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

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

Plains All American Pipeline, L.P.
Summary Financial Information (unaudited)
(in millions, except per unit data)
	Three Months Ended							Nine Months Ended
	September 30,					%		September 30,				%
GAAP Results	2017			2016		Change		2017		2016		Change
Net income attributable to PAA	$	33		$	297	(89	)%	$	665	$	599	11	%
Diluted net income/(loss) per common unit	$	(0.01	)	$	0.40	(103	)%	$	0.76	$	0.27	181	%
Diluted weighted average common units outstanding	725			402		80	%	715		400		79	%
Distribution per common unit declared for the period	$	0.30		$	0.55	(45	)%
	Three Months Ended							Nine Months Ended
	September 30,					%		September 30,				%
Non-GAAP Results ^(1)	2017			2016		Change		2017		2016		Change
Adjusted net income attributable to PAA	$	195		$	293	(33	)%	$	609	$	783	(22	)%
Diluted adjusted net income per common unit	$	0.21		$	0.39	(46	)%	$	0.69	$	0.72	(4	)%
Adjusted EBITDA ^(2)	$	489		$	463	6	%	$	1,452	$	1,569	(7	)%

^(1)

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

^(2)

Prior period amounts have been recast to conform to certain changes made in the fourth quarter of 2016.

“PAA reported third-quarter results that were slightly above guidance,” stated Greg L. Armstrong, Chairman and CEO of Plains All American Pipeline. “We are on track to execute our leverage reduction plan, on-time and on-budget with our capital program and making progress on a number of additional commercial initiatives. Additionally, due to significant preparation, coordination and execution by our employees, the recent hurricanes had minimal impact on our operations and financial results and we were able to service our customers without interruption. I want to publicly thank our employees and vendors for their commitment and hard work in that regard and also for the actions they took to help one another and our communities in the recovery efforts.”

Segment adjusted EBITDA for the third quarter and first nine months of 2017 and 2016 is presented below:

Summary of Selected Financial Data by Segment ^(1) (unaudited)
(in millions)
	Three Months Ended September 30, 2017									Three Months Ended September 30, 2016
	Transportation			Facilities			Supply and Logistics			Transportation		Facilities		Supply and Logistics
Segment adjusted EBITDA	$	363		$	182		$	(56	)	$	308	$	171	$	(17	)
Percentage change in segment adjusted EBITDA versus 2016 period	18		%	6		%	**
	Nine Months Ended September 30, 2017									Nine Months Ended September 30, 2016
	Transportation			Facilities			Supply and Logistics			Transportation		Facilities		Supply and Logistics
Segment adjusted EBITDA	$	933		$	550		$	(32	)	$	863	$	497	$	208
Percentage change in segment adjusted EBITDA versus 2016 period	8		%	11		%	**

**	Indicates that variance as a percentage is not meaningful.
^(1)	During the fourth quarter of 2016, we modified our primary segment performance measure to segment adjusted EBITDA from segment profit and also modified our definition of adjusted EBITDA to exclude our proportionate share of depreciation and amortization expense associated with equity method investments. Prior-period segment amounts have been recast to reflect these changes.

Third-quarter 2017 Transportation segment adjusted EBITDA increased by 18% over comparable 2016 results. This increase was primarily driven by increased volumes on our Permian Basin systems, in addition to contributions from our Eagle Ford JV system, which receives Permian volumes from our Cactus pipeline.

Third-quarter 2017 Facilities segment adjusted EBITDA increased by 6% versus comparable 2016 results. This increase was primarily driven by higher fee-based revenues at certain of our NGL facilities, partially offset by lower rail activity and the impact of an asset sale completed in June 2017.

Overall negative Supply & Logistics results for both third-quarter periods primarily relate to the seasonality of our NGL supply business. Third-quarter 2017 Supply and Logistics segment adjusted EBITDA decreased by $39 million relative to comparable 2016 results due to continued competitive pressures, margin compression, and reduced arbitrage opportunities.

The Partnership estimates an approximate $6 million third-quarter 2017 adjusted EBITDA aggregate impact due to lower volumes resulting from operational downtime associated with Hurricane Harvey.

2017 Full-Year Guidance

The table below presents our full-year 2017 financial and operating guidance:

Financial and Operating Guidance (unaudited)
(in millions, except per barrel data)
	Twelve Months Ended December 31,
	2015			2016			2017 (G)
							+ / -
Segment Adjusted EBITDA
Transportation	$	1,056		$	1,141		$	1,275
Facilities	588			667			725
Fee-Based	$	1,644		$	1,808		$	2,000
Supply and Logistics	568			359			75
Other income/(expense), net	1			2			—
Adjusted EBITDA ^(1)	$	2,213		$	2,169		$	2,075
Interest expense, net ^(2)	(417		)	(451		)	(485		)
Maintenance capital	(220		)	(186		)	(240		)
Current income tax expense	(84		)	(85		)	(25		)
Other	(18		)	(33		)	5
Implied DCF ^(1)	$	1,474		$	1,414		$	1,330
Operating Data
Transportation
Average daily volumes (MBbls/d)	4,453			4,637			5,160
Segment Adjusted EBITDA per barrel	$	0.65		$	0.67		$	0.68
Facilities
Average capacity (MMBbls/Mo)	126			129			131
Segment Adjusted EBITDA per barrel	$	0.39		$	0.43		$	0.46
Supply and Logistics
Average daily volumes (MBbls/d)	1,168			1,160			1,205
Segment Adjusted EBITDA per barrel	$	1.33		$	0.85		$	0.17
Expansion Capital	$	2,170		$	1,405		$	1,050
Fourth-Quarter Adjusted EBITDA as Percentage of Full Year	26%			28%			30%

(G)	2017 Guidance forecasts are intended to be + / - amounts.
^(1)	See the section of this release entitled “Non-GAAP Financial Measures and Selected Items Impacting Comparability” and the Financial Data Reconciliations table attached hereto for information regarding non-GAAP financial measures and, for the historical 2015 and 2016 periods, their reconciliation to the most directly comparable measures as reported in accordance with GAAP. We do not provide a reconciliation of non-GAAP financial measures to the equivalent GAAP financial measures on a forward-looking basis as it is impractical to forecast certain items that we have defined as “Selected Items Impacting Comparability” without unreasonable effort, due to the uncertainty and inherent difficulty of predicting the occurrence and financial impact of and the periods in which such items may be recognized. Thus, a reconciliation of non-GAAP financial measures to the equivalent GAAP financial measures could result in disclosure that could be imprecise or potentially misleading.
^(2)	Excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps.

Plains GP Holdings

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

	Q3 2017		Q2 2017			Q3 2016
Distribution per Class A share declared for the period ^(1)	$	0.30	$	0.55		$	0.55
Q3 2017 distribution percentage change from prior periods			(45		)%	(45		)%

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

Conference Call

PAA and PAGP will hold a conference call at 9:00 a.m. CT on Tuesday, November 7, 2017 to discuss the following items:

1. PAA’s third-quarter 2017 performance;
2. Financial and operating guidance for the full year of 2017;
3. Capitalization and liquidity; and
4. PAA and PAGP’s outlook for the future.

Conference Call Webcast Instructions

To access the internet webcast please go to https://event.webcasts.com/starthere.jsp?ei=1165323&tp_key=ec99532516

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

Non-GAAP Financial Measures and Selected Items Impacting Comparability

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

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

Plains All American Pipeline, L.P. is a publicly traded master limited partnership that owns and operates midstream energy infrastructure and provides logistics services for crude oil, NGLs, natural gas and refined products. PAA owns an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins and transportation corridors and at major market hubs in the United States and Canada. On average, PAA handles over 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,
	2017			2016			2017			2016
REVENUES	$	5,873		$	5,170		$	18,618		$	14,231
COSTS AND EXPENSES
Purchases and related costs	5,327			4,429			16,239			12,000
Field operating costs	283			289			876			893
General and administrative expenses	68			70			210			210
Depreciation and amortization	151			33			401			351
Total costs and expenses	5,829			4,821			17,726			13,454
OPERATING INCOME	44			349			892			777
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	80			46			201			133
Interest expense, net	(134		)	(113		)	(390		)	(339		)
Other income/(expense), net	(1		)	17			(6		)	46
INCOME/(LOSS) BEFORE TAX	(11		)	299			697			617
Current income tax benefit/(expense)	1			(4		)	(9		)	(45		)
Deferred income tax benefit/(expense)	44			3			(21		)	30
NET INCOME	34			298			667			602
Net income attributable to noncontrolling interests	(1		)	(1		)	(2		)	(3		)
NET INCOME ATTRIBUTABLE TO PAA	$	33		$	297		$	665		$	599
NET INCOME/(LOSS) PER COMMON UNIT:
Net income/(loss) allocated to common unitholders — Basic	$	(8	)	$	162		$	547		$	110
Basic weighted average common units outstanding	725			401			714			399
Basic net income/(loss) per common unit	$	(0.01	)	$	0.40		$	0.77		$	0.27
Net income/(loss) allocated to common unitholders — Diluted	$	(8	)	$	162		$	547		$	110
Diluted weighted average common units outstanding	725			402			715			400
Diluted net income/(loss) per common unit	$	(0.01	)	$	0.40		$	0.76		$	0.27
NON-GAAP ADJUSTED RESULTS
(in millions, except per unit data)
	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Adjusted net income attributable to PAA	$	195		$	293		$	609		$	783
Diluted adjusted net income per common unit	$	0.21		$	0.39		$	0.69		$	0.72
Adjusted EBITDA	$	489		$	463		$	1,452		$	1,569

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
CONDENSED CONSOLIDATED BALANCE SHEET DATA
(in millions)
	September 30, 2017			December 31, 2016
ASSETS
Current assets	$	4,015		$	4,272
Property and equipment, net	14,269			13,872
Goodwill	2,598			2,344
Investments in unconsolidated entities	2,671			2,343
Linefill and base gas	884			896
Long-term inventory	135			193
Other long-term assets, net	911			290
Total assets	$	25,483		$	24,210
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities	$	4,016		$	4,664
Senior notes, net of unamortized discounts and debt issuance costs	9,881			9,874
Other long-term debt	608			250
Other long-term liabilities and deferred credits	698			606
Total liabilities	$	15,203		$	15,394
Partners' capital excluding noncontrolling interests	10,223			8,759
Noncontrolling interests	57			57
Total partners' capital	10,280			8,816
Total liabilities and partners' capital	$	25,483		$	24,210
DEBT CAPITALIZATION RATIOS
(in millions)
	September 30, 2017			December 31, 2016
Short-term debt ^(1)	$	918		$	1,715
Long-term debt	10,489			10,124
Total debt	$	11,407		$	11,839
Long-term debt	$	10,489		$	10,124
Partners' capital	10,280			8,816
Total book capitalization	$	20,769		$	18,940
Total book capitalization, including short-term debt	$	21,687		$	20,655
Long-term debt-to-total book capitalization	51		%	53		%
Total debt-to-total book capitalization, including short-term debt	53		%	57		%

^(1)

As of September 30, 2017 and December 31, 2016, short-term debt includes borrowings of approximately $724 million and $1,303 million, respectively, for short-term hedged inventory purchases and borrowings of approximately $194 million and $410 million, respectively, for cash margin deposits with our clearing brokers, which are associated with financial derivatives used for hedging purposes.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
OPERATING DATA ^(1)
	Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016
Transportation segment (average daily volumes in thousands of barrels per day):
Tariff activities volumes
Crude oil pipelines (by region):
Permian Basin ^(2)	2,963	2,162	2,732	2,129
South Texas / Eagle Ford ^(2)	362	263	341	283
Western	190	194	186	193
Rocky Mountain ^(2)	426	475	418	448
Gulf Coast	359	423	362	538
Central ^(2)	424	403	419	393
Canada	351	379	359	384
Crude oil pipelines	5,075	4,299	4,817	4,368
NGL pipelines	172	185	169	182
Tariff activities total volumes	5,247	4,484	4,986	4,550
Trucking volumes	94	118	102	113
Transportation segment total volumes	5,341	4,602	5,088	4,663
Facilities segment (average monthly volumes):
Crude oil, refined products and NGL terminalling and storage (average monthly capacity in millions of barrels)	112	109	112	106
Rail load / unload volumes (average volumes in thousands of barrels per day)	30	73	38	97
Natural gas storage (average monthly working capacity in billions of cubic feet)	67	97	87	97
NGL fractionation (average volumes in thousands of barrels per day)	131	119	125	113
Facilities segment total volumes (average monthly volumes in millions of barrels) ^(3)	128	131	131	129
Supply and Logistics segment (average daily volumes in thousands of barrels per day):
Crude oil lease gathering purchases	929	883	929	894
NGL sales	202	207	254	230
Waterborne cargos	—	8	2	7
Supply and Logistics segment total volumes	1,131	1,098	1,185	1,131

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

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
COMPUTATION OF BASIC AND DILUTED NET INCOME/(LOSS) PER COMMON UNIT ^(1)
(in millions, except per unit data)
	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Basic Net Income/(Loss) per Common Unit
Net income attributable to PAA	$	33		$	297		$	665		$	599
Distributions to Series A preferred unitholders	(36		)	(33		)	(105		)	(88		)
Distributions to general partner	—			(102		)	—			(412		)
Other	(5		)	—			(13		)	11
Net income/(loss) allocated to common unitholders	$	(8	)	$	162		$	547		$	110
Basic weighted average common units outstanding	725			401			714			399
Basic net income/(loss) per common unit	$	(0.01	)	$	0.40		$	0.77		$	0.27
Diluted Net Income/(Loss) per Common Unit
Net income attributable to PAA	$	33		$	297		$	665		$	599
Distributions to Series A preferred unitholders	(36		)	(33		)	(105		)	(88		)
Distributions to general partner	—			(102		)	—			(412		)
Other	(5		)	—			(13		)	11
Net income/(loss) allocated to common unitholders	$	(8	)	$	162		$	547		$	110
Basic weighted average common units outstanding	725			401			714			399
Effect of dilutive securities:
LTIP units ^(2)	—			1			1			1
Diluted weighted average common units outstanding	725			402			715			400
Diluted net income/(loss) per common unit ^(3)	$	(0.01	)	$	0.40		$	0.76		$	0.27

^(1)	We calculate net income/(loss) allocated to common unitholders based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings (“undistributed loss”), if any, are allocated to the general partner, common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method. The Simplification Transactions, which closed on November 15, 2016, simplified our governance structure and permanently eliminated our IDRs and the economic rights associated with our 2% general partner interest. As such, beginning with the distribution pertaining to the fourth quarter of 2016, our general partner is no longer entitled to receive distributions on these interests.
^(2)	Our Long-term Incentive Plan (“LTIP”) awards that contemplate the issuance of common units are considered dilutive unless (i) vesting occurs only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards that are deemed to be dilutive are reduced by a hypothetical unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. 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.
^(3)	The possible conversion of our Series A preferred units was excluded from the calculation of diluted net income/(loss) per common unit for the three and nine months ended September 30, 2017 and 2016 as the effect was antidilutive.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
SELECTED FINANCIAL DATA BY SEGMENT ^(1)
(in millions)
	Three Months Ended September 30, 2017									Three Months Ended September 30, 2016
	Transportation			Facilities			Supply and Logistics			Transportation			Facilities			Supply and Logistics
Revenues ^(2)	$	446		$	291		$	5,574		$	401		$	282		$	4,879
Purchases and related costs ^(2)	(29		)	(3		)	(5,729		)	(24		)	(6		)	(4,788		)
Field operating costs ^(2) (3)	(134		)	(88		)	(62		)	(133		)	(85		)	(70		)
Equity-indexed compensation expense - field operating costs	(2		)	(1		)	—			(3		)	(1		)	—
Segment general and administrative expenses ^(3) (4)	(22		)	(16		)	(23		)	(22		)	(15		)	(23		)
Equity-indexed compensation expense - general and administrative	(3		)	(2		)	(2		)	(4		)	(2		)	(4		)
Equity earnings in unconsolidated entities	80			—			—			46			—			—
Adjustments: ^(5)
Depreciation and amortization of unconsolidated entities	13			—			—			13			—			—
(Gains)/losses from derivative activities net of inventory valuation adjustments	—			2			214			—			1			(53		)
Long-term inventory costing adjustments	—			—			(16		)	—			—			38
Deficiencies under minimum volume commitments, net	11			(3		)	—			30			(5		)	—
Equity-indexed compensation expense	3			2			2			4			2			2
Net (gain)/loss on foreign currency revaluation	—			—			(14		)	—			—			2
Segment adjusted EBITDA	$	363		$	182		$	(56	)	$	308		$	171		$	(17	)
Maintenance capital	$	32		$	28		$	3		$	29		$	15		$	3

^(1)	During the fourth quarter of 2016, we modified our primary segment performance measure to segment adjusted EBITDA from segment profit. Segment adjusted EBITDA forms the basis of our internal financial reporting and is the primary measure used by our Chief Operating Decision Maker (“CODM”) in assessing performance and allocating resources among our operating segments. Prior period segment amounts have been recast to reflect this change.
^(2)	Includes intersegment amounts.
^(3)	Field operating costs and Segment general and administrative expenses exclude equity-indexed compensation expense, which is presented separately in the table above.
^(4)	Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.
^(5)	Represents adjustments utilized by our CODM in the evaluation of segment results. Many of these adjustments are also considered selected items impacting comparability when calculating consolidated non-GAAP financial measures such as Adjusted EBITDA. See the “Selected Items Impacting Comparability” table for additional discussion.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
SELECTED FINANCIAL DATA BY SEGMENT ^(1)
(in millions)
	Nine Months Ended September 30, 2017									Nine Months Ended September 30, 2016
	Transportation			Facilities			Supply and Logistics			Transportation			Facilities			Supply and Logistics
Revenues ^(2)	$	1,260		$	873		$	17,757		$	1,188		$	817		$	13,353
Purchases and related costs ^(2)	(74		)	(19		)	(17,407		)	(69		)	(17		)	(13,031		)
Field operating costs ^(2) (3)	(427		)	(256		)	(193		)	(406		)	(258		)	(226		)
Equity-indexed compensation expense - field operating costs	(9		)	(2		)	—			(9		)	(3		)	(1		)
Segment general and administrative expenses ^(3) (4)	(70		)	(50		)	(68		)	(67		)	(44		)	(72		)
Equity-indexed compensation expense - general and administrative	(8		)	(5		)	(9		)	(10		)	(7		)	(10		)
Equity earnings in unconsolidated entities	201			—			—			133			—			—
Adjustments: ^(5)
Depreciation and amortization of unconsolidated entities	31			—			—			38			—			—
(Gains)/losses from derivative activities net of inventory valuation adjustments	—			3			(89		)	—			—			189
Long-term inventory costing adjustments	—			—			(2		)	—			—			(6		)
Deficiencies under minimum volume commitments, net	2			3			—			54			5			—
Equity-indexed compensation expense	9			3			6			11			5			7
Net (gain)/loss on foreign currency revaluation	—			—			(27		)	—			(1		)	5
Line 901 incident	12			—			—			—			—			—
Significant acquisition-related expenses	6			—			—			—			—			—
Segment adjusted EBITDA	$	933		$	550		$	(32	)	$	863		$	497		$	208
Maintenance capital	$	89		$	94		$	11		$	86		$	32		$	10

^(1)	During the fourth quarter of 2016, we modified our primary segment performance measure to segment adjusted EBITDA from segment profit. Segment adjusted EBITDA forms the basis of our internal financial reporting and is the primary measure used by our CODM in assessing performance and allocating resources among our operating segments. Prior period segment amounts have been recast to reflect this change.
^(2)	Includes intersegment amounts.
^(3)	Field operating costs and Segment general and administrative expenses exclude equity-indexed compensation expense, which is presented separately in the table above.
^(4)	Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.
^(5)	Represents adjustments utilized by our CODM in the evaluation of segment results. Many of these adjustments are also considered selected items impacting comparability when calculating consolidated non-GAAP financial measures such as Adjusted EBITDA. See the “Selected Items Impacting Comparability” table for additional discussion.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
SELECTED ITEMS IMPACTING COMPARABILITY
(in millions, except per unit data)
	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Selected Items Impacting Comparability: ^(1)
Gains/(losses) from derivative activities net of inventory valuation adjustments ^(2)	$	(214	)	$	69		$	86		$	(147	)
Long-term inventory costing adjustments ^(3)	16			(38		)	2			6
Deficiencies under minimum volume commitments, net ^(4)	(8		)	(25		)	(5		)	(59		)
Equity-indexed compensation expense ^(5)	(7		)	(8		)	(18		)	(23		)
Net gain/(loss) on foreign currency revaluation ^(6)	11			(3		)	20			(1		)
Line 901 incident ^(7)	—			—			(12		)	—
Significant acquisition-related expenses ^(8)	—			—			(6		)	—
Selected items impacting comparability - Adjusted EBITDA	$	(202	)	$	(5	)	$	67		$	(224	)
Losses from derivative activities ^(2)	(8		)	—			(10		)	—
Tax effect on selected items impacting comparability	48			9			(1		)	40
Selected items impacting comparability - Adjusted net income attributable to PAA	$	(162	)	$	4		$	56		$	(184	)

^(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 data)
	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Net Income to Adjusted EBITDA and Implied DCF Reconciliation
Net Income	$	34		$	298		$	667		$	602
Interest expense, net	134			113			390			339
Income tax (benefit)/expense	(45		)	1			30			15
Depreciation and amortization	151			33			401			351
Depreciation and amortization of unconsolidated entities^(1)	13			13			31			38
Selected items impacting comparability - Adjusted EBITDA ^(2)	202			5			(67		)	224
Adjusted EBITDA	$	489		$	463		$	1,452		$	1,569
Interest expense, net ^(3)	(121		)	(109		)	(367		)	(327		)
Maintenance capital	(63		)	(47		)	(194		)	(128		)
Current income tax benefit/(expense)	1			(4		)	(9		)	(45		)
Adjusted equity earnings in unconsolidated entities, net of distributions ^(4)	(7		)	(9		)	11			(20		)
Distributions to noncontrolling interests ^(5)	—			(1		)	(1		)	(3		)
Implied DCF ^(6)	$	299		$	293		$	892		$	1,046

^(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)	Includes cash distributions that pertain to the current period’s net income, which are paid in the subsequent period.
^(6)	Including net costs recognized during the periods related to the Line 901 incident that occurred in May 2015, Implied DCF would have been $880 million for the nine months ended September 30, 2017, respectively.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
NON-GAAP RECONCILIATIONS (continued)
(in millions, except per unit data)
	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Net Income/(Loss) Per Common Unit to Adjusted Net Income Per Common Unit Reconciliation
Basic net income/(loss) per common unit	$	(0.01	)	$	0.40		$	0.77		$	0.27
Selected items impacting comparability ^(1)	0.22			(0.01		)	(0.08		)	0.46
Basic adjusted net income per common unit	$	0.21		$	0.39		$	0.69		$	0.73
Diluted net income/(loss) per common unit	$	(0.01	)	$	0.40		$	0.76		$	0.27
Selected items impacting comparability ^(1)	0.22			(0.01		)	(0.07		)	0.45
Diluted adjusted net income per common unit	$	0.21		$	0.39		$	0.69		$	0.72

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

	Twelve Months Ended December 31,
	2016			2015
Net Income to Adjusted EBITDA and Implied DCF Reconciliation
Net Income	$	730		$	906
Interest expense, net	467			432
Income tax expense	25			100
Depreciation and amortization	494			432
Depreciation and amortization of unconsolidated entities^(1)	50			45
Selected items impacting comparability - Adjusted EBITDA	403			298
Adjusted EBITDA	$	2,169		$	2,213
Interest expense, net ^(2)	(451		)	(417		)
Maintenance capital	(186		)	(220		)
Current income tax expense	(85		)	(84		)
Adjusted equity earnings in unconsolidated entities, net of distributions ^(3)	(29		)	(14		)
Distributions to noncontrolling interests ^(4)	(4		)	(4		)
Implied DCF	$	1,414		$	1,474

^(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)	Includes cash distributions that pertain to the current period’s net income, which are paid in the subsequent period.

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,
	2017			2016			2017			2016
Basic Adjusted Net Income per Common Unit
Net income attributable to PAA	$	33		$	297		$	665		$	599
Selected items impacting comparability - Adjusted net income attributable to PAA ^(2)	162			(4		)	(56		)	184
Adjusted net income attributable to PAA	195			293			609			783
Distributions to Series A preferred unitholders	(36		)	(33		)	(105		)	(88		)
Distributions to general partner	—			(102		)	—			(412		)
Other	(5		)	—			(13		)	7
Adjusted net income allocated to common unitholders	$	154		$	158		$	491		$	290
Basic weighted average common units outstanding	725			401			714			399
Basic adjusted net income per common unit	$	0.21		$	0.39		$	0.69		$	0.73
Diluted Adjusted Net Income per Common Unit
Net income attributable to PAA	$	33		$	297		$	665		$	599
Selected items impacting comparability - Adjusted net income attributable to PAA ^(2)	162			(4		)	(56		)	184
Adjusted net income attributable to PAA	195			293			609			783
Distributions to Series A preferred unitholders	(36		)	(33		)	(105		)	(88		)
Distributions to general partner	—			(102		)	—			(412		)
Other	(5		)	—			(13		)	7
Adjusted net income allocated to common unitholders	$	154		$	158		$	491		$	290
Basic weighted average common units outstanding	725			401			714			399
Effect of dilutive securities:
LTIP units ^(3)	1			1			1			1
Diluted weighted average common units outstanding	726			402			715			400
Diluted adjusted net income per common unit ^(4)	$	0.21		$	0.39		$	0.69		$	0.72

^(1)	We calculate adjusted net income allocated to common unitholders based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings (“undistributed loss”), if any, are allocated to the general partner, common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method. The Simplification Transactions, which closed on November 15, 2016, simplified our governance structure and permanently eliminated our IDRs and the economic rights associated with our 2% general partner interest. As such, beginning with the distribution pertaining to the fourth quarter of 2016, our general partner is no longer entitled to receive distributions from these interests.
^(2)	Certain of our non-GAAP financial measures may not be impacted by each of the selected items impacting comparability.
^(3)	Our LTIP awards that contemplate the issuance of common units are considered dilutive unless (i) vesting occurs only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards that are deemed to be dilutive are reduced by a hypothetical unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB.
^(4)	The possible conversion of our Series A preferred units was excluded from the calculation of diluted adjusted net income per common unit for the three and nine months ended September 30, 2017 and 2016 as the effect was antidilutive.

PLAINS GP HOLDINGS AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS ^(1)
(in millions, except per share data)
	Three Months Ended September 30, 2017									Three Months Ended September 30, 2016
				Consolidating									Consolidating
	PAA			Adjustments ^(2)			PAGP			PAA			Adjustments ^(2)			PAGP
REVENUES	$	5,873		$	—		$	5,873		$	5,170		$	—		$	5,170
COSTS AND EXPENSES
Purchases and related costs	5,327			—			5,327			4,429			—			4,429
Field operating costs	283			—			283			289			—			289
General and administrative expenses	68			—			68			70			1			71
Depreciation and amortization	151			1			152			33			—			33
Total costs and expenses	5,829			1			5,830			4,821			1			4,822
OPERATING INCOME	44			(1		)	43			349			(1		)	348
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	80			—			80			46			—			46
Interest expense, net	(134		)	—			(134		)	(113		)	(3		)	(116		)
Other income/(expense), net	(1		)	—			(1		)	17			—			17
INCOME/(LOSS) BEFORE TAX	(11		)	(1		)	(12		)	299			(4		)	295
Current income tax benefit/(expense)	1			—			1			(4		)	—			(4		)
Deferred income tax benefit/(expense)	44			(2		)	42			3			(15		)	(12		)
NET INCOME	34			(3		)	31			298			(19		)	279
Net income attributable to noncontrolling interests	(1		)	(26		)	(27		)	(1		)	(254		)	(255		)
NET INCOME ATTRIBUTABLE TO PAGP	$	33		$	(29	)	$	4		$	297		$	(273	)	$	24
BASIC NET INCOME PER CLASS A SHARE							$	0.03								$	0.24
DILUTED NET INCOME PER CLASS A SHARE							$	0.03								$	0.24
BASIC WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING							154									101
DILUTED WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING							154									101

^(1)	A reverse split of PAGP’s Class A shares was completed on November 15, 2016. The effect of the reverse split has been retroactively applied to all share and per-share amounts presented.
^(2)	Represents the aggregate consolidating adjustments necessary to produce consolidated financial statements for PAGP.

PLAINS GP HOLDINGS AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS ^(1)
(in millions, except per share data)
	Nine Months Ended September 30, 2017									Nine Months Ended September 30, 2016
				Consolidating									Consolidating
	PAA			Adjustments ^(2)			PAGP			PAA			Adjustments ^(2)			PAGP
REVENUES	$	18,618		$	—		$	18,618		$	14,231		$	—		$	14,231
COSTS AND EXPENSES
Purchases and related costs	16,239			—			16,239			12,000			—			12,000
Field operating costs	876			—			876			893			—			893
General and administrative expenses	210			3			213			210			2			212
Depreciation and amortization	401			2			403			351			1			352
Total costs and expenses	17,726			5			17,731			13,454			3			13,457
OPERATING INCOME	892			(5		)	887			777			(3		)	774
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	201			—			201			133			—			133
Interest expense, net	(390		)	—			(390		)	(339		)	(10		)	(349		)
Other income/(expense), net	(6		)	—			(6		)	46			—			46
INCOME BEFORE TAX	697			(5		)	692			617			(13		)	604
Current income tax expense	(9		)	—			(9		)	(45		)	—			(45		)
Deferred income tax benefit/(expense)	(21		)	(55		)	(76		)	30			(51		)	(21		)
NET INCOME	667			(60		)	607			602			(64		)	538
Net income attributable to noncontrolling interests	(2		)	(536		)	(538		)	(3		)	(433		)	(436		)
NET INCOME ATTRIBUTABLE TO PAGP	$	665		$	(596	)	$	69		$	599		$	(497	)	$	102
BASIC NET INCOME PER CLASS A SHARE							$	0.49								$	1.03
DILUTED NET INCOME PER CLASS A SHARE							$	0.49								$	1.02
BASIC WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING							142									99
DILUTED WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING							142									236

^(1)	A reverse split of PAGP’s Class A shares was completed on November 15, 2016. The effect of the reverse split has been retroactively applied to all share and per-share amounts presented.
^(2)	Represents the aggregate consolidating adjustments necessary to produce consolidated financial statements for PAGP.

PLAINS GP HOLDINGS AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
CONDENSED CONSOLIDATING BALANCE SHEET DATA
(in millions)
	September 30, 2017							December 31, 2016
			Consolidating							Consolidating
	PAA		Adjustments ^(1)			PAGP		PAA		Adjustments ^(1)			PAGP
ASSETS
Current assets	$	4,015	$	3		$	4,018	$	4,272	$	3		$	4,275
Property and equipment, net	14,269		16			14,285		13,872		18			13,890
Goodwill	2,598		—			2,598		2,344		—			2,344
Investments in unconsolidated entities	2,671		—			2,671		2,343		—			2,343
Deferred tax asset	—		2,210			2,210		—		1,876			1,876
Linefill and base gas	884		—			884		896		—			896
Long-term inventory	135		—			135		193		—			193
Other long-term assets, net	911		(2		)	909		290		(4		)	286
Total assets	$	25,483	$	2,227		$	27,710	$	24,210	$	1,893		$	26,103
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities	$	4,016	$	2		$	4,018	$	4,664	$	2		$	4,666
Senior notes, net of unamortized discounts and debt issuance costs	9,881		—			9,881		9,874		—			9,874
Other long-term debt	608		—			608		250		—			250
Other long-term liabilities and deferred credits	698		—			698		606		—			606
Total liabilities	$	15,203	$	2		$	15,205	$	15,394	$	2		$	15,396
Partners' capital excluding noncontrolling interests	10,223		(7,695		)	2,528		8,759		(7,022		)	1,737
Noncontrolling interests	57		9,920			9,977		57		8,913			8,970
Total partners' capital	10,280		2,225			12,505		8,816		1,891			10,707
Total liabilities and partners' capital	$	25,483	$	2,227		$	27,710	$	24,210	$	1,893		$	26,103

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

PLAINS GP HOLDINGS AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
COMPUTATION OF BASIC AND DILUTED NET INCOME PER CLASS A SHARE ^(1)
(in millions, except per share data)
	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Basic Net Income per Class A Share
Net income attributable to PAGP	$	4	$	24	$	69	$	102
Basic weighted average Class A shares outstanding	154		101		142		99
Basic net income per Class A share	$	0.03	$	0.24	$	0.49	$	1.03
Diluted Net Income per Class A Share
Net income attributable to PAGP	$	4	$	24	$	69	$	102
Incremental net income attributable to PAGP resulting from assumed exchange of AAP units and AAP Management Units	—		—		—		138
Net income attributable to PAGP including incremental net income from assumed exchange of AAP units and AAP Management Units	$	4	$	24	$	69	$	240
Basic weighted average Class A shares outstanding	154		101		142		99
Dilutive shares resulting from assumed exchange of AAP units and AAP Management Units	—		—		—		137
Diluted weighted average Class A shares outstanding	154		101		142		236
Diluted net income per Class A share ^(2)	$	0.03	$	0.24	$	0.49	$	1.02

^(1)

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

^(2)

For the three and nine months ended September 30, 2017, and the three months ended September 30, 2016, 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. For the nine months ended September 30, 2016, the possible exchange of any AAP units would have had a dilutive effect on basic net income per Class A share and the possible exchange of certain AAP Management Units would not have had a dilutive effect on basic net income per Class A share.