0.43   $ 0.77    

 

________________________

 

(1)

We calculate net income allocated to common unitholders based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period's distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner, common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method.

 

The Simplification Transactions, which closed on November 15, 2016, included the permanent elimination of our IDRs and the economic rights associated with our 2% general partner interest in exchange for the issuance by us of approximately 244.7 million common units and the assumption of Plains AAP, L.Ps.'s ("AAP") debt. As such, beginning with the distribution pertaining to the fourth quarter of 2016, our general partner is no longer entitled to receive distributions on the IDRs or 2% general partner interest.

 

(2)

We have considered the common units issued in connection with the Simplification Transactions to be outstanding for the entire fourth quarter of 2016 in the calculation of weighted average common units outstanding to more closely reflect the ownership interests in us with rights to the distributions for the periods included in the calculation of net income allocated to common unitholders.

 

(3)

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.

 

(4)

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, 2016 as the effect was antidilutive.

    PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited)  

SELECTED FINANCIAL DATA BY SEGMENT(1)

(in millions)           Three Months Ended Three Months Ended December 31, 2016 December 31, 2015     Supply and     Supply and Transportation Facilities Logistics Transportation Facilities Logistics Revenues (2) $ 396 $ 290 $ 5,665 $ 391 $ 261 $ 4,706 Purchases and related costs (2) (25 ) (9 ) (5,596 ) (23 ) (7 ) (4,464 ) Field operating costs (2) (3) (131 ) (90 ) (65 ) (159 ) (94 ) (94 ) Equity-indexed compensation expense - field operating costs (5 ) (1 ) - - 1 - Segment general and administrative expenses (3) (4) (20 ) (13 ) (22 ) (22 ) (14 ) (24 ) Equity-indexed compensation expense - general and administrative (5 ) (3 ) (5 ) - - (1 ) Equity earnings in unconsolidated entities 61 - - 49 - -   Adjustments(5): Depreciation and amortization of unconsolidated entities 13 - - 12 - - (Gains)/losses from derivative activities net of inventory valuation adjustments - (2 ) 217 - 2 (4 ) Long-term inventory costing adjustments - - (51 ) - - 37 Deficiencies under minimum volume commitments, net (11 ) (3 ) - - - - Equity-indexed compensation expense 5 2 3 2 1 2 Net (gain)/loss on foreign currency revaluation - - 5 - - (1 ) Line 901 incident   -       -     -     18       -     -   Segment adjusted EBITDA $ 278     $ 171   $ 151   $ 268     $ 150   $ 157     Maintenance capital $ 35     $ 23   $ -   $ 43     $ 20   $ 3             Twelve Months Ended     Twelve Months Ended December 31, 2016 December 31, 2015   Supply and   Supply and Transportation   Facilities Logistics Transportation   Facilities Logistics Revenues (2) $ 1,584 $ 1,107 $ 19,018 $ 1,594 $ 1,050 $ 21,945 Purchases and related costs (2) (94 ) (26 ) (18,627 ) (108 ) (24 ) (21,018 ) Field operating costs (2) (3) (537 ) (347 ) (291 ) (652 ) (377 ) (433 ) Equity-indexed compensation expense - field operating costs (14 ) (5 ) (1 ) (5 ) - - Segment general and administrative expenses (3) (4) (88 ) (58 ) (93 ) (89 ) (65 ) (102 ) Equity-indexed compensation expense - general and administrative (15 ) (10 ) (15 ) (6 ) (5 ) (11 ) Equity earnings in unconsolidated entities 195 - - 183 - -   Adjustments (5): Depreciation and amortization of unconsolidated entities 50 - - 45 - - (Gains)/losses from derivative activities net of inventory valuation adjustments - (2 ) 406 - 4 106 Long-term inventory costing adjustments - - (58 ) - - 99 Deficiencies under minimum volume commitments, net 44 2 - - - - Equity-indexed compensation expense 16 7 10 11 5 11 Net (gain)/loss on foreign currency revaluation - (1 ) 10 - - (29 ) Line 901 incident   -       -     -     83       -     -   Segment adjusted EBITDA $ 1,141     $ 667   $ 359   $ 1,056     $ 588   $ 568     Maintenance capital $ 121     $ 55   $ 10   $ 144     $ 68   $ 8    

________________________

 

(1)

 

During the fourth quarter of 2016, we modified our primary segment performance measure to segment adjusted EBITDA from segment profit. Segment adjusted EBITDA forms the basis of our internal financial reporting and is the primary measure used by our CODM in assessing performance and allocating resources among our operating segments. Prior period segment amounts have been recast to reflect this change.

 

(2)

Includes intersegment amounts.

 

(3)

Field operating costs and Segment general and administrative expenses exclude equity-indexed compensation expense, which is presented separately in the table above.

 

(4)

Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.

 

(5)

Represents adjustments utilized by our CODM in the evaluation of segment results. Many of these adjustments are also considered selected items impacting comparability when calculating consolidated non-GAAP financial measures such as Adjusted EBITDA. See the "Selected Items Impacting Comparability" table on the following page for additional discussion.

    PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited)  

SELECTED ITEMS IMPACTING COMPARABILITY

(in millions, except per unit data)         Three Months Ended     Twelve Months Ended December 31, December 31, 2016     2015 2016     2015 Selected Items Impacting Comparability (1): Gains/(losses) from derivative activities net of inventory valuation adjustments (2) $ (227 ) $ 2 $ (374 ) $ (110 ) Long-term inventory costing adjustments (3) 51 (37 ) 58 (99 ) Deficiencies under minimum volume commitments, net (4) 14 - (46 ) - Equity-indexed compensation expense (5) (10 ) (5 ) (33 ) (27 ) Net gain/(loss) on foreign currency revaluation (6) (7 ) 1 (8 ) 21 Line 901 incident (7)   -     (18 )   -     (83 ) Selected items impacting comparability - Adjusted EBITDA $ (179 ) $ (57 ) $ (403 ) $ (298 ) Deferred income tax expense (8) - - - (22 ) Tax effect on selected items impacting comparability   27     -     67     32   Selected items impacting comparability - Adjusted net income attributable to PAA $ (152 ) $ (57 ) $ (336 ) $ (288 )   Impact to basic net income per common unit $ (0.23 ) $ (0.14 ) $ (0.72 ) $ (0.71 ) Impact to diluted net income per common unit $ (0.23 ) $ (0.14 ) $ (0.71 ) $ (0.71 )  

________________________

 

(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 that is comprised of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets). We treat the impact of changes in the average cost of the long-term inventory (that result from fluctuations in market prices) and writedowns of such inventory that result from price declines as a selected item impacting comparability.

 

(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 the initial cumulative effect of a change in Canadian tax legislation impacting the period.

    PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited)  

FINANCIAL DATA RECONCILIATIONS

(in millions)         Three Months Ended     Twelve Months Ended December 31, December 31, 2016     2015 2016     2015 Net Income to Adjusted EBITDA and Implied DCF Reconciliations Net Income $ 127 $ 248 $ 730 $ 906 Interest expense, net 127 111 467 432 Income tax expense 11 34 25 100 Depreciation and amortization 143 113 494 432 Depreciation and amortization of unconsolidated entities (1) 13 12 50 45 Selected items impacting comparability - Adjusted EBITDA (2)   179     57     403     298   Adjusted EBITDA $ 600 $ 575 $ 2,169 $ 2,213 Interest expense, net (3) (123 ) (107 ) (451 ) (417 ) Maintenance capital (58 ) (66 ) (186 ) (220 ) Current income tax expense (41 ) (12 ) (85 ) (84 ) Adjusted equity earnings in unconsolidated entities, net of distributions (4) (9 ) (6 ) (29 ) (14 ) Distributions to noncontrolling interests (5)   (1 )   (1 )   (4 )   (4 ) Implied DCF (6) $ 368   $ 383   $ 1,414   $ 1,474    

________________________

 

(1)

 

Over the past several years, we have increased our participation in pipeline strategic joint venture projects, which are accounted for under the equity method of accounting. Management excludes our proportionate share of the depreciation and amortization expense associated with such unconsolidated entities when reviewing Adjusted EBITDA.

 

(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)

Equity earnings are adjusted for our proportionate share of the depreciation and amortization of unconsolidated entities, as such expenses are excluded from the calculation of Adjusted EBITDA.

 

(5)

Includes distributions that pertain to the current period's net income, which are paid in the subsequent period.

 

(6)

Including net costs recognized during the period related to the Line 901 incident that occurred during May 2015, Implied DCF would have been $365 million and $1,391 million for the three and twelve months ended December 31, 2015.

    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     Twelve Months Ended December 31, December 31, 2016     2015 2016     2015 Basic Adjusted Net Income per Common Unit Net income attributable to PAA $ 126 $ 247 $ 726 $ 903

Selected items impacting comparability - Adjusted net income attributable to PAA (2)

  152     57     336     288   Adjusted net income attributable to PAA 278 304 1,062 1,191 Distributions to Series A preferred units (34 ) - (122 ) - Distributions to general partner - (155 ) (412 ) (608 ) Distributions to participating securities - (1 ) (4 ) (6 ) Undistributed loss allocated to general partner - 3 10 11 Other   (1 )   -     (1 )   -   Adjusted net income allocated to common unitholders in accordance with application of the two-class method $ 243   $ 151   $ 533   $ 588     Basic weighted average common units outstanding (3) 660 398 464 394   Basic adjusted net income per common unit $ 0.37   $ 0.38   $ 1.15   $ 1.49     Diluted Adjusted Net Income per Common Unit Net income attributable to PAA $ 126 $ 247 $ 726 $ 903 Selected items impacting comparability - Adjusted net income attributable to PAA (2)   152     57     336     288   Adjusted net income attributable to PAA 278 304 1,062 1,191 Distributions to Series A preferred units (34 ) - (122 ) - Distributions to general partner - (155 ) (412 ) (608 ) Distributions to participating securities - (1 ) (4 ) (6 ) Undistributed loss allocated to general partner - 3 10 11 Other   (1 )   -     (1 )   -   Adjusted net income allocated to common unitholders in accordance with application of the two-class method $ 243   $ 151   $ 533   $ 588     Basic weighted average common units outstanding (3) 660 398 464 394 Effect of dilutive securities: Weighted average LTIP units (4)   2     1     2     2   Diluted weighted average common units outstanding   662     399     466     396     Diluted adjusted net income per common unit (5) $ 0.37   $ 0.38   $ 1.14   $ 1.48    

________________________

 

(1)

 

We calculate adjusted net income allocated to common unitholders based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period's distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner, common unitholders and participating securities in accordance with the contractual terms of our partnership agreement and as further prescribed under the two-class method.

 

The Simplification Transactions, which closed on November 15, 2016, included the permanent elimination of our IDRs and the economic rights associated with our 2% general partner interest in exchange for the issuance by us of approximately 244.7 million common units and the assumption of AAP's debt. As such, beginning with the distribution pertaining to the fourth quarter of 2016, our general partner is no longer entitled to receive distributions on the IDRs or 2% general partner interest.

 

(2)

Certain of our non-GAAP financial measures may not be impacted by each of the selected items impacting comparability.

 

(3)

We have considered the common units issued in connection with the Simplification Transactions to be outstanding for the entire fourth quarter of 2016 in the calculation of weighted average common units outstanding to more closely reflect the ownership interests in us with rights to the distributions for the periods included in the calculation of adjusted net income allocated to common unitholders.

 

(4)

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.

 

(5)

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, 2016 as the effect was antidilutive.

  PLAINS GP HOLDINGS AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited)  

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (1)

(in millions, except per share data)             Three Months Ended       Three Months Ended December 31, 2016 December 31, 2015 PAA     Consolidating

Adjustments (2)

    PAGP PAA     Consolidating

Adjustments (2)

    PAGP   REVENUES $ 5,952 $ - $ 5,952 $ 4,996 $ - $ 4,996   COSTS AND EXPENSES Purchases and related costs 5,234 - 5,234 4,135 - 4,135 Field operating costs 289 - 289 343 - 343 General and administrative expenses 68 1 69 61 1 62 Depreciation and amortization   143     -     143     113     -     113   Total costs and expenses 5,734 1 5,735 4,652 1 4,653   OPERATING INCOME 218 (1 ) 217 344 (1 ) 343   OTHER INCOME/(EXPENSE) Equity earnings in unconsolidated entities 61 - 61 49 - 49 Interest expense, net (127 ) (3 ) (130 ) (111 ) (3 ) (114 ) Other expense, net   (14 )   -     (14 )   -     -     -     INCOME BEFORE TAX 138 (4 ) 134 282 (4 ) 278 Current income tax expense (41 ) - (41 ) (12 ) - (12 ) Deferred income tax benefit/(expense)   30     (1 )   29     (22 )   (28 )   (50 )   NET INCOME 127 (5 ) 122 248 (32 ) 216 Net income attributable to noncontrolling interests   (1 )   (129 )   (130 )   (1 )   (190 )   (191 ) NET INCOME/(LOSS) ATTRIBUTABLE TO PAGP $ 126   $ (134 ) $ (8 ) $ 247   $ (222 ) $ 25       BASIC AND DILUTED NET INCOME/(LOSS) PER CLASS A SHARE $ (0.08 ) $ 0.29     BASIC AND DILUTED WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING   101     86    

________________________

 

(1)

 

A reverse split of PAGP's Class A shares was completed on November 15, 2016. The effect of the reverse split has been retroactively applied to all share and per-share amounts presented.

 

(2)

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

    PLAINS GP HOLDINGS AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited)  

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (1)

(in millions, except per share data)             Twelve Months Ended Twelve Months Ended December 31, 2016 December 31, 2015 PAA     Consolidating

Adjustments (2)

    PAGP PAA     Consolidating

Adjustments (2)

    PAGP   REVENUES $ 20,182 $ - $ 20,182 $ 23,152 $ - $ 23,152   COSTS AND EXPENSES Purchases and related costs 17,233 - 17,233 19,726 - 19,726 Field operating costs 1,182 - 1,182 1,454 - 1,454 General and administrative expenses 279 3 282 278 3 281 Depreciation and amortization   494     1     495     432     1     433   Total costs and expenses 19,188 4 19,192 21,890 4 21,894   OPERATING INCOME 994 (4 ) 990 1,262 (4 ) 1,258   OTHER INCOME/(EXPENSE) Equity earnings in unconsolidated entities 195 - 195 183 - 183 Interest expense, net (467 ) (13 ) (480 ) (432 ) (11 ) (443 ) Other income/(expense), net   33     -     33     (7 )   -     (7 )   INCOME BEFORE TAX 755 (17 ) 738 1,006 (15 ) 991 Current income tax expense (85 ) - (85 ) (84 ) - (84 ) Deferred income tax benefit/(expense)   60     (53 )   7     (16 )   (82 )   (98 )   NET INCOME 730 (70 ) 660 906 (97 ) 809 Net income attributable to noncontrolling interests   (4 )   (562 )   (566 )   (3 )   (688 )   (691 ) NET INCOME ATTRIBUTABLE TO PAGP $ 726   $ (632 ) $ 94   $ 903   $ (785 ) $ 118       BASIC AND DILUTED NET INCOME PER CLASS A SHARE $ 0.94   $ 1.41     BASIC AND DILUTED WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING   99     83    

________________________

 

(1)

 

A reverse split of PAGP's Class A shares was completed on November 15, 2016. The effect of the reverse split has been retroactively applied to all share and per-share amounts presented.

 

(2)

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

                PLAINS GP HOLDINGS AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited)                

CONDENSED CONSOLIDATING BALANCE SHEET DATA

(in millions) December 31, 2016 December 31, 2015 PAA Consolidating

Adjustments (1)

PAGP PAA Consolidating

Adjustments (1)

PAGP ASSETS Current assets $ 4,272 $ 3 $ 4,275 $ 2,969 $ 3 $ 2,972 Property and equipment, net 13,872 18 13,890 13,474 19 13,493 Goodwill 2,344 - 2,344 2,405 - 2,405 Investments in unconsolidated entities 2,343 - 2,343 2,027 - 2,027 Deferred tax asset - 1,876 1,876 - 1,835 1,835 Linefill and base gas 896 - 896 898 - 898 Long-term inventory 193 - 193 129 - 129 Other long-term assets, net   290   (4 )   286   386   (3 )   383 Total assets $ 24,210 $ 1,893   $ 26,103 $ 22,288 $ 1,854   $ 24,142   LIABILITIES AND PARTNERS' CAPITAL Current liabilities $ 4,664 $ 2 $ 4,666 $ 3,407 $ 2 $ 3,409 Senior notes, net of unamortized discounts and debt issuance costs 9,874 - 9,874 9,698 - 9,698 Other long-term debt, net of unamortized debt issuance costs 250 - 250 677 557 1,234 Other long-term liabilities and deferred credits   606   -     606   567   -     567 Total liabilities 15,394 2 15,396 14,349 559 14,908   Partners' capital excluding noncontrolling interests 8,759 (7,022 ) 1,737 7,881 (6,119 ) 1,762 Noncontrolling interests   57   8,913     8,970   58   7,414     7,472 Total partners' capital   8,816   1,891     10,707   7,939   1,295     9,234 Total liabilities and partners' capital $ 24,210 $ 1,893   $ 26,103 $ 22,288 $ 1,854   $ 24,142  

________________________

  (1)   Represents the aggregate consolidating adjustments necessary to produce consolidated financial statements for PAGP.             PLAINS GP HOLDINGS AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited)                    

COMPUTATION OF BASIC AND DILUTED NET INCOME PER CLASS A SHARE (1)

(in millions, except per share data) Three Months Ended Twelve Months Ended December 31, December 31, 2016 2015 2016 2015 Basic and Diluted Net Income per Class A Share Net income/(loss) attributable to PAGP $ (8 ) $ 25 $ 94 $ 118 Basic and diluted weighted average Class A shares outstanding 101 86 99 83   Basic and diluted net income/(loss) per Class A share $ (0.08 ) $ 0.29 $ 0.94 $ 1.41  

________________________

  (1)   A reverse split of PAGP's Class A shares was completed on November 15, 2016. The effect of the reverse split has been retroactively applied to all share and per-share amounts presented.  

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Plains All American Pipeline, L.P. and Plains GP HoldingsRyan Smith, 866-809-1291Director, Investor RelationsorAl Swanson, 800-564-3036Executive Vice President, CFO