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

Nov 06, 2018 04:17 pm

HOUSTON --

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

Third-Quarter Highlights

Delivered 3Q18 financial and operating results ahead of expectations
Increased 2018 Adjusted EBITDA guidance
Announced and closed sale of 30% interest in BridgeTex for net proceeds of $862 million, resulting in a gain of $210 million
Continued progress on leverage reduction plan with visibility to complete during 1H19

“We are pleased to report solid third-quarter results and increased guidance for the full year that reflects continued execution of our business plan and constructive industry fundamentals,” stated Willie Chiang, Chief Executive Officer of Plains All American Pipeline. “We are on track with our deleveraging objectives, our capital program and other commercial and operating initiatives and believe that we are well positioned for the future.”


Plains All American Pipeline, L.P.

Summary Financial Information (unaudited)
(in millions, except per unit data)


	Three Months Ended September 30,					%		Nine Months Ended September 30,				%
GAAP Results	2018		2017			Change		2018		2017		Change
Net income attributable to PAA	$	710	$	33		**		$	1,099	$	665	65	%
Diluted net income/(loss) per common unit	$	0.87	$	(0.01	)	**		$	1.30	$	0.76	71	%
Diluted weighted average common units outstanding	799		725			10	%	728		715		2	%
Distribution per common unit declared for the period	$	0.30	$	0.30		—	%

	Three Months Ended September 30,					%		Nine Months Ended September 30,				%
Non-GAAP Results ⁽¹⁾	2018		2017			Change		2018		2017		Change
Adjusted net income attributable to PAA	$	361	$	195		85	%	$	995	$	609	63	%
Diluted adjusted net income per common unit	$	0.43	$	0.21		105	%	$	1.16	$	0.69	68	%
Adjusted EBITDA	$	636	$	489		30	%	$	1,735	$	1,452	19	%
Implied DCF per common unit	$	0.55	$	0.41		34	%	$	1.52	$	1.25	22	%

____________________
^**			Indicates that variance as a percentage is not meaningful.
⁽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 third quarter and first nine months of 2018 and 2017 is presented below:


Summary of Selected Financial Data by Segment (unaudited)
(in millions)


	Segment Adjusted EBITDA
	Transportation			Facilities			Supply and Logistics
Three Months Ended September 30, 2018	$	388		$	173		$	75
Three Months Ended September 30, 2017	$	363		$	182		$	(56	)
Percentage change in Segment Adjusted EBITDA versus 2017 period	7		%	(5		)%	234		%
Percentage change in Segment Adjusted EBITDA versus 2017 period further adjusted for impact of divested assets	12		%	(1		)%	N/A

	Segment Adjusted EBITDA
	Transportation			Facilities			Supply and Logistics
Nine Months Ended September 30, 2018	$	1,083		$	530		$	120
Nine Months Ended September 30, 2017	$	933		$	550		$	(32	)
Percentage change in Segment Adjusted EBITDA versus 2017 period	16		%	(4		)%	475		%
Percentage change in Segment Adjusted EBITDA versus 2017 period further adjusted for impact of divested assets	21		%	3		%	N/A

Third-quarter 2018 Transportation Segment Adjusted EBITDA increased by 7% over comparable 2017 results. This increase was primarily driven by increased volume on our Permian Basin systems. Third-quarter 2018 results also benefited from the Diamond pipeline being placed into service in late 2017. These favorable results were partially offset by the impact of asset sales in the Rocky Mountain and Central regions.

Third-quarter 2018 Facilities Segment Adjusted EBITDA decreased by 5% versus comparable 2017 results, primarily due to the impact of asset sales. This was partially offset by increased revenue from capacity expansions and increased throughput at our Cushing terminal, as well as increased activity at our St. James terminal and certain crude oil rail terminals.

Third-quarter 2018 Supply and Logistics Segment Adjusted EBITDA increased versus comparable 2017 results due to favorable regional crude oil differentials, higher lease gathering margins and volumes, and a benefit from an audit recovery in our NGL business.

2018 Full-Year Guidance

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


Financial and Operating Guidance (unaudited)
(in millions, except volumes, per unit and per barrel data)


	Twelve Months Ended December 31,
	2016			2017			2018 (G)
								+ / -
Segment Adjusted EBITDA
Transportation	$	1,141		$	1,287		$	1,510
Facilities		667			734			690
Fee-Based	$	1,808		$	2,021		$	2,200
Supply and Logistics		359			60			350
Adjusted other income/(expense), net		2			1			—
Adjusted EBITDA ⁽¹⁾	$	2,169		$	2,082		$	2,550
Interest expense, net ⁽²⁾		(451	)		(483	)		(420	)
Maintenance capital		(186	)		(247	)		(240	)
Current income tax expense		(85	)		(28	)		(55	)
Other		(33	)		(12	)		5
Implied DCF ⁽¹⁾	$	1,414		$	1,312		$	1,840
Preferred unit distributions paid ⁽³⁾		—			(5	)		(160	)
General partner cash distributions		(565	)		—			—
Implied DCF Available to Common Unitholders	$	849		$	1,307		$	1,680

Implied DCF per Common Unit ⁽¹⁾	$	1.83		$	1.82		$	2.31
Implied DCF per Common Unit and Common Equivalent Unit ⁽¹⁾	$	1.63		$	1.67		$	2.25

Distributions per Common Unit ⁽⁴⁾	$	2.65		$	1.95		$	1.20
Common Unit Distribution Coverage Ratio	0.87		x	0.94		x	1.93		x

Operating Data
Transportation
Average daily volumes (MBbls/d)		4,637			5,186			5,925
Segment Adjusted EBITDA per barrel	$	0.67		$	0.68		$	0.70

Facilities
Average capacity (MMBbls/Mo)		127			130			125
Segment Adjusted EBITDA per barrel	$	0.44		$	0.47		$	0.46

Supply and Logistics
Average daily volumes (MBbls/d)		1,153			1,219			1,275
Segment Adjusted EBITDA per barrel	$	0.85		$	0.13		$	0.75

Expansion Capital	$	1,405		$	1,135		$	1,950

Fourth-Quarter Adjusted EBITDA as Percentage of Full Year		28	%		30	%		32	%

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

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:


	Q3 2018		Q2 2018			Q3 2017
Distribution per Class A share declared for the period	$	0.30	$	0.30		$	0.30
Q3 2018 distribution percentage change from prior periods			—		%	—		%

Conference Call

PAA and PAGP will hold a joint conference call at 4:00 p.m. CT on Tuesday, November 6, 2018 to discuss the following items:

PAA’s third-quarter 2018 performance;
Financial and operating guidance for the full year of 2018 and preliminary 2019;
Capitalization and liquidity; and
PAA and PAGP’s outlook for the future.

Conference Call Webcast Instructions

To access the internet webcast please go to https://event.webcasts.com/starthere.jsp?ei=1213672&tp_key=802fe3c91a

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

Non-GAAP Financial Measures and Selected Items Impacting Comparability

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

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

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

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

Forward-Looking Statements

Except for the historical information contained herein, the matters discussed in this release consist of forward-looking statements that involve certain risks and uncertainties that could cause actual results or outcomes to differ materially from results or outcomes anticipated in the forward-looking statements. These risks and uncertainties include, among other things, declines in the actual or expected volume of crude oil and NGL shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of our assets, whether due to declines in production from existing oil and gas reserves, reduced demand, failure to develop or slowdown in the development of additional oil and gas reserves, whether from reduced cash flow to fund drilling or the inability to access capital, or other factors; the effects of competition; market distortions caused by over-commitments to infrastructure projects, which impacts volumes, margins, returns and overall earnings; unanticipated changes in crude oil and NGL market structure, grade differentials and volatility (or lack thereof); 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, NGL and natural gas and resulting changes in pricing conditions or transportation throughput requirements; maintenance of our credit rating and ability to receive open credit from our suppliers and trade counterparties; the occurrence of a natural disaster, catastrophe, terrorist attack (including eco-terrorist attacks) or other event, including attacks on our electronic and computer systems; failure to implement or capitalize, or delays in implementing or capitalizing, on expansion projects, whether due to permitting delays, permitting withdrawals or other factors; shortages or cost increases of supplies, materials or labor; the impact of current and future laws, rulings, governmental regulations, accounting standards and statements, and related interpretations; the failure to consummate, or significant delay in consummating, sales of assets or interests as a part of our strategic divestiture program; tightened capital markets or other factors that increase our cost of capital or limit our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, expansion projects, working capital requirements and the repayment or refinancing of indebtedness; the availability of, and our ability to consummate, acquisition or combination opportunities; the successful integration and future performance of acquired assets or businesses and the risks associated with operating in lines of business that are distinct and separate from our historical operations; the currency exchange rate of the Canadian dollar; continued creditworthiness of, and performance by, our counterparties, including financial institutions and trading companies with which we do business; inability to recognize current revenue attributable to deficiency payments received from customers who fail to ship or move more than minimum contracted volumes until the related credits expire or are used; non-utilization of our assets and facilities; increased costs, or lack of availability, of insurance; weather interference with business operations or project construction, including the impact of extreme weather events or conditions; the effectiveness of our risk management activities; fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our long-term incentive plans; risks related to the development and operation of our assets, including our ability to satisfy our contractual obligations to our customers; factors affecting demand for natural gas and natural gas storage services and rates; general economic, market or business conditions and the amplification of other risks caused by volatile financial markets, capital constraints and pervasive liquidity concerns; and other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil, as well as in the storage of natural gas and the processing, transportation, fractionation, storage and marketing of natural gas liquids as discussed in the Partnerships’ filings with the Securities and Exchange Commission.

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

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


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


CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per unit data)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
REVENUES	$	8,792		$	5,873		$	25,269		$	18,618

COSTS AND EXPENSES
Purchases and related costs	7,768			5,327			22,838			16,239
Field operating costs	326			283			931			876
General and administrative expenses	74			68			232			210
Depreciation and amortization	131			151			306			401
Total costs and expenses	8,299			5,829			24,307			17,726

OPERATING INCOME	493			44			962			892

OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	110			80			281			201
Gain on sale of investment in unconsolidated entities	210			—			210			—
Interest expense, net	(110		)	(134		)	(327		)	(390		)
Other income/(expense), net	(3		)	(1		)	8			(6		)

INCOME/(LOSS) BEFORE TAX	700			(11		)	1,134			697
Current income tax (expense)/benefit	(14		)	1			(34		)	(9		)
Deferred income tax (expense)/benefit	24			44			(1		)	(21		)

NET INCOME	710			34			1,099			667
Net income attributable to noncontrolling interests	—			(1		)	—			(2		)
NET INCOME ATTRIBUTABLE TO PAA	$	710		$	33		$	1,099		$	665

NET INCOME/(LOSS) PER COMMON UNIT:
Net income/(loss) allocated to common unitholders — Basic	$	658		$	(8	)	$	946		$	547
Basic weighted average common units outstanding	726			725			726			714
Basic net income/(loss) per common unit	$	0.91		$	(0.01	)	$	1.30		$	0.77

Net income/(loss) allocated to common unitholders — Diluted	$	697		$	(8	)	$	947		$	547
Diluted weighted average common units outstanding	799			725			728			715
Diluted net income/(loss) per common unit	$	0.87		$	(0.01	)	$	1.30		$	0.76

NON-GAAP ADJUSTED RESULTS
(in millions, except per unit data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Adjusted net income attributable to PAA	$	361		$	195		$	995		$	609

Diluted adjusted net income per common unit	$	0.43		$	0.21		$	1.16		$	0.69

Adjusted EBITDA	$	636		$	489		$	1,735		$	1,452


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


CONDENSED CONSOLIDATED BALANCE SHEET DATA
(in millions)

	September 30, 2018			December 31, 2017
ASSETS
Current assets	$	4,127		$	4,000
Property and equipment, net	14,677			14,089
Goodwill	2,540			2,566
Investments in unconsolidated entities	2,539			2,756
Linefill and base gas	914			872
Long-term inventory	179			164
Other long-term assets, net	951			904
Total assets	$	25,927		$	25,351

LIABILITIES AND PARTNERS' CAPITAL
Current liabilities	$	4,656		$	4,531
Senior notes, net	8,939			8,933
Other long-term debt, net	201			250
Other long-term liabilities and deferred credits	781			679
Total liabilities	14,577			14,393

Partners' capital	11,350			10,958
Total liabilities and partners' capital	$	25,927		$	25,351

DEBT CAPITALIZATION RATIOS
(in millions)

	September 30, 2018			December 31, 2017
Short-term debt ⁽¹⁾	$	429		$	737
Long-term debt	9,140			9,183
Total debt	$	9,569		$	9,920

Long-term debt	$	9,140		$	9,183
Partners' capital	11,350			10,958
Total book capitalization	$	20,490		$	20,141
Total book capitalization, including short-term debt	$	20,919		$	20,878

Long-term debt-to-total book capitalization	45		%	46		%
Total debt-to-total book capitalization, including short-term debt	46		%	48		%

____________________
⁽¹⁾			Includes borrowings for cash margin deposits with our clearing brokers, which are associated with financial derivatives used for hedging purposes, and for short-term hedged inventory purchases.


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


COMPUTATION OF BASIC AND DILUTED NET INCOME/(LOSS) PER COMMON UNIT ⁽¹⁾
(in millions, except per unit data)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Basic Net Income/(Loss) per Common Unit
Net income attributable to PAA	$	710		$	33		$	1,099		$	665
Distributions to Series A preferred unitholders	(37		)	(36		)	(112		)	(105		)
Distributions to Series B preferred unitholders	(12		)	—			(37		)	—
Other	(3		)	(5		)	(4		)	(13		)
Net income/(loss) allocated to common unitholders	$	658		$	(8	)	$	946		$	547

Basic weighted average common units outstanding	726			725			726			714

Basic net income/(loss) per common unit	$	0.91		$	(0.01	)	$	1.30		$	0.77

Diluted Net Income/(Loss) per Common Unit
Net income attributable to PAA	$	710		$	33		$	1,099		$	665
Distributions to Series A preferred unitholders	—			(36		)	(112		)	(105		)
Distributions to Series B preferred unitholders	(12		)	—			(37		)	—
Other	(1		)	(5		)	(3		)	(13		)
Net income/(loss) allocated to common unitholders	$	697		$	(8	)	$	947		$	547

Basic weighted average common units outstanding	726			725			726			714
Effect of dilutive securities:
Series A preferred units ⁽²⁾	71			—			—			—
Equity-indexed compensation plan awards ⁽³⁾	2			—			2			1
Diluted weighted average common units outstanding	799			725			728			715

Diluted net income/(loss) per common unit	$	0.87		$	(0.01	)	$	1.30		$	0.76

____________________
⁽¹⁾			We calculate net income/(loss) allocated to common unitholders based on the distributions pertaining to the current period’s net income (whether paid in cash or in-kind). After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method.
⁽²⁾			The possible conversion of our Series A preferred units was excluded from the calculation of diluted net income/(loss) per common unit for the nine months ended September 30, 2018 and the three and nine months ended September 30, 2017 as the effect was antidilutive.
⁽³⁾			Our Long-term Incentive Plan (“LTIP”) awards that contemplate the issuance of common units and certain AAP Management Units that contemplate the issuance of common units to AAP when such AAP Management Units become earned are considered dilutive unless (i) they become vested or earned only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards and AAP Management Units that are deemed to be dilutive are reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. Such LTIP awards were excluded from the calculation of diluted net loss per common unit for the three months ended September 30, 2017 as the effect was antidilutive.


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


SELECTED ITEMS IMPACTING COMPARABILITY
(in millions)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Selected Items Impacting Comparability: ⁽¹⁾
Gains/(losses) from derivative activities net of inventory valuation adjustments ⁽²⁾	$	108		$	(214	)	$	(104	)	$	86
Long-term inventory costing adjustments ⁽³⁾	10			16			18			2
Deficiencies under minimum volume commitments, net ⁽⁴⁾	4			(8		)	(9		)	(5		)
Equity-indexed compensation expense ⁽⁵⁾	(14		)	(7		)	(37		)	(18		)
Net gain/(loss) on foreign currency revaluation ⁽⁶⁾	2			11			(2		)	20
Line 901 incident ⁽⁷⁾	—			—			—			(12		)
Significant acquisition-related expenses ⁽⁸⁾	—			—			—			(6		)
Selected items impacting comparability - Adjusted EBITDA	$	110		$	(202	)	$	(134	)	$	67
Gains/(losses) from derivative activities ⁽²⁾	—			(8		)	3			(10		)
Gain on sale of investment in unconsolidated entities	210			—			210			—
Tax effect on selected items impacting comparability	29			48			25			(1		)
Selected items impacting comparability - Adjusted net income attributable to PAA	$	349		$	(162	)	$	104		$	56

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


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


COMPUTATION OF BASIC AND DILUTED ADJUSTED NET INCOME PER COMMON UNIT ⁽¹⁾
(in millions, except per unit data)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Basic Adjusted Net Income per Common Unit
Net income attributable to PAA	$	710		$	33		$	1,099		$	665
Selected items impacting comparability - Adjusted net income attributable to PAA ⁽²⁾	(349		)	162			(104		)	(56		)
Adjusted net income attributable to PAA	$	361		$	195		$	995		$	609
Distributions to Series A preferred unitholders	(37		)	(36		)	(112		)	(105		)
Distributions to Series B preferred unitholders	(12		)	—			(37		)	—
Other	(1		)	(5		)	(4		)	(13		)
Adjusted net income allocated to common unitholders	$	311		$	154		$	842		$	491

Basic weighted average common units outstanding	726			725			726			714

Basic adjusted net income per common unit	$	0.43		$	0.21		$	1.16		$	0.69

Diluted Adjusted Net Income per Common Unit
Net income attributable to PAA	$	710		$	33		$	1,099		$	665
Selected items impacting comparability - Adjusted net income attributable to PAA ⁽²⁾	(349		)	162			(104		)	(56		)
Adjusted net income attributable to PAA	$	361		$	195		$	995		$	609
Distributions to Series A preferred unitholders	(37		)	(36		)	(112		)	(105		)
Distributions to Series B preferred unitholders	(12		)	—			(37		)	—
Other	(1		)	(5		)	(3		)	(13		)
Adjusted net income allocated to common unitholders	$	311		$	154		$	843		$	491

Basic weighted average common units outstanding	726			725			726			714
Effect of dilutive securities:
Equity-indexed compensation plan awards ⁽³⁾	2			1			2			1
Diluted weighted average common units outstanding	728			726			728			715

Diluted adjusted net income per common unit ⁽⁴⁾	$	0.43		$	0.21		$	1.16		$	0.69

____________________
⁽¹⁾			We calculate adjusted net income allocated to common unitholders based on the distributions pertaining to the current period’s net income (whether paid in cash or in-kind). After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method.
⁽²⁾			Certain of our non-GAAP financial measures may not be impacted by each of the selected items impacting comparability.
⁽³⁾			Our LTIP awards that contemplate the issuance of common units and certain AAP Management Units that contemplate the issuance of common units to AAP when such AAP Management Units become earned are considered dilutive unless (i) they become vested or earned only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards and AAP Management Units that are deemed to be dilutive are reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB.
⁽⁴⁾			The possible conversion of our Series A preferred units was excluded from the calculation of diluted adjusted net income per common unit for the three and nine months ended September 30, 2018 and 2017 as the effect was antidilutive.


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


NON-GAAP RECONCILIATIONS
(in millions, except per unit and ratio data)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Net Income to Adjusted EBITDA and Implied DCF Reconciliation
Net Income	$	710		$	34		$	1,099		$	667
Interest expense, net	110			134			327			390
Income tax (benefit)/expense	(10		)	(45		)	35			30
Depreciation and amortization	131			151			306			401
Depreciation and amortization of unconsolidated entities⁽¹⁾	15			13			44			31
Gain on sale of investment in unconsolidated entities	(210		)	—			(210		)	—
Selected items impacting comparability - Adjusted EBITDA ⁽²⁾	(110		)	202			134			(67		)
Adjusted EBITDA	$	636		$	489		$	1,735		$	1,452
Interest expense, net ⁽³⁾	(106		)	(121		)	(318		)	(367		)
Maintenance capital	(78		)	(63		)	(186		)	(194		)
Current income tax benefit/(expense)	(14		)	1			(34		)	(9		)
Adjusted equity earnings in unconsolidated entities, net of distributions ⁽⁴⁾	(5		)	(7		)	9			11
Distributions to noncontrolling interests ⁽⁵⁾	—			(1		)	—			(2		)
Implied DCF	$	433		$	298		$	1,206		$	891
Preferred unit distributions ⁽⁶⁾	(37		)	—			(99		)	—
Implied DCF Available to Common Unitholders	$	396		$	298		$	1,107		$	891

Weighted average common units outstanding	726			725			726			714
Weighted average common units and common equivalent units	797			793			797			780

Implied DCF per Common Unit ⁽⁷⁾	$	0.55		$	0.41		$	1.52		$	1.25
Implied DCF per Common Unit and Common Equivalent Unit ⁽⁸⁾	$	0.54		$	0.38		$	1.48		$	1.14

Cash Distribution Paid per Common Unit	$	0.30		$	0.55		$	0.90		$	1.65
Common Unit Cash Distributions ⁽⁵⁾	$	218		$	399		$	653		$	1,168
Common Unit Distribution Coverage Ratio	1.82x			0.75x			1.70x			0.76x

Implied DCF Excess / (Shortage)	$	178		$	(101	)	$	454		$	(277	)

____________________
⁽¹⁾			Adjustment to add back our proportionate share of depreciation and amortization expense and gains and 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 and losses on significant asset sales) and cash distributions received from such entities.
⁽⁵⁾			Cash distributions paid during the period presented.
⁽⁶⁾			Cash distributions paid to our preferred unitholders during the period presented. The current $0.5250 quarterly ($2.10 annualized) per unit distribution requirement of our Series A preferred units was paid-in-kind for each quarterly distribution from their issuance through February 2018. Distributions on our Series A preferred units were paid in cash beginning with the May 2018 quarterly distribution. The current $61.25 per unit annual distribution requirement of our Series B preferred units, which were issued in October 2017, is payable semi-annually in arrears on May 15 and November 15.
⁽⁷⁾			Implied DCF Available to Common Unitholders for the period divided by the weighted average common units outstanding for the period.
⁽⁸⁾			Implied DCF Available to Common Unitholders for the period, adjusted for Series A preferred unit cash distributions paid (if any), divided by the weighted average common units and common equivalent units outstanding for the periods. Our Series A preferred units are convertible into common units, generally on a one-for-one basis and subject to customary anti-dilution adjustments, at any time after January 28, 2018, in whole or in part, subject to certain minimum conversion amounts.


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


NON-GAAP RECONCILIATIONS (continued)
(in millions, except per unit and ratio data)


	Twelve Months Ended December 31,
	2017			2016
Net Income to Adjusted EBITDA and Implied DCF Reconciliation
Net Income	$	858		$	730
Interest expense, net	510			467
Income tax expense	44			25
Depreciation and amortization	626			494
Depreciation and amortization of unconsolidated entities⁽¹⁾	45			50
Selected items impacting comparability - Adjusted EBITDA	(1		)	403
Adjusted EBITDA	$	2,082		$	2,169
Interest expense, net ⁽²⁾	(483		)	(451		)
Maintenance capital	(247		)	(186		)
Current income tax expense	(28		)	(85		)
Adjusted equity earnings in unconsolidated entities, net of distributions ⁽³⁾	(10		)	(29		)
Distributions to noncontrolling interests	(2		)	(4		)
Implied DCF	$	1,312		$	1,414
Preferred unit distributions ⁽⁴⁾	(5		)	—
General partner cash distributions ⁽⁵⁾	—			(565		)
Implied DCF Available to Common Unitholders	$	1,307		$	849

Implied DCF per Common Unit ⁽⁶⁾	$	1.82		$	1.83
Implied DCF per Common Unit and Common Equivalent Unit ⁽⁷⁾	$	1.67		$	1.63

Cash Distribution Paid per Common Unit	$	1.95		$	2.65
Common Unit Cash Distributions ⁽⁸⁾	$	1,386		$	1,627
Common Unit Distribution Coverage Ratio	0.94x			0.87x

Implied DCF Excess / (Shortage)	$	(79	)	$	(213	)

____________________
⁽¹⁾			Adjustment to add back our proportionate share of depreciation and amortization expense and gains and losses on significant asset sales of unconsolidated entities.
⁽²⁾			Excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps.
⁽³⁾			Represents the difference between non-cash equity earnings in unconsolidated entities (adjusted for our proportionate share of depreciation and amortization and gains and losses on significant asset sales) and cash distributions received from such entities.
⁽⁴⁾			Cash distributions paid to our preferred unitholders during the period presented. The $0.5250 quarterly ($2.10 annualized) per unit distribution requirement of our Series A preferred units was paid-in-kind for all 2016 and 2017 quarterly distributions as such, no Series A preferred unit distributions were included for any periods presented. Distributions on our Series A preferred units must be paid in cash beginning with the May 2018 quarterly distribution. The $61.25 per unit annual distribution requirement of our Series B preferred units, which were issued in October 2017, is payable semi-annually in arrears on May 15 and November 15. A pro-rated initial distribution on the Series B preferred units was paid on November 15, 2017.
⁽⁵⁾			The Simplification Transactions, which closed on November 15, 2016, simplified our governance structure and permanently eliminated our incentive distribution rights (IDRs) and the economic rights associated with our 2% general partner interest.
⁽⁶⁾			Implied DCF Available to Common Unitholders for the period divided by the weighted average common units outstanding for the periods of 717 million and 464 million, respectively.
⁽⁷⁾			Implied DCF Available to Common Unitholders for the period, adjusted for Series A preferred unit cash distributions paid (if any), divided by the weighted average common units and common equivalent units outstanding for the periods of 784 million and 522 million, respectively. Our Series A preferred units are convertible into common units, generally on a one-for-one basis and subject to customary anti-dilution adjustments, at any time after January 28, 2018, in whole or in part, subject to certain minimum conversion amounts.
⁽⁸⁾			Cash distributions paid during the period presented. For the twelve months ended December 31, 2016, includes $565 million of cash distributions paid to the general partner during the period.


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


NON-GAAP RECONCILIATIONS (continued)

Net Income/(Loss) Per Common Unit to Adjusted Net Income Per Common Unit Reconciliation:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Basic net income/(loss) per common unit	$	0.91		$	(0.01	)	$	1.30		$	0.77
Selected items impacting comparability per common unit ⁽¹⁾	(0.48		)	0.22			(0.14		)	(0.08		)
Basic adjusted net income per common unit	$	0.43		$	0.21		$	1.16		$	0.69

Diluted net income/(loss) per common unit	$	0.87		$	(0.01	)	$	1.30		$	0.76
Selected items impacting comparability per common unit ⁽¹⁾	(0.44		)	0.22			(0.14		)	(0.07		)
Diluted adjusted net income per common unit	$	0.43		$	0.21		$	1.16		$	0.69

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


Net Income/(Loss) Per Common Unit to Implied DCF Per Common Unit and Common Equivalent Unit Reconciliations:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018		2017
Basic net income/(loss) per common unit	$	0.91		$	(0.01	)	$	1.30	$	0.77
Reconciling items per common unit ^{(1) (2)}	(0.36		)	0.42			0.22		0.48
Implied DCF per common unit	$	0.55		$	0.41		$	1.52	$	1.25

Basic net income/(loss) per common unit	$	0.91		$	(0.01	)	$	1.30	$	0.77
Reconciling items per common unit and common equivalent unit ^(1) (3)	(0.37		)	0.39			0.18		0.37
Implied DCF per common unit and common equivalent unit	$	0.54		$	0.38		$	1.48	$	1.14

							Twelve Months Ended December 31,
							2017		2016
Basic net income per common unit							$	0.96	$	0.43
Reconciling items per common unit ^{(1) (4)}							0.86		1.40
Implied DCF per common unit							$	1.82	$	1.83

Basic net income per common unit							$	0.96	$	0.43
Reconciling items per common unit and common equivalent unit ^(1) (5)							0.71		1.20
Implied DCF per common unit and common equivalent unit							$	1.67	$	1.63

____________________
⁽¹⁾			Represents adjustments to Net Income to calculate Implied DCF Available to Common Unitholders. See the “Net Income to Adjusted EBITDA and Implied DCF Reconciliation” table for additional information.
⁽²⁾			Based on weighted average common units outstanding for the period of 726 million, 725 million, 726 million and 714 million, respectively.
⁽³⁾			Based on weighted average common units outstanding for the period, as well as weighted average Series A preferred units outstanding for the period of approximately 71 million, 68 million, 71 million and 66 million, respectively.
⁽⁴⁾			Based on weighted average common units outstanding for the period of 717 million and 464 million, respectively.
⁽⁵⁾			Based on weighted average common units outstanding for the period, as well as weighted average Series A preferred units outstanding for the period of 67 million and 58 million, respectively.


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


SELECTED FINANCIAL DATA BY SEGMENT
(in millions)


	Three Months Ended September 30, 2018									Three Months Ended September 30, 2017
	Transportation			Facilities			Supply and Logistics			Transportation			Facilities			Supply and Logistics
Revenues ⁽¹⁾	$	498		$	289		$	8,483		$	446		$	291		$	5,574
Purchases and related costs ⁽¹⁾	(49		)	(3		)	(8,191		)	(29		)	(3		)	(5,729		)
Field operating costs ^{(1) (2)}	(164		)	(95		)	(70		)	(136		)	(89		)	(62		)
Segment general and administrative expenses ^{(2) (3)}	(28		)	(18		)	(28		)	(25		)	(18		)	(25		)
Equity earnings in unconsolidated entities	110			—			—			80			—			—

Adjustments: ⁽⁴⁾
Depreciation and amortization of unconsolidated entities	15			—			—			13			—			—
(Gains)/losses from derivative activities net of inventory valuation adjustments	—			—			(110		)	—			2			214
Long-term inventory costing adjustments	—			—			(10		)	—			—			(16		)
Deficiencies under minimum volume commitments, net	(1		)	(3		)	—			11			(3		)	—
Equity-indexed compensation expense	7			3			4			3			2			2
Net gain on foreign currency revaluation	—			—			(3		)	—			—			(14		)
Segment Adjusted EBITDA	$	388		$	173		$	75		$	363		$	182		$	(56	)

Maintenance capital	$	41		$	33		$	4		$	32		$	28		$	3

____________________
⁽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)


	Nine Months Ended September 30, 2018									Nine Months Ended September 30, 2017
	Transportation			Facilities			Supply and Logistics			Transportation			Facilities			Supply and Logistics
Revenues ⁽¹⁾	$	1,427		$	866		$	24,376		$	1,260		$	873		$	17,757
Purchases and related costs ⁽¹⁾	(141		)	(12		)	(24,076		)	(74		)	(19		)	(17,407		)
Field operating costs ^{(1) (2)}	(469		)	(271		)	(200		)	(436		)	(258		)	(193		)
Segment general and administrative expenses ^{(2) (3)}	(86		)	(59		)	(87		)	(78		)	(55		)	(77		)
Equity earnings in unconsolidated entities	281			—			—			201			—			—

Adjustments: ⁽⁴⁾
Depreciation and amortization of unconsolidated entities	44			—			—			31			—			—
(Gains)/losses from derivative activities net of inventory valuation adjustments	(1		)	(2		)	110			—			3			(89		)
Long-term inventory costing adjustments	—			—			(18		)	—			—			(2		)
Deficiencies under minimum volume commitments, net	8			1			—			2			3			—
Equity-indexed compensation expense	20			7			10			9			3			6
Net (gain)/loss on foreign currency revaluation	—			—			5			—			—			(27		)
Line 901 incident	—			—			—			12			—			—
Significant acquisition-related expenses	—			—			—			6			—			—
Segment Adjusted EBITDA	$	1,083		$	530		$	120		$	933		$	550		$	(32	)

Maintenance capital	$	102		$	74		$	10		$	89		$	94		$	11

____________________
⁽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)


OPERATING DATA BY SEGMENT ⁽¹⁾


	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
Transportation segment (average daily volumes in thousands of barrels per day):
Tariff activities volumes
Crude oil pipelines (by region):
Permian Basin ⁽²⁾	3,880	2,963	3,621	2,732
South Texas / Eagle Ford ⁽²⁾	451	362	436	341
Central ⁽²⁾	480	424	456	419
Gulf Coast	171	359	182	362
Rocky Mountain ⁽²⁾	258	426	261	418
Western	184	190	180	186
Canada	322	351	312	359
Crude oil pipelines	5,746	5,075	5,448	4,817
NGL pipelines	174	172	173	169
Tariff activities total volumes	5,920	5,247	5,621	4,986
Trucking volumes	95	94	95	102
Transportation segment total volumes	6,015	5,341	5,716	5,088

Facilities segment (average monthly volumes):
Liquids storage (average monthly capacity in millions of barrels)	109	112	109	112
Natural gas storage (average monthly working capacity in billions of cubic feet)	65	67	66	87
NGL fractionation (average volumes in thousands of barrels per day)	115	131	128	125
Facilities segment total volumes (average monthly volumes in millions of barrels) ⁽³⁾	123	127	124	130

Supply and Logistics segment (average daily volumes in thousands of barrels per day):
Crude oil lease gathering purchases	1,042	929	1,034	929
NGL sales	195	202	243	254
Supply and Logistics segment total volumes	1,237	1,131	1,277	1,183

____________________
⁽¹⁾			Average volumes are calculated as the total volumes (attributable to our interest) for the period 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)


NON-GAAP SEGMENT RECONCILIATIONS
(in millions)

Fee-based Segment Adjusted EBITDA to Adjusted EBITDA Reconciliation:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2018		2017			2018		2017
Transportation Segment Adjusted EBITDA	$	388	$	363		$	1,083	$	933
Facilities Segment Adjusted EBITDA	173		182			530		550
Fee-based Segment Adjusted EBITDA	$	561	$	545		$	1,613	$	1,483
Supply and Logistics Segment Adjusted EBITDA	75		(56		)	120		(32		)
Adjusted other income/(expense), net ⁽¹⁾	—		—			2		1
Adjusted EBITDA ⁽²⁾	$	636	$	489		$	1,735	$	1,452

____________________
⁽¹⁾			Represents “Other income/(expense), net” as reported on our Condensed Consolidated Statements of Operations, adjusted for selected items impacting comparability of $3 million, $1 million, $(6) million and $7 million for the three and nine months ended September 30, 2018 and 2017, respectively. See the “Selected Items Impacting Comparability” table for additional information.
⁽²⁾			See the “Net Income to Adjusted EBITDA and Implied DCF Reconciliation” table for reconciliation to Net Income.


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

	Three Months Ended September 30, 2018								Three Months Ended September 30, 2017
	Transportation			Facilities			Supply and Logistics		Transportation			Facilities			Supply and Logistics
Segment Adjusted EBITDA	$	388		$	173		$	75	$	363		$	182		$	(56	)
Impact of divested assets ⁽¹⁾	—			—			—		(17		)	(8		)	—
Segment Adjusted EBITDA further adjusted for impact of divested assets	$	388		$	173		$	75	$	346		$	174		$	(56	)

	Nine Months Ended September 30, 2018								Nine Months Ended September 30, 2017
	Transportation			Facilities			Supply and Logistics		Transportation			Facilities			Supply and Logistics
Segment Adjusted EBITDA	$	1,083		$	530		$	120	$	933		$	550		$	(32	)
Impact of divested assets ⁽¹⁾	(6		)	(2		)	—		(43		)	(37		)	—
Segment Adjusted EBITDA further adjusted for impact of divested assets	$	1,077		$	528		$	120	$	890		$	513		$	(32	)

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


PLAINS GP HOLDINGS AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)


CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(in millions, except per share data)


	Three Months Ended September 30, 2018									Three Months Ended September 30, 2017
				Consolidating									Consolidating
	PAA			Adjustments ⁽¹⁾			PAGP			PAA			Adjustments ⁽¹⁾			PAGP
REVENUES	$	8,792		$	—		$	8,792		$	5,873		$	—		$	5,873

COSTS AND EXPENSES
Purchases and related costs	7,768			—			7,768			5,327			—			5,327
Field operating costs	326			—			326			283			—			283
General and administrative expenses	74			1			75			68			—			68
Depreciation and amortization	131			—			131			151			1			152
Total costs and expenses	8,299			1			8,300			5,829			1			5,830

OPERATING INCOME	493			(1		)	492			44			(1		)	43

OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	110			—			110			80			—			80
Gain on sale of investment in unconsolidated entities	210			—			210			—			—			—
Interest expense, net	(110		)	—			(110		)	(134		)	—			(134		)
Other expense, net	(3		)	—			(3		)	(1		)	—			(1		)

INCOME/(LOSS) BEFORE TAX	700			(1		)	699			(11		)	(1		)	(12		)
Current income tax (expense)/benefit	(14		)	—			(14		)	1			—			1
Deferred income tax (expense)/benefit	24			(33		)	(9		)	44			(2		)	42

NET INCOME	710			(34		)	676			34			(3		)	31
Net income attributable to noncontrolling interests	—			(565		)	(565		)	(1		)	(26		)	(27		)
NET INCOME ATTRIBUTABLE TO PAGP	$	710		$	(599	)	$	111		$	33		$	(29	)	$	4

BASIC AND DILUTED NET INCOME PER CLASS A SHARE							$	0.70								$	0.03

BASIC AND DILUTED WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING							158									154

____________________
⁽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)


	Nine Months Ended September 30, 2018									Nine Months Ended September 30, 2017
				Consolidating									Consolidating
	PAA			Adjustments ⁽¹⁾			PAGP			PAA			Adjustments ⁽¹⁾			PAGP
REVENUES	$	25,269		$	—		$	25,269		$	18,618		$	—		$	18,618

COSTS AND EXPENSES
Purchases and related costs	22,838			—			22,838			16,239			—			16,239
Field operating costs	931			—			931			876			—			876
General and administrative expenses	232			3			235			210			3			213
Depreciation and amortization	306			1			307			401			2			403
Total costs and expenses	24,307			4			24,311			17,726			5			17,731

OPERATING INCOME	962			(4		)	958			892			(5		)	887

OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	281			—			281			201			—			201
Gain on sale of investment in unconsolidated entities	210			—			210			—			—			—
Interest expense, net	(327		)	—			(327		)	(390		)	—			(390		)
Other income/(expense), net	8			—			8			(6		)	—			(6		)

INCOME BEFORE TAX	1,134			(4		)	1,130			697			(5		)	692
Current income tax expense	(34		)	—			(34		)	(9		)	—			(9		)
Deferred income tax expense	(1		)	(49		)	(50		)	(21		)	(55		)	(76		)

NET INCOME	1,099			(53		)	1,046			667			(60		)	607
Net income attributable to noncontrolling interests	—			(892		)	(892		)	(2		)	(536		)	(538		)
NET INCOME ATTRIBUTABLE TO PAGP	$	1,099		$	(945	)	$	154		$	665		$	(596	)	$	69

BASIC AND DILUTED NET INCOME PER CLASS A SHARE							$	0.98								$	0.49

BASIC AND DILUTED WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING							157									142

____________________
⁽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)


	September 30, 2018							December 31, 2017
			Consolidating							Consolidating
	PAA		Adjustments ⁽¹⁾			PAGP		PAA		Adjustments ⁽¹⁾			PAGP
ASSETS
Current assets	$	4,127	$	4		$	4,131	$	4,000	$	3		$	4,003
Property and equipment, net	14,677		15			14,692		14,089		16			14,105
Goodwill	2,540		—			2,540		2,566		—			2,566
Investments in unconsolidated entities	2,539		—			2,539		2,756		—			2,756
Deferred tax asset	—		1,347			1,347		—		1,386			1,386
Linefill and base gas	914		—			914		872		—			872
Long-term inventory	179		—			179		164		—			164
Other long-term assets, net	951		(3		)	948		904		(3		)	901
Total assets	$	25,927	$	1,363		$	27,290	$	25,351	$	1,402		$	26,753

LIABILITIES AND PARTNERS' CAPITAL
Current liabilities	$	4,656	$	2		$	4,658	$	4,531	$	2		$	4,533
Senior notes, net	8,939		—			8,939		8,933		—			8,933
Other long-term debt, net	201		—			201		250		—			250
Other long-term liabilities and deferred credits	781		—			781		679		—			679
Total liabilities	$	14,577	$	2		$	14,579	$	14,393	$	2		$	14,395

Partners' capital excluding noncontrolling interests	11,350		(9,603		)	1,747		10,958		(9,263		)	1,695
Noncontrolling interests	—		10,964			10,964		—		10,663			10,663
Total partners' capital	11,350		1,361			12,711		10,958		1,400			12,358
Total liabilities and partners' capital	$	25,927	$	1,363		$	27,290	$	25,351	$	1,402		$	26,753

____________________
⁽¹⁾			Represents the aggregate consolidating adjustments necessary to produce consolidated financial statements for PAGP.


PLAINS GP HOLDINGS AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)


COMPUTATION OF BASIC AND DILUTED NET INCOME PER CLASS A SHARE
(in millions, except per share data)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Basic and Diluted Net Income per Class A Share ⁽¹⁾
Net income attributable to PAGP	$	111	$	4	$	154	$	69
Basic and diluted weighted average Class A shares outstanding	158		154		157		142

Basic and diluted net income per Class A share	$	0.70	$	0.03	$	0.98	$	0.49

____________________
⁽¹⁾			For the three and nine months ended September 30, 2018 and 2017, the possible exchange of any AAP units and certain AAP Management Units would not have had a dilutive effect on basic net income per Class A share.

View source version on businesswire.com: https://www.businesswire.com/news/home/20181106005951/en/

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
Director, Investor Relations

You are here

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