Plains All American Reports First-Quarter 2022 Results

Rhea-AI Summary

Plains All American Pipeline reported first-quarter 2022 results with a net income of $187 million and net cash from operations of $340 million. The company increased its full-year Adjusted EBITDA guidance by $75 million to approximately $2.275 billion. Permian gathering volumes are projected to grow by 280 thousand barrels per day. Notably, they raised the annual common distribution by $0.15 to $0.87 per unit and repurchased $25 million worth of common units. However, net income decreased by 56% compared to the previous year.

Positive

• Increased full-year Adjusted EBITDA guidance by $75 million to $2.275 billion.
• Forecasted Permian gathering volume growth of 280,000 barrels per day.
• Raised annual common distribution by $0.15 to $0.87 per unit.
• Repurchased $25 million of common units in Q1 2022.

Negative

• Net income decreased by 56% compared to Q1 2021.
• Net cash provided by operating activities fell by 57% year-over-year.
• Free Cash Flow declined by 71% to $200 million.

HOUSTON, May 04, 2022 (GLOBE NEWSWIRE) -- Plains All American Pipeline, L.P. (Nasdaq: PAA) and Plains GP Holdings (Nasdaq: PAGP) today reported first-quarter 2022 results and provided the following updates:

• Reported first-quarter Net income attributable to PAA of $187 million and Net cash provided by operating activities of $340 million
  
  
• Reported strong first-quarter Adjusted EBITDA attributable to PAA of $614 million and increased full-year 2022 Adjusted EBITDA attributable to PAA guidance by $75 million to +/- $2.275 billion
  
  
• Forecast Permian gathering volume growth of +/- 280 thousand barrels per day in 2022 (YE-21 to YE-22)
  
  
• Increased annualized common distribution by $0.15 to $0.87 per unit and repurchased $25 million of common units in the first quarter
  

“Our business is off to a positive start in 2022, supported by constructive, long-term fundamentals and a strong commodity price environment,” stated Willie Chiang, Chairman and CEO of Plains. “We delivered strong first-quarter results above our previous expectations and increased our 2022 Adjusted EBITDA guidance by $75 million to $2.275 billion, with a bias to the upside. Current global events have reaffirmed the importance of energy in everyday life and the need for reliable, secure and responsibly produced energy. Our integrated business model and asset base is critical to meeting global energy demand, and we are very well positioned to generate significant multi-year Free Cash Flow and maximize unitholder returns for years to come.”

Plains All American Pipeline

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

		Three Months Ended March 31,						%
GAAP Results			2022			2021		Change
Net income attributable to PAA		$	187		$	422		(56)	%
Diluted net income per common unit		$	0.19		$	0.51		(63)	%
Diluted weighted average common units outstanding			705			722		(2)	%
Net cash provided by operating activities		$	340		$	791		(57)	%
Distribution per common unit declared for the period		$	0.2175		$	0.18		21	%

		Three Months Ended March 31,						%
Non-GAAP Results (1)			2022			2021		Change
Adjusted net income attributable to PAA		$	266		$	232		15	%
Diluted adjusted net income per common unit		$	0.31		$	0.25		24	%
Adjusted EBITDA		$	690		$	546		26	%
Adjusted EBITDA attributable to PAA (2)		$	614		$	543		13	%
Implied DCF per common unit and common unit equivalent		$	0.56		$	0.51		10	%
Free Cash Flow		$	200		$	678		(71)	%
Free Cash Flow after Distributions		$	36		$	511		(93)	%

_____________________

⁽¹⁾ See the section of this release entitled “Non-GAAP Financial Measures and Selected Items Impacting Comparability” and the tables attached hereto for information regarding 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.

⁽²⁾ Excludes amounts attributable to noncontrolling interests in the Plains Oryx Permian Basin LLC joint venture (the “Permian JV’) and Red River Pipeline LLC.

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

	Segment Adjusted EBITDA(1) (2)
	Crude Oil				NGL
Three Months Ended March 31, 2022	$	453			$	161
Three Months Ended March 31, 2021	$	474			$	69
Percentage change in Segment Adjusted EBITDA versus 2021 period	(4)%					133	%
Percentage change in Segment Adjusted EBITDA versus 2021 period further adjusted for impact of divested assets (3)		3	%			133	%

_____________________

⁽¹⁾ During the fourth quarter of 2021, we modified our definition of Segment Adjusted EBITDA to exclude amounts attributable to noncontrolling interests. In connection with the Permian JV formation in October 2021, our Chief Operating Decision Maker (“CODM”) determined this modification resulted in amounts that were more meaningful to evaluate segment performance. Amounts for prior periods have been recast to reflect this modification.

⁽²⁾ During the fourth quarter of 2021, we effected changes in the primary financial information provided to our CODM (our Chief Executive Officer) for assessing performance and allocating resources to present two operating segments, Crude Oil and NGL. Prior to the fourth quarter of 2021, this information was organized into three operating segments: Transportation, Facilities and Supply and Logistics. The change in our segments is reflective of a change in how our CODM views our business and stems primarily from (i) a multi-year transition in the midstream energy industry driven by increased competition that has reduced the stand alone earnings opportunities of our supply and logistics activities such that those activities now primarily support our effort to increase the utilization of our Crude Oil and NGL assets and (ii) internal changes regarding the oversight and reporting of our assets and related results of operations. All segment data and related disclosures for earlier periods presented herein have been recast to reflect the new segment reporting structure.

⁽³⁾ Estimated impact of divestitures completed during 2021, assuming an effective date of January 1, 2021. Divested assets primarily included certain natural gas storage facilities previously included in our Crude Oil segment.

First-quarter 2022 Crude Oil Segment Adjusted EBITDA decreased 4% versus comparable 2021 results primarily due to (i) the sale of our natural gas storage facilities in August of 2021 and (ii) gains related to hedged power costs resulting from Winter Storm Uri recognized in the first quarter of 2021. These items were partially offset by increased earnings in the first quarter of 2022 from higher tariff volumes on our pipelines.

First-quarter 2022 NGL Segment Adjusted EBITDA increased 133% versus comparable 2021 results primarily due to the favorable impact of higher realized fractionation spreads and higher NGL sales prices, partially offset by lower NGL sales volumes.

Line 901 Update

Included in our results for the first quarter of 2022 is a net increase of $85 million in our estimate of aggregate total costs we have incurred or will incur with respect to the May 2015 Line 901 incident. Such net increase is included in the table attached to this release entitled “Selected Items Impacting Comparability” and is net of amounts we believe are probable of recovery from insurance. The increase in estimated costs includes, among other items, the combined impact of agreements in principle regarding the proposed settlement of two lawsuits that arose out of the Line 901 incident, a class action lawsuit pending in the United States District Court for the Central District of California (the “Class Action Lawsuit”) and a derivative lawsuit pending in the Delaware Chancery Court (the “Derivative Lawsuit”).

With respect to the Class Action Lawsuit, which involves claims by (i) a class of commercial fishermen and processors and (ii) a class of beachfront and shoreline property owners, Plains has agreed to pay $230 million to fully and finally settle all of the plaintiff’s claims. We believe these claims are covered by insurance and, subject to our policy limits, we expect a significant portion of this settlement will be recoverable from our insurance carriers. The settlement is subject to negotiation of final documentation and approval of the trial court.

With respect to the Derivative Lawsuit, wherein the plaintiff alleges that PAGP's Board of Directors failed to exercise proper oversight over PAA’s pipeline integrity efforts, Plains has agreed to settle the lawsuit in exchange for (i) the payment by us of approximately $2 million of attorney’s fees to plaintiff’s counsel (which amount our director and officer insurance provider has agreed to pay) and (ii) non-monetary compensation in the form of the agreement of Plains to comply with various covenants regarding the implementation and/or continuation of certain Board oversight practices with respect to pipeline integrity. The settlement is subject to court approval and notice to all PAA unitholders, which will be effected following Chancery Court approval via the filing by PAA with the Securities and Exchange Commission of a Current Report on Form 8-K.

We have made adjustments to our total estimated Line 901 costs that incorporate the anticipated settlements described above and general refinements of previous cost estimates, and we have adjusted the receivable we recognized for costs related to the Line 901 incident that we believe are probable of recovery from insurance carriers, net of deductibles. Effective as of March 31, 2022, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will increase by $230 million to $725 million, of which the remaining undiscounted net liability is approximately $95 million, consisting of approximately $335 million of gross remaining liability offset by approximately $240 million of remaining costs that we expect to recover from insurance. Full collection of the amounts we believe are recoverable from our insurance carriers will reach the limit of our $500 million 2015 insurance program applicable to the Line 901 incident.

Taking into account the costs that we have included in our total estimate of costs for the Line 901 incident and considering what we regard as very strong defenses to the claims made in our remaining Line 901 lawsuits, we do not believe the ultimate resolution of such remaining lawsuits will have material adverse effect on our consolidated financial condition, results of operations or cash flows.

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

PAA and PAGP will hold a joint conference call at 4:00 p.m. CT on Wednesday, May 4, 2022 to discuss the following items:

1. PAA’s first-quarter 2022 performance;
2. Capitalization and liquidity; and
3. Financial and operating guidance.
   

Conference Call Webcast Instructions

To access the internet webcast, please go to https://edge.media-server.com/mmc/p/hq8d7unf.

Alternatively, the webcast can be accessed on our website (www.plains.com) under Investor Relations (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 our website within two hours after the end of the call and will be accessible for a period of 365 days. Slides will be posted prior to the call and a complete transcript will be posted after the call at the above referenced website.

Non-GAAP Financial Measures and Selected Items Impacting Comparability

To supplement our financial information presented in accordance with GAAP, management uses additional measures known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the future 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”), Free Cash Flow and Free Cash Flow after Distributions.

Adjusted EBITDA is defined as earnings before interest, taxes, depreciation and amortization (including our proportionate share of depreciation and amortization, including write-downs related to cancelled projects, of unconsolidated entities), gains and losses on asset sales and asset impairments, goodwill impairment losses and gains on and impairments of investments in unconsolidated entities, adjusted for certain selected items impacting comparability. 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 Free Cash Flow and Free Cash Flow after Distributions 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.

Performance Measures

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 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. All 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.

Liquidity Measures

Management also uses the non-GAAP financial measures Free Cash Flow and 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. Free Cash Flow is defined as Net Cash Provided by Operating Activities, less Net Cash 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 and base gas, net of proceeds from the sales of assets and further impacted by cash received from or paid to noncontrolling interests. Free Cash Flow is further reduced by cash distributions paid to our preferred and common unitholders to arrive at Free Cash Flow after Distributions.

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,
	2022				2021
REVENUES	$	13,694			$	8,383
COSTS AND EXPENSES
Purchases and related costs		12,785				7,392
Field operating costs		346				219
General and administrative expenses		82				67
Depreciation and amortization		230				177
(Gains)/losses on asset sales and asset impairments, net		(42	)			2
Total costs and expenses		13,401				7,857
OPERATING INCOME		293				526
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities		97				88
Interest expense, net		(107	)			(107	)
Other expense, net		(37	)			(60	)
INCOME BEFORE TAX		246				447
Current income tax expense		(19	)			(1	)
Deferred income tax expense		(2	)			(23	)
NET INCOME		225				423
Net income attributable to noncontrolling interests		(38	)			(1	)
NET INCOME ATTRIBUTABLE TO PAA	$	187			$	422
NET INCOME PER COMMON UNIT:
Net income allocated to common unitholders — Basic and Diluted	$	137			$	371
Basic and diluted weighted average common units outstanding		705				722
Basic and diluted net income per common unit	$	0.19			$	0.51

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

CONDENSED CONSOLIDATED BALANCE SHEET DATA
(in millions)

	March 31, 2022			December 31, 2021
ASSETS
Current assets (including Cash and cash equivalents of $114 and $449, respectively)	$	8,097		$	6,137
Property and equipment, net		14,864			14,903
Investments in unconsolidated entities		3,807			3,805
Intangible assets, net		1,901			1,960
Linefill		919			907
Long-term operating lease right-of-use assets, net		387			393
Long-term inventory		374			253
Other long-term assets, net		293			251
Total assets	$	30,642		$	28,609
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	8,570		$	6,232
Senior notes, net		7,931			8,329
Other long-term debt, net		55			69
Long-term operating lease liabilities		331			339
Other long-term liabilities and deferred credits		901			830
Total liabilities		17,788			15,799
Partners’ capital excluding noncontrolling interests		10,043			9,972
Noncontrolling interests		2,811			2,838
Total partners’ capital		12,854			12,810
Total liabilities and partners’ capital	$	30,642		$	28,609

DEBT CAPITALIZATION RATIOS
(in millions)

	March 31, 2022				December 31, 2021
Short-term debt	$	900			$	822
Long-term debt		7,986				8,398
Total debt	$	8,886			$	9,220
Long-term debt	$	7,986			$	8,398
Partners’ capital excluding noncontrolling interests		10,043				9,972
Total book capitalization excluding noncontrolling interests (“Total book capitalization”)	$	18,029			$	18,370
Total book capitalization, including short-term debt	$	18,929			$	19,192
Long-term debt-to-total book capitalization		44	%			46	%
Total debt-to-total book capitalization, including short-term debt		47	%			48	%

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,
	2022				2021
Basic and Diluted Net Income per Common Unit
Net income attributable to PAA	$	187			$	422
Distributions to Series A preferred unitholders		(37	)			(37	)
Distributions to Series B preferred unitholders		(12	)			(12	)
Other		(1	)			(2	)
Net income allocated to common unitholders	$	137			$	371
Basic and diluted weighted average common units outstanding (2) (3)		705				722
Basic and diluted net income per common unit	$	0.19			$	0.51

_____________________

⁽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⁾ The possible conversion of our Series A preferred units was excluded from the calculation of diluted net income per common unit for the three months ended March 31, 2022 and 2021 as the effect was antidilutive.

⁽³⁾ Our equity-indexed compensation plan awards that contemplate the issuance of common units are considered 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. For the three months ended March 31, 2022 and 2021, the effect of equity-indexed compensation plan awards was antidilutive, or did not change the presentation of diluted weighted average common units outstanding or diluted net income per common unit.

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

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

	Three Months Ended March 31,
	2022				2021
Basic and Diluted Adjusted Net Income per Common Unit
Net income attributable to PAA	$	187			$	422
Selected items impacting comparability - Adjusted net income attributable to PAA (2)		79				(190	)
Adjusted net income attributable to PAA	$	266			$	232
Distributions to Series A preferred unitholders		(37	)			(37	)
Distributions to Series B preferred unitholders		(12	)			(12	)
Other		(1	)			(1	)
Adjusted net income allocated to common unitholders	$	216			$	182
Basic and diluted weighted average common units outstanding (3) (4)		705				722
Basic and diluted adjusted net income per common unit	$	0.31			$	0.25

____________________

⁽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⁾ Certain of our non-GAAP financial measures may not be impacted by each of the selected items impacting comparability. See the “Selected Items Impacting Comparability” table for additional information.

⁽³⁾ The possible conversion of our Series A preferred units was excluded from the calculation of diluted net income per common unit for the three months ended March 31, 2022 and 2021 as the effect was antidilutive.

⁽⁴⁾ Our equity-indexed compensation plan awards that contemplate the issuance of common units are considered 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. For the three months ended March 31, 2022 and 2021, the effect of equity-indexed compensation plan awards was antidilutive, or did not change the presentation of diluted weighted average common units outstanding or diluted adjusted net income per common unit.

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

	Three Months Ended March 31,
	2022			2021
Basic and diluted net income per common unit	$	0.19		$	0.51
Selected items impacting comparability per common unit (1)		0.12			(0.26	)
Basic and diluted adjusted net income per common unit	$	0.31		$	0.25

____________________

⁽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)

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

Net Income to Adjusted EBITDA attributable to PAA and Implied DCF Reconciliation:

	Three Months Ended March 31,
	2022				2021
Net Income	$	225			$	423
Interest expense, net		107				107
Income tax expense		21				24
Depreciation and amortization		230				177
(Gains)/losses on asset sales and asset impairments, net		(42	)			2
Depreciation and amortization of unconsolidated entities (1)		20				20
Selected items impacting comparability - Adjusted EBITDA (2)		129				(207	)
Adjusted EBITDA	$	690			$	546
Adjusted EBITDA attributable to noncontrolling interests		(76	)			(3	)
Adjusted EBITDA attributable to PAA	$	614			$	543
Adjusted EBITDA	$	690			$	546
Interest expense, net of certain non-cash items (3)		(101	)			(101	)
Maintenance capital		(27	)			(35	)
Investment capital of noncontrolling interests (4)		(15	)			—
Current income tax expense		(19	)			(1	)
Distributions from unconsolidated entities in excess of/(less than) adjusted equity earnings (5)		(31	)			5
Distributions to noncontrolling interests (6)		(59	)			(6	)
Implied DCF	$	438			$	408
Preferred unit distributions paid (6)		(37	)			(37	)
Implied DCF Available to Common Unitholders	$	401			$	371
Weighted Average Common Units Outstanding		705				722
Weighted Average Common Units and Common Unit Equivalents		776				793
Implied DCF per Common Unit (7)	$	0.57			$	0.51
Implied DCF per Common Unit and Common Unit Equivalent (8)	$	0.56			$	0.51
Cash Distribution Paid per Common Unit	$	0.18			$	0.18
Common Unit Cash Distributions (6)	$	127			$	130
Common Unit Distribution Coverage Ratio	3.16x				2.85x
Implied DCF Excess	$	274			$	241

_____________________

⁽¹⁾ Adjustment to exclude our proportionate share of depreciation and amortization expense (including write-downs related to cancelled projects) of unconsolidated entities.

⁽²⁾ See the “Selected Items Impacting Comparability” table for additional information.

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

⁽⁴⁾ Investment capital expenditures attributable to noncontrolling interests that reduce Implied DCF available to PAA common unitholders.

⁽⁵⁾ 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 selected items impacting comparability of unconsolidated entities).

⁽⁶⁾ Cash distributions paid during the period presented.

⁽⁷⁾ Implied DCF Available to Common Unitholders for the period divided by the weighted average common units outstanding for the period.

⁽⁸⁾ Implied DCF Available to Common Unitholders for the period, adjusted for Series A preferred unit cash distributions paid, 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)

NON-GAAP RECONCILIATIONS (continued)

Net Income Per Common Unit to Implied DCF Per Common Unit and Common Unit Equivalent Reconciliation:

	Three Months Ended March 31,
	2022			2021
Basic net income per common unit	$	0.19		$	0.51
Reconciling items per common unit (1) (2)		0.38			—
Implied DCF per common unit	$	0.57		$	0.51
Basic net income per common unit	$	0.19		$	0.51
Reconciling items per common unit and common unit equivalent (1) (3)		0.37			—
Implied DCF per common unit and common unit equivalent	$	0.56		$	0.51

_____________________

⁽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 period of 705 million and 722 million, respectively.

⁽³⁾ Based on weighted average common units outstanding for the period, as well as weighted average Series A preferred units outstanding of 71 million for each of the periods presented.

Free Cash Flow and Free Cash Flow after Distributions Reconciliation ⁽¹⁾:

	Three Months Ended March 31,
	2022				2021
Net cash provided by operating activities	$	340			$	791
Adjustments to reconcile net cash provided by operating activities to free cash flow:
Net cash used in investing activities		(81	)			(108	)
Cash contributions from noncontrolling interests		—				1
Cash distributions paid to noncontrolling interests (2)		(59	)			(6	)
Free Cash Flow	$	200			$	678
Cash distributions (3)		(164	)			(167	)
Free Cash Flow after Distributions	$	36			$	511

_____________________

⁽¹⁾ Management uses the Non-GAAP financial liquidity measures Free Cash Flow and 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.

⁽²⁾ Cash distributions paid during the period presented.

⁽³⁾ Cash distributions paid to preferred and common unitholders during the period.

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

SELECTED ITEMS IMPACTING COMPARABILITY
(in millions)

	Three Months Ended March 31,
	2022				2021
Selected Items Impacting Comparability: (1)
Gains/(losses) from derivative activities and inventory valuation adjustments (2)	$	(132	)		$	131
Long-term inventory costing adjustments (3)		92				41
Deficiencies under minimum volume commitments, net (4)		(6	)			32
Equity-indexed compensation expense (5)		(7	)			(5	)
Net gain on foreign currency revaluation (6)		9				8
Line 901 incident (7)		(85	)			—
Selected items impacting comparability - Adjusted EBITDA	$	(129	)		$	207
Gains/(losses) on asset sales and asset impairments, net		42				(2	)
Tax effect on selected items impacting comparability		8				(15	)
Selected items impacting comparability - Adjusted net income attributable to PAA	$	(79	)		$	190

______________________

⁽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” table 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 of operations, 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.

⁽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 investments, 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, or our equity method investees, 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, or our equity method investees, 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. These gains and losses are not integral to our core operating performance and were thus classified as a selected item impacting comparability.

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


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

SELECTED FINANCIAL DATA BY SEGMENT
(in millions)

	Three Months Ended March 31, 2022									Three Months Ended March 31, 2021
	Crude Oil				NGL					Crude Oil				NGL
Revenues (1)	$	13,079			$	735				$	7,853			$	639
Purchases and related costs (1)		(12,393	)			(512	)				(7,047	)			(454	)
Field operating costs (2)		(282	)			(64	)				(165	)			(54	)
Segment general and administrative expenses (2) (3)		(63	)			(19	)				(50	)			(17	)
Equity earnings in unconsolidated entities		97				—					88				—
Adjustments: (4)
Depreciation and amortization of unconsolidated entities		20				—					20				—
(Gains)/losses from derivative activities and inventory valuation adjustments		59				29					(159	)			(39	)
Long-term inventory costing adjustments		(85	)			(7	)				(35	)			(6	)
Deficiencies under minimum volume commitments, net		6				—					(32	)			—
Equity-indexed compensation expense		7				—					5				—
Net gain on foreign currency revaluation		(1	)			(1	)				(1	)			—
Line 901 incident		85				—					—				—
Adjusted EBITDA attributable to noncontrolling interests (5)		(76	)			—					(3	)			—
Segment Adjusted EBITDA (6)	$	453			$	161				$	474			$	69
Maintenance capital	$	19			$	8				$	28			$	7

________________________

⁽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 (beginning October 2021) and Red River Pipeline LLC.

⁽⁶⁾ During the fourth quarter of 2021, we modified our definition of Segment Adjusted EBITDA to exclude amounts attributable to noncontrolling interests. In connection with the Permian JV formation in October 2021, our CODM determined this modification resulted in amounts that were more meaningful to evaluate segment performance. Amounts attributable to noncontrolling interests for periods prior have been recast to reflect this modification.

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

OPERATING DATA BY SEGMENT ⁽¹⁾

	Three Months Ended March 31,
	2022		2021
Crude Oil Segment Volumes
Crude oil pipeline tariff volumes (by region) (1):
Permian Basin (2)	5,214		3,753
South Texas / Eagle Ford (2)	365		320
Mid-Continent (2)	472		373
Gulf Coast	196		145
Rocky Mountain (2)	346		287
Western	235		237
Canada	331		315
Crude oil pipeline tariff volumes (average volumes in thousands of barrels per day) (1) (2)	7,159		5,430
Commercial crude oil storage capacity (average monthly volumes in millions of barrels) (2) (3)	72		73
Crude oil lease gathering purchases (average volumes in thousands of barrels per day) (1)	1,361		1,174
NGL Segment Volumes
NGL fractionation (average volumes in thousands of barrels per day) (1)	134		144
NGL pipeline tariff volumes (average volumes in thousands of barrels per day) (1)	176		183
NGL sales (average volumes in thousands of barrels per day) (1)	168		220

_______________________

⁽¹⁾ Average daily volumes calculated as the total volumes (attributable to our interest for pipelines owned by unconsolidated entities or undivided joint interests) for the period divided by the number of days in the period. Volumes associated with acquisitions 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.

⁽³⁾ Average monthly capacity calculated as total volumes for the period divided by the number of months in the period.

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

NON-GAAP SEGMENT RECONCILIATIONS
(in millions)

Segment Adjusted EBITDA to Adjusted EBITDA attributable to PAA Reconciliation:

	Three Months Ended March 31,
	2022			2021
Crude Oil Segment Adjusted EBITDA	$	453		$	474
NGL Segment Adjusted EBITDA		161			69
Segment Adjusted EBITDA	$	614		$	543
Adjusted other income/(expense), net (1)		—			—
Adjusted EBITDA attributable to PAA (2)	$	614		$	543

_______________________

⁽¹⁾ Represents “Other expense, net” as reported on our Condensed Consolidated Statements of Operations, adjusted for selected items impacting comparability of $37 million and $60 million for the three months ended March 31, 2022 and 2021, respectively. See the “Selected Items Impacting Comparability” table for additional information. Adjusted other income/(expense), net attributable to noncontrolling interests is less than $1 million for each of the periods presented.

⁽²⁾ See the “Net Income to Adjusted EBITDA attributable to PAA and Implied DCF Reconciliation” table for reconciliation to Net Income.

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

	Three Months Ended March 31, 2022							Three Months Ended March 31, 2021
	Crude Oil			NGL				Crude Oil				NGL
Segment Adjusted EBITDA	$	453		$	161			$	474			$	69
Impact of divested assets (1)		—			—				(35	)			—
Segment Adjusted EBITDA further adjusted for impact of divested assets	$	453		$	161			$	439			$	69

⁽¹⁾ Estimated impact of divestitures completed during 2021, assuming an effective date of January 1, 2021. Divested assets primarily included certain natural gas storage facilities previously included in our Crude Oil segment. Note: The natural gas storage business captured one-time benefits from Winter Storm Uri in the first quarter 2021.

PLAINS GP HOLDINGS AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)

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

	Three Months Ended March 31, 2022													Three Months Ended March 31, 2021
					Consolidating													Consolidating
	PAA				Adjustments(1)				PAGP					PAA				Adjustments(1)				PAGP
REVENUES	$	13,694			$	—			$	13,694				$	8,383			$	—			$	8,383
COSTS AND EXPENSES
Purchases and related costs		12,785				—				12,785					7,392				—				7,392
Field operating costs		346				—				346					219				—				219
General and administrative expenses		82				1				83					67				1				68
Depreciation and amortization		230				1				231					177				1				178
(Gains)/losses on asset sales and asset impairments, net		(42	)			—				(42	)				2				—				2
Total costs and expenses		13,401				2				13,403					7,857				2				7,859
OPERATING INCOME		293				(2	)			291					526				(2	)			524
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities		97				—				97					88				—				88
Interest expense, net		(107	)			—				(107	)				(107	)			—				(107	)
Other expense, net		(37	)			—				(37	)				(60	)			—				(60	)
INCOME BEFORE TAX		246				(2	)			244					447				(2	)			445
Current income tax expense		(19	)			—				(19	)				(1	)			—				(1	)
Deferred income tax expense		(2	)			(14	)			(16	)				(23	)			(29	)			(52	)
NET INCOME		225				(16	)			209					423				(31	)			392
Net income attributable to noncontrolling interests		(38	)			(149	)			(187	)				(1	)			(321	)			(322	)
NET INCOME ATTRIBUTABLE TO PAGP	$	187			$	(165	)		$	22				$	422			$	(352	)		$	70
BASIC AND DILUTED WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING										194													194
BASIC AND DILUTED NET INCOME PER CLASS A SHARE									$	0.11												$	0.36

______________________

⁽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, 2022											December 31, 2021
				Consolidating											Consolidating
	PAA			Adjustments (1)				PAGP				PAA			Adjustments (1)				PAGP
ASSETS
Current assets	$	8,097		$	3			$	8,100			$	6,137		$	3			$	6,140
Property and equipment, net		14,864			5				14,869				14,903			6				14,909
Investments in unconsolidated entities		3,807			—				3,807				3,805			—				3,805
Intangible assets, net		1,901			—				1,901				1,960			—				1,960
Deferred tax asset		—			1,341				1,341				—			1,362				1,362
Linefill		919			—				919				907			—				907
Long-term operating lease right-of-use assets, net		387			—				387				393			—				393
Long-term inventory		374			—				374				253			—				253
Other long-term assets, net		293			—				293				251			(2	)			249
Total assets	$	30,642		$	1,349			$	31,991			$	28,609		$	1,369			$	29,978
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	8,570		$	2			$	8,572			$	6,232		$	2			$	6,234
Senior notes, net		7,931			—				7,931				8,329			—				8,329
Other long-term debt, net		55			—				55				69			—				69
Long-term operating lease liabilities		331			—				331				339			—				339
Other long-term liabilities and deferred credits		901			—				901				830			—				830
Total liabilities		17,788			2				17,790				15,799			2				15,801
Partners’ capital excluding noncontrolling interests		10,043			(8,503	)			1,540				9,972			(8,439	)			1,533
Noncontrolling interests		2,811			9,850				12,661				2,838			9,806				12,644
Total partners’ capital		12,854			1,347				14,201				12,810			1,367				14,177
Total liabilities and partners’ capital	$	30,642		$	1,349			$	31,991			$	28,609		$	1,369			$	29,978

_______________________

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

PLAINS GP HOLDINGS AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)

COMPUTATION OF BASIC AND DILUTED NET INCOME PER CLASS A SHARE ⁽¹⁾
(in millions, except per share data)

	Three Months Ended March 31,
	2022			2021
Basic and Diluted Net Income per Class A Share
Net income attributable to PAGP	$	22		$	70
Basic and diluted weighted average Class A shares outstanding		194			194
Basic and diluted net income per Class A share	$	0.11		$	0.36

______________________

⁽¹⁾ For the three months ended March 31, 2022 and 2021, the possible exchange of AAP units and AAP Management units would not have had a dilutive effect on basic net income per Class A share.

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:

• declines in global crude oil demand and crude oil prices (whether due to the COVID-19 pandemic, future pandemics or other factors) that correspondingly lead to a significant reduction of North American crude oil and natural gas liquids (“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 commercial opportunities that might otherwise be available to us;
• the effects of competition and capacity overbuild in areas where we operate, including 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;
• 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;
• unanticipated changes in crude oil and NGL market structure, grade differentials and volatility (or lack thereof);
• 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 continued supply chain issues, the impact of coronavirus variants on growth, and the timing, pace and extent of economic recovery) that impact demand for crude oil, drilling and production activities and therefore the demand for the midstream services we provide and commercial opportunities available to us;
• the impact of current and future laws, rulings, governmental regulations, executive orders, trade policies, accounting standards and statements, and related interpretations, including legislation, executive orders or regulatory initiatives that arise out of pandemic related concerns, that prohibit, restrict or regulate hydraulic fracturing or that prohibit the development of oil and gas resources and the related infrastructure on lands dedicated to or served by our pipelines;
• environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;
• loss of key personnel and inability to attract and retain new talent;
• fluctuations in refinery capacity in areas supplied by our mainlines and other factors affecting demand for various grades of crude oil and NGL and resulting changes in pricing conditions or transportation throughput requirements;
• 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, divestitures, joint ventures, acquisitions or other strategic opportunities;
• maintenance of our credit rating and ability to receive open credit from our suppliers and trade counterparties;
• the occurrence of a natural disaster, catastrophe, terrorist attack (including eco-terrorist attacks) or other event that materially impacts our operations, including cyber or other attacks on our electronic and computer systems;
• weather interference with business operations or project construction, including the impact of extreme weather events or conditions;
• 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;
• 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, legal constraints (including governmental orders or guidance), or other factors or events;
• the incurrence of costs and expenses related to unexpected or unplanned capital expenditures, third-party claims or other factors;
• disruptions to futures markets for crude oil, NGL and other petroleum products, which may impair our ability to execute our commercial or hedging strategies;
• 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;
• shortages or cost increases of supplies, materials or labor;
• 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 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;
• 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;
• significant under-utilization of our assets and facilities;
• increased costs, or lack of availability, of insurance;
• the effectiveness of our risk management activities;
• fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our long-term incentive plans;
• risks related to the development and operation of our assets; 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 more than 6 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:

Roy Lamoreaux

Vice President, Investor Relations, Communications and Government Relations

(866) 809-1291

Michael Gladstein

Director, Investor Relations

(866) 809-1291

FAQ

What were Plains All American Pipeline's Q1 2022 results?

Plains reported a net income of $187 million, with net cash provided by operating activities at $340 million.

How much did Plains increase its Adjusted EBITDA guidance for 2022?

The company increased its full-year Adjusted EBITDA guidance by $75 million to approximately $2.275 billion.

What is the forecasted growth in Permian gathering volumes for Plains in 2022?

Plains forecasts a growth of 280,000 barrels per day in Permian gathering volumes.

What is the new annual common distribution per unit for Plains?

The annual common distribution has been raised by $0.15 to $0.87 per unit.

How much free cash flow did Plains report in Q1 2022?

Plains reported free cash flow of $200 million in Q1 2022, a decline of 71% year-over-year.