Plains All American Reports Fourth-Quarter and Full-Year 2023 Results; Announces 2024 Guidance

Plains All American Pipeline, L.P.; Plains GP Holdings

HOUSTON, Feb. 09, 2024 (GLOBE NEWSWIRE) -- Plains All American Pipeline, L.P. (Nasdaq: PAA) and Plains GP Holdings (Nasdaq: PAGP) today reported fourth-quarter and full-year 2023 results, announced 2024 guidance and provided the following highlights:

2023 Highlights

• Fourth-quarter and full-year 2023 Net income attributable to PAA of $312 million and $1.23 billion, respectively, and 2023 Net cash provided by operating activities of $1.01 billion and $2.73 billion, respectively
  
  

• Delivered strong fourth-quarter and full-year 2023 Adjusted EBITDA attributable to PAA above the top-end of guidance with $737 million and $2.71 billion, respectively
  
  

• Generated full-year 2023 Adjusted Free Cash Flow (excluding changes in Assets & Liabilities) of $1.60 billion and achieved year-end leverage of 3.1x
  
  

• Delivered on commitment to increase cash return to equity holders by increasing distributions $0.20 per unit annualized in February 2023, representing a 23% aggregate increase in the annualized distribution versus 2022 levels
  
  

• High graded the asset base through continued portfolio optimization including two asset sales and three bolt-on acquisitions
  
  

• Received two credit rating agency upgrades demonstrating progress on deleveraging efforts and our target to achieve BBB credit ratings
  

2024 Outlook

• Expect full-year 2024 Adjusted EBITDA attributable to PAA of $2.625 - $2.725 billion
  
  

• Reaffirming leverage ratio target range of 3.25x - 3.75x reflecting commitment to balance sheet strength and flexibility
  
  

• Board approved increasing the annualized common distribution by $0.20 to $1.27 per unit commencing in February 2024, representing a 19% aggregate increase in the annualized distribution versus 2023 levels
  
  

• Expect to generate approximately $1.65 billion of Adjusted Free Cash Flow (excluding changes in Assets & Liabilities) and $500 million of Adjusted Free Cash Flow after Distributions (excluding changes in Assets & Liabilities)
  
  

• Remain focused on disciplined capital investments, anticipating full-year 2024 Investment and Maintenance Capital of +/- $375 million and +/- $230 million, net to PAA, respectively
  

“Strong execution in 2023 drove better-than-expected results and allowed us to accelerate progress on our long-term goals and objectives. This included lowering our leverage ratio target range, increasing capital returns to equity holders through increased distributions, and completing multiple win-win strategic transactions in both our Crude Oil and NGL segments,” said Willie Chiang, Chairman and CEO of Plains. “Looking forward to 2024, Plains remains well-positioned to deliver value to our unitholders through our continued focus on generating strong free cash flow, capital discipline, and increasing returns to unitholders all while maintaining our financial flexibility.”

Plains All American Pipeline

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

		Three Months Ended December 31,						%				Twelve Months Ended December 31,						%
GAAP Results		2023			2022			Change				2023			2022			Change
Net income attributable to PAA (1)		$	312		$	263		19	%			$	1,230		$	1,037		19	%
Diluted net income per common unit		$	0.35		$	0.30		17	%			$	1.40		$	1.19		18	%
Diluted weighted average common units outstanding			701			698		—	%				699			701		—	%
Net cash provided by operating activities		$	1,011		$	335		202	%			$	2,727		$	2,408		13	%
Distribution per common unit declared for the period		$	0.3175		$	0.2675		19	%			$	1.1200		$	0.9200		22	%

____________________

(1)	Reported results for the three and twelve months ended December 31, 2022 include a non-cash asset impairment of $330 million related to our California assets and a non-cash gain on investments in unconsolidated entities of approximately $370 million related to our purchase of an additional interest in the Cactus II pipeline.

		Three Months Ended December 31,							%				Twelve Months Ended December 31,						%
Non-GAAP Results (1)		2023			2022				Change				2023			2022			Change
Adjusted net income attributable to PAA		$	355		$	286			24	%			$	1,250		$	1,091		15	%
Diluted adjusted net income per common unit		$	0.42		$	0.33			27	%			$	1.42		$	1.26		13	%
Adjusted EBITDA		$	875		$	759			15	%			$	3,167		$	2,875		10	%
Adjusted EBITDA attributable to PAA (2)		$	737		$	659			12	%			$	2,711		$	2,510		8	%
Implied DCF per common unit and common unit equivalent		$	0.68		$	0.58			17	%			$	2.46		$	2.26		9	%
Adjusted Free Cash Flow (3)		$	710		$	(4	)		**				$	1,798		$	1,610		12	%
Adjusted Free Cash Flow after Distributions		$	458		$	(218	)		**				$	809		$	828		(2	)%
Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities)		$	402		$	236			70	%			$	1,604		$	1,801		(11	)%
Adjusted Free Cash Flow after Distributions (Excluding Changes in Assets & Liabilities)		$	150		$	22			**				$	615		$	1,019		(40	)%

____________________

**      Indicates that variance as a percentage is not meaningful.

(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, Cactus II Pipeline LLC and Red River Pipeline LLC.
(3)	Fourth-quarter 2022 Adjusted Free Cash Flow is impacted by a $230 million payment related to the settlement of a Line 901 class action lawsuit.

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

	Segment Adjusted EBITDA
	Crude Oil				NGL
Three Months Ended December 31, 2023	$	563			$	169
Three Months Ended December 31, 2022	$	504			$	151
Percentage change in Segment Adjusted EBITDA versus 2022 period		12	%			12	%
	Segment Adjusted EBITDA
	Crude Oil				NGL
Twelve Months Ended December 31, 2023	$	2,163			$	522
Twelve Months Ended December 31, 2022	$	1,986			$	518
Percentage change in Segment Adjusted EBITDA versus 2022 period		9	%			1	%

Fourth-quarter 2023 Crude Oil Segment Adjusted EBITDA increased 12% versus comparable 2022 results primarily due to higher volumes across our pipeline systems, contributions from acquisitions and the benefit of tariff escalation, partially offset by fewer market-based opportunities for our merchant activities.

Fourth-quarter 2023 NGL Segment Adjusted EBITDA increased 12% versus comparable 2022 results primarily due to favorable NGL basis differentials and additional market-based opportunities partially offset by the divestiture of our interest in the KFS facility and increased field operating costs.

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, February 9, 2024 to discuss fourth-quarter performance and related items.

To access the internet webcast, please go to https://edge.media-server.com/mmc/p/ukgq4wwt/.

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 / 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 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 interest expense, income tax (expense)/benefit, depreciation and amortization (including our proportionate share of depreciation and amortization, including write-downs related to cancelled projects and impairments, of unconsolidated entities), gains and losses on asset sales and asset impairments and gains or losses on investments in unconsolidated entities, 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 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 Annual Report on Form 10-K.

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. 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 December 31,								Twelve Months Ended December 31,
	2023				2022				2023				2022
REVENUES	$	12,698			$	12,952			$	48,712			$	57,342
COSTS AND EXPENSES
Purchases and related costs		11,558				11,995				44,531				53,176
Field operating costs		363				343				1,425				1,315
General and administrative expenses		87				82				350				325
Depreciation and amortization		273				254				1,048				965
(Gains)/losses on asset sales and asset impairments, net		(9	)			315				(152	)			269
Total costs and expenses		12,272				12,989				47,202				56,050
OPERATING INCOME/(LOSS)		426				(37	)			1,510				1,292
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities		92				96				369				403
Gains/(losses) on investments in unconsolidated entities, net		—				345				28				346
Interest expense, net		(97	)			(100	)			(386	)			(405	)
Other income/(expense), net		17				18				102				(219	)
INCOME BEFORE TAX		438				322				1,623				1,417
Current income tax expense		(41	)			(24	)			(145	)			(84	)
Deferred income tax (expense)/benefit		2				12				24				(105	)
NET INCOME		399				310				1,502				1,228
Net income attributable to noncontrolling interests		(87	)			(47	)			(272	)			(191	)
NET INCOME ATTRIBUTABLE TO PAA	$	312			$	263			$	1,230			$	1,037
NET INCOME PER COMMON UNIT:
Net income allocated to common unitholders — Basic and Diluted	$	248			$	210			$	976			$	831
Basic and diluted weighted average common units outstanding		701				698				699				701
Basic and diluted net income per common unit	$	0.35			$	0.30			$	1.40			$	1.19

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

CONDENSED CONSOLIDATED BALANCE SHEET DATA
(in millions)

	December 31, 2023			December 31, 2022
ASSETS
Current assets (including Cash and cash equivalents of $450 and $401, respectively)	$	4,913		$	5,355
Property and equipment, net		15,782			15,250
Investments in unconsolidated entities		2,820			3,084
Intangible assets, net		1,875			2,145
Linefill		976			961
Long-term operating lease right-of-use assets, net		313			349
Long-term inventory		265			284
Other long-term assets, net		411			464
Total assets	$	27,355		$	27,892
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	5,003		$	5,891
Senior notes, net		7,242			7,237
Other long-term debt, net		63			50
Long-term operating lease liabilities		274			308
Other long-term liabilities and deferred credits		1,041			1,081
Total liabilities		13,623			14,567
Partners’ capital excluding noncontrolling interests		10,422			10,057
Noncontrolling interests		3,310			3,268
Total partners’ capital		13,732			13,325
Total liabilities and partners’ capital	$	27,355		$	27,892

DEBT CAPITALIZATION RATIOS
(in millions)

	December 31, 2023				December 31, 2022
Short-term debt	$	446			$	1,159
Long-term debt		7,305				7,287
Total debt	$	7,751			$	8,446
Long-term debt	$	7,305			$	7,287
Partners’ capital excluding noncontrolling interests		10,422				10,057
Total book capitalization excluding noncontrolling interests (“Total book capitalization”)	$	17,727			$	17,344
Total book capitalization, including short-term debt	$	18,173			$	18,503
Long-term debt-to-total book capitalization		41	%			42	%
Total debt-to-total book capitalization, including short-term debt		43	%			46	%

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 December 31,								Twelve Months Ended December 31,
	2023				2022				2023				2022
Basic and Diluted Net Income per Common Unit
Net income attributable to PAA	$	312			$	263			$	1,230			$	1,037
Distributions to Series A preferred unitholders		(44	)			(37	)			(173	)			(149	)
Distributions to Series B preferred unitholders		(20	)			(15	)			(76	)			(52	)
Amounts allocated to participating securities		(1	)			(1	)			(10	)			(5	)
Other		1				—				5				—
Net income allocated to common unitholders	$	248			$	210			$	976			$	831
Basic and diluted weighted average common units outstanding (2) (3)		701				698				699				701
Basic and diluted net income per common unit	$	0.35			$	0.30			$	1.40			$	1.19

____________________

(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 and twelve months ended December 31, 2023 and 2022 as the effect was either antidilutive or did not change net income per common unit.
(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.

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

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)

	Twelve Months Ended December 31, 2023
	2023				2022
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	1,502			$	1,228
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization		1,048				965
(Gains)/losses on asset sales and asset impairments, net		(152	)			269
Deferred income tax expense/(benefit)		(24	)			105
Change in fair value of Preferred Distribution Rate Reset Option		(58	)			189
Equity earnings in unconsolidated entities		(369	)			(403	)
Distributions on earnings from unconsolidated entities		458				488
(Gains)/losses on investments in unconsolidated entities, net		(28	)			(346	)
Other		156				104
Changes in assets and liabilities, net of acquisitions		194				(191	)
Net cash provided by operating activities		2,727				2,408
CASH FLOWS FROM INVESTING ACTIVITIES
Net cash used in investing activities		(702	)			(526	)
CASH FLOWS FROM FINANCING ACTIVITIES
Net cash used in financing activities		(1,976	)			(1,931	)
Effect of translation adjustment		—				(3	)
Net increase/(decrease) in cash and cash equivalents and restricted cash		49				(52	)
Cash and cash equivalents and restricted cash, beginning of period		401				453
Cash and cash equivalents and restricted cash, end of period	$	450			$	401

CAPITAL EXPENDITURES
(in millions)

	Net to PAA (1)												Consolidated
	Three Months Ended December 31,						Twelve Months Ended December 31,						Three Months Ended December 31,						Twelve Months Ended December 31,
	2023			2022			2023			2022			2023			2022			2023			2022
Investment capital expenditures:
Crude Oil	$	75		$	44		$	245		$	229		$	100		$	64		$	334		$	298
NGL		14			8			65			36			14			8			65			36
Total Investment capital expenditures		89			52			310			265			114			72			399			334
Maintenance capital expenditures		58			63			214			202			63			65			231			211
	$	147		$	115		$	524		$	467		$	177		$	137		$	630		$	545

____________________

(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 December 31,								Twelve Months Ended December 31,
		2023				2022				2023				2022
Basic and Diluted Adjusted Net Income per Common Unit
Net income attributable to PAA	$	312			$	263			$	1,230			$	1,037
Selected items impacting comparability - Adjusted net income attributable to PAA (2)		43				23				20				54
Adjusted net income attributable to PAA	$	355			$	286			$	1,250			$	1,091
Distributions to Series A preferred unitholders		(44	)			(37	)			(173	)			(149	)
Distributions to Series B preferred unitholders		(20	)			(15	)			(76	)			(52	)
Amounts allocated to participating securities		(1	)			(1	)			(10	)			(5	)
Other		1				—				5				—
Adjusted net income allocated to common unitholders	$	291			$	233			$	996			$	885
Basic and diluted weighted average common units outstanding (3) (4)		701				698				699				701
Basic and diluted adjusted net income per common unit	$	0.42			$	0.33			$	1.42			$	1.26

____________________

(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)	The possible conversion of our Series A preferred units was excluded from the calculation of diluted adjusted net income per common unit for the three and twelve months ended December 31, 2023 and 2022 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.

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

	Three Months Ended December 31,						Twelve Months Ended December 31,
	2023			2022			2023			2022
Basic and diluted net income per common unit	$	0.35		$	0.30		$	1.40		$	1.19
Selected items impacting comparability per common unit (1)		0.07			0.03			0.02			0.07
Basic and diluted adjusted net income per common unit	$	0.42		$	0.33		$	1.42		$	1.26

____________________

(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 December 31,								Twelve Months Ended December 31,
	2023				2022				2023				2022
Net Income	$	399			$	310			$	1,502			$	1,228
Interest expense, net		97				100				386				405
Income tax expense		39				12				121				189
Depreciation and amortization		273				254				1,048				965
(Gains)/losses on asset sales and asset impairments, net		(9	)			315				(152	)			269
(Gains)/losses on investments in unconsolidated entities, net		—				(345	)			(28	)			(346	)
Depreciation and amortization of unconsolidated entities (1)		20				27				87				85
Selected items impacting comparability - Adjusted EBITDA (2)		56				86				203				80
Adjusted EBITDA	$	875			$	759			$	3,167			$	2,875
Adjusted EBITDA attributable to noncontrolling interests		(138	)			(100	)			(456	)			(365	)
Adjusted EBITDA attributable to PAA	$	737			$	659			$	2,711			$	2,510
Adjusted EBITDA	$	875			$	759			$	3,167			$	2,875
Interest expense, net of certain non-cash items (3)		(92	)			(96	)			(367	)			(391	)
Maintenance capital		(63	)			(65	)			(231	)			(211	)
Investment capital of noncontrolling interests (4)		(24	)			(18	)			(87	)			(69	)
Current income tax expense		(41	)			(24	)			(145	)			(84	)
Distributions from unconsolidated entities in excess of/(less than) adjusted equity earnings (5)		(15	)			20				(37	)			(28	)
Distributions to noncontrolling interests (6)		(97	)			(104	)			(333	)			(298	)
Implied DCF	$	543			$	472			$	1,967			$	1,794
Preferred unit cash distributions (6)		(64	)			(62	)			(241	)			(198	)
Implied DCF Available to Common Unitholders	$	479			$	410			$	1,726			$	1,596
Weighted Average Common Units Outstanding		701				698				699				701
Weighted Average Common Units and Common Unit Equivalents		772				769				770				772
Implied DCF per Common Unit (7)	$	0.68			$	0.59			$	2.47			$	2.28
Implied DCF per Common Unit and Common Unit Equivalent (8)	$	0.68			$	0.58			$	2.46			$	2.26
Cash Distribution Paid per Common Unit	$	0.2675			$	0.2175			$	1.0700			$	0.8325
Common Unit Cash Distributions (6)	$	188			$	152			$	748			$	584
Common Unit Distribution Coverage Ratio	2.55x				2.70x				2.31x				2.73x
Implied DCF Excess	$	291			$	258			$	978			$	1,012

____________________

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

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

	Three Months Ended December 31,						Twelve Months Ended December 31,
	2023			2022			2023			2022
Basic net income per common unit	$	0.35		$	0.30		$	1.40		$	1.19
Reconciling items per common unit (1) (2)		0.33			0.29			1.07			1.09
Implied DCF per common unit	$	0.68		$	0.59		$	2.47		$	2.28
Basic net income per common unit	$	0.35		$	0.30		$	1.40		$	1.19
Reconciling items per common unit and common unit equivalent (1) (3)		0.33			0.28			1.06			1.07
Implied DCF per common unit and common unit equivalent	$	0.68		$	0.58		$	2.46		$	2.26

____________________

(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 701 million, 698 million, 699 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 of 71 million for each of the periods presented.

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 December 31,								Twelve Months Ended December 31,
	2023				2022				2023				2022
Net cash provided by operating activities	$	1,011			$	335			$	2,727			$	2,408
Adjustments to reconcile net cash provided by operating activities to free cash flow:
Net cash used in investing activities		(257	)			(235	)			(702	)			(526	)
Cash contributions from noncontrolling interests		53				—				106				26
Cash distributions paid to noncontrolling interests (1)		(97	)			(104	)			(333	)			(298	)
Adjusted Free Cash Flow (2)	$	710			$	(4	)		$	1,798			$	1,610
Cash distributions (3)		(252	)			(214	)			(989	)			(782	)
Adjusted Free Cash Flow after Distributions (2)	$	458			$	(218	)		$	809			$	828
	Three Months Ended December 31,								Twelve Months Ended December 31,
	2023				2022				2023				2022
Adjusted Free Cash Flow (2)	$	710			$	(4	)		$	1,798			$	1,610
Changes in assets and liabilities, net of acquisitions (4)		(308	)			240				(194	)			191
Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities) (5)	$	402			$	236			$	1,604			$	1,801
Cash distributions (3)		(252	)			(214	)			(989	)			(782	)
Adjusted Free Cash Flow after Distributions (Excluding Changes in Assets & Liabilities) (5)	$	150			$	22			$	615			$	1,019

____________________

(1)	Cash distributions paid during the period presented.
(2)	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.
(3)	Cash distributions paid to preferred and common unitholders during the period.
(4)	See the “Condensed Consolidated Statements of Cash Flows” table.
(5)	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 December 31,								Twelve Months Ended December 31,
	2023				2022				2023				2022
Selected Items Impacting Comparability: (1)
Derivative activities and inventory valuation adjustments (2)	$	43			$	(76	)		$	(101	)		$	91
Long-term inventory costing adjustments (3)		(62	)			(18	)			(35	)			4
Deficiencies under minimum volume commitments, net (4)		(8	)			24				(12	)			(7	)
Equity-indexed compensation expense (5)		(8	)			(8	)			(36	)			(32	)
Foreign currency revaluation (6)		(11	)			2				(8	)			(41	)
Line 901 incident (7)		(10	)			(10	)			(10	)			(95	)
Transaction-related expenses (8)		—				—				(1	)			—
Selected items impacting comparability - Adjusted EBITDA	$	(56	)		$	(86	)		$	(203	)		$	(80	)
Derivative activities		—				1				—				7
Gains/(losses) on investments in unconsolidated entities, net		—				345				28				346
Gains/(losses) on asset sales and asset impairments, net		9				(315	)			152				(269	)
Tax effect on selected items impacting comparability		4				24				13				(65	)
Aggregate selected items impacting noncontrolling interests		—				8				(10	)			7
Selected items impacting comparability - Adjusted net income attributable to PAA	$	(43	)		$	(23	)		$	(20	)		$	(54	)

____________________

(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, 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)	Includes costs recognized during the period related to the Line 901 incident that occurred in May 2015, net of amounts we believe are probable of recovery from insurance.
(8)	Includes expenses associated with the Rattler Permian Transaction.

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

SELECTED FINANCIAL DATA BY SEGMENT
(in millions)

	Three Months Ended December 31, 2023									Three Months Ended December 31, 2022
	Crude Oil				NGL					Crude Oil				NGL
Revenues (1)	$	12,187			$	623				$	12,386			$	686
Purchases and related costs (1)		(11,306	)			(364	)				(11,593	)			(522	)
Field operating costs (2)		(274	)			(89	)				(253	)			(90	)
Segment general and administrative expenses (2) (3)		(68	)			(19	)				(63	)			(19	)
Equity earnings in unconsolidated entities		92				—					96				—
Adjustments: (4)
Depreciation and amortization of unconsolidated entities		20				—					27				—
Derivative activities and inventory valuation adjustments		(52	)			9					(8	)			91
Long-term inventory costing adjustments		58				4					14				4
Deficiencies under minimum volume commitments, net		8				—					(24	)			—
Equity-indexed compensation expense		8				—					8				—
Foreign currency revaluation		18				5					4				1
Line 901 incident		10				—					10				—
Segment amounts attributable to noncontrolling interests (5)		(138	)			—					(100	)			—
Segment Adjusted EBITDA	$	563			$	169				$	504			$	151
Maintenance capital expenditures	$	39			$	24				$	32			$	33

____________________

(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 (beginning November 2022) and Red River Pipeline LLC.

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

SELECTED FINANCIAL DATA BY SEGMENT
(in millions)

	Twelve Months Ended December 31, 2023									Twelve Months Ended December 31, 2022
	Crude Oil				NGL					Crude Oil				NGL
Revenues (1)	$	47,174			$	1,935				$	55,080			$	2,761
Purchases and related costs (1)		(43,805	)			(1,123	)				(52,088	)			(1,587	)
Field operating costs (2)		(1,053	)			(372	)				(1,003	)			(312	)
Segment general and administrative expenses (2) (3)		(271	)			(79	)				(250	)			(75	)
Equity earnings in unconsolidated entities		369				—					403				—
Adjustments: (4)
Depreciation and amortization of unconsolidated entities		87				—					85				—
Derivative activities and inventory valuation adjustments		17				142					(11	)			(269	)
Long-term inventory costing adjustments		22				13					(3	)			(1	)
Deficiencies under minimum volume commitments, net		12				—					7				—
Equity-indexed compensation expense		35				1					32				—
Foreign currency revaluation		19				5					3				1
Line 901 incident		10				—					95				—
Transaction-related expenses		1				—					—				—
Segment amounts attributable to noncontrolling interests (5)		(454	)			—					(364	)			—
Segment Adjusted EBITDA	$	2,163			$	522				$	1,986			$	518
Maintenance capital expenditures	$	145			$	86				$	112			$	99

____________________

(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 (beginning November 2022) and Red River Pipeline LLC.

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

OPERATING DATA BY SEGMENT

	Three Months Ended December 31,				Twelve Months Ended December 31,
	2023		2022		2023		2022
Crude Oil Segment Volumes
Crude oil pipeline tariff (by region) (1)
Permian Basin (2)	6,710		6,195		6,356		5,638
South Texas / Eagle Ford (2)	411		382		410		357
Mid-Continent (2)	503		538		507		512
Gulf Coast (2)	250		229		260		219
Rocky Mountain (2)	452		327		372		332
Western	237		90		214		179
Canada	340		333		341		328
Total crude oil pipeline tariff (1) (2)	8,903		8,094		8,460		7,565
Commercial crude oil storage capacity (2) (3)	72		72		72		72
Crude oil lease gathering purchases (1)	1,518		1,409		1,452		1,382
NGL Segment Volumes (1)
NGL fractionation	127		155		115		137
NGL pipeline tariff	188		222		180		192
Propane and butane sales	125		128		86		94

____________________

(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.
(3)	Average monthly capacity in millions of barrels 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)

Supplemental Adjusted EBITDA attributable to PAA Reconciliation:

	Three Months Ended December 31,						Twelve Months Ended December 31,
	2023			2022			2023			2022
Crude Oil Segment Adjusted EBITDA	$	563		$	504		$	2,163		$	1,986
NGL Segment Adjusted EBITDA		169			151			522			518
Adjusted other income/(expense), net (1)		5			4			26			6
Adjusted EBITDA attributable to PAA (2)	$	737		$	659		$	2,711		$	2,510

____________________

(1)	Represents “Other income/(expense), net” as reported on our Condensed Consolidated Statements of Operations, excluding other income/(expense), 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 December 31, 2023													Three Months Ended December 31, 2022
					Consolidating													Consolidating
	PAA				Adjustments (1)				PAGP					PAA				Adjustments (1)				PAGP
REVENUES	$	12,698			$	—			$	12,698				$	12,952			$	—			$	12,952
COSTS AND EXPENSES
Purchases and related costs		11,558				—				11,558					11,995				—				11,995
Field operating costs		363				—				363					343				—				343
General and administrative expenses		87				1				88					82				1				83
Depreciation and amortization		273				—				273					254				1				255
(Gains)/losses on asset sales and asset impairments, net		(9	)			—				(9	)				315				—				315
Total costs and expenses		12,272				1				12,273					12,989				2				12,991
OPERATING INCOME/(LOSS)		426				(1	)			425					(37	)			(2	)			(39	)
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities		92				—				92					96				—				96
Gains/(losses) on investments in unconsolidated entities, net		—				—				—					345				—				345
Interest expense, net		(97	)			—				(97	)				(100	)			—				(100	)
Other income, net		17				—				17					18				—				18
INCOME BEFORE TAX		438				(1	)			437					322				(2	)			320
Current income tax expense		(41	)			—				(41	)				(24	)			—				(24	)
Deferred income tax (expense)/benefit		2				(16	)			(14	)				12				(13	)			(1	)
NET INCOME		399				(17	)			382					310				(15	)			295
Net income attributable to noncontrolling interests		(87	)			(243	)			(330	)				(47	)			(204	)			(251	)
NET INCOME ATTRIBUTABLE TO PAGP	$	312			$	(260	)		$	52				$	263			$	(219	)		$	44
Basic and diluted weighted average Class A shares outstanding										196													194
Basic and diluted net income per Class A share									$	0.27												$	0.23

____________________

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

PLAINS GP HOLDINGS AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)

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

	Twelve Months Ended December 31, 2023													Twelve Months Ended December 31, 2022
					Consolidating													Consolidating
	PAA				Adjustments (1)				PAGP					PAA				Adjustments (1)				PAGP
REVENUES	$	48,712			$	—			$	48,712				$	57,342			$	—			$	57,342
COSTS AND EXPENSES
Purchases and related costs		44,531				—				44,531					53,176				—				53,176
Field operating costs		1,425				—				1,425					1,315				—				1,315
General and administrative expenses		350				6				356					325				5				330
Depreciation and amortization		1,048				3				1,051					965				3				968
(Gains)/losses on asset sales and asset impairments, net		(152	)			—				(152	)				269				—				269
Total costs and expenses		47,202				9				47,211					56,050				8				56,058
OPERATING INCOME		1,510				(9	)			1,501					1,292				(8	)			1,284
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities		369				—				369					403				—				403
Gains/(losses) on investments in unconsolidated entities, net		28				—				28					346				—				346
Interest expense, net		(386	)			—				(386	)				(405	)			—				(405	)
Other income/(expense), net		102				—				102					(219	)			—				(219	)
INCOME BEFORE TAX		1,623				(9	)			1,614					1,417				(8	)			1,409
Current income tax expense		(145	)			—				(145	)				(84	)			—				(84	)
Deferred income tax (expense)/benefit		24				(68	)			(44	)				(105	)			(57	)			(162	)
NET INCOME		1,502				(77	)			1,425					1,228				(65	)			1,163
Net income attributable to noncontrolling interests		(272	)			(955	)			(1,227	)				(191	)			(804	)			(995	)
NET INCOME ATTRIBUTABLE TO PAGP	$	1,230			$	(1,032	)		$	198				$	1,037			$	(869	)		$	168
Basic and diluted weighted average Class A shares outstanding										195													194
Basic and diluted net income per Class A share									$	1.01												$	0.86

____________________

(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)

	December 31, 2023											December 31, 2022
				Consolidating											Consolidating
	PAA			Adjustments (1)				PAGP				PAA			Adjustments (1)				PAGP
ASSETS
Current assets	$	4,913		$	3			$	4,916			$	5,355		$	3			$	5,358
Property and equipment, net		15,782			—				15,782				15,250			3				15,253
Investments in unconsolidated entities		2,820			—				2,820				3,084			—				3,084
Intangible assets, net		1,875			—				1,875				2,145			—				2,145
Deferred tax asset		—			1,239				1,239				—			1,309				1,309
Linefill		976			—				976				961			—				961
Long-term operating lease right-of-use assets, net		313			—				313				349			—				349
Long-term inventory		265			—				265				284			—				284
Other long-term assets, net		411			—				411				464			—				464
Total assets	$	27,355		$	1,242			$	28,597			$	27,892		$	1,315			$	29,207
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	5,003		$	2			$	5,005			$	5,891		$	2			$	5,893
Senior notes, net		7,242			—				7,242				7,237			—				7,237
Other long-term debt, net		63			—				63				50			—				50
Long-term operating lease liabilities		274			—				274				308			—				308
Other long-term liabilities and deferred credits		1,041			—				1,041				1,081			—				1,081
Total liabilities		13,623			2				13,625				14,567			2				14,569
Partners’ capital excluding noncontrolling interests		10,422			(8,874	)			1,548				10,057			(8,533	)			1,524
Noncontrolling interests		3,310			10,114				13,424				3,268			9,846				13,114
Total partners’ capital		13,732			1,240				14,972				13,325			1,313				14,638
Total liabilities and partners’ capital	$	27,355		$	1,242			$	28,597			$	27,892		$	1,315			$	29,207

____________________

(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 December 31,						Twelve Months Ended December 31,
	2023			2022			2023			2022
Basic and Diluted Net Income per Class A Share
Net income attributable to PAGP	$	52		$	44		$	198		$	168
Basic and diluted weighted average Class A shares outstanding		196			194			195			194
Basic and diluted net income per Class A share	$	0.27		$	0.23		$	1.01		$	0.86

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 continued 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 crude oil prices (whether due to global public health events, such as pandemics, or other factors) 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 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;

• 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;

• 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;

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

• 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 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 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 or that negatively impact our ability to develop, operate or repair midstream assets;

• 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 rating and ability to receive open credit from our suppliers and trade counterparties;

• 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;

• 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, 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 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 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;

• 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;

• the pace of development of natural gas infrastructure and its impact on expected crude oil production growth; 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:

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

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