Category: Intelligence

Source: GlobeNewswire (MIL-OSI)

HOUSTON, May 09, 2025 (GLOBE NEWSWIRE) — Plains All American Pipeline, L.P. (Nasdaq: PAA) and Plains GP Holdings (Nasdaq: PAGP) today reported first-quarter 2025 results and provided the following highlights:

First-Quarter Results

• Reported net income attributable to PAA of $443 million and net cash provided by operating activities of $639 million
• Delivered Adjusted EBITDA attributable to PAA of $754 million
• Exited the quarter with 3.3x leverage ratio, toward the low end of our target range of 3.25x – 3.75x (includes previously announced and closed transactions)
• Paid a quarterly cash distribution of $0.38 per unit ($1.52 per unit annualized), representing a current distribution yield of ~9.0%

Business Highlights

• Plains acquired the remaining 50% interest in Cheyenne Pipeline, enhancing our integration from the Guernsey market to pipelines supplying Cushing, Oklahoma, which closed on February 28, 2025
• Plains acquired Black Knight Midstream’s Permian Basin crude oil gathering business, for approximately $55 million, which closed effective May 1, 2025
• Placed into service the 30 Mb/d Fort Saskatchewan fractionation complex debottleneck project enhancing our fee-based cash flow in Canada
• Increased our 2025 C3+ spec product sales hedge profile to approximately 80% at approximately $0.70 per gallon level

“Plains delivered another quarter of solid operational and financial performance,” said Willie Chiang, Chairman and CEO. “Substantial cash flow generation from our integrated Crude Oil and NGL footprints coupled with a strong balance sheet positions us well through a time of market volatility and uncertainty. Our focus on efficient growth remains consistent with the addition of two new bolt-on acquisitions and our Fort Saskatchewan fractionation complex debottleneck project now in service. Finally, our commitment to financial discipline and financial flexibility remains unchanged while continuing to return cash to unitholders through a strong distribution payout.”

Plains All American Pipeline

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

		Three Months Ended March 31,								%
GAAP Results		2025				2024				Change
Net income attributable to PAA (1)		$	443			$	266				67	%
Diluted net income per common unit		$	0.49			$	0.29				69	%
Diluted weighted average common units outstanding			704				701				—	%
Net cash provided by operating activities		$	639			$	419				53	%
Distribution per common unit declared for the period		$	0.3800			$	0.3175				20	%

		Three Months Ended March 31,								%
Non-GAAP Results (2)		2025				2024				Change
Adjusted net income attributable to PAA (1)		$	375			$	354				6	%
Diluted adjusted net income per common unit		$	0.39			$	0.41			(5		)%
Adjusted EBITDA		$	881			$	847				4	%
Adjusted EBITDA attributable to PAA (1)		$	754			$	718				5	%
Implied DCF per common unit and common unit equivalent		$	0.66			$	0.67			(1		)%
Adjusted Free Cash Flow (3)		$	(308	)		$	70			**
Adjusted Free Cash Flow after Distributions (3)		$	(639	)		$	(217	)		**
Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities) (3)		$	(169	)		$	262			**
Adjusted Free Cash Flow after Distributions (Excluding Changes in Assets & Liabilities) (3)		$	(500	)		$	(25	)		**

_____________________

**	Indicates that variance as a percentage is not meaningful.
(1)	Excludes amounts attributable to noncontrolling interests in the Plains Oryx Permian Basin LLC (the “Permian JV”), Cactus II Pipeline LLC and Red River Pipeline LLC joint ventures.
(2)	See the section of this release entitled “Non-GAAP Financial Measures and Selected Items Impacting Comparability” and the tables attached hereto for information regarding our Non-GAAP financial measures, including their reconciliation to the most directly comparable measures as reported in accordance with GAAP, and certain selected items that PAA believes impact comparability of financial results between reporting periods.
(3)	The 2025 period includes the impact of a net cash outflow of $624 million for bolt-on acquisitions.

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

	Segment Adjusted EBITDA
	Crude Oil				NGL
Three Months Ended March 31, 2025	$	559			$	189
Three Months Ended March 31, 2024	$	553			$	159
Percentage change in Segment Adjusted EBITDA versus 2024 period		1	%			19	%

First-quarter 2025 Crude Oil Segment Adjusted EBITDA was in line with comparable 2024 results. Favorable results in the 2025 period from (i) higher tariff volumes on our pipelines, (ii) tariff escalations and (iii) contributions from recently completed bolt-on acquisitions were largely offset by (iv) higher operating expenses and (v) the impact to our assets from refinery downtime.

First-quarter 2025 NGL Segment Adjusted EBITDA increased 19% versus comparable 2024 results primarily due to higher weighted average frac spreads and NGL sales volumes in the first quarter of 2025.

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 attached hereto.

Conference Call and Webcast Instructions

PAA and PAGP will hold a joint conference call at 9:00 a.m. CT on Friday, May 9, 2025 to discuss first-quarter performance and related items.

To access the internet webcast, please go to https://edge.media-server.com/mmc/p/qqvgtyoa/

Alternatively, the webcast can be accessed on our website at https://ir.plains.com/news-events/events-presentations. Following the live webcast, an audio replay will be available on our website and will be accessible for a period of 365 days. Slides will be posted prior to the call at the above referenced website.

Non-GAAP Financial Measures and Selected Items Impacting Comparability

To supplement our financial information presented in accordance with GAAP, management uses additional measures known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the future and to assess the amount of cash that is available for distributions, debt repayments, common equity repurchases and other general partnership purposes. The primary additional measures used by management are Adjusted EBITDA, Adjusted EBITDA attributable to PAA, Implied Distributable Cash Flow (“DCF”), Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions.

Our definition and calculation of certain non-GAAP financial measures may not be comparable to similarly-titled measures of other companies. Adjusted EBITDA, Adjusted EBITDA attributable to PAA, Implied DCF and certain other non-GAAP financial performance measures are reconciled to Net Income, and Adjusted Free Cash Flow, Adjusted Free Cash Flow after Distributions and certain other non-GAAP financial liquidity measures are reconciled to Net Cash Provided by Operating Activities (the most directly comparable measures 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 accompanying notes. In addition, we encourage you to visit our website at www.plains.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. We do not reconcile non-GAAP financial measures on a forward-looking basis as it is impractical to do so without unreasonable effort.

Non-GAAP Financial Performance Measures

Adjusted EBITDA is defined as earnings before (i) interest expense, (ii) income tax (expense)/benefit, (iii) depreciation and amortization (including our proportionate share of depreciation and amortization, including write-downs related to cancelled projects and impairments, of unconsolidated entities), (iv) gains and losses on asset sales, asset impairments and other, net, (v) gains on investments in unconsolidated entities, net and (vi) interest income on promissory notes by and among PAA and certain Plains entities, and (vii) adjusted for certain selected items impacting comparability. Adjusted EBITDA attributable to PAA excludes the portion of Adjusted EBITDA that is attributable to noncontrolling interests.

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

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

Non-GAAP Financial Liquidity Measures

Management uses the non-GAAP financial liquidity measures Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions to assess the amount of cash that is available for distributions, debt repayments, common equity repurchases and other general partnership purposes. Adjusted Free Cash Flow is defined as Net Cash Provided by Operating Activities, less Net Cash Provided by/(Used in) Investing Activities, which primarily includes acquisition, investment and maintenance capital expenditures, investments in unconsolidated entities and the impact from the purchase and sale of linefill, net of proceeds from the sales of assets and further impacted by distributions to and contributions from noncontrolling interests and proceeds from the issuance of related party notes. Adjusted Free Cash Flow is further reduced by cash distributions paid to our preferred and common unitholders to arrive at Adjusted Free Cash Flow after Distributions.

We also present these measures and additional non-GAAP financial liquidity measures as they are measures that investors have indicated are useful. We present the Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities) for use in assessing our underlying business liquidity and cash flow generating capacity excluding fluctuations caused by timing of when amounts earned or incurred were collected, received or paid from period to period. Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities) is defined as Adjusted Free Cash Flow excluding the impact of “Changes in assets and liabilities, net of acquisitions” on our Condensed Consolidated Statements of Cash Flows. Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities) is further reduced by cash distributions paid to our preferred and common unitholders to arrive at Adjusted Free Cash Flow after Distributions (Excluding Changes in Assets & Liabilities).

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 March 31,
		2025				2024
REVENUES	$	12,011			$	11,995
COSTS AND EXPENSES
Purchases and related costs		10,761				10,917
Field operating costs		368				358
General and administrative expenses		100				96
Depreciation and amortization		262				254
Gain on asset sales, net		(13	)			—
Total costs and expenses		11,478				11,625
OPERATING INCOME		533				370
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities		103				95
Gain on investments in unconsolidated entities, net		31				—
Interest expense, net (1)		(127	)			(95	)
Other income/(expense), net (1)		26				(5	)
INCOME BEFORE TAX		566				365
Current income tax expense		(46	)			(53	)
Deferred income tax (expense)/benefit		(4	)			39
NET INCOME		516				351
Net income attributable to noncontrolling interests		(73	)			(85	)
NET INCOME ATTRIBUTABLE TO PAA	$	443			$	266
NET INCOME PER COMMON UNIT:
Net income allocated to common unitholders — Basic and Diluted	$	343			$	203
Basic and diluted weighted average common units outstanding		704				701
Basic and diluted net income per common unit	$	0.49			$	0.29

_____________________

(1)

PAA and certain Plains entities have issued promissory notes by and among such entities to facilitate financing. “Interest expense, net” and “Other income/(expense), net” each include $20 million for the three months ended March 31, 2025 related to interest on such related party promissory notes. These amounts offset and do not impact Net Income or Non-GAAP metrics such as Adjusted EBITDA, Implied DCF and Adjusted Free Cash Flow.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited)
CONDENSED CONSOLIDATED BALANCE SHEET DATA (in millions)
	March 31, 2025				December 31, 2024
ASSETS
Current assets (including cash and cash equivalents of $427 and $348, respectively)	$	4,735			$	4,802
Property and equipment, net		16,062				15,424
Investments in unconsolidated entities		2,745				2,811
Intangible assets, net		1,675				1,677
Linefill		988				968
Long-term operating lease right-of-use assets, net		321				332
Long-term inventory		289				280
Other long-term assets, net		244				268
Total assets	$	27,059			$	26,562
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	4,691			$	4,950
Senior notes, net		8,131				7,141
Other long-term debt, net		73				72
Long-term operating lease liabilities		301				313
Other long-term liabilities and deferred credits		1,003				990
Total liabilities		14,199				13,466
Partners’ capital excluding noncontrolling interests		9,632				9,813
Noncontrolling interests		3,228				3,283
Total partners’ capital		12,860				13,096
Total liabilities and partners’ capital	$	27,059			$	26,562

DEBT CAPITALIZATION RATIOS
(in millions)

	March 31, 2025				December 31, 2024
Short-term debt	$	478			$	408
Long-term debt		8,204				7,213
Total debt	$	8,682			$	7,621
Long-term debt	$	8,204			$	7,213
Partners’ capital excluding noncontrolling interests		9,632				9,813
Total book capitalization excluding noncontrolling interests (“Total book capitalization”)	$	17,836			$	17,026
Total book capitalization, including short-term debt	$	18,314			$	17,434
Long-term debt-to-total book capitalization		46	%			42	%
Total debt-to-total book capitalization, including short-term debt		47	%			44	%

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited)
COMPUTATION OF BASIC AND DILUTED NET INCOME PER COMMON UNIT (1) (in millions, except per unit data)
	Three Months Ended March 31,
	2025				2024
Basic and Diluted Net Income per Common Unit
Net income attributable to PAA	$	443			$	266
Distributions to Series A preferred unitholders		(39	)			(44	)
Distributions to Series B preferred unitholders		(18	)			(19	)
Amounts allocated to participating securities		(1	)			(1	)
Impact from repurchase of Series A preferred units (2)		(43	)			—
Other		1				1
Net income allocated to common unitholders	$	343			$	203
Basic and diluted weighted average common units outstanding (3) (4)		704				701
Basic and diluted net income per common unit	$	0.49			$	0.29

_____________________

(1)	We calculate net income allocated to common unitholders based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method.
(2)	We repurchased approximately 12.7 million Series A preferred units on January 31, 2025. The difference between the cash we paid for the repurchase of such units and their carrying value on our balance sheet is considered a return to Series A preferred unitholders for the calculation of net income allocated to common unitholders.
(3)	The possible conversion of our Series A preferred units was excluded from the calculation of diluted net income per common unit for each of the three months ended March 31, 2025 and 2024 as the effect was antidilutive.
(4)	Our equity-indexed compensation plan awards that contemplate the issuance of common units are considered potentially dilutive unless (i) they become vested only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. Equity-indexed compensation plan awards that are deemed to be dilutive are reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited)
CONDENSED CONSOLIDATED CASH FLOW DATA (in millions)
	Three Months Ended March 31,
	2025				2024
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	516			$	351
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization		262				254
Gain on asset sales, net		(13	)			—
Deferred income tax expense/(benefit)		4				(39	)
Equity earnings in unconsolidated entities		(103	)			(95	)
Distributions on earnings from unconsolidated entities		125				132
Other		(13	)			8
Changes in assets and liabilities, net of acquisitions		(139	)			(192	)
Net cash provided by operating activities		639				419
CASH FLOWS FROM INVESTING ACTIVITIES
Net cash used in investing activities (1)(2)		(1,149	)			(261	)
CASH FLOWS FROM FINANCING ACTIVITIES
Net cash provided by/(used in) financing activities (1)		590				(273	)
Effect of translation adjustment		(1	)			(4	)
Net increase/(decrease) in cash and cash equivalents and restricted cash		79				(119	)
Cash and cash equivalents and restricted cash, beginning of period		348				450
Cash and cash equivalents and restricted cash, end of period	$	427			$	331

_____________________

(1)	PAA and certain Plains entities have issued promissory notes by and among such entities to facilitate financing. For the three months ended March 31, 2025, “Net cash used in investing activities” includes a cash outflow of approximately $330 million associated with our investment in related party notes. An equal and offsetting cash inflow associated with our issuance of related party notes is included in “Net cash provided by/(used in) financing activities.”
(2)	The 2025 period includes a net cash outflow of $624 million for bolt-on acquisitions.

CAPITAL EXPENDITURES
(in millions)

	Net to PAA (1)								Consolidated
	Three Months Ended March 31,								Three Months Ended March 31,
	2025				2024				2025				2024
Investment capital expenditures:
Crude Oil	$	89			$	65			$	120			$	90
NGL		41				14				41				14
Total Investment capital expenditures		130				79				161				104
Maintenance capital expenditures		38				53				41				57
	$	168			$	132			$	202			$	161

_____________________

(1)	Excludes expenditures attributable to noncontrolling interests.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited)
NON-GAAP RECONCILIATIONS (in millions, except per unit and ratio data)
Computation of Basic and Diluted Adjusted Net Income Per Common Unit (1):
	Three Months Ended March 31,
	2025				2024
Basic and Diluted Adjusted Net Income per Common Unit
Net income attributable to PAA	$	443			$	266
Selected items impacting comparability – Adjusted net income attributable to PAA (2)		(68	)			88
Adjusted net income attributable to PAA	$	375			$	354
Distributions to Series A preferred unitholders		(39	)			(44	)
Distributions to Series B preferred unitholders		(18	)			(19	)
Amounts allocated to participating securities		(1	)			(2	)
Impact from repurchase of Series A preferred units (3)		(43	)			—
Other		1				1
Adjusted net income allocated to common unitholders	$	275			$	290
Basic and diluted weighted average common units outstanding (4) (5)		704				701
Basic and diluted adjusted net income per common unit	$	0.39			$	0.41

_____________________

(1)	We calculate adjusted net income allocated to common unitholders based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method.
(2)	See the “Selected Items Impacting Comparability” table for additional information.
(3)	We repurchased approximately 12.7 million Series A preferred units on January 31, 2025. The difference between the cash we paid for the repurchase of such units and their carrying value on our balance sheet is considered a return to Series A preferred unitholders for the calculation of adjusted net income allocated to common unitholders.
(4)	The possible conversion of our Series A preferred units was excluded from the calculation of diluted adjusted net income per common unit for each of the three months ended March 31, 2025 and 2024 as the effect was antidilutive.
(5)	Our equity-indexed compensation plan awards that contemplate the issuance of common units are considered potentially dilutive unless (i) they become vested only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. Equity-indexed compensation plan awards that are deemed to be dilutive are reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB.

Net Income Per Common Unit to Adjusted Net Income Per Common Unit Reconciliation:

	Three Months Ended March 31,
	2025				2024
Basic and diluted net income per common unit	$	0.49			$	0.29
Selected items impacting comparability per common unit (1)		(0.10	)			0.12
Basic and diluted adjusted net income per common unit	$	0.39			$	0.41

_____________________

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

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited)
Net Income to Adjusted EBITDA attributable to PAA and Implied DCF Reconciliation:
	Three Months Ended March 31,
	2025				2024
Net income	$	516			$	351
Interest expense, net of certain items (1)		107				95
Income tax expense		50				14
Depreciation and amortization		262				254
Gain on asset sales, net		(13	)			—
Gain on investments in unconsolidated entities, net		(31	)			—
Depreciation and amortization of unconsolidated entities (2)		20				19
Selected items impacting comparability – Adjusted EBITDA (3)		(30	)			114
Adjusted EBITDA	$	881			$	847
Adjusted EBITDA attributable to noncontrolling interests		(127	)			(129	)
Adjusted EBITDA attributable to PAA	$	754			$	718
Adjusted EBITDA	$	881			$	847
Interest expense, net of certain non-cash and other items (4)		(104	)			(90	)
Maintenance capital		(41	)			(57	)
Investment capital of noncontrolling interests (5)		(30	)			(25	)
Current income tax expense		(46	)			(53	)
Distributions from unconsolidated entities in excess of/(less than) adjusted equity earnings (6)		(2	)			12
Distributions to noncontrolling interests (7)		(132	)			(100	)
Implied DCF	$	526			$	534
Preferred unit distributions paid (7)		(64	)			(64	)
Implied DCF Available to Common Unitholders	$	462			$	470
Weighted Average Common Units Outstanding		704				701
Weighted Average Common Units and Common Unit Equivalents		767				772
Implied DCF per Common Unit (8)	$	0.66			$	0.67
Implied DCF per Common Unit and Common Unit Equivalent (9)	$	0.66			$	0.67
Cash Distribution Paid per Common Unit	$	0.3800			$	0.3175
Common Unit Cash Distributions (7)	$	267			$	223
Common Unit Distribution Coverage Ratio	1.73x				2.11x
Implied DCF Excess	$	195			$	247

_____________________

(1)	Represents “Interest expense, net” as reported on our Condensed Consolidated Statements of Operations, net of interest income associated with promissory notes by and among PAA and certain Plains entities.
(2)	Adjustment to exclude our proportionate share of depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities.
(3)	See the “Selected Items Impacting Comparability” table for additional information.
(4)	Amount excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps and is net of interest income associated with promissory notes by and among PAA and certain Plains entities.
(5)	Investment capital expenditures attributable to noncontrolling interests that reduce Implied DCF available to PAA common unitholders.
(6)	Comprised of cash distributions received from unconsolidated entities less equity earnings in unconsolidated entities (adjusted for our proportionate share of depreciation and amortization, including write-downs related to cancelled projects and impairments, and selected items impacting comparability of unconsolidated entities).
(7)	Cash distributions paid during the period presented.
(8)	Implied DCF Available to Common Unitholders for the period divided by the weighted average common units outstanding for the period.
(9)	Implied DCF Available to Common Unitholders for the period, adjusted for Series A preferred unit cash distributions paid, divided by the weighted average common units and common unit equivalents outstanding for the period. Our Series A preferred units are convertible into common units, generally on a one-for-one basis and subject to customary anti-dilution adjustments, in whole or in part, subject to certain minimum conversion amounts.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited)
Net Income Per Common Unit to Implied DCF Per Common Unit and Common Unit Equivalent Reconciliation:
	Three Months Ended March 31,
	2025				2024
Basic net income per common unit	$	0.49			$	0.29
Reconciling items per common unit (1) (2)		0.17				0.38
Implied DCF per common unit	$	0.66			$	0.67
Basic net income per common unit	$	0.49			$	0.29
Reconciling items per common unit and common unit equivalent (1) (3)		0.17				0.38
Implied DCF per common unit and common unit equivalent	$	0.66			$	0.67

_____________________

(1)	Represents adjustments to Net Income to calculate Implied DCF Available to Common Unitholders. See the “Net Income to Adjusted EBITDA attributable to PAA and Implied DCF Reconciliation” table for additional information.
(2)	Based on weighted average common units outstanding for the three months ended March 31, 2025 and 2024 of 704 million and 701 million, respectively.
(3)	Based on weighted average common units outstanding for the period, as well as weighted average Series A preferred units outstanding for the three months ended March 31, 2025 and 2024 of 63 million and 71 million, respectively.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited)
Net Cash Provided by Operating Activities to Non-GAAP Financial Liquidity Measures Reconciliation:
	Three Months Ended March 31,
		2025				2024
Net cash provided by operating activities	$	639			$	419
Adjustments to reconcile Net cash provided by operating activities to Adjusted Free Cash Flow:
Net cash used in investing activities (1)(2)		(1,149	)			(261	)
Cash contributions from noncontrolling interests		4				12
Cash distributions paid to noncontrolling interests (3)		(132	)			(100	)
Proceeds from the issuance of related party notes (1)		330				—
Adjusted Free Cash Flow (4)	$	(308	)		$	70
Cash distributions (5)		(331	)			(287	)
Adjusted Free Cash Flow after Distributions (4) (6)	$	(639	)		$	(217	)
	Three Months Ended March 31,
		2025				2024
Adjusted Free Cash Flow (4)	$	(308	)		$	70
Changes in assets and liabilities, net of acquisitions (7)		139				192
Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities) (8)	$	(169	)		$	262
Cash distributions (5)		(331	)			(287	)
Adjusted Free Cash Flow after Distributions (Excluding Changes in Assets & Liabilities) (8)	$	(500	)		$	(25	)

_____________________

(1)	PAA and certain Plains entities have issued promissory notes by and among such entities to facilitate financing. “Proceeds from the issuance of related party notes” has an equal and offsetting cash outflow associated with our investment in related party notes, which is included as a component of “Net cash used in investing activities.”
(2)	The 2025 period includes a net cash outflow of $624 million for bolt-on acquisitions.
(3)	Cash distributions paid during the period presented.
(4)	Management uses the non-GAAP financial liquidity measures Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions to assess the amount of cash that is available for distributions, debt repayments, common equity repurchases and other general partnership purposes. Adjusted Free Cash Flow after Distributions shortages, if any, may be funded from previously established reserves, cash on hand or from borrowings under our credit facilities or commercial paper program.
(5)	Cash distributions paid to preferred and common unitholders during the period.
(6)	Excess Adjusted Free Cash Flow after Distributions is retained to establish reserves for future distributions, capital expenditures, debt reduction and other partnership purposes. Adjusted Free Cash Flow after Distributions shortages may be funded from previously established reserves, cash on hand or from borrowings under our credit facilities or commercial paper program.
(7)	See the “Condensed Consolidated Cash Flow Data” table.
(8)	Management uses the non-GAAP financial liquidity measures Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities) and Adjusted Free Cash Flow after Distributions (Excluding Changes in Assets & Liabilities) to assess the underlying business liquidity and cash flow generating capacity excluding fluctuations caused by timing of when amounts earned or incurred were collected, received or paid from period to period.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited)
SELECTED ITEMS IMPACTING COMPARABILITY (in millions)
	Three Months Ended March 31,
	2025				2024
Selected Items Impacting Comparability: (1)
Derivative activities and inventory valuation adjustments (2)	$	34			$	(159	)
Long-term inventory costing adjustments (3)		3				33
Deficiencies under minimum volume commitments, net (4)		7				12
Equity-indexed compensation expense (5)		(9	)			(9	)
Foreign currency revaluation (6)		—				9
Transaction-related expenses (7)		(5	)			—
Selected items impacting comparability – Adjusted EBITDA	$	30			$	(114	)
Gain on investments in unconsolidated entities, net		31				—
Gain on asset sales, net		13				—
Tax effect on selected items impacting comparability		(3	)			30
Aggregate selected items impacting noncontrolling interests		(3	)			(4	)
Selected items impacting comparability – Adjusted net income attributable to PAA	$	68			$	(88	)

_____________________

(1)	Certain of our non-GAAP financial measures may not be impacted by each of the selected items impacting comparability. See the “Net Income to Adjusted EBITDA attributable to PAA and Implied DCF Reconciliation” and “Computation of Basic and Diluted Adjusted Net Income Per Common Unit” tables for additional details on how these selected items impacting comparability affect such measures.
(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, we identify differences in the timing of earnings from the derivative instruments and the underlying transactions and exclude the related gains and losses in determining adjusted results such that the earnings from the derivative instruments and the underlying transactions impact adjusted results in the same period. In addition, we exclude gains and losses on derivatives that are related to (i) investing activities, such as the purchase of linefill, and (ii) purchases of long-term inventory. We also exclude the impact of corresponding inventory valuation adjustments, as applicable. For applicable periods, we excluded gains and losses from the mark-to-market of the embedded derivative associated with the Preferred Distribution Rate Reset Option of our Series A preferred units.
(3)	We carry crude oil and NGL inventory that is comprised of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets). We treat the impact of changes in the average cost of the long-term inventory (that result from fluctuations in market prices) and write-downs of such inventory that result from price declines as a selected item impacting comparability.
(4)	We, and certain of our equity method investees, 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 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 or equity earnings, 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 be settled in units and awards that will be settled in cash. The awards that will 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, as applicable. The portion of compensation expense associated with awards that will 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 the realization of foreign exchange gains and losses on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency. The associated gains and losses are not integral to our results and were thus classified as a selected item impacting comparability.
(7)	Primarily related to acquisitions completed during the first quarter of 2025.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited)
SELECTED FINANCIAL DATA BY SEGMENT (in millions)
	Three Months Ended March 31, 2025									Three Months Ended March 31, 2024
	Crude Oil				NGL					Crude Oil				NGL
Revenues (1)	$	11,439			$	638				$	11,582			$	507
Purchases and related costs (1)		(10,488	)			(339	)				(10,665	)			(346	)
Field operating costs (2)		(292	)			(76	)				(266	)			(92	)
Segment general and administrative expenses (2) (3)		(79	)			(21	)				(73	)			(23	)
Equity earnings in unconsolidated entities		103				—					95				—
Other segment items: (4)
Depreciation and amortization of unconsolidated entities		20				—					19				—
Derivative activities and inventory valuation adjustments		(24	)			(10	)				37				122
Long-term inventory costing adjustments		—				(3	)				(28	)			(5	)
Deficiencies under minimum volume commitments, net		(7	)			—					(12	)			—
Equity-indexed compensation expense		9				—					9				—
Foreign currency revaluation		—				—					(17	)			(4	)
Transaction-related expenses		5				—					—				—
Segment amounts attributable to noncontrolling interests (5)		(127	)			—					(128	)			—
Segment Adjusted EBITDA	$	559			$	189				$	553			$	159
Maintenance capital expenditures	$	31			$	10				$	46			$	11

_____________________

(1)	Includes intersegment amounts.
(2)	Field operating costs and Segment general and administrative expenses include equity-indexed compensation expense.
(3)	Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.
(4)	Represents adjustments utilized by our CODM in the evaluation of segment results. Many of these adjustments are also considered selected items impacting comparability when calculating consolidated non-GAAP financial measures such as Adjusted EBITDA. See the “Selected Items Impacting Comparability” table for additional discussion.
(5)	Reflects amounts attributable to noncontrolling interests in the Permian JV, Cactus II Pipeline LLC and Red River Pipeline LLC.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited)
OPERATING DATA BY SEGMENT (1)
	Three Months Ended March 31,
	2025				2024
Crude Oil Segment Volumes
Crude oil pipeline tariff (by region)
Permian Basin (2)		6,869				6,428
South Texas / Eagle Ford (2)		492				378
Mid-Continent (2)		415				486
Gulf Coast (2)		214				202
Rocky Mountain (2)		495				499
Western		247				259
Canada		354				348
Total crude oil pipeline tariff (2)		9,086				8,600
NGL Segment Volumes
NGL fractionation		157				128
NGL pipeline tariff		234				214
Propane and butane sales		147				128

_____________________

(1)	Average volumes in thousands of barrels per day calculated as the total volumes (attributable to our interest for assets owned by unconsolidated entities or through undivided joint interests) for the period divided by the number of days in the period. Volumes associated with assets acquired during the period represent total volumes for the number of days we actually owned the assets divided by the number of days in the period.
(2)	Includes volumes (attributable to our interest) from assets owned by unconsolidated entities.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited)
NON-GAAP SEGMENT RECONCILIATIONS (in millions)
Supplemental Adjusted EBITDA attributable to PAA Reconciliation:
	Three Months Ended March 31,
	2025				2024
Crude Oil Segment Adjusted EBITDA	$	559			$	553
NGL Segment Adjusted EBITDA		189				159
Adjusted other income, net (1)		6				6
Adjusted EBITDA attributable to PAA (2)	$	754			$	718

_____________________

(1)	Represents “Other income/(expense), net” as reported on our Condensed Consolidated Statements of Operations, excluding interest income on promissory notes by and among PAA and certain Plains entities, as well as other income, net attributable to noncontrolling interests, adjusted for selected items impacting comparability. See the “Selected Items Impacting Comparability” table for additional information.
(2)	See the “Net Income to Adjusted EBITDA attributable to PAA and Implied DCF Reconciliation” table for reconciliation to Net Income.

PLAINS GP HOLDINGS AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (in millions, except per share data)
	Three Months Ended March 31, 2025													Three Months Ended March 31, 2024
					Consolidating													Consolidating
	PAA				Adjustments (1)				PAGP					PAA				Adjustments (1)				PAGP
REVENUES	$	12,011			$	—			$	12,011				$	11,995			$	—			$	11,995
COSTS AND EXPENSES
Purchases and related costs		10,761				—				10,761					10,917				—				10,917
Field operating costs		368				—				368					358				—				358
General and administrative expenses		100				1				101					96				1				97
Depreciation and amortization		262				—				262					254				—				254
Gain on asset sales, net		(13	)			—				(13	)				—				—				—
Total costs and expenses		11,478				1				11,479					11,625				1				11,626
OPERATING INCOME		533				(1	)			532					370				(1	)			369
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities		103				—				103					95				—				95
Gain on investments in unconsolidated entities, net		31				—				31					—				—				—
Interest expense, net		(127	)			20				(107	)				(95	)			—				(95	)
Other income/(expense), net		26				(20	)			6					(5	)			—				(5	)
INCOME BEFORE TAX		566				(1	)			565					365				(1	)			364
Current income tax expense		(46	)			—				(46	)				(53	)			—				(53	)
Deferred income tax (expense)/benefit		(4	)			(23	)			(27	)				39				(14	)			25
NET INCOME		516				(24	)			492					351				(15	)			336
Net income attributable to noncontrolling interests		(73	)			(335	)			(408	)				(85	)			(209	)			(294	)
NET INCOME ATTRIBUTABLE TO PAGP	$	443			$	(359	)		$	84				$	266			$	(224	)		$	42
Basic and diluted weighted average Class A shares outstanding										198													197
Basic and diluted net income per Class A share									$	0.42												$	0.21

_____________________

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

 

PLAINS GP HOLDINGS AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited)
CONDENSED CONSOLIDATING BALANCE SHEET DATA (in millions)
	March 31, 2025													December 31, 2024
					Consolidating													Consolidating
	PAA				Adjustments (1)				PAGP					PAA				Adjustments (1)				PAGP
ASSETS
Current assets	$	4,735			$	(6	)		$	4,729				$	4,802			$	(26	)		$	4,776
Property and equipment, net		16,062				—				16,062					15,424				—				15,424
Investments in unconsolidated entities		2,745				—				2,745					2,811				—				2,811
Intangible assets, net		1,675				—				1,675					1,677				—				1,677
Deferred tax asset		—				1,199				1,199					—				1,220				1,220
Linefill		988				—				988					968				—				968
Long-term operating lease right-of-use assets, net		321				—				321					332				—				332
Long-term inventory		289				—				289					280				—				280
Other long-term assets, net		244				—				244					268				—				268
Total assets	$	27,059			$	1,193			$	28,252				$	26,562			$	1,194			$	27,756
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	4,691			$	(7	)		$	4,684				$	4,950			$	(26	)		$	4,924
Senior notes, net		8,131				—				8,131					7,141				—				7,141
Other long-term debt, net		73				—				73					72				—				72
Long-term operating lease liabilities		301				—				301					313				—				313
Other long-term liabilities and deferred credits		1,003				—				1,003					990				—				990
Total liabilities		14,199				(7	)			14,192					13,466				(26	)			13,440
Partners’ capital excluding noncontrolling interests		9,632				(8,276	)			1,356					9,813				(8,462	)			1,351
Noncontrolling interests		3,228				9,476				12,704					3,283				9,682				12,965
Total partners’ capital		12,860				1,200				14,060					13,096				1,220				14,316
Total liabilities and partners’ capital	$	27,059			$	1,193			$	28,252				$	26,562			$	1,194			$	27,756

_____________________

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

PLAINS GP HOLDINGS AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited)
COMPUTATION OF BASIC AND DILUTED NET INCOME PER CLASS A SHARE (in millions, except per share data)
	Three Months Ended March 31,
	2025				2024
Basic and Diluted Net Income per Class A Share
Net income attributable to PAGP	$	84			$	42
Basic and diluted weighted average Class A shares outstanding		198				197
Basic and diluted net income per Class A share	$	0.42			$	0.21

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, the following:

• general economic, market or business conditions in the United States and elsewhere (including the potential for a recession or significant slowdown in economic activity levels, the risk of persistently high inflation and supply chain issues, the impact of global public health events, such as pandemics, on demand and growth, and the timing, pace and extent of economic recovery) that impact (i) demand for crude oil, drilling and production activities and therefore the demand for the midstream services we provide and (ii) commercial opportunities available to us;
• declines in global crude oil demand and/or crude oil prices or other factors that correspondingly lead to a significant reduction of North American crude oil and NGL production (whether due to reduced producer cash flow to fund drilling activities or the inability of producers to access capital, or both, the unavailability of pipeline and/or storage capacity, the shutting-in of production by producers, government-mandated pro-ration orders, or other factors), which in turn could result in significant 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 and/or the reduction of the margins we can earn or the commercial opportunities that might otherwise be available to us;
• fluctuations in refinery capacity and other factors affecting demand for various grades of crude oil and NGL and resulting changes in pricing conditions or transportation throughput requirements;
• unanticipated changes in crude oil and NGL market structure, grade differentials and volatility (or lack thereof);
• the effects of competition and capacity overbuild in areas where we operate, including downward pressure on rates, volumes and margins, contract renewal risk and the risk of loss of business to other midstream operators who are willing or under pressure to aggressively reduce transportation rates in order to capture or preserve customers;
• the successful operation of joint ventures and joint operating arrangements we enter into from time to time, whether relating to assets operated by us or by third parties, and the successful integration and future performance of acquired assets or businesses;
• the availability of, and our ability to consummate, acquisitions, divestitures, joint ventures or other strategic opportunities and realize benefits therefrom;
• environmental liabilities, litigation or other events that are not covered by an indemnity, insurance or existing reserves;
• negative societal sentiment regarding the hydrocarbon energy industry and the continued development and consumption of hydrocarbons, which could influence consumer preferences and governmental or regulatory actions that adversely impact our business;
• the occurrence of a natural disaster, catastrophe, terrorist attack (including eco-terrorist attacks) or other event that materially impacts our operations, including cyber or other attacks on our or our service providers’ electronic and computer systems;
• weather interference with business operations or project construction, including the impact of extreme weather events or conditions (including hurricanes, floods, wildfires and drought);
• the impact of current and future laws, rulings, legislation, governmental regulations, executive orders, trade policies, trade tariffs, accounting standards and statements, and related interpretations that (i) prohibit, restrict or regulate the development of oil and gas resources and the related infrastructure on lands dedicated to or served by our pipelines or (ii) negatively impact our ability to develop, operate or repair midstream assets, or (iii) otherwise negatively impact our business or increase our exposure to risk;
• negative impacts on production levels in the Permian Basin or elsewhere due to issues associated with (or laws, rules or regulations relating to) hydraulic fracturing and related activities (including wastewater injection or disposal), including earthquakes, subsidence, expansion or other issues;
• the pace of development of natural gas or other infrastructure and its impact on expected crude oil production growth in the Permian Basin;
• the refusal or inability of our customers or counterparties to perform their obligations under their contracts with us (including commercial contracts, asset sale agreements and other agreements), whether justified or not and whether due to financial constraints (such as reduced creditworthiness, liquidity issues or insolvency), market constraints, legal constraints (including governmental orders or guidance), the exercise of contractual or common law rights that allegedly excuse their performance (such as force majeure or similar claims) or other factors;
• loss of key personnel and inability to attract and retain new talent;
• disruptions to futures markets for crude oil, NGL and other petroleum products, which may impair our ability to execute our commercial or hedging strategies;
• the effectiveness of our risk management activities;
• shortages or cost increases of supplies, materials or labor;
• maintenance of our credit ratings and ability to receive open credit from our suppliers and trade counterparties;
• our inability to perform our obligations under our contracts, whether due to non-performance by third parties, including our customers or counterparties, market constraints, third-party constraints, supply chain issues, legal constraints (including governmental orders or guidance), or other factors or events;
• the incurrence of costs and expenses related to unexpected or unplanned capital or maintenance expenditures, third-party claims or other factors;
• failure to implement or capitalize, or delays in implementing or capitalizing, on investment capital 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, investment capital projects, working capital requirements and the repayment or refinancing of indebtedness;
• the amplification of other risks caused by volatile or closed financial markets, capital constraints, liquidity concerns and inflation;
• the use or availability of third-party assets upon which our operations depend and over which we have little or no control;
• the currency exchange rate of the Canadian dollar to the United States dollar;
• the deferral of current revenue recognition attributable to deficiency payments received from customers who fail to ship or move their minimum contracted volumes;
• significant under-utilization of our assets and facilities;
• increased costs, or lack of availability, of insurance;
• 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; and
• other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil, as well as in the processing, transportation, fractionation, storage and marketing of NGL as discussed in the Partnerships’ filings with the Securities and Exchange Commission.

About Plains:

PAA is a publicly traded master limited partnership that owns and operates midstream energy infrastructure and provides logistics services for crude oil and natural gas liquids (“NGL”). PAA owns an extensive network of pipeline gathering and transportation systems, in addition to terminalling, storage, processing, fractionation and other infrastructure assets serving key producing basins, transportation corridors and major market hubs and export outlets in the United States and Canada. On average, PAA handles over 8 million barrels per day of crude oil and NGL.

PAGP 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.

PAA and PAGP are headquartered in Houston, Texas. For more information, please visit www.plains.com.

Contacts:

Blake Fernandez
Vice President, Investor Relations
(866) 809-1291

Michael Gladstein
Director, Investor Relations
(866) 809-1291

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