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

Aug 07, 2018 04:17 pm

HOUSTON --

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

Second-Quarter Highlights

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

“We are pleased to report solid second-quarter results and increased guidance for the full year,” stated Willie Chiang, Executive Vice President and Chief Operating Officer of Plains All American Pipeline. “We remain on track to achieve our deleveraging objectives and targeted credit metrics within the first half of 2019, while maintaining substantial distribution coverage underpinned by fee-based cash flow. Additionally, strong Permian Basin fundamentals, combined with the growth and execution of our capital program, provide visibility for continued momentum for fee-based cash flow growth.”


Plains All American Pipeline, L.P.

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

	Three Months Ended June 30,				%		Six Months Ended June 30,				%
GAAP Results	2018		2017		Change		2018		2017		Change
Net income attributable to PAA	$	100	$	188	(47	)%	$	388	$	632	(39	)%
Diluted net income per common unit	$	0.07	$	0.21	(67	)%	$	0.39	$	0.78	(50	)%
Diluted weighted average common units outstanding	727		727		—	%	727		710		2	%
Distribution per common unit declared for the period	$	0.30	$	0.55	(45	)%

	Three Months Ended June 30,				%		Six Months Ended June 30,				%
Non-GAAP Results ⁽¹⁾	2018		2017		Change		2018		2017		Change
Adjusted net income attributable to PAA	$	324	$	189	71	%	$	634	$	414	53	%
Diluted adjusted net income per common unit	$	0.38	$	0.21	81	%	$	0.73	$	0.47	55	%
Adjusted EBITDA	$	506	$	451	12	%	$	1,098	$	963	14	%
Implied DCF per Common Unit	$	0.37	$	0.40	(8	)%	$	0.98	$	0.84	17	%

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

Segment Adjusted EBITDA for the second quarter and first half of 2018 and 2017 is presented below:


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

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

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

Second-quarter 2018 Transportation Segment Adjusted EBITDA increased by 21% over comparable 2017 results. This increase was primarily driven by increased volume on our Permian Basin systems, in addition to contributions from our Eagle Ford JV system, which receives Permian volumes from our Cactus pipeline. Second-quarter 2018 also benefited from Diamond pipeline being placed into service in late 2017. Second-quarter 2018 results also were impacted by the sale of assets in the Rocky Mountain and Central regions.

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

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

2018 Full-Year Guidance

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


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

	Twelve Months Ended December 31,
	2016			2017			2018 (G)
							+ / -
Segment Adjusted EBITDA
Transportation	$	1,141		$	1,287		$	1,535
Facilities	667			734			690
Fee-Based	$	1,808		$	2,021		$	2,225
Supply and Logistics	359			60			175
Other income/(expense), net	2			1			—
Adjusted EBITDA ⁽¹⁾	$	2,169		$	2,082		$	2,400
Interest expense, net ⁽²⁾	(451		)	(483		)	(420		)
Maintenance capital	(186		)	(247		)	(225		)
Current income tax expense	(85		)	(28		)	(45		)
Other	(33		)	(12		)	5
Implied DCF ⁽¹⁾	$	1,414		$	1,312		$	1,715
Preferred unit distributions paid ⁽³⁾	—			(5		)	(160		)
General partner cash distributions	(565		)	—			—
Implied DCF Available to Common Unitholders	$	849		$	1,307		$	1,555

Implied DCF per Common Unit ⁽¹⁾	$	1.83		$	1.82		$	2.14
Implied DCF per Common Unit and Common Equivalent Unit ⁽¹⁾	$	1.63		$	1.67		$	2.09

Distributions per Common Unit ⁽⁴⁾	$	2.65		$	1.95		$	1.20
Common Unit Distribution Coverage Ratio	0.87x			0.94x			1.79x

Operating Data
Transportation
Average daily volumes (MBbls/d)	4,637			5,186			5,925
Segment Adjusted EBITDA per barrel	$	0.67		$	0.68		$	0.71

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

Supply and Logistics
Average daily volumes (MBbls/d)	1,153			1,219			1,275
Segment Adjusted EBITDA per barrel	$	0.85		$	0.13		$	0.38

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

Third-Quarter Adjusted EBITDA as Percentage of Full Year	21%			23%			23%

____________________
(G)			2018 Guidance forecasts are intended to be + / - amounts.

⁽¹⁾			^{See the section of this release entitled “Non-GAAP Financial Measures and Selected Items Impacting Comparability” and the Non-GAAP Reconciliation tables attached hereto for information regarding non-GAAP financial measures and, for the historical 2016 and 2017 periods, their reconciliation to the most directly comparable measures as reported in accordance with GAAP. We do not provide a reconciliation of non-GAAP financial measures to the equivalent GAAP financial measures on a forward-looking basis as it is impractical to forecast certain items that we have defined as “Selected Items Impacting Comparability” without unreasonable effort, due to the uncertainty and inherent difficulty of predicting the occurrence and financial impact of and the periods in which such items may be recognized. Thus, a reconciliation of non-GAAP financial measures to the equivalent GAAP financial measures could result in disclosure that could be imprecise or potentially misleading.}

⁽²⁾			^{Excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps.}

⁽³⁾			^{Cash distributions paid to our preferred unitholders during the year presented. The distribution requirement of our Series A preferred units was paid-in-kind for all 2016 and 2017 quarterly distributions and for the February 2018 quarterly distribution. Distributions on our Series A preferred units must be paid in cash beginning with the May 2018 quarterly distribution. The distribution requirement of our Series B preferred units, which were issued in October 2017, is payable semi-annually in arrears on May 15 and November 15. A pro-rated initial distribution on the Series B preferred units was paid on November 15, 2017.}

⁽⁴⁾			^{Cash distributions per common unit paid during 2016 and 2017. 2018(G) reflects the current distribution rate held constant.}

Plains GP Holdings

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

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

Conference Call

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

PAA’s second-quarter 2018 performance;
Financial and operating guidance for the full year of 2018;
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=1199816&tp_key=608fb57b8d

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

Non-GAAP Financial Measures and Selected Items Impacting Comparability

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

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

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

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

Forward-Looking Statements

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

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

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


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


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

	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
REVENUES	$	8,080		$	6,078		$	16,478		$	12,745

COSTS AND EXPENSES
Purchases and related costs	7,551			5,320			15,070			10,912
Field operating costs	312			304			605			593
General and administrative expenses	80			68			159			142
Depreciation and amortization	49			129			175			250
Total costs and expenses	7,992			5,821			16,009			11,897

OPERATING INCOME	88			257			469			848

OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	96			68			171			121
Interest expense, net	(111		)	(127		)	(217		)	(256		)
Other income/(expense), net	11			1			10			(4		)

INCOME BEFORE TAX	84			199			433			709
Current income tax expense	(7		)	(1		)	(20		)	(11		)
Deferred income tax benefit/(expense)	23			(9		)	(25		)	(65		)

NET INCOME	100			189			388			633
Net income attributable to noncontrolling interests	—			(1		)	—			(1		)
NET INCOME ATTRIBUTABLE TO PAA	$	100		$	188		$	388		$	632

NET INCOME PER COMMON UNIT:
Net income allocated to common unitholders — Basic	$	50		$	148		$	286		$	555
Basic weighted average common units outstanding	725			725			725			708
Basic net income per common unit	$	0.07		$	0.21		$	0.39		$	0.78

Net income allocated to common unitholders — Diluted	$	50		$	148		$	286		$	555
Diluted weighted average common units outstanding	727			727			727			710
Diluted net income per common unit	$	0.07		$	0.21		$	0.39		$	0.78

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Adjusted net income attributable to PAA	$	324		$	189		$	634		$	414

Diluted adjusted net income per common unit	$	0.38		$	0.21		$	0.73		$	0.47

Adjusted EBITDA	$	506		$	451		$	1,098		$	963


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


CONDENSED CONSOLIDATED BALANCE SHEET DATA
(in millions)

	June 30, 2018			December 31, 2017
ASSETS
Current assets	$	3,852		$	4,000
Property and equipment, net	14,257			14,089
Goodwill	2,535			2,566
Investments in unconsolidated entities	3,116			2,756
Linefill and base gas	866			872
Long-term inventory	169			164
Other long-term assets, net	904			904
Total assets	$	25,699		$	25,351

LIABILITIES AND PARTNERS' CAPITAL
Current liabilities	$	5,122		$	4,531
Senior notes, net of unamortized discounts and debt issuance costs	8,937			8,933
Other long-term debt	29			250
Other long-term liabilities and deferred credits	787			679
Total liabilities	14,875			14,393

Partners' capital	10,824			10,958
Total liabilities and partners' capital	$	25,699		$	25,351

DEBT CAPITALIZATION RATIOS
(in millions)

	June 30, 2018			December 31, 2017
Short-term debt ⁽¹⁾	$	943		$	737
Long-term debt	8,966			9,183
Total debt	$	9,909		$	9,920

Long-term debt	$	8,966		$	9,183
Partners' capital	10,824			10,958
Total book capitalization	$	19,790		$	20,141
Total book capitalization, including short-term debt	$	20,733		$	20,878

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

____________________
⁽¹⁾		^{As of June 30, 2018 and December 31, 2017, short-term debt includes borrowings of approximately $515 million and $523 million, respectively, for short-term hedged inventory purchases and borrowings of approximately $426 million and $212 million, respectively, for cash margin deposits with our clearing brokers, which are associated with financial derivatives used for hedging purposes.}


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


OPERATING DATA ⁽¹⁾

	Three Months Ended June 30,		Six Months Ended June 30,
	2018	2017	2018	2017
Transportation segment (average daily volumes in thousands of barrels per day):
Tariff activities volumes
Crude oil pipelines (by region):
Permian Basin ⁽²⁾	3,734	2,761	3,489	2,614
South Texas / Eagle Ford ⁽²⁾	434	349	428	330
Central ⁽²⁾	448	427	445	416
Gulf Coast	170	385	187	364
Rocky Mountain ⁽²⁾	270	444	263	415
Western	181	179	177	184
Canada	298	363	308	363
Crude oil pipelines	5,535	4,908	5,297	4,686
NGL pipelines	171	156	172	168
Tariff activities total volumes	5,706	5,064	5,469	4,854
Trucking volumes	91	99	95	106
Transportation segment total volumes	5,797	5,163	5,564	4,960

Facilities segment (average monthly volumes):
Liquids storage (average monthly capacity in millions of barrels)	109	112	109	112
Natural gas storage (average monthly working capacity in billions of cubic feet)	65	97	66	97
NGL fractionation (average volumes in thousands of barrels per day)	132	119	135	122
Facilities segment total volumes (average monthly volumes in millions of barrels) ⁽³⁾	124	132	124	132

Supply and Logistics segment (average daily volumes in thousands of barrels per day):
Crude oil lease gathering purchases	1,028	940	1,030	929
NGL sales	174	210	266	280
Supply and Logistics segment total volumes	1,202	1,150	1,296	1,209

____________________
⁽¹⁾		^{Average volumes are calculated as total volumes for the period (attributable to our interest) divided by the number of days or months in the period.}

⁽²⁾		^{Region includes volumes (attributable to our interest) from pipelines owned by unconsolidated entities.}

⁽³⁾		^{Facilities segment total volumes is calculated as the sum of: (i) liquids storage capacity; (ii) natural gas storage working capacity divided by 6 to account for the 6:1 mcf of natural gas to crude Btu equivalent ratio and further divided by 1,000 to convert to monthly volumes in millions; and (iii) NGL fractionation volumes multiplied by the number of days in the period and divided by the number of months in the period.}


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


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

	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Basic Net Income per Common Unit
Net income attributable to PAA	$	100		$	188		$	388		$	632
Distributions to Series A preferred unitholders	(37		)	(35		)	(74		)	(69		)
Distributions to Series B preferred unitholders	(12		)	—			(25		)	—
Other	(1		)	(5		)	(3		)	(8		)
Net income allocated to common unitholders	$	50		$	148		$	286		$	555

Basic weighted average common units outstanding	725			725			725			708

Basic net income per common unit	$	0.07		$	0.21		$	0.39		$	0.78

Diluted Net Income per Common Unit
Net income attributable to PAA	$	100		$	188		$	388		$	632
Distributions to Series A preferred unitholders	(37		)	(35		)	(74		)	(69		)
Distributions to Series B preferred unitholders	(12		)	—			(25		)	—
Other	(1		)	(5		)	(3		)	(8		)
Net income allocated to common unitholders	$	50		$	148		$	286		$	555

Basic weighted average common units outstanding	725			725			725			708
Effect of dilutive securities:
Equity-indexed compensation plan awards ⁽²⁾	2			2			2			2
Diluted weighted average common units outstanding	727			727			727			710

Diluted net income per common unit ⁽³⁾	$	0.07		$	0.21		$	0.39		$	0.78

____________________
⁽¹⁾		^{We calculate net income allocated to common unitholders based on the distributions pertaining to the current period’s net income (whether paid in cash or in-kind). After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method.}

⁽²⁾		^{Our Long-term Incentive Plan (“LTIP”) awards that contemplate the issuance of common units and certain AAP Management Units that contemplate the issuance of common units to AAP when such AAP Management Units become earned are considered dilutive unless (i) they become vested or earned only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards and AAP Management Units that are deemed to be dilutive are reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB.}

⁽³⁾		^{The possible conversion of our Series A preferred units was excluded from the calculation of diluted net income per common unit for the three and six months ended June 30, 2018 and 2017 as the effect was antidilutive.}


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


SELECTED FINANCIAL DATA BY SEGMENT
(in millions)

	Three Months Ended June 30, 2018									Three Months Ended June 30, 2017
	Transportation			Facilities			Supply and Logistics			Transportation			Facilities			Supply and Logistics
Revenues ⁽¹⁾	$	475		$	284		$	7,781		$	425		$	289		$	5,783
Purchases and related costs ⁽¹⁾	(46		)	(3		)	(7,959		)	(21		)	(6		)	(5,708		)
Field operating costs ^{(1) (2)}	(157		)	(92		)	(66		)	(158		)	(85		)	(65		)
Segment general and administrative expenses ^{(2) (3)}	(30		)	(21		)	(29		)	(24		)	(18		)	(26		)
Equity earnings in unconsolidated entities	96			—			—			68			—			—

Adjustments: ⁽⁴⁾
Depreciation and amortization of unconsolidated entities	14			—			—			4			—			—
(Gains)/losses from derivative activities net of inventory valuation adjustments	—			(1		)	241			—			(1		)	(12		)
Long-term inventory costing adjustments	—			—			5			—			—			7
Deficiencies under minimum volume commitments, net	1			2			—			(14		)	—			—
Equity-indexed compensation expense	7			2			3			5			1			3
Net gain on foreign currency revaluation	—			—			(2		)	—			—			(10		)
Line 901 incident	—			—			—			12			—			—
Significant acquisition-related expenses	—			—			—			1			—			—
Segment Adjusted EBITDA	$	360		$	171		$	(26	)	$	298		$	180		$	(28	)

Maintenance capital	$	32		$	26		$	5		$	27		$	39		$	5

____________________
⁽¹⁾		^{Includes intersegment amounts.}

⁽²⁾		^{Field operating costs and Segment general and administrative expenses include equity-indexed compensation expense.}

⁽³⁾		^{Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.}

⁽⁴⁾		^{Represents adjustments utilized by our Chief Operating Decision Maker (“CODM”) in the evaluation of segment results. Many of these adjustments are also considered selected items impacting comparability when calculating consolidated non-GAAP financial measures such as Adjusted EBITDA. See the “Selected Items Impacting Comparability” table for additional discussion.}


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


SELECTED FINANCIAL DATA BY SEGMENT
(in millions)


	Six Months Ended June 30, 2018									Six Months Ended June 30, 2017
	Transportation			Facilities			Supply and Logistics			Transportation			Facilities			Supply and Logistics
Revenues ⁽¹⁾	$	929		$	576		$	15,893		$	814		$	582		$	12,184
Purchases and related costs ⁽¹⁾	(92		)	(8		)	(15,884		)	(45		)	(17		)	(11,678		)
Field operating costs ^{(1) (2)}	(304		)	(176		)	(131		)	(299		)	(169		)	(132		)
Segment general and administrative expenses ^{(2) (3)}	(58		)	(42		)	(59		)	(53		)	(37		)	(52		)
Equity earnings in unconsolidated entities	171			—			—			121			—			—

Adjustments: ⁽⁴⁾
Depreciation and amortization of unconsolidated entities	29			—			—			18			—			—
(Gains)/losses from derivative activities net of inventory valuation adjustments	(1		)	(2		)	219			—			1			(303		)
Long-term inventory costing adjustments	—			—			(7		)	—			—			14
Deficiencies under minimum volume commitments, net	9			4			—			(9		)	6			—
Equity-indexed compensation expense	12			5			6			6			2			4
Net (gain)/loss on foreign currency revaluation	—			—			8			—			—			(14		)
Line 901 incident	—			—			—			12			—			—
Significant acquisition-related expenses	—			—			—			6			—			—
Segment Adjusted EBITDA	$	695		$	357		$	45		$	571		$	368		$	23

Maintenance capital	$	61		$	41		$	6		$	57		$	66		$	8

____________________
⁽¹⁾		^{Includes intersegment amounts.}

⁽²⁾		^{Field operating costs and Segment general and administrative expenses include equity-indexed compensation expense.}

⁽³⁾		^{Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.}

⁽⁴⁾		^{Represents adjustments utilized by our CODM in the evaluation of segment results. Many of these adjustments are also considered selected items impacting comparability when calculating consolidated non-GAAP financial measures such as Adjusted EBITDA. See the “Selected Items Impacting Comparability” table for additional discussion.}


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


SELECTED ITEMS IMPACTING COMPARABILITY
(in millions)


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

____________________
⁽¹⁾		^{Certain of our non-GAAP financial measures may not be impacted by each of the selected items impacting comparability.}

⁽²⁾		^{We use derivative instruments for risk management purposes and our related processes include specific identification of hedging instruments to an underlying hedged transaction. Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction. In the course of evaluating our results of operations, we identify the earnings that were recognized during the period related to derivative instruments for which the identified underlying transaction does not occur in the current period and exclude the related gains and losses in determining adjusted results. In addition, we exclude gains and losses on derivatives that are related to investing activities, such as the purchase of linefill. We also exclude the impact of corresponding inventory valuation adjustments, as applicable, as well as the mark-to-market adjustment related to our Preferred Distribution Rate Reset Option.}

⁽³⁾		^{We carry crude oil and NGL inventory comprised of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets). We treat the impact of changes in the average cost of the long-term inventory (that result from fluctuations in market prices) and writedowns of such inventory that result from price declines as a selected item impacting comparability.}

⁽⁴⁾		^{We have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. Substantially all of such agreements were entered into with counterparties to economically support the return on our capital expenditure necessary to construct the related asset. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue, as a selected item impacting comparability. We believe the inclusion of the contractually committed revenues associated with that period is meaningful to investors as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results.}

⁽⁵⁾		^{Our total equity-indexed compensation expense includes expense associated with awards that will or may be settled in units and awards that will or may be settled in cash. The awards that will or may be settled in units are included in our diluted net income per unit calculation when the applicable performance criteria have been met. We consider the compensation expense associated with these awards as a selected item impacting comparability as the dilutive impact of the outstanding awards is included in our diluted net income per unit calculation and the majority of the awards are expected to be settled in units. The portion of compensation expense associated with awards that are certain to be settled in cash is not considered a selected item impacting comparability.}

⁽⁶⁾		^{During the periods presented, there were fluctuations in the value of the Canadian dollar to the U.S. dollar, resulting in gains and losses that were not related to our core operating results for the period and were thus classified as a selected item impacting comparability.}

⁽⁷⁾		^{Includes costs recognized during the period related to the Line 901 incident that occurred in May 2015, net of amounts we believe are probable of recovery from insurance.}

⁽⁸⁾		^{Includes acquisition-related expenses associated with the Alpha Crude Connector acquisition.}


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


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


	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Net Income to Adjusted EBITDA and Implied DCF Reconciliation
Net Income	$	100		$	189		$	388		$	633
Interest expense, net	111			127			217			256
Income tax (benefit)/expense	(16		)	10			45			76
Depreciation and amortization	49			129			175			250
Depreciation and amortization of unconsolidated entities⁽¹⁾	14			4			29			18
Selected items impacting comparability - Adjusted EBITDA ⁽²⁾	248			(8		)	244			(270		)
Adjusted EBITDA	$	506		$	451		$	1,098		$	963
Interest expense, net ⁽³⁾	(107		)	(121		)	(212		)	(246		)
Maintenance capital	(63		)	(71		)	(108		)	(131		)
Current income tax expense	(7		)	(1		)	(20		)	(11		)
Adjusted equity earnings in unconsolidated entities, net of distributions ⁽⁴⁾	1			32			15			18
Distributions to noncontrolling interests ⁽⁵⁾	—			—			—			(1		)
Implied DCF	$	330		$	290		$	773		$	592
Preferred unit distributions ⁽⁶⁾	(62		)	—			(62		)	—
Implied DCF Available to Common Unitholders	$	268		$	290		$	711		$	592

Implied DCF per Common Unit ⁽⁷⁾	$	0.37		$	0.40		$	0.98		$	0.84
Implied DCF per Common Unit and Common Equivalent Unit ⁽⁸⁾	$	0.38		$	0.37		$	0.94		$	0.76

Cash Distribution Paid per Common Unit	$	0.30		$	0.55		$	0.60		$	1.10
Common Unit Cash Distributions ⁽⁵⁾	$	218		$	399		$	435		$	770
Common Unit Distribution Coverage Ratio	1.23x			0.73x			1.63x			0.77x

Implied DCF Excess / (Shortage)	$	50		$	(109	)	$	276		$	(178	)

____________________
⁽¹⁾		^{Adjustment to add back our proportionate share of depreciation and amortization expense and gains or losses on significant asset sales of unconsolidated entities.}

⁽²⁾		^{Certain of our non-GAAP financial measures may not be impacted by each of the selected items impacting comparability.}

⁽³⁾		^{Excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps.}

⁽⁴⁾		^{Represents the difference between non-cash equity earnings in unconsolidated entities (adjusted for our proportionate share of depreciation and amortization and gains or losses on significant asset sales) and cash distributions received from such entities.}

⁽⁵⁾		^{Cash distributions paid during the period presented.}

⁽⁶⁾		^{Cash distributions paid to our preferred unitholders during the period presented. The current $0.5250 quarterly ($2.10 annualized) per unit distribution requirement of our Series A preferred units was paid-in-kind for each quarterly distribution from their issuance through February 2018. Distributions on our Series A preferred units were paid in cash beginning with the May 2018 quarterly distribution. The current $61.25 per unit annual distribution requirement of our Series B preferred units, which were issued in October 2017, is payable semi-annually in arrears on May 15 and November 15.}

⁽⁷⁾		^{Implied DCF Available to Common Unitholders for the period divided by the weighted average common units outstanding for the period of 725 million, 725 million, 725 million, and 708 million, respectively.}

⁽⁸⁾		^{Implied DCF Available to Common Unitholders for the period, adjusted for Series A preferred unit cash distributions paid (if any), divided by the weighted average common units and common equivalent units outstanding for the periods of 796 million, 791 million, 796 million, and 774 million, respectively. Our Series A preferred units are convertible into common units, generally on a one-for-one basis and subject to customary anti-dilution adjustments, at any time after January 28, 2018, in whole or in part, subject to certain minimum conversion amounts.}


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


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

	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Net Income Per Common Unit to Implied DCF Per Common Unit and Common Equivalent Unit Reconciliation
Basic net income per common unit	$	0.07	$	0.21	$	0.39	$	0.78
Reconciling items per common unit ^{(1) (2)}	0.30		0.19		0.59		0.06
Implied DCF per common unit	$	0.37	$	0.40	$	0.98	$	0.84

Basic net income per common unit	$	0.07	$	0.21	$	0.39	$	0.78
Reconciling items per common unit and common equivalent unit ^(1) (3)	0.31		0.16		0.55		(0.02		)
Implied DCF per common unit and common equivalent unit	$	0.38	$	0.37	$	0.94	$	0.76

____________________
⁽¹⁾		^{Represents adjustments to Net Income to calculate Implied DCF Available to Common Unitholders. See the “Net Income to Adjusted EBITDA and Implied DCF Reconciliation” table for additional information.}

⁽²⁾		^{Based on weighted average common units outstanding for the period of 725 million, 725 million, 725 million and 708 million, respectively.}

⁽³⁾		^{Based on weighted average common units outstanding for the period, as well as weighted average Series A preferred units outstanding for the period of approximately 71 million, 66 million, 71 million and 66 million, respectively.}


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

Diluted net income per common unit	$	0.07	$	0.21	$	0.39	$	0.78
Selected items impacting comparability per common unit ⁽¹⁾	0.31		—		0.34		(0.31		)
Diluted adjusted net income per common unit	$	0.38	$	0.21	$	0.73	$	0.47

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


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

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

⁽²⁾		^{See the “Net Income to Adjusted EBITDA and Implied DCF Reconciliation” table for reconciliation to net income.}


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


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

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

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

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

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

____________________
⁽¹⁾		^{Adjustment to add back our proportionate share of depreciation and amortization expense and gains or losses on significant asset sales of unconsolidated entities.}

⁽²⁾		^{Excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps.}

⁽³⁾		^{Represents the difference between non-cash equity earnings in unconsolidated entities (adjusted for our proportionate share of depreciation and amortization and gains or losses on significant asset sales) and cash distributions received from such entities.}

⁽⁴⁾		^{Cash distributions paid to our preferred unitholders during the period presented. The $0.5250 quarterly ($2.10 annualized) per unit distribution requirement of our Series A preferred units has been paid-in-kind for each quarterly distribution since their issuance; as such, no Series A preferred unit distributions are included for any periods presented. Distributions on our Series A preferred units must be paid in cash beginning with the May 2018 quarterly distribution. The $61.25 per unit annual distribution requirement of our Series B preferred units, which were issued in October 2017, is payable semi-annually in arrears on May 15 and November 15. A pro-rated initial distribution on the Series B preferred units was paid on November 15, 2017.}

⁽⁵⁾		^{The Simplification Transactions, which closed on November 15, 2016, simplified our governance structure and permanently eliminated our incentive distribution rights (IDRs) and the economic rights associated with our 2% general partner interest.}

⁽⁶⁾		^{Implied DCF Available to Common Unitholders for the period divided by the weighted average common units outstanding for the periods of 717 million and 464 million, respectively.}

⁽⁷⁾		^{Implied DCF Available to Common Unitholders for the period, adjusted for Series A preferred unit cash distributions paid (if any), divided by the weighted average common units and common equivalent units outstanding for the periods of 784 million and 522 million, respectively. Our Series A preferred units are convertible into common units, generally on a one-for-one basis and subject to customary anti-dilution adjustments, at any time after January 28, 2018, in whole or in part, subject to certain minimum conversion amounts.}

⁽⁸⁾		^{Cash distributions paid during the period presented. For the twelve months ended December 31, 2016, includes $565 million of cash distributions paid to the general partner during the period.}


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


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

	Twelve Months Ended December 31,
	2017		2016
Net Income Per Common Unit to Implied DCF Per Common Unit and Common Equivalent Unit Reconciliation
Basic net income per common unit	$	0.96	$	0.43
Reconciling items per common unit ^{(1) (2)}	0.86		1.40
Implied DCF per common unit	$	1.82	$	1.83

Basic net income per common unit	$	0.96	$	0.43
Reconciling items per common unit and common equivalent unit ^(1) (3)	0.71		1.20
Implied DCF per common unit and common equivalent unit	$	1.67	$	1.63

____________________
⁽¹⁾		^{Represents adjustments to Net Income to calculate Implied DCF Available to Common Unitholders. See the “Net Income to Adjusted EBITDA and Implied DCF Reconciliation” table for additional information.}

⁽²⁾		^{Based on weighted average common units outstanding for the period of 717 million and 464 million, respectively.}

⁽³⁾		^{Based on weighted average common units outstanding for the period, as well as weighted average Series A preferred units outstanding for the period of 67 million and 58 million, respectively.}


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

	Six Months Ended June 30, 2018								Six Months Ended June 30, 2017
	Transportation			Facilities			Supply and Logistics		Transportation			Facilities			Supply and Logistics
Segment Adjusted EBITDA	$	695		$	357		$	45	$	571		$	368		$	23
Impact of divested assets ⁽¹⁾	(6		)	(2		)	—		(26		)	(29		)	—
Segment Adjusted EBITDA further adjusted for impact of divested assets	$	689		$	355		$	45	$	545		$	339		$	23

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


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


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

	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Basic Adjusted Net Income per Common Unit
Net income attributable to PAA	$	100		$	188		$	388		$	632
Selected items impacting comparability - Adjusted net income attributable to PAA ⁽²⁾	224			1			246			(218		)
Adjusted net income attributable to PAA	$	324		$	189		$	634		$	414
Distributions to Series A preferred unitholders	(37		)	(35		)	(74		)	(69		)
Distributions to Series B preferred unitholders	(12		)	—			(25		)	—
Other	(1		)	(5		)	(3		)	(8		)
Adjusted net income allocated to common unitholders	$	274		$	149		$	532		$	337

Basic weighted average common units outstanding	725			725			725			708

Basic adjusted net income per common unit	$	0.38		$	0.21		$	0.73		$	0.47

Diluted Adjusted Net Income per Common Unit
Net income attributable to PAA	$	100		$	188		$	388		$	632
Selected items impacting comparability - Adjusted net income attributable to PAA ⁽²⁾	224			1			246			(218		)
Adjusted net income attributable to PAA	$	324		$	189		$	634		$	414
Distributions to Series A preferred unitholders	(37		)	(35		)	(74		)	(69		)
Distributions to Series B preferred unitholders	(12		)	—			(25		)	—
Other	(1		)	(5		)	(3		)	(8		)
Adjusted net income allocated to common unitholders	$	274		$	149		$	532		$	337

Basic weighted average common units outstanding	725			725			725			708
Effect of dilutive securities:
Equity-indexed compensation plan awards ⁽³⁾	2			2			2			2
Diluted weighted average common units outstanding	727			727			727			710

Diluted adjusted net income per common unit ⁽⁴⁾	$	0.38		$	0.21		$	0.73		$	0.47

____________________
⁽¹⁾		^{We calculate adjusted net income allocated to common unitholders based on the distributions pertaining to the current period’s net income (whether paid in cash or in-kind). After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method.}

⁽²⁾		^{Certain of our non-GAAP financial measures may not be impacted by each of the selected items impacting comparability.}

⁽³⁾		^{Our LTIP awards that contemplate the issuance of common units and certain AAP Management Units that contemplate the issuance of common units to AAP when such AAP Management Units become earned are considered dilutive unless (i) they become vested or earned only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards and AAP Management Units that are deemed to be dilutive are reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB.}

⁽⁴⁾		^{The possible conversion of our Series A preferred units was excluded from the calculation of diluted adjusted net income per common unit for the three and six months ended June 30, 2018 and 2017 as the effect was antidilutive.}


PLAINS GP HOLDINGS AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)


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

	Three Months Ended June 30, 2018									Three Months Ended June 30, 2017
				Consolidating Adjustments ⁽¹⁾									Consolidating Adjustments ⁽¹⁾
	PAA						PAGP			PAA						PAGP
REVENUES	$	8,080		$	—		$	8,080		$	6,078		$	—		$	6,078

COSTS AND EXPENSES
Purchases and related costs	7,551			—			7,551			5,320			—			5,320
Field operating costs	312			—			312			304			—			304
General and administrative expenses	80			1			81			68			1			69
Depreciation and amortization	49			1			50			129			—			129
Total costs and expenses	7,992			2			7,994			5,821			1			5,822

OPERATING INCOME	88			(2		)	86			257			(1		)	256

OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	96			—			96			68			—			68
Interest expense, net	(111		)	—			(111		)	(127		)	—			(127		)
Other income, net	11			—			11			1			—			1

INCOME BEFORE TAX	84			(2		)	82			199			(1		)	198
Current income tax expense	(7		)	—			(7		)	(1		)	—			(1		)
Deferred income tax benefit/(expense)	23			(2		)	21			(9		)	(14		)	(23		)

NET INCOME	100			(4		)	96			189			(15		)	174
Net income attributable to noncontrolling interests	—			(89		)	(89		)	(1		)	(149		)	(150		)
NET INCOME ATTRIBUTABLE TO PAGP	$	100		$	(93	)	$	7		$	188		$	(164	)	$	24

BASIC AND DILUTED NET INCOME PER CLASS A SHARE							$	0.05								$	0.16

BASIC AND DILUTED WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING							157									153

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


PLAINS GP HOLDINGS AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)


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

	Six Months Ended June 30, 2018									Six Months Ended June 30, 2017
				Consolidating Adjustments ⁽¹⁾									Consolidating Adjustments ⁽¹⁾
	PAA						PAGP			PAA						PAGP
REVENUES	$	16,478		$	—		$	16,478		$	12,745		$	—		$	12,745

COSTS AND EXPENSES
Purchases and related costs	15,070			—			15,070			10,912			—			10,912
Field operating costs	605			—			605			593			—			593
General and administrative expenses	159			2			161			142			3			145
Depreciation and amortization	175			1			176			250			1			251
Total costs and expenses	16,009			3			16,012			11,897			4			11,901

OPERATING INCOME	469			(3		)	466			848			(4		)	844

OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	171			—			171			121			—			121
Interest expense, net	(217		)	—			(217		)	(256		)	—			(256		)
Other income/(expense), net	10			—			10			(4		)	—			(4		)

INCOME BEFORE TAX	433			(3		)	430			709			(4		)	705
Current income tax expense	(20		)	—			(20		)	(11		)	—			(11		)
Deferred income tax expense	(25		)	(16		)	(41		)	(65		)	(54		)	(119		)

NET INCOME	388			(19		)	369			633			(58		)	575
Net income attributable to noncontrolling interests	—			(325		)	(325		)	(1		)	(509		)	(510		)
NET INCOME ATTRIBUTABLE TO PAGP	$	388		$	(344	)	$	44		$	632		$	(567	)	$	65

BASIC AND DILUTED NET INCOME PER CLASS A SHARE							$	0.28								$	0.47

BASIC AND DILUTED WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING							157									136

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


PLAINS GP HOLDINGS AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)


CONDENSED CONSOLIDATING BALANCE SHEET DATA
(in millions)

	June 30, 2018							December 31, 2017
			Consolidating Adjustments ⁽¹⁾							Consolidating Adjustments ⁽¹⁾
	PAA		Consolidating Adjustments ⁽¹⁾			PAGP		PAA		Consolidating Adjustments ⁽¹⁾			PAGP
ASSETS
Current assets	$	3,852	$	3		$	3,855	$	4,000	$	3		$	4,003
Property and equipment, net	14,257		16			14,273		14,089		16			14,105
Goodwill	2,535		—			2,535		2,566		—			2,566
Investments in unconsolidated entities	3,116		—			3,116		2,756		—			2,756
Deferred tax asset	—		1,377			1,377		—		1,386			1,386
Linefill and base gas	866		—			866		872		—			872
Long-term inventory	169		—			169		164		—			164
Other long-term assets, net	904		(3		)	901		904		(3		)	901
Total assets	$	25,699	$	1,393		$	27,092	$	25,351	$	1,402		$	26,753

LIABILITIES AND PARTNERS' CAPITAL
Current liabilities	$	5,122	$	2		$	5,124	$	4,531	$	2		$	4,533
Senior notes, net of unamortized discounts and debt issuance costs	8,937		—			8,937		8,933		—			8,933
Other long-term debt	29		—			29		250		—			250
Other long-term liabilities and deferred credits	787		—			787		679		—			679
Total liabilities	$	14,875	$	2		$	14,877	$	14,393	$	2		$	14,395

Partners' capital excluding noncontrolling interests	10,824		(9,163		)	1,661		10,958		(9,263		)	1,695
Noncontrolling interests	—		10,554			10,554		—		10,663			10,663
Total partners' capital	10,824		1,391			12,215		10,958		1,400			12,358
Total liabilities and partners' capital	$	25,699	$	1,393		$	27,092	$	25,351	$	1,402		$	26,753

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


PLAINS GP HOLDINGS AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)


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

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

Basic and diluted net income per Class A share	$	0.05	$	0.16	$	0.28	$	0.47

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

View source version on businesswire.com: https://www.businesswire.com/news/home/20180807005802/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

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