0001104659-16-117695.txt : 20160504 0001104659-16-117695.hdr.sgml : 20160504 20160504161657 ACCESSION NUMBER: 0001104659-16-117695 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 20160504 ITEM INFORMATION: Results of Operations and Financial Condition ITEM INFORMATION: Regulation FD Disclosure ITEM INFORMATION: Financial Statements and Exhibits FILED AS OF DATE: 20160504 DATE AS OF CHANGE: 20160504 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PLAINS ALL AMERICAN PIPELINE LP CENTRAL INDEX KEY: 0001070423 STANDARD INDUSTRIAL CLASSIFICATION: PIPE LINES (NO NATURAL GAS) [4610] IRS NUMBER: 760582150 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-14569 FILM NUMBER: 161619551 BUSINESS ADDRESS: STREET 1: 333 CLAY STREET STREET 2: SUITE 1600 CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: 7136544100 MAIL ADDRESS: STREET 1: 333 CLAY STREET STREET 2: SUITE 1600 CITY: HOUSTON STATE: TX ZIP: 77002 8-K 1 a16-10112_18k.htm 8-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d) of The Securities Exchange Act of 1934

Date of Report (Date of earliest event reported) — May 4, 2016

Plains All American Pipeline, L.P.

(Exact name of registrant as specified in its charter)

DELAWARE		1-14569		76-0582150
(State or other jurisdiction of incorporation)		(Commission File Number)		(IRS Employer Identification No.)

333 Clay Street, Suite 1600, Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: 713-646-4100

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 9.01. Financial Statements and Exhibits

(d) Exhibit 99.1 — Press Release dated May 4, 2016

Item 2.02 and Item 7.01. Results of Operations and Financial Condition; Regulation FD Disclosure

Plains All American Pipeline, L.P. (the “Partnership”) today issued a press release reporting its first-quarter 2016 results. We are furnishing the press release, attached as Exhibit 99.1, pursuant to Item 2.02 and Item 7.01 of Form 8-K. Pursuant to Item 7.01, we are also providing detailed guidance of financial performance for the second quarter and second half of 2016. In accordance with General Instruction B.2. of Form 8-K, the information presented herein under Item 2.02 and Item 7.01 shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), nor shall it be deemed incorporated by reference in any filing under the Exchange Act or Securities Act of 1933, as amended, except as expressly set forth by specific reference in such a filing.

Disclosure of Second-Quarter and Second-Half 2016 Guidance

We based our guidance for the three-month period ending June 30, 2016 and six-month period ending December 31, 2016 on assumptions and estimates that we believe are reasonable, given our assessment of historical trends (modified for changes in market conditions, including an assumption that U.S. onshore oil production continues to decline in 2016 as well as a continuation of a competitive crude oil market), business cycles and other reasonably available information. Projections covering multi-quarter periods contemplate inter-period changes in future performance resulting from new expansion projects, seasonal operational changes (such as NGL sales) and acquisition synergies. Our assumptions and future performance, however, are both subject to a wide range of business risks and uncertainties, so we can provide no assurance that actual performance will fall within the guidance ranges. Please refer to information under the caption “Forward-Looking Statements” included in this document. These risks and uncertainties, as well as other unforeseeable risks and uncertainties, could cause our actual results to differ materially from those in the following table. The operating and financial guidance provided in the following pages is given as of the date hereof, based on information known to us as of May 3, 2016. We undertake no obligation to publicly update or revise any forward-looking statements.

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. 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 in conjunction with related GAAP financial measures, (i) provide additional information about our core operating performance and ability to generate and distribute cash flow, (ii) provide investors with the financial analytical framework upon which management bases financial, operational, compensation and planning decisions and (iii) present measurements that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations. EBITDA (as defined in Note 1 to the “Operating and Financial Guidance” table) is a non-GAAP financial measure. Net income represents one of the two most directly comparable GAAP measures to EBITDA. In Note 10, we reconcile net income to EBITDA and adjusted EBITDA for the 2016 guidance periods presented. Cash flows from operating activities is the other most comparable GAAP measure. We do not, however, reconcile cash flows from operating activities to EBITDA, because such reconciliations are impractical for forecasted periods. 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 historical reconciliation of EBITDA as well as certain other commonly used non-GAAP and supplemental financial measures. These measures may exclude, for example, (i) charges for obligations that are expected to be settled with the issuance of equity instruments, (ii) the mark-to-market of derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), 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” in our Condensed Consolidated Financial Statements. Such amounts are presented net of applicable amounts subsequently recognized into revenue. 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 consider an understanding of these selected items impacting comparability to be material to the evaluation of our operating results and prospects.

Plains All American Pipeline, L.P.

Operating and Financial Guidance

(in millions, except per unit data)

	Actual			Guidance (a)
	3 Months			3 Months Ending						6 Months Ending						12 Months Ending
	Ended			Jun 30, 2016						Dec 31, 2016						Dec 31, 2016
	Mar 31, 2016			Low			High			Low			High			Low			High
Segment Profit
Net revenues (including equity earnings in unconsolidated entities)	$	810		$	801		$	841		$	1,812		$	1,892		$	3,423		$	3,543
Field operating costs	(300		)	(320		)	(312		)	(634		)	(619		)	(1,254		)	(1,231		)
General and administrative expenses	(67		)	(71		)	(69		)	(137		)	(132		)	(275		)	(268		)
	443			410			460			1,041			1,141			1,894			2,044
Depreciation and amortization expense	(114		)	(131		)	(127		)	(223		)	(215		)	(468		)	(456		)
Interest expense, net	(112		)	(113		)	(109		)	(226		)	(218		)	(451		)	(439		)
Income tax expense	(19		)	(11		)	(7		)	(60		)	(52		)	(90		)	(78		)
Other income / (expense), net	5			—			—			—			—			5			5
Net Income	203			155			217			532			656			890			1,076
Net income attributable to noncontrolling interests	(1		)	(1		)	(1		)	(2		)	(2		)	(4		)	(4		)
Net Income Attributable to PAA	$	202		$	154		$	216		$	530		$	654		$	886		$	1,072

Net income/(loss) attributable to common unitholders (b)	$	28		$	(29	)	$	32		$	157		$	278		$	156		$	338
Basic net income/(loss) per common unit (b)
Weighted average common units outstanding	398			398			398			398			398			398			398
Net income/(loss) per common unit	$	0.07		$	(0.07	)	$	0.08		$	0.39		$	0.70		$	0.39		$	0.85

Diluted net income/(loss) per common unit(b)(c)
Weighted average common units outstanding (c)	399			399			399			399			399			399			399
Net income/(loss) per common unit	$	0.07		$	(0.07	)	$	0.08		$	0.39		$	0.70		$	0.39		$	0.85

EBITDA	$	448		$	410		$	460		$	1,041		$	1,141		$	1,899		$	2,049

Selected items impacting comparability
Gains/(losses) from derivative activities net of inventory valuation adjustments	$	(122	)	$	—		$	—		$	—		$	—		$	(122	)	$	(122	)
Deficiencies under minimum volume commitments, net	(27		)	3			3			(13		)	(13		)	(37		)	(37		)
Long-term inventory costing adjustments	(23		)	—			—			—			—			(23		)	(23		)
Equity-indexed compensation expense	(4		)	(8		)	(8		)	(10		)	(10		)	(22		)	(22		)
Net gain/(loss) on foreign currency revaluation	3			—			—			—			—			3			3
Tax effect on selected items impacting comparability	20			—			—			—			—			20			20
Selected items impacting comparability of net income attributable to PAA	$	(153	)	$	(5	)	$	(5	)	$	(23	)	$	(23	)	$	(181	)	$	(181	)


Excluding selected items impacting comparability
Adjusted segment profit
Transportation	$	269		$	244		$	259		$	572		$	602		$	1,085		$	1,130
Facilities	167			143			153			301			321			611			641
Supply and Logistics	184			28			53			191			241			403			478
Other income / (expense), net	1			—			—			—			—			1			1
Adjusted EBITDA	$	621		$	415		$	465		$	1,064		$	1,164		$	2,100		$	2,250
Adjusted net income attributable to PAA	$	355		$	159		$	221		$	553		$	677		$	1,067		$	1,253
Basic adjusted net income/(loss) per common unit (b)	$	0.45		$	(0.06	)	$	0.09		$	0.45		$	0.76		$	0.84		$	1.30
Diluted adjusted net income/(loss) per common unit (b)(c)	$	0.45		$	(0.06	)	$	0.09		$	0.45		$	0.75		$	0.84		$	1.29

(a) The assumed average foreign exchange rate is $1.30 Canadian dollar (CAD) to $1.00 U.S. dollar (USD) for the three-month period ending June 30, 2016 and the six-month period ending December 31, 2016. The rate as of May 3, 2016 was $1.27 CAD to $1.00 USD. We do not anticipate that fluctuations in the foreign exchange rate will have significant impact on aggregate reported financial results, but such fluctuations will result in variations between segments.

(b) We allocate Net Income Attributable to PAA among our Series A Preferred Unitholders, Common Unitholders and General Partner interest using the two-class method in accordance with applicable authoritative accounting guidance. Under the two-class method, we allocate Net Income Attributable to PAA based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner, common unitholders and participating securities in accordance with the contractual terms of the partnership agreement and as further prescribed under the two-class method.

(c) Diluted net income per common unit is computed based on the weighted average number of common units outstanding plus the effect of dilutive potential units outstanding during the period using the two-class method, unless the effects of such units are anti-dilutive.

Notes and Significant Assumptions:

1. Definitions.

EBITDA	Earnings before interest, taxes and depreciation and amortization
Segment Profit	Net revenues (including equity earnings in unconsolidated entities, as applicable) less segment field operating costs and general and administrative expenses
DCF	Distributable cash flow
Bbls/d	Barrels per day
Mcf Bcf	Thousand cubic feet Billion cubic feet
LTIP	Long-term incentive plan
NGL	Natural gas liquids, including ethane and natural gasoline products as well as propane and butane, which are often referred to as liquefied petroleum gas (LPG). When used in this document NGL refers to all NGL products including LPG.
FX	Foreign currency exchange
G&A	General and administrative
General partner (GP)	As the context requires, “general partner” or “GP” refers to any or all of (i) PAA GP LLC, the owner of our 2% general partner interest, (ii) Plains AAP, L.P., the sole member of PAA GP LLC and owner of our incentive distribution rights and (iii) Plains All American GP LLC, the general partner of Plains AAP, L.P.

2. Operating Segments. We manage our operations through three operating segments: Transportation, Facilities and Supply and Logistics. The following is a brief explanation of the operating activities for each segment as well as key metrics.

a. Transportation. Our Transportation segment operations generally consist of fee-based activities associated with transporting crude oil and NGL on pipelines, gathering systems, trucks and barges. The Transportation segment generates revenue through a combination of tariffs, third-party pipeline capacity agreements and other transportation fees. Our transportation segment also includes equity earnings from our investments in the entities that own BridgeTex, Eagle Ford, Frontier, Saddlehorn, White Cliffs, and Butte pipeline systems as well as Settoon Towing, in which we own interests ranging from 22% to 50%. We account for these investments under the equity method of accounting.

Pipeline volume estimates are based on historical trends, anticipated future operating performance and assumed completion of capital projects. Actual volumes will be influenced by maintenance schedules at refineries, drilling and completion activity levels, production trends, weather and other natural occurrences including hurricanes, changes in the quantity of inventory held in tanks, variations due to market structure and other external factors beyond our control. We forecast adjusted segment profit using the volume assumptions in the following table, priced at forecasted tariff rates, less estimated field operating costs and G&A expenses. Field operating costs do not include depreciation. Actual adjusted segment profit could vary materially depending on the level and mix of volumes transported or expenses incurred during the period, as well as any differences between forecasted and actual recognition of minimum ship or pay commitments. The following table summarizes our total transportation volumes and is broken down by crude oil geographic area as well as total NGL and trucking volumes.

	Actual		Guidance
	Three Months		Three Months			Six Months			Twelve Months
	Ended		Ending			Ending			Ending
	Mar 31, 2016		Jun 30, 2016			Dec 31, 2016			Dec 31, 2016
Average daily volumes (MBbls/d)
Volumes from tariff activities
Crude oil pipelines (by region):
Permian Basin (1)	2,045		2,180			2,300			2,207
South Texas / Eagle Ford (1)	313		285			300			300
Western	175		195			240			212
Rocky Mountain (1)	437		435			450			443
Gulf Coast	581		615			385			491
Central	379		380			400			390
Canada	394		390			395			393
Crude oil pipelines	4,324		4,480			4,470			4,436
NGL pipelines	178		155			175			171
Total volumes from tariff activities	4,502		4,635			4,645			4,607
Trucking	106		135			135			128
Total Transportation segment volumes	4,608		4,770			4,780			4,735

Adjusted segment profit per barrel ($/Bbl)	$	0.64	$	0.58	(2)	$	0.67	(2)	$	0.64	(2)

Adjusted segment profit (excluding MVC selected item) per barrel ($/Bbl)	$	0.59	$	0.59	(2)	$	0.65	(2)	$	0.62	(2)

(1) Region includes volumes (attributable to our interest) from pipelines owned by unconsolidated entities.

(2) Represents the midpoint of guidance.

b. Facilities. Our Facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services for crude oil, refined products, NGL and natural gas, as well as NGL fractionation and isomerization services and natural gas and condensate processing services. The Facilities segment generates revenue through a combination of month-to-month and multi-year agreements and processing arrangements.

Revenues generated in this segment primarily include (i) fees that are generated from storage capacity agreements, (ii) terminal throughput fees that are generated when we receive crude oil, refined products or NGL from one connecting source and deliver the applicable product to another connecting carrier, (iii) loading and unloading fees at our rail terminals, (iv) fees from NGL fractionation and isomerization services, (v) fees from natural gas and condensate processing services and (vi) fees associated with natural gas park and loan activities, interruptible storage services and wheeling and balancing services. Adjusted segment profit is forecasted using the volume assumptions in the following table, priced at forecasted rates, less estimated field operating costs and G&A expenses. Field operating costs do not include depreciation.

	Actual		Guidance
	Three Months		Three Months			Six Months			Twelve Months
	Ended		Ending			Ending			Ending
	Mar 31, 2016		Jun 30, 2016			Dec 31, 2016			Dec 31, 2016
Operating Data
Crude oil, refined products and NGL terminalling and storage capacity (MMBbls/Mo.)	105		105			108			107
Rail load / unload volumes (MBbls/d)	91		140			95			105
Natural gas storage capacity (Bcf/Mo.)	97		97			97			97
NGL fractionation volumes (MBbls/d)	115		105			120			115
Total Facilities segment volumes
Avg. Capacity (MMBbls/Mo.) (1)	127		129			131			130

Adjusted segment profit per barrel ($/Bbl)	$	0.44	$	0.38	(2)	$	0.40	(2)	$	0.40	(2)

Adjusted segment profit (excluding MVC selected item) per barrel ($/Bbl)	$	0.42	$	0.38	(2)	$	0.40	(2)	$	0.40	(2)

(1) 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.

(2) Represents the midpoint of guidance.

c. Supply and Logistics. Our Supply and Logistics segment operations generally consist of the following merchant-related activities:

· the purchase of U.S. and Canadian crude oil at the wellhead, the bulk purchase of crude oil at pipeline, terminal and rail facilities and the purchase of cargos at their load port and various other locations in transit;

· the storage of inventory during contango market conditions and the seasonal storage of NGL and natural gas;

· the purchase of NGL from producers, refiners, processors and other marketers;

· the resale or exchange of crude oil and NGL at various points along the distribution chain to refiners or other resellers;

· the transportation of crude oil and NGL on trucks, barges, railcars, pipelines and ocean-going vessels from various delivery points, market hub locations or directly to end users such as refineries, processors and fractionation facilities; and

· the purchase and sale of natural gas.

We characterize a substantial portion of our baseline profit generated by our Supply and Logistics segment as fee equivalent. This portion of the segment profit is generated by the purchase and resale of crude oil on an index-related basis, which results in us generating a gross margin for such activities. This gross margin is reduced by the transportation, facilities and other logistical costs associated with delivering the crude oil to market and carrying costs for hedged inventory as well as any operating and G&A expenses. The level of profit associated with a portion of the other activities we conduct in the Supply and Logistics segment is influenced by overall market structure and the degree of market volatility as well as variable operating expenses. Forecasted operating results for the three-month period ending June 30, 2016 and for the six-month period ending December 31, 2016 reflect current market structure as well as seasonal, weather-related and other anticipated variations in crude oil, NGL and natural gas sales. Variations in weather, market structure or volatility could cause actual results to differ materially from forecasted results.

We forecast adjusted segment profit using the volume assumptions stated below, as well as estimates of unit margins, field operating costs, G&A expenses and carrying costs for hedged inventory, based on current and anticipated market conditions. Actual volumes are influenced by temporary market-driven storage and withdrawal of crude oil, maintenance schedules at refineries, actual production levels, weather, and other external factors beyond our control. Field operating costs do not include depreciation. Realized unit margins for any given lease-gathered barrel could vary significantly based on a variety of factors including location and quality differentials as well as contract structure. Accordingly, the projected adjusted segment profit per barrel can vary significantly even if aggregate volumes are in line with the forecasted levels.

	Actual		Guidance
	Three Months		Three Months			Six Months			Twelve Months
	Ended		Ending			Ending			Ending
	Mar 31, 2016		Jun 30, 2016			Dec 31, 2016			Dec 31, 2016
Average daily volumes (MBbls/d)
Crude oil lease gathering purchases	913		895			935			920
NGL sales	308		170			285			262
Waterborne cargos	7		5			—			3
Total Supply and Logistics segment volumes	1,228		1,070			1,220			1,185

Adjusted segment profit per barrel ($/Bbl)	$	1.65	$	0.42	(1)	$	0.96	(1)	$	1.02	(1)

(1) Represents the midpoint of guidance.

3. Depreciation and Amortization. We forecast depreciation and amortization based on our existing depreciable assets, forecasted capital expenditures and projected in-service dates. Depreciation may also vary due to gains and losses on intermittent sales of assets, asset retirement obligations, asset impairments, and acceleration of depreciation or foreign exchange rates.

4. Capital Expenditures and Acquisitions. Although acquisitions constitute a key element of our growth strategy, the forecasted results and associated estimates do not include any forecasts for acquisitions that we may commit to after the date hereof (the forecast does include the announced Empress acquisition that is expected to close during the second quarter of 2016). We forecast capital expenditures during calendar year 2016 to be approximately $1.5 billion for expansion projects with an additional $190 million to $210 million for maintenance capital projects. During the first three months of 2016, we invested $370 million and $47 million for expansion and maintenance projects, respectively. The following are some of the more notable projects and forecasted expenditures for the year ending December 31, 2016:

		Calendar 2016
		(in millions)
Expansion Capital
• Red River Pipeline (Cushing to Longview)		$285
• Diamond Pipeline		235
• Permian Basin Area Pipeline Projects		210
• Fort Saskatchewan Facility Projects		190
• Saddlehorn Pipeline		150
• Cushing Terminal Expansions		70
• St. James Terminal Expansions		45
• Caddo Pipeline		30
• Cactus Pipeline		20
• Eagle Ford JV Project		20
• Other Projects		245
		$1,500
Potential Adjustments for Timing / Scope Refinement (1)		- $100 + $100
Total Projected Expansion Capital Expenditures		$1,400 - $1,600

Maintenance Capital Expenditures		$190 - $210

(1) Potential variation to current capital costs estimates may result from (i) changes to project design, (ii) final cost of materials and labor and (iii) timing of incurrence of costs due to uncontrollable factors such as receipt of permits, or regulatory approvals and weather.

5. Asset Sales. This guidance takes into account the sale of non-core assets for aggregate total proceeds of $500 million to $600 million for the full year 2016. We do not expect that in the aggregate any net gain or loss from these asset sales will be material and thus, we have not included any such estimate in our guidance.

6. Capital Structure. This guidance is based on our capital structure as of March 31, 2016.

7. Interest Expense. Debt balances are projected based on estimated cash flows, estimated distribution rates, estimated capital expenditures for maintenance and expansion projects, anticipated equity proceeds from the continuous offering program, expected timing of collections and payments and forecasted levels of inventory and other working capital sources and uses. Interest rate assumptions for variable-rate debt are based on the LIBOR curve as of late April 2016.

Interest expense is net of amounts capitalized for expansion capital projects and does not include interest on borrowings for hedged inventory. We treat interest on hedged inventory borrowings as carrying costs of crude oil, NGL, and natural gas and include it in purchases and related costs.

8. Income Taxes. We expect our Canadian income tax expense to be approximately $9 million and $84 million for the three-month period ending June 30, 2016 and twelve-month period ending December 31, 2016, respectively, of which approximately $4 million and $74 million, respectively, is classified as a current income tax expense. For the twelve-month period ending December 31, 2016 we expect to have a deferred tax expense of $10 million. All or part of the annual income tax expense of $84 million may result in a tax credit to our equity holders.

9. Equity-Indexed Compensation Plans. The majority of grants outstanding under our various equity-indexed compensation plans contain vesting criteria that are based on a combination of performance benchmarks and service periods. The grants will vest in various percentages, typically on the later to occur of specified vesting dates and the dates on which minimum distribution levels are reached.

Guidance assumes a market price of $21 per unit as well as an accrual associated with awards that will vest on a certain date. A $2 change in the unit price would change the second-quarter and full year equity-indexed compensation expense by approximately $4 million. Therefore, actual net income could differ from our projections.

10. Reconciliation of Net Income to EBITDA and Adjusted EBITDA. The following table reconciles net income to EBITDA and Adjusted EBITDA for the indicated periods.

	Actual		Guidance
	3 Months		3 Months Ending				6 Months Ending				12 Months Ending
	Ended		Jun 30, 2016				Dec 31, 2016				Dec 31, 2016
	Mar 31, 2016		Low		High		Low		High		Low		High
	(in millions)
Reconciliation to EBITDA and Adjusted EBITDA
Net income	$	203	$	155	$	217	$	532	$	656	$	890	$	1,076
Interest expense, net	112		113		109		226		218		451		439
Income tax expense	19		11		7		60		52		90		78
Depreciation and amortization	114		131		127		223		215		468		456
EBITDA	$	448	$	410	$	460	$	1,041	$	1,141	$	1,899	$	2,049

Selected items impacting comparability of EBITDA	173		5		5		23		23		201		201
Adjusted EBITDA	$	621	$	415	$	465	$	1,064	$	1,164	$	2,100	$	2,250

11. Implied DCF. The following table reconciles adjusted EBITDA to implied DCF for the indicated periods.

	Actual			Mid-Point Guidance
	Three Months			Three Months			Six Months			Twelve Months
	Ended			Ending			Ending			Ending
	Mar 31, 2016			Jun 30, 2016			Dec 31, 2016			Dec 31, 2016
	(in millions)
Adjusted EBITDA	$	621		$	440		$	1,114		$	2,175
Interest expense, net (1)	(108		)	(107		)	(214		)	(429		)
Maintenance capital	(47		)	(51		)	(102		)	(200		)
Current income tax expense	(31		)	(4		)	(39		)	(74		)
Other, net	4			7			10			21
Implied DCF	$	439		$	285		$	769		$	1,493

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

Forward-Looking Statements

All statements included in this report, other than statements of historical fact, are forward-looking statements, including, but not limited to, statements incorporating the words “anticipate,” “believe,” “estimate,” “expect,” “plan,” “intend” and “forecast,” as well as similar expressions and statements regarding our business strategy, plans and objectives for future operations. The absence of such words, expressions or statements, however, does not mean that the statements are not forward-looking. Any such forward-looking statements reflect our current views with respect to future events, based on what we believe to be reasonable assumptions. Certain factors could cause actual results or outcomes to differ materially from the results or outcomes anticipated in the forward-looking statements. The most important of these factors include, but are not limited to:

· declines in the volume of crude oil, refined product and NGL shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of our assets, whether due to declines in production from existing oil and gas reserves, 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;

· failure to implement or capitalize, or delays in implementing or capitalizing, on expansion projects;

· unanticipated changes in crude oil market structure, grade differentials and volatility (or lack thereof);

· environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;

· 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 or other event, including attacks on our electronic and computer systems;

· maintenance of our credit rating and ability to receive open credit from our suppliers and trade counterparties;

· 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 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 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 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.

We undertake no obligation to publicly update or revise any forward-looking statements. Further information on risks and uncertainties is available in our filings with the Securities and Exchange Commission, which information is incorporated by reference herein.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	PLAINS ALL AMERICAN PIPELINE, L.P.

	By:	PAA GP LLC, its general partner

	By:	PLAINS AAP, L. P., its sole member

	By:	PLAINS ALL AMERICAN GP LLC, its general partner

Date: May 4, 2016	By:	/s/ Sharon Spurlin
		Name:	Sharon Spurlin
		Title:	Vice President and Treasurer

EX-99.1 2 a16-10112_1ex99d1.htm EX-99.1

Exhibit 99.1

FOR IMMEDIATE RELEASE

Plains All American Pipeline, L.P. and Plains GP Holdings Report First-Quarter 2016 Results

(Houston — May 4, 2016) Plains All American Pipeline, L.P. (NYSE: PAA) and Plains GP Holdings (NYSE: PAGP) today reported first-quarter 2016 results.

Plains All American Pipeline, L.P.

Summary Financial Information (1) (unaudited)

(in millions, except per unit data)

	Three Months Ended
	March 31,				%
	2016		2015		Change
Net income attributable to PAA	$	202	$	283	(29)%

Diluted net income per common unit	$	0.07	$	0.35	(80)%

Diluted weighted average common units outstanding	399		385		4%

EBITDA	$	448	$	509	(12)%

	Three Months Ended
	March 31,				%
	2016		2015		Change
Adjusted net income attributable to PAA	$	355	$	369	(4)%

Diluted adjusted net income per common unit	$	0.45	$	0.57	(21)%

Adjusted EBITDA	$	621	$	622	—%

Distribution per common unit declared for the period	$	0.700	$	0.685	2.2%

(1) PAA’s reported results include the impact of items that affect comparability between reporting periods. The impact of certain of these items is excluded from adjusted results. 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.

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“PAA reported first-quarter adjusted EBITDA of $621 million, which was approximately $51 million or 9% above the midpoint of our first-quarter guidance,” said Greg Armstrong, Chairman and CEO of Plains All American. “PAA’s results reflect a combination of performance above expectations, the inclusion of deficiency amounts for ship or pay obligations that have been billed or collected, and some timing related items expected to reverse later in the year.”

Armstrong added, “We are cautious over the near term as recent drilling and completion activity is meaningfully below levels of just a few months ago and what we anticipated in our initial 2016 guidance. These lower activity levels are starting to impact U.S. oil production and, accordingly, we are revising our full-year 2016 midpoint guidance for adjusted EBITDA downward by approximately 4% to $2.175 billion.

Importantly, PAA ended the first quarter of 2016 with $3.8 billion of committed liquidity and an improved balance sheet as a result of the $1.6 billion preferred equity offering completed in January. We believe PAA is well positioned to manage through near-term challenges and to prosper over the intermediate to long term as the industry recovers.”

The following table summarizes selected PAA financial information by segment for the first quarter of 2016:

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

(in millions)

	Three Months Ended									Three Months Ended
	March 31, 2016									March 31, 2015
	Transportation			Facilities			Supply and Logistics			Transportation		Facilities		Supply and Logistics
Reported segment profit	$	247		$	159		$	37		$	241	$	142	$	130
Selected items impacting comparability of segment profit (2)	22			8			147			5		2		101
*Adjusted segment profit*	$	*269*		$	*167*		$	*184*		$	*246*	$	*144*	$	*231*
*Percentage change in adjusted segment profit versus 2015 period*	9		%	16		%	*(20*		)%

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

First-quarter 2016 Transportation adjusted segment profit increased 9% over comparable 2015 results. This increase was primarily driven by higher crude oil pipeline volumes associated with our Cactus pipeline, which was placed into service in April 2015, and the expansion of our pipeline system in the Delaware Basin. Such increases were partially offset by lower pipeline loss allowance revenues.

First-quarter 2016 Facilities adjusted segment profit increased by 16% over comparable 2015 results. This increase was primarily due to an increase in capacity and higher utilization of our crude oil storage facilities and lower operating expenses.

First-quarter 2016 Supply and Logistics adjusted segment profit decreased by 20% as compared to 2015 results. This decrease was primarily driven by lower volumes and margins associated with our U.S. crude oil lease gathering due to crude oil production declines in certain basins and the resulting increase in competitive pressures for lease gathered barrels as well as lower margins from our NGL sales activities. Such decreases were partially offset by the benefit of contango storage opportunities.

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Plains GP Holdings

PAGP’s sole assets are its ownership interest in PAA’s general partner and incentive distribution rights. 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:

	Q1 2016		Q4 2015			Q1 2015
Distribution per Class A share declared for the period	$	0.231	$	0.231		$	0.222
Q1 2016 distribution percentage growth from prior periods			—		%	4.1		%

Conference Call

PAA and PAGP will hold a conference call on May 5, 2016 (see details below). Prior to this conference call, PAA will furnish a current report on Form 8-K, which will include material in this news release as well as PAA’s financial and operational guidance for the second quarter and full year of 2016. A copy of the Form 8-K will be available at www.plainsallamerican.com, where PAA and PAGP routinely post important information.

The PAA and PAGP conference call will be held at 11:00 a.m. ET on Thursday, May 5, 2016 to discuss the following items:

1. PAA’s first-quarter 2016 performance;

2. The status of major expansion projects;

3. Capitalization and liquidity;

4. Financial and operating guidance for the second quarter and full year of 2016; and

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

Conference Call Access Instructions

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

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Non-GAAP Financial Measures and Selected Items Impacting Comparability

To supplement our financial information presented in accordance with GAAP, management uses additional measures that are known as “non-GAAP financial measures” (such as adjusted EBITDA and implied distributable cash flow (“DCF”)) in its evaluation of past performance and prospects for the future. 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 in conjunction with related GAAP financial measures, (i) provide additional information about our core operating performance and ability to generate and distribute cash flow, (ii) provide investors with the financial analytical framework upon which management bases financial, operational, compensation and planning decisions and (iii) present measurements that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations. These measures may exclude, for example, (i) charges for obligations that are expected to be settled with the issuance of equity instruments, (ii) the mark-to-market of derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), 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” in our Condensed Consolidated Financial Statements. Such amounts are presented net of applicable amounts subsequently recognized into revenue. 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 consider an understanding of these selected items impacting comparability to be material to the evaluation of our operating results and prospects.

Although we present selected items that we consider 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 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.

Adjusted EBITDA and other non-GAAP financial measures are reconciled to the most comparable measures as reported in accordance with GAAP for the 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, PAA maintains on its website (www.plainsallamerican.com) a reconciliation of adjusted EBITDA and certain commonly used non-GAAP financial information to the most comparable GAAP measures. To access the information, investors should click on “PAA” under the “Investor Relations” tab on the home page, select the “Financial Information” tab and navigate to the “Non-GAAP Reconciliations” link.

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Forward Looking Statements

Except for the historical information contained herein, the matters discussed in this release consist of forward-looking statements that involve certain risks and uncertainties that could cause actual results or outcomes to differ materially from results or outcomes anticipated in the forward-looking statements. These risks and uncertainties include, among other things, declines in the volume of crude oil, refined product and NGL shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of our assets, whether due to declines in production from existing oil and gas reserves, 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; failure to implement or capitalize, or delays in implementing or capitalizing, on expansion projects; unanticipated changes in crude oil market structure, grade differentials and volatility (or lack thereof); environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves; 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 or other event, including attacks on our electronic and computer systems; maintenance of our credit rating and ability to receive open credit from our suppliers and trade counterparties; 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 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 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 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.

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Plains All American Pipeline, L.P. is a publicly traded master limited partnership that owns and operates midstream energy infrastructure and provides logistics services for crude oil, natural gas liquids (“NGL”), natural gas and refined products. PAA owns an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins and transportation corridors and at major market hubs in the United States and Canada. On average, PAA handles over 4.6 million barrels per day of crude oil and NGL in its Transportation segment. PAA is headquartered in Houston, Texas.

Plains GP Holdings is a publicly traded entity that owns an interest in the general partner and incentive distribution rights of Plains All American Pipeline, L.P., one of the largest energy infrastructure and logistics companies in North America. PAGP is headquartered in Houston, Texas.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (1)

(in millions, except per unit data)

	Three Months Ended
	March 31,
	2016			2015

REVENUES	$	4,111		$	5,942

COSTS AND EXPENSES
Purchases and related costs	3,348			5,042
Field operating costs	300			346
General and administrative expenses	67			78
Depreciation and amortization	114			104
Total costs and expenses	3,829			5,570

OPERATING INCOME	282			372

OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	47			37
Interest expense, net	(112		)	(105		)
Other income/(expense), net	5			(4		)

INCOME BEFORE TAX	222			300
Current income tax expense	(31		)	(42		)
Deferred income tax benefit	12			26

NET INCOME	203			284
Net income attributable to noncontrolling interests	(1		)	(1		)
NET INCOME ATTRIBUTABLE TO PAA	$	202		$	283

NET INCOME PER COMMON UNIT:
Net income attributable to common unitholders — Basic	$	28		$	136
Basic weighted average common units outstanding	398			383
Basic net income per common unit	$	0.07		$	0.36

Net income attributable to common unitholders — Diluted	$	28		$	136
Diluted weighted average common units outstanding	399			385
Diluted net income per common unit	$	0.07		$	0.35

(1) The 2015 periods have been retroactively adjusted to reflect the reclassification of the amortization of debt issuance costs from “Depreciation and amortization” to “Interest expense, net” as a result of our adoption of revised debt issuance costs guidance issued by the FASB.

ADJUSTED RESULTS

(in millions, except per unit data)

	Three Months Ended
	March 31,
	2016		2015

ADJUSTED NET INCOME ATTRIBUTABLE TO PAA	$	355	$	369

DILUTED ADJUSTED NET INCOME PER COMMON UNIT	$	0.45	$	0.57

ADJUSTED EBITDA	$	621	$	622

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

CONDENSED CONSOLIDATED BALANCE SHEET DATA

(in millions)

	March 31,		December 31,
	2016		2015
ASSETS
Current assets	$	2,780	$	2,969
Property and equipment, net	13,670		13,474
Goodwill	2,405		2,405
Investments in unconsolidated entities	2,097		2,027
Linefill and base gas	899		898
Long-term inventory	112		129
Other long-term assets, net	334		386
Total assets	$	22,297	$	22,288

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	3,063	$	3,407
Senior notes, net of unamortized discounts and debt issuance costs	9,126		9,698
Other long-term debt	27		677
Other long-term liabilities and deferred credits	710		567
Total liabilities	12,926		14,349

Partners’ capital excluding noncontrolling interests	9,313		7,881
Noncontrolling interests	58		58
Total partners’ capital	9,371		7,939
Total liabilities and partners’ capital	$	22,297	$	22,288

DEBT CAPITALIZATION RATIOS

(in millions)

	March 31,			December 31,
	2016			2015
Short-term debt	$	715		$	999
Long-term debt	9,153			10,375
Total debt	$	9,868		$	11,374

Long-term debt	$	9,153		$	10,375
Partners’ capital	9,371			7,939
Total book capitalization	$	18,524		$	18,314
Total book capitalization, including short-term debt	$	19,239		$	19,313

Long-term debt-to-total book capitalization	49		%	57		%
Total debt-to-total book capitalization, including short-term debt	51		%	59		%

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

SELECTED FINANCIAL DATA BY SEGMENT

(in millions)

	Three Months Ended									Three Months Ended
	March 31, 2016									March 31, 2015
							Supply and									Supply and
	Transportation			Facilities			Logistics			Transportation			Facilities			Logistics
Revenues (1)	$	383		$	265		$	3,821		$	400		$	257		$	5,634
Purchases and related costs (1)	(21		)	(5		)	(3,677		)	(30		)	(4		)	(5,353		)
Field operating costs (1) (2)	(137		)	(85		)	(81		)	(136		)	(91		)	(118		)
Equity-indexed compensation expense - operations	—			—			—			(3		)	(1		)	(1		)
Segment general and administrative expenses (2) (3)	(23		)	(15		)	(25		)	(22		)	(15		)	(27		)
Equity-indexed compensation expense - general and administrative	(2		)	(1		)	(1		)	(5		)	(4		)	(5		)
Equity earnings in unconsolidated entities	47			—			—			37			—			—
Reported segment profit	$	247		$	159		$	37		241			142			130
Selected items impacting comparability of segment profit (4)	22			8			147			5			2			101
Adjusted segment profit	$	269		$	167		$	184		$	246		$	144		$	231

Maintenance capital	$	35		$	9		$	3		$	33		$	15		$	2

(1) Includes intersegment amounts.

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

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

OPERATING DATA (1)

	Three Months Ended
	March 31,
	2016	2015

Transportation segment (average daily volumes in thousands of barrels per day):
Volumes from tariff activities
Crude oil pipelines (by region):
Permian Basin (2)	2,045	1,658
South Texas / Eagle Ford (2)	313	263
Western	175	268
Rocky Mountain (2)	437	453
Gulf Coast	581	441
Central	379	435
Canada	394	414
Crude oil pipelines	4,324	3,932
NGL pipelines	178	191
Total volumes from tariff activities	4,502	4,123
Trucking	106	121
Transportation segment total volumes	4,608	4,244

Facilities segment (average monthly volumes):
Crude oil, refined products and NGL terminalling and storage (average monthly capacity in millions of barrels)	105	99
Rail load / unload volumes (average volumes in thousands of barrels per day)	91	206
Natural gas storage (average monthly working capacity in billions of cubic feet)	97	97
NGL fractionation (average volumes in thousands of barrels per day)	115	102
Facilities segment total volumes (average monthly volumes in millions of barrels) (3)	127	124

Supply and Logistics segment (average daily volumes in thousands of barrels per day):
Crude oil lease gathering purchases	913	981
NGL sales	308	286
Waterborne cargos	7	—
Supply and Logistics segment total volumes	1,228	1,267

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

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

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

COMPUTATION OF BASIC AND DILUTED NET INCOME PER COMMON UNIT

(in millions, except per unit data)

	Three Months Ended
	March 31,
	2016			2015
Basic Net Income per Common Unit
Net income attributable to PAA	$	202		$	283
Less: Distributions to Series A preferred units (1)	(23		)	—
Less: Distributions to general partner (1)	(155		)	(148		)
Less: Distributions to participating securities (1)	(1		)	(2		)
Less: Undistributed loss allocated to general partner (1)	5			3
Net income attributable to common unitholders in accordance with application of the two-class method for MLPs	$	28		$	136

Basic weighted average common units outstanding	398			383

Basic net income per common unit	$	0.07		$	0.36

Diluted Net Income per Common Unit
Net income attributable to PAA	$	202		$	283
Less: Distributions to Series A preferred units (1)	(23		)	—
Less: Distributions to general partner (1)	(155		)	(148		)
Less: Distributions to participating securities (1)	(1		)	(2		)
Less: Undistributed loss allocated to general partner (1)	5			3
Net income attributable to common unitholders in accordance with application of the two-class method for MLPs	$	28		$	136

Basic weighted average common units outstanding	398			383
Effect of dilutive securities: Weighted average LTIP units (2)	1			2
Diluted weighted average common units outstanding	399			385

Diluted net income per common unit (3)	$	0.07		$	0.35

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

(2) Our Long-term Incentive Plan (“LTIP”) awards that contemplate the issuance of common units are considered dilutive unless (i) vesting occurs only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards that are deemed to be dilutive are reduced by a hypothetical unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB.

(3) The Series A preferred units were excluded from the calculation of diluted net income per common unit as the effect was antidilutive.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

SELECTED ITEMS IMPACTING COMPARABILITY

(in millions, except per unit data)

	Three Months Ended
	March 31,
	2016			2015
Selected Items Impacting Comparability (1):
Gains/(losses) from derivative activities net of inventory valuation adjustments (2)	$	(122	)	$	(91	)
Deficiencies under minimum volume commitments, net (3)	(27		)	—
Long-term inventory costing adjustments (4)	(23		)	(38		)
Equity-indexed compensation expense (5)	(4		)	(11		)
Net gain on foreign currency revaluation	3			27
Tax effect on selected items impacting comparability	20			27
Selected items impacting comparability of net income attributable to PAA	$	(153	)	$	(86	)

Impact to basic net income per common unit	$	(0.38	)	$	(0.22	)
Impact to diluted net income per common unit	$	(0.38	)	$	(0.22	)

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

(2) Includes mark-to-market and other gains and losses resulting from derivative instruments that are related to underlying activities in another period (or the reversal of mark-to-market gains and losses from a prior period), gains and losses on derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable.

(3) Includes the impact of amounts billed to counterparties for their deficiency obligation under agreements with minimum volume commitments, net of applicable amounts subsequently recognized into revenue.

(4) Includes the impact of changes in the average cost of long-term inventory that result from fluctuations in market prices and writedowns of such inventory that result from price declines. Long-term inventory consists of minimum working inventory requirements in third-party assets and other working inventory 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).

(5) Includes equity-indexed compensation expense associated with LTIP awards that will or may be settled in units, as the dilutive impact of these outstanding awards is included in our diluted net income per unit calculation and the majority of these awards are expected to be settled in units.

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333 Clay Street, Suite 1600 Houston, Texas 77002 713-646-4100 / 866-809-1291

Page 13

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

COMPUTATION OF ADJUSTED BASIC AND DILUTED NET INCOME PER COMMON UNIT

(in millions, except per unit data)

	Three Months Ended
	March 31,
	2016			2015
Basic Adjusted Net Income per Common Unit
Net income attributable to PAA	$	202		$	283
Selected items impacting comparability of net income attributable to PAA (1)	153			86
Adjusted net income attributable to PAA	355			369
Less: Distributions to Series A preferred units (2)	(23		)	—
Less: Distributions to general partner (2)	(155		)	(148		)
Less: Distributions to participating securities (2)	(1		)	(2		)
Less: Undistributed loss allocated to general partner (2)	3			1
Adjusted net income attributable to common unitholders in accordance with application of the two-class method for MLPs	$	179		$	220

Basic weighted average common units outstanding	398			383

Basic adjusted net income per common unit	$	0.45		$	0.58

Diluted Adjusted Net Income per Common Unit
Net income attributable to PAA	$	202		$	283
Selected items impacting comparability of net income attributable to PAA (1)	153			86
Adjusted net income attributable to PAA	355			369
Less: Distributions to Series A preferred units (2)	(23		)	—
Less: Distributions to general partner (2)	(155		)	(148		)
Less: Distributions to participating securities (2)	(1		)	(2		)
Less: Undistributed loss allocated to general partner (2)	3			1
Adjusted net income attributable to common unitholders in accordance with application of the two-class method for MLPs	$	179		$	220

Diluted weighted average common units outstanding	399			385

Diluted adjusted net income per common unit (3)	$	0.45		$	0.57

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

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

(3) The Series A preferred units were excluded from the calculation of diluted net income per common unit as the effect was antidilutive.

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333 Clay Street, Suite 1600 Houston, Texas 77002 713-646-4100 / 866-809-1291

Page 14

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

FINANCIAL DATA RECONCILIATIONS

(in millions)

	Three Months Ended
	March 31,
	2016		2015
Net Income to Earnings Before Interest, Taxes, Depreciation and Amortization (“EBITDA”) and Excluding Selected Items Impacting Comparability (“Adjusted EBITDA”) Reconciliations
Net Income	$	203	$	284
Add: Interest expense, net	112		105
Add: Income tax expense	19		16
Add: Depreciation and amortization	114		104
EBITDA	448		509
Selected items impacting comparability of EBITDA (1)	173		113
Adjusted EBITDA	$	621	$	622

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

	Three Months Ended
	March 31,
	2016			2015
Adjusted EBITDA to Implied Distributable Cash Flow (“DCF”) Reconciliation
Adjusted EBITDA	$	621		$	622
Interest expense, net (1)	(108		)	(101		)
Maintenance capital	(47		)	(50		)
Current income tax expense	(31		)	(42		)
Equity earnings in unconsolidated entities, net of distributions	5			17
Distributions to noncontrolling interests (2)	(1		)	(1		)
Implied DCF	$	439		$	445

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

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

	Three Months Ended
	March 31,
	2016			2015
Net Cash Provided by Operating Activities Reconciliation
EBITDA	$	448		$	509
Current income tax expense	(31		)	(42		)
Interest expense, net (1)	(108		)	(101		)
Net change in assets and liabilities, net of acquisitions	322			347
Other items to reconcile to net cash provided by operating activities:
Equity-indexed compensation expense	4			19
Net cash provided by operating activities	$	635		$	732

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

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333 Clay Street, Suite 1600 Houston, Texas 77002 713-646-4100 / 866-809-1291

Page 15

PLAINS GP HOLDINGS AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (1)

(in millions, except per share data)

	Three Months Ended									Three Months Ended
	March 31, 2016									March 31, 2015
	PAA			Consolidating Adjustments (2)			PAGP			PAA			Consolidating Adjustments (2)			PAGP

REVENUES	$	4,111		$	—		$	4,111		$	5,942		$	—		$	5,942

COSTS AND EXPENSES
Purchases and related costs	3,348			—			3,348			5,042			—			5,042
Field operating costs	300			—			300			346			—			346
General and administrative expenses	67			1			68			78			1			79
Depreciation and amortization	114			—			114			104			1			105
Total costs and expenses	3,829			1			3,830			5,570			2			5,572

OPERATING INCOME	282			(1		)	281			372			(2		)	370

OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	47			—			47			37			—			37
Interest expense, net	(112		)	(4		)	(116		)	(105		)	(2		)	(107		)
Other income/(expense), net	5			—			5			(4		)	—			(4		)

INCOME BEFORE TAX	222			(5		)	217			300			(4		)	296
Current income tax expense	(31		)	—			(31		)	(42		)	—			(42		)
Deferred income tax (expense)/benefit	12			(21		)	(9		)	26			(18		)	8

NET INCOME	203			(26		)	177			284			(22		)	262
Net income attributable to noncontrolling interests	(1		)	(140		)	(141		)	(1		)	(230		)	(231		)
NET INCOME ATTRIBUTABLE TO PAGP	$	202		$	(166	)	$	36		$	283		$	(252	)	$	31

BASIC AND DILUTED NET INCOME PER CLASS A SHARE							$	0.14								$	0.14

BASIC AND DILUTED WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING							253									212

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

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333 Clay Street, Suite 1600 Houston, Texas 77002 713-646-4100 / 866-809-1291

Page 16

PLAINS GP HOLDINGS AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

CONDENSED CONSOLIDATING BALANCE SHEET DATA

(in millions)

	March 31, 2016							December 31, 2015
	PAA		Consolidating Adjustments (1)			PAGP		PAA		Consolidating Adjustments (2)			PAGP
ASSETS
Current assets	$	2,780	$	4		$	2,784	$	2,969	$	3		$	2,972
Property and equipment, net	13,670		19			13,689		13,474		19			13,493
Goodwill	2,405		—			2,405		2,405		—			2,405
Investments in unconsolidated entities	2,097		—			2,097		2,027		—			2,027
Deferred tax asset	—		1,907			1,907		—		1,835			1,835
Linefill and base gas	899		—			899		898		—			898
Long-term inventory	112		—			112		129		—			129
Other long-term assets, net	334		(2		)	332		386		(3		)	383
Total assets	$	22,297	$	1,928		$	24,225	$	22,288	$	1,854		$	24,142

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	3,063	$	3		$	3,066	$	3,407	$	2		$	3,409
Senior notes, net of unamortized discounts and debt issuance costs	9,126		—			9,126		9,698		—			9,698
Other long-term debt, net of unamortized debt issuance costs	27		591			618		677		557			1,234
Other long-term liabilities and deferred credits	710		—			710		567		—			567
Total liabilities	12,926		594			13,520		14,349		559			14,908

Partners’ capital excluding noncontrolling interests	9,313		(7,492		)	1,821		7,881		(6,119		)	1,762
Noncontrolling interests	58		8,826			8,884		58		7,414			7,472
Total partners’ capital	9,371		1,334			10,705		7,939		1,295			9,234
Total liabilities and partners’ capital	$	22,297	$	1,928		$	24,225	$	22,288	$	1,854		$	24,142

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

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333 Clay Street, Suite 1600 Houston, Texas 77002 713-646-4100 / 866-809-1291

Page 17

PLAINS GP HOLDINGS AND SUBSIDIARIES

DISTRIBUTION SUMMARY (unaudited)

Q1 2016 PAGP DISTRIBUTION SUMMARY

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

	Q1 2016 (1)
PAA Distribution/Common Unit	$	0.7000
GP Distribution/Common Unit	$	0.3885
Total Distribution/Common Unit	$	1.0885

PAA Common Units Outstanding at 4/29/16	398

Gross GP Distribution	$	160
Less: IDR Reduction	(5		)
Net Distribution from PAA to AAP (2)	$	155
Less: Debt Service	(3		)
Less: G&A Expense	(1		)
Cash Available for Distribution by AAP	$	150

Distributions to AAP Partners
Direct AAP Owners & AAP Management (59% economic interest)	$	89
PAGP (41% economic interest)	61
Total distributions to AAP Partners	$	150

Distribution to PAGP Investors	$	62
PAGP Class A Shares Outstanding at 4/29/16	267
PAGP Distribution/Class A Share	$	0.231

(1) Amounts may not recalculate due to rounding.

(2) Plains AAP, L.P. (“AAP”) is the general partner of PAA.

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333 Clay Street, Suite 1600 Houston, Texas 77002 713-646-4100 / 866-809-1291

Page 18

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
	March 31,
	2016		2015
Basic and Diluted Net Income per Class A Share (1)
Net income attributable to PAGP	$	36	$	31
Basic and diluted weighted average Class A shares outstanding	253		212

Basic and diluted net income per Class A share	$	0.14	$	0.14

(1) Assumed exchanges of AAP units and AAP Management Units were excluded from the calculation of diluted net income per Class A share as the effect was not dilutive.

Contacts:

Ryan Smith		Al Swanson
Director, Investor Relations		Executive Vice President, CFO
(866) 809-1291		(800) 564-3036

###

333 Clay Street, Suite 1600 Houston, Texas 77002 713-646-4100 / 866-809-1291

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