0001581990-23-000011 | 10-Q | XBRL Viewer

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Organization and Basis of Consolidation and Presentation - Narrative (Details) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2023 USD ($) segment shares	Dec. 31, 2022 USD ($)
Organization and basis of presentation
Operating segments number \| segment	2
Deferred tax asset \| $	$ 1,278	$ 1,309
Consolidated Entity Excluding VIE
Organization and basis of presentation
Deferred tax asset \| $	$ 1,278	$ 1,309
AAP
Organization and basis of presentation
Consolidated subsidiary, ownership interest (as a percent)	81.00%
Consolidated subsidiary, ownership interest (units) \| shares	194.4
GP LLC
Organization and basis of presentation
Consolidated subsidiary, ownership interest (as a percent)	100.00%
PAA \| AAP
Organization and basis of presentation
Consolidated subsidiary, ownership interest (as a percent)	31.00%
Consolidated subsidiary, ownership interest (units) \| shares	240.8

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Income Statement [Abstract]
Capitalized interest	$ 2	$ 1

Derivatives and Risk Management Activities - Commodity Price Risk Hedging (Details) bbl in Millions	3 Months Ended
	Mar. 31, 2023 TWh bbl Bcf
Crude oil purchases \| Long
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf)	4.8
Time spread on hedging anticipated crude oil lease gathering purchases \| Short
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf)	5.3
Crude oil basis spread position
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf)	5.1
Anticipated net sales of crude oil and NGL inventory \| Short
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf)	14.3
Natural gas purchases for processing and operational needs \| Long
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf) \| Bcf	56.0
Propane contracts related to subsequent sale of products \| Short
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf)	10.6
Butane contracts related to subsequent sale of products \| Short
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf)	1.0
Condensate sales contracts related to subsequent sale of products \| Short
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf)	0.7
Fuel gas requirements \| Long
Commodity Price Risk Hedging:
Derivative position notional amount (in barrels or Bcf) \| Bcf	5.7
Power supply requirements \| Long
Commodity Price Risk Hedging:
Derivative position notional amount (in Terawatt hours) \| TWh	2.0

Net Income Per Class A Share (Tables)

3 Months Ended

Mar. 31, 2023

Earnings Per Share [Abstract]

Computation of basic and diluted net income per Class A share

The following table sets forth the computation of basic and diluted net income per Class A share (in millions, except per share data):


	Three Months Ended March 31,
	2023		2022
Basic and Diluted Net Income per Class A Share
Net income attributable to PAGP	$	69	$	22
Basic and diluted weighted average Class A shares outstanding	194		194

Basic and diluted net income per Class A share	$	0.35	$	0.11

Inventory, Linefill and Long-term Inventory (Tables)

3 Months Ended

Mar. 31, 2023

Inventory Disclosure [Abstract]

Schedule of inventory

Inventory, linefill and long-term inventory consisted of the following (barrels in thousands and carrying value in millions):


	March 31, 2023						December 31, 2022
	Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)
Inventory
Crude oil	5,373	barrels	$	342	$	63.65	6,713	barrels	$	452	$	67.33
NGL	3,427	barrels	111		$	32.39	7,285	barrels	270		$	37.06

Other	N/A		10		N/A		N/A		7		N/A
Inventory subtotal			463						729

Linefill
Crude oil	15,459	barrels	907		$	58.67	15,480	barrels	906		$	58.53
NGL	1,865	barrels	55		$	29.49	1,876	barrels	55		$	29.32

Linefill subtotal			962						961

Long-term inventory
Crude oil	3,136	barrels	227		$	72.39	3,102	barrels	246		$	79.30
NGL	1,063	barrels	30		$	28.22	1,066	barrels	38		$	35.65
Long-term inventory subtotal			257						284

Total			$	1,682					$	1,974

(1)Price per unit of measure is comprised of a weighted average associated with various grades, qualities and locations. Accordingly, these prices may not coincide with any published benchmarks for such products.

Schedule of linefill and long-term inventory

Inventory, linefill and long-term inventory consisted of the following (barrels in thousands and carrying value in millions):


	March 31, 2023						December 31, 2022
	Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)
Inventory
Crude oil	5,373	barrels	$	342	$	63.65	6,713	barrels	$	452	$	67.33
NGL	3,427	barrels	111		$	32.39	7,285	barrels	270		$	37.06

Other	N/A		10		N/A		N/A		7		N/A
Inventory subtotal			463						729

Linefill
Crude oil	15,459	barrels	907		$	58.67	15,480	barrels	906		$	58.53
NGL	1,865	barrels	55		$	29.49	1,876	barrels	55		$	29.32

Linefill subtotal			962						961

Long-term inventory
Crude oil	3,136	barrels	227		$	72.39	3,102	barrels	246		$	79.30
NGL	1,063	barrels	30		$	28.22	1,066	barrels	38		$	35.65
Long-term inventory subtotal			257						284

Total			$	1,682					$	1,974

Revenues and Accounts Receivable - Segment Revenue (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Disaggregation of Revenue
Total revenues	$ 12,341	$ 13,694
Operating Segments
Disaggregation of Revenue
Revenues from contracts with customers	12,417	13,981
Other revenues	31	(167)
Total revenues	12,448	13,814
Operating Segments \| Crude Oil
Disaggregation of Revenue
Revenues from contracts with customers	11,721	13,102
Other revenues	37	(23)
Total revenues	11,758	13,079
Operating Segments \| NGL
Disaggregation of Revenue
Revenues from contracts with customers	696	879
Other revenues	(6)	(144)
Total revenues	690	735
Intersegment revenues elimination
Disaggregation of Revenue
Total revenues	$ (107)	$ (120)

- Definition

Amount, excluding tax collected from customer, of revenue from satisfaction of performance obligation by transferring promised good or service to customer. Tax collected from customer is tax assessed by governmental authority that is both imposed on and concurrent with specific revenue-producing transaction, including, but not limited to, sales, use, value added and excise.

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+ Details

- Definition

Amount of revenue recognized from goods sold, services rendered, insurance premiums, or other activities that constitute an earning process. Includes, but is not limited to, investment and interest income before deduction of interest expense when recognized as a component of revenue, and sales and trading gain (loss).

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+ Details

Revenues and Accounts Receivable - Narrative (Details)	3 Months Ended	12 Months Ended
Revenues and Accounts Receivable - Narrative (Details)	Mar. 31, 2023	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
Substantially all trade accounts receivable, net, maximum age of balances past their invoice date	30 days	30 days

Derivatives and Risk Management Activities (Tables)

3 Months Ended

Mar. 31, 2023

Derivatives and Risk Management Activities

Summary of impact of derivatives recognized in earnings

The following table summarizes the impact of our commodity derivatives recognized in earnings (in millions):


	Three Months Ended March 31,
	2023		2022
Product sales revenues	$	(1)	$	(213)
Field operating costs	(19)		13

Net loss from commodity derivative activity	$	(20)	$	(200)

Schedule of net broker receivable/(payable)

The following table provides the components of our net broker receivable/(payable) (in millions):


	March 31, 2023		December 31, 2022
Initial margin	$	74	$	93
Variation margin returned	(85)		(236)
Letters of credit	(25)		(25)
Net broker payable	$	(36)	$	(168)

Summary of derivative assets and liabilities on condensed consolidated balance sheets on a gross basis

The following table reflects the Condensed Consolidated Balance Sheet line items that include the fair values of our commodity derivative assets and liabilities and the effect of the collateral netting. Such amounts are presented on a gross basis, before the effects of counterparty netting. However, we have elected to present our commodity derivative assets and liabilities with the same counterparty on a net basis on our Condensed Consolidated Balance Sheet when the legal right of offset exists. Amounts in the table below are presented in millions.


	March 31, 2023								December 31, 2022
					Effect of Collateral Netting		Net Carrying Value Presented on the Balance Sheet						Effect of Collateral Netting		Net Carrying Value Presented on the Balance Sheet
	Commodity Derivatives								Commodity Derivatives
	Assets		Liabilities						Assets		Liabilities
Derivative Assets
Other current assets	$	120	$	(33)	$	(36)	$	51	$	300	$	(71)	$	(168)	$	61
Other long-term assets, net	6		—		—		6		9		(5)		—		4
Derivative Liabilities
Other current liabilities	7		(52)		—		(45)		2		(13)		—		(11)
Other long-term liabilities and deferred credits	1		(5)		—		(4)		—		—		—		—
Total	$	134	$	(90)	$	(36)	$	8	$	311	$	(89)	$	(168)	$	54

Summary of net unrealized gain/(loss) recognized in AOCI for derivatives

The following table summarizes the net unrealized gain/(loss) recognized in AOCI for derivatives (in millions):


	Three Months Ended March 31,
	2023		2022
Interest rate derivatives, net	$	(5)	$	32

Schedule of derivative financial assets and liabilities accounted for at fair value on a recurring basis, by level within the fair value hierarchy

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis (in millions):


	Fair Value as of March 31, 2023								Fair Value as of December 31, 2022
Recurring Fair Value Measures (1)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Commodity derivatives	$	1	$	43	$	—	$	44	$	(7)	$	229	$	—	$	222
Interest rate derivatives	—		115		—		115		—		120		—		120

Preferred Distribution Rate Reset Option	—		—		—		—		—		—		(189)		(189)
Total net derivative asset/(liability)	$	1	$	158	$	—	$	159	$	(7)	$	349	$	(189)	$	153

(1)Derivative assets and liabilities are presented above on a net basis but do not include related cash margin deposits.

Summary of reconciliation of changes in fair value of derivatives classified as Level 3

The following table provides a reconciliation of changes in fair value of the beginning and ending balances for our derivatives classified as Level 3 (in millions):


	Three Months Ended March 31,
	2023		2022
Beginning Balance	$	(189)	$	(2)
Net gains/(losses) for the period included in earnings	58		(44)
Settlements	131		2

Ending Balance	$	—	$	(44)

Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period	$	—	$	(44)

Commodity derivatives

Derivatives and Risk Management Activities

Summary of open derivative positions

The following table summarizes our open derivative positions utilized to hedge the price risk associated with anticipated purchases and sales related to our natural gas processing and NGL fractionation activities as of March 31, 2023:

Notional Volume

(Short)/Long

Remaining Tenor

Natural gas purchases

56.0 Bcf

December 2024

Propane sales

(10.6) MMbls

December 2024

Butane sales

(1.0) MMbls

December 2024

Condensate sales

(0.7) MMbls

December 2024

Fuel gas requirements (1)

5.7 Bcf

June 2024

Power supply requirements (1)

2.0 TWh

December 2030

(1)Positions to hedge a portion of our power supply and fuel gas requirements at our Canadian natural gas processing and fractionation plants.

Interest Rate Swap

Derivatives and Risk Management Activities

Schedule of terms of outstanding interest rate derivatives

The following table summarizes the terms of our outstanding interest rate derivatives as of March 31, 2023 (notional amounts in millions):

Hedged Transaction

Number and Types of
Derivatives Employed

Notional
Amount

Expected
Termination Date

Average Rate
Locked

Accounting
Treatment

Anticipated interest payments

8 forward starting swaps

(30-year)

200

6/15/2023

1.38

Cash flow hedge

Anticipated interest payments

4 forward starting swaps

(30-year)

100

6/14/2024

0.74

Cash flow hedge

Derivatives and Risk Management Activities - Broker Receivable/Payable (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Offsetting Assets, Liabilities [Line Items]
Initial margin	$ 74	$ 93
Variation margin returned	(85)	(236)
Letters of credit	(144)	(102)
Net broker payable	(36)	(168)
Exchange traded
Offsetting Assets, Liabilities [Line Items]
Letters of credit	$ (25)	$ (25)

Revenues and Accounts Receivable - Disaggregation of Revenue (Details) - Operating Segments - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Disaggregation of Revenue
Revenues from contracts with customers	$ 12,417	$ 13,981
Crude Oil
Disaggregation of Revenue
Revenues from contracts with customers	11,721	13,102
Crude Oil \| Sales
Disaggregation of Revenue
Revenues from contracts with customers	11,381	12,857
Crude Oil \| Transportation
Disaggregation of Revenue
Revenues from contracts with customers	250	155
Crude Oil \| Terminalling, Storage and Other
Disaggregation of Revenue
Revenues from contracts with customers	90	90
NGL
Disaggregation of Revenue
Revenues from contracts with customers	696	879
NGL \| Sales
Disaggregation of Revenue
Revenues from contracts with customers	660	845
NGL \| Transportation
Disaggregation of Revenue
Revenues from contracts with customers	8	9
NGL \| Terminalling, Storage and Other
Disaggregation of Revenue
Revenues from contracts with customers	$ 28	$ 25

- Definition

+ References

+ Details

Partners' Capital and Distributions - Distributions, Class A (Details) - Class A Shares - Cash Distribution - USD ($) $ / shares in Units, $ in Millions	May 15, 2023	Feb. 14, 2023
Partners' Capital and Distributions
Distributions paid to limited partners		$ 52
Distribution per Class A share, paid (usd per share)		$ 0.2675
Forecast
Partners' Capital and Distributions
Distributions paid to limited partners	$ 52
Distribution per Class A share, paid (usd per share)	$ 0.2675

Inventory, Linefill and Long-term Inventory (Details) bbl in Thousands, $ in Millions	Mar. 31, 2023 USD ($) $ / bbl bbl	Dec. 31, 2022 USD ($) $ / bbl bbl
Inventory by category
Inventory	$ 463	$ 729
Linefill	962	961
Long-term inventory	257	284
Total	$ 1,682	$ 1,974
Crude oil
Inventory by category
Inventory, Volumes (in barrels) \| bbl	5,373	6,713
Linefill, Volumes (in barrels) \| bbl	15,459	15,480
Long-term inventory, Volumes (in barrels) \| bbl	3,136	3,102
Inventory	$ 342	$ 452
Linefill	907	906
Long-term inventory	$ 227	$ 246
Inventory (Price/Unit of measure) (in dollars per units) \| $ / bbl	63.65	67.33
Linefill (Price/Unit of measure) (in dollars per units) \| $ / bbl	58.67	58.53
Long-term inventory (Price/Unit of measure) (in dollars per units) \| $ / bbl	72.39	79.30
NGL
Inventory by category
Inventory, Volumes (in barrels) \| bbl	3,427	7,285
Linefill, Volumes (in barrels) \| bbl	1,865	1,876
Long-term inventory, Volumes (in barrels) \| bbl	1,063	1,066
Inventory	$ 111	$ 270
Linefill	55	55
Long-term inventory	$ 30	$ 38
Inventory (Price/Unit of measure) (in dollars per units) \| $ / bbl	32.39	37.06
Linefill (Price/Unit of measure) (in dollars per units) \| $ / bbl	29.49	29.32
Long-term inventory (Price/Unit of measure) (in dollars per units) \| $ / bbl	28.22	35.65
Other
Inventory by category
Inventory	$ 10	$ 7

Segment Information

3 Months Ended

Mar. 31, 2023

Segment Reporting [Abstract]

Segment Information

We manage our operations through two operating segments, which are also our reportable segments: Crude Oil and NGL. See Note 20 to our Consolidated Financial Statements included in Part IV of our 2022 Annual Report on Form 10-K for a summary of the types of products and services from which each segment derives its revenues. Our CODM (our Chief Executive Officer) evaluates segment performance based on measures including Segment Adjusted EBITDA (as defined below) and maintenance capital.

The measure of Segment Adjusted EBITDA forms the basis of our internal financial reporting and is the primary performance measure used by our CODM in assessing performance and allocating resources among our operating segments. We define Segment Adjusted EBITDA as revenues and equity earnings in unconsolidated entities less (a) purchases and related costs, (b) field operating costs and (c) segment general and administrative expenses, plus (d) our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities, further adjusted (e) for certain selected items including (i) 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, (ii) long-term inventory costing adjustments, (iii) charges for obligations that are expected to be settled with the issuance of equity instruments, (iv) amounts related to deficiencies associated with minimum volume commitments, net of the applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understanding our core segment operating performance and (f) to exclude the portion of all preceding items that is attributable to noncontrolling interests (“Adjusted EBITDA attributable to noncontrolling interests”).

The following tables reflect certain financial data for each segment (in millions):


	Crude Oil		NGL		Intersegment Revenues Elimination		Total
Three Months Ended March 31, 2023
Revenues (1):
Product sales	$	11,409	$	635	$	(101)	$	11,943
Services	349		55		(6)		398
Total revenues	$	11,758	$	690	$	(107)	$	12,341
Equity earnings in unconsolidated entities	$	89	$	—			$	89
Segment Adjusted EBITDA	$	517	$	192			$	709

Maintenance capital expenditures	$	32	$	16			$	48





Three Months Ended March 31, 2022
Revenues (1):
Product sales	$	12,811	$	682	$	(112)	$	13,381
Services	268		53		(8)		313
Total revenues	$	13,079	$	735	$	(120)	$	13,694
Equity earnings in unconsolidated entities	$	97	$	—			$	97
Segment Adjusted EBITDA	$	453	$	161			$	614

Maintenance capital expenditures	$	19	$	8			$	27

(1)Segment revenues include intersegment amounts that are eliminated in Purchases and related costs. Intersegment activities are conducted at posted tariff rates where applicable, or otherwise at rates similar to those charged to third parties or rates that we believe approximate market at the time the agreement is executed or renegotiated.

Segment Adjusted EBITDA Reconciliation

The following table reconciles Segment Adjusted EBITDA to Net income attributable to PAGP (in millions):


	Three Months Ended March 31,
	2023		2022
Segment Adjusted EBITDA	$	709	$	614
Adjustments: (1)
Depreciation and amortization of unconsolidated entities (2)	(22)		(20)
Derivative activities and inventory valuation adjustments (3)	(92)		(88)
Long-term inventory costing adjustments (4)	(29)		92
Deficiencies under minimum volume commitments, net (5)	7		(6)
Equity-indexed compensation expense (6)	(10)		(7)
Foreign currency revaluation (7)	3		2
Line 901 incident (8)	—		(85)

Adjusted EBITDA attributable to noncontrolling interests in consolidated joint ventures (9)	98		76
Unallocated general and administrative expenses (10)	(1)		(1)
Depreciation and amortization	(257)		(231)
Gains/(losses) on asset sales and asset impairments, net	154		42

Interest expense, net	(98)		(107)
Other income/(expense), net	64		(37)
Income before tax	526		244
Income tax expense	(83)		(35)
Net income	443		209
Net income attributable to noncontrolling interests	(374)		(187)
Net income attributable to PAGP	$	69	$	22

(1)Represents adjustments utilized by our CODM in the evaluation of segment results.

(2)Includes our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities.

(3)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 Segment Adjusted EBITDA such that the earnings from the derivative instruments and the underlying transactions impact Segment Adjusted EBITDA 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.

(4)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 exclude 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 from Segment Adjusted EBITDA.

(5)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 our capital expenditure necessary to construct the related asset. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue, as a selected item impacting comparability. Our CODM views the inclusion of the contractually committed revenues associated with that period as meaningful to Segment Adjusted EBITDA 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.

(6)Our total equity-indexed compensation expense includes expense associated with awards that will be settled in PAA common units and awards that will be settled in cash. The awards that will be settled in PAA common units are included in PAA’s diluted net income per unit calculation when the applicable performance criteria have been met. We exclude compensation expense associated with these awards in determining Segment Adjusted EBITDA as the dilutive impact of the outstanding awards is included in PAA’s diluted net income per unit calculation, as applicable. The portion of compensation expense associated with awards that will settle in cash is not excluded in determining Segment Adjusted EBITDA. See Note 18 to our Consolidated Financial Statements included in Part IV of our 2022 Annual Report on Form 10-K for a discussion regarding our equity-indexed compensation plans.

(7)During the periods presented, there were fluctuations in the value of CAD to USD, 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 therefore excluded in determining Segment Adjusted EBITDA.

(8)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. See Note 9 for additional information regarding the Line 901 incident.

(9)Reflects amounts attributable to noncontrolling interests in the Permian JV, Cactus II and Red River.

(10)Represents general and administrative expenses incremental to those of PAA, which are not allocated to our reporting segments in determining Segment Adjusted EBITDA.

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

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+ Details

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
CURRENT ASSETS
Cash and cash equivalents	$ 529	$ 404
Trade accounts receivable and other receivables, net	3,968	3,907
Inventory	463	729
Other current assets	165	318
Total current assets	5,125	5,358
PROPERTY AND EQUIPMENT	20,173	20,055
Accumulated depreciation	(4,976)	(4,802)
Property and equipment, net	15,197	15,253
OTHER ASSETS
Investments in unconsolidated entities	3,070	3,084
Intangible assets, net	2,073	2,145
Deferred tax asset	1,278	1,309
Linefill	962	961
Long-term operating lease right-of-use assets, net	347	349
Long-term inventory	257	284
Other long-term assets, net	430	464
Total assets	28,739	29,207
CURRENT LIABILITIES
Trade accounts payable	4,010	4,045
Short-term debt	708	1,159
Other current liabilities	650	689
Total current liabilities	5,368	5,893
LONG-TERM LIABILITIES
Senior notes, net	7,238	7,237
Other long-term debt, net	50	50
Long-term operating lease liabilities	307	308
Other long-term liabilities and deferred credits	1,012	1,081
Total long-term liabilities	8,607	8,676
COMMITMENTS AND CONTINGENCIES (NOTE 9)
PARTNERS’ CAPITAL
Noncontrolling interests	13,220	13,114
Total partners’ capital	14,764	14,638
Total liabilities and partners’ capital	28,739	29,207
Class A Shares
PARTNERS’ CAPITAL
Class A shareholders (194,407,642 and 194,407,642 shares outstanding, respectively)	$ 1,544	$ 1,524

Segment Information (Tables)

3 Months Ended

Mar. 31, 2023

Segment Reporting [Abstract]

Segment financial data

The following tables reflect certain financial data for each segment (in millions):


	Crude Oil		NGL		Intersegment Revenues Elimination		Total
Three Months Ended March 31, 2023
Revenues (1):
Product sales	$	11,409	$	635	$	(101)	$	11,943
Services	349		55		(6)		398
Total revenues	$	11,758	$	690	$	(107)	$	12,341
Equity earnings in unconsolidated entities	$	89	$	—			$	89
Segment Adjusted EBITDA	$	517	$	192			$	709

Maintenance capital expenditures	$	32	$	16			$	48





Three Months Ended March 31, 2022
Revenues (1):
Product sales	$	12,811	$	682	$	(112)	$	13,381
Services	268		53		(8)		313
Total revenues	$	13,079	$	735	$	(120)	$	13,694
Equity earnings in unconsolidated entities	$	97	$	—			$	97
Segment Adjusted EBITDA	$	453	$	161			$	614

Maintenance capital expenditures	$	19	$	8			$	27

Reconciliation of Segment Adjusted EBITDA to Net income attributable to PAA

The following table reconciles Segment Adjusted EBITDA to Net income attributable to PAGP (in millions):


	Three Months Ended March 31,
	2023		2022
Segment Adjusted EBITDA	$	709	$	614
Adjustments: (1)
Depreciation and amortization of unconsolidated entities (2)	(22)		(20)
Derivative activities and inventory valuation adjustments (3)	(92)		(88)
Long-term inventory costing adjustments (4)	(29)		92
Deficiencies under minimum volume commitments, net (5)	7		(6)
Equity-indexed compensation expense (6)	(10)		(7)
Foreign currency revaluation (7)	3		2
Line 901 incident (8)	—		(85)

Adjusted EBITDA attributable to noncontrolling interests in consolidated joint ventures (9)	98		76
Unallocated general and administrative expenses (10)	(1)		(1)
Depreciation and amortization	(257)		(231)
Gains/(losses) on asset sales and asset impairments, net	154		42

Interest expense, net	(98)		(107)
Other income/(expense), net	64		(37)
Income before tax	526		244
Income tax expense	(83)		(35)
Net income	443		209
Net income attributable to noncontrolling interests	(374)		(187)
Net income attributable to PAGP	$	69	$	22

(1)Represents adjustments utilized by our CODM in the evaluation of segment results.

(2)Includes our proportionate share of the depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities.

(9)Reflects amounts attributable to noncontrolling interests in the Permian JV, Cactus II and Red River.

(10)Represents general and administrative expenses incremental to those of PAA, which are not allocated to our reporting segments in determining Segment Adjusted EBITDA.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Statement of Comprehensive Income [Abstract]
Net income	$ 443	$ 209
Other comprehensive income/(loss)	(1)	74
Comprehensive income	442	283
Comprehensive income attributable to noncontrolling interests	(373)	(240)
Comprehensive income attributable to PAGP	$ 69	$ 43

- Definition

Amount after tax of increase (decrease) in equity from transactions and other events and circumstances from net income (loss) and other comprehensive income (loss), attributable to noncontrolling interests. Excludes changes in equity resulting from investments by owners and distributions to owners.

+ References + Details

- Definition

Amount after tax of increase (decrease) in equity from transactions and other events and circumstances from net income and other comprehensive income. Excludes changes in equity resulting from investments by owners and distributions to owners.

+ References + Details

- Definition

Amount after tax and reclassification adjustments of other comprehensive income (loss).

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- Definition

The consolidated profit or loss for the period, net of income taxes, including the portion attributable to the noncontrolling interest.

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+ Details

Organization and Basis of Consolidation and Presentation

3 Months Ended

Mar. 31, 2023

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Basis of Consolidation and Presentation

Organization

Plains GP Holdings, L.P. (“PAGP”) is a Delaware limited partnership formed in 2013 that has elected to be taxed as a corporation for United States federal income tax purposes. PAGP does not directly own any operating assets; as of March 31, 2023, its principal source of cash flow is derived from an indirect investment in Plains All American Pipeline, L.P. (“PAA”), a publicly traded Delaware limited partnership. As used in this Form 10-Q and unless the context indicates otherwise (taking into account the fact that PAGP has no operating activities apart from those conducted by PAA and its subsidiaries), the terms “Partnership,” “we,” “us,” “our,” “ours” and similar terms refer to PAGP and its subsidiaries.

As of March 31, 2023, we owned an approximate 81% limited partner interest in Plains AAP L.P. (“AAP”) through our ownership of approximately 194.4 million Class A units of AAP (“AAP Units”). We also own a 100% managing member interest in Plains All American GP LLC (“GP LLC”), a Delaware limited liability company that holds the non-economic general partner interest in AAP. AAP is a Delaware limited partnership that, as of March 31, 2023, directly owned a limited partner interest in PAA through its ownership of approximately 240.8 million PAA common units (approximately 31% of PAA’s total outstanding common units and Series A preferred units combined). AAP is the sole member of PAA GP LLC (“PAA GP”), a Delaware limited liability company that directly holds the non-economic general partner interest in PAA.

PAA’s business model integrates large-scale supply aggregation capabilities with the ownership and operation of critical midstream infrastructure systems that connect major producing regions to key demand centers and export terminals. As one of the largest midstream service providers in North America, PAA owns an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and natural gas liquids (“NGL”) producing basins (including the Permian Basin) and transportation corridors and at major market hubs in the United States and Canada. PAA’s assets and the services it provides are primarily focused on and conducted through two operating segments: Crude Oil and NGL. See Note 10 for further discussion of our operating segments.

PAA GP Holdings LLC, a Delaware limited liability company, is our general partner. Our general partner manages our operations and activities and is responsible for exercising on our behalf any rights we have as the sole and managing member of GP LLC, including responsibility for conducting the business and managing the operations of AAP and PAA. GP LLC employs our domestic officers and personnel involved in the operation and management of AAP and PAA. PAA’s Canadian officers and personnel are employed by our subsidiary, Plains Midstream Canada ULC.

References to the “Plains Entities” include us, our general partner, GP LLC, AAP, PAA GP and PAA and its subsidiaries.

Definitions

Additional defined terms are used in this Form 10-Q and shall have the meanings indicated below:


AOCI	=	Accumulated other comprehensive income/(loss)
ASC	=	Accounting Standards Codification
ASU	=	Accounting Standards Update
Bcf	=	Billion cubic feet
Btu	=	British thermal unit
CAD	=	Canadian dollar
CODM	=	Chief Operating Decision Maker
EBITDA	=	Earnings before interest, taxes, depreciation and amortization
EPA	=	United States Environmental Protection Agency
FASB	=	Financial Accounting Standards Board
GAAP	=	Generally accepted accounting principles in the United States
ICE	=	Intercontinental Exchange
ISDA	=	International Swaps and Derivatives Association
LIBOR	=	London Interbank Offered Rate
LTIP	=	Long-term incentive plan
Mcf	=	Thousand cubic feet
MMbls	=	Million barrels
NGL	=	Natural gas liquids, including ethane, propane and butane
NYMEX	=	New York Mercantile Exchange
SEC	=	United States Securities and Exchange Commission
TWh	=	Terawatt hour
USD	=	United States dollar
WTI	=	West Texas Intermediate

Basis of Consolidation and Presentation

The accompanying unaudited condensed consolidated interim financial statements and related notes thereto should be read in conjunction with our 2022 Annual Report on Form 10-K. The accompanying condensed consolidated financial statements include the accounts of PAGP and all of its wholly owned subsidiaries and those entities that it controls. Investments in entities over which we have significant influence but not control are accounted for by the equity method. We apply proportionate consolidation for pipelines and other assets in which we own undivided joint interests. The financial statements have been prepared in accordance with the instructions for interim reporting as set forth by the SEC. The condensed consolidated balance sheet data as of December 31, 2022 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three months ended March 31, 2023 should not be taken as indicative of results to be expected for the entire year. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. All significant intercompany balances and transactions have been eliminated in consolidation, and certain reclassifications have been made to information from previous years to conform to the current presentation.

Management judgment is required to evaluate whether PAGP controls an entity. Key areas of that evaluation include (i) determining whether an entity is a variable interest entity (“VIE”); (ii) determining whether PAGP is the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that PAGP and its related parties have over those activities through variable interests; and (iii) identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating whether PAGP is a VIE’s primary beneficiary.

We have determined that our subsidiaries, PAA and AAP, are VIEs and should be consolidated by PAGP because:

•The limited partners of PAA and AAP lack (i) substantive “kick-out rights” (i.e., the right to remove the general partner) based on a simple majority or lower vote and (ii) substantive participation rights and thus lack the ability to block actions of the general partner that most significantly impact the economic performance of PAA and AAP, respectively.

•AAP is the primary beneficiary of PAA because it has the power to direct the activities that most significantly impact PAA’s performance and the right to receive benefits, and obligation to absorb losses, that could be significant to PAA.

•PAGP is the primary beneficiary of AAP because it has the power to direct the activities that most significantly impact AAP’s performance and the right to receive benefits, and obligation to absorb losses, that could be significant to AAP.

With the exception of a deferred tax asset of $1.278 billion and $1.309 billion as of March 31, 2023 and December 31, 2022, respectively, substantially all assets and liabilities presented on PAGP’s Condensed Consolidated Balance Sheets are those of PAA. Only the assets of each respective VIE can be used to settle the obligations of that individual VIE, and the creditors of each/either of those VIEs do not have recourse against the general credit of PAGP. PAGP did not provide any financial support to PAA or AAP during the three months ended March 31, 2023 or the year ended December 31, 2022. See Note 17 to our Consolidated Financial Statements included in Part IV of our 2022 Annual Report on Form 10-K for information regarding the Omnibus Agreement entered into by the Plains Entities on November 15, 2016.

Subsequent Events

Subsequent events have been evaluated through the financial statements issuance date and have been included in the following footnotes where applicable.

Recent Accounting Pronouncements

Except as discussed in our 2022 Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the three months ended March 31, 2023 that are of significance or potential significance to us.

Segment Information - Segment Adjusted EBITDA Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Segment Reporting, Reconciling Item from Segments to Consolidated
Segment Adjusted EBITDA	$ 709	$ 614
Adjustments:
Depreciation and amortization of unconsolidated entities	(22)	(20)
Derivative activities and inventory valuation adjustments	(92)	(88)
Long-term inventory costing adjustments	(29)	92
Deficiencies under minimum volume commitments, net	7	(6)
Equity-indexed compensation expense	(10)	(7)
Foreign currency revaluation	3	2
Adjusted EBITDA attributable to noncontrolling interests in consolidated joint ventures	98	76
Unallocated general and administrative expenses	(87)	(83)
Depreciation and amortization	(257)	(231)
Gains/(losses) on asset sales and asset impairments, net	154	42
Interest expense, net	(98)	(107)
Other income/(expense), net	64	(37)
INCOME BEFORE TAX	526	244
Income tax expense	(83)	(35)
NET INCOME	443	209
Net income attributable to noncontrolling interests	(374)	(187)
NET INCOME ATTRIBUTABLE TO PAGP	69	22
Unallocated
Adjustments:
Unallocated general and administrative expenses	(1)	(1)
Line 901 Incident
Adjustments:
Significant costs related to legal and environmental remediation matters	$ 0	$ (85)

Debt - Components (Details) - USD ($) $ in Millions	Mar. 31, 2023	Jan. 31, 2023	Dec. 31, 2022
SHORT-TERM DEBT
Total short-term debt	$ 708		$ 1,159
LONG-TERM DEBT
Senior notes, net	7,238		7,237
Other	50		50
Total long-term debt	7,288		7,287
Total debt	7,996		8,446
Senior notes
LONG-TERM DEBT
Senior notes, net	7,238		7,237
Unamortized discounts and debt issuance costs	45		46
Debt instrument face value	8,000		8,400
Senior notes \| Level 2
LONG-TERM DEBT
Debt instrument fair value	7,300		7,600
Other
LONG-TERM DEBT
Other	50		50
Other
SHORT-TERM DEBT
Total short-term debt	8		59
2.85% senior notes due January 2023 \| Senior notes
SHORT-TERM DEBT
Total short-term debt			$ 400
Debt instrument, interest rate (as a percent)		2.85%	2.85%
3.85% senior notes due October 2023 \| Senior notes
SHORT-TERM DEBT
Total short-term debt	$ 700		$ 700
Debt instrument, interest rate (as a percent)	3.85%

Cover Page - shares	3 Months Ended
Cover Page - shares	Mar. 31, 2023	May 01, 2023
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2023
Document Transition Report	false
Entity File Number	1-36132
Entity Registrant Name	PLAINS GP HOLDINGS LP
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	90-1005472
Entity Address, Address Line One	333 Clay Street
Entity Address, Address Line Two	Suite 1600
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	713
Local Phone Number	646-4100
Title of 12(b) Security	Class A Shares
Trading Symbol	PAGP
Security Exchange Name	NASDAQ
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Small Business Entity	false
Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (shares)		194,407,642
Entity Central Index Key	0001581990
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	Q1

Derivatives and Risk Management Activities - Interest Rate Risk Hedging (Details) - Cash flow hedge $ in Millions	3 Months Ended
	Mar. 31, 2023 USD ($) contract
8 forward starting interest rate swaps (30-year), 1.38%
Interest Rate Risk Hedging
Number of interest rate derivatives \| contract	8
Term of derivative contract	30 years
Notional amount of derivatives \| $	$ 200
Average rate locked (percent)	1.38%
4 forward starting interest rate swaps (30-year), 0.74%
Interest Rate Risk Hedging
Number of interest rate derivatives \| contract	4
Term of derivative contract	30 years
Notional amount of derivatives \| $	$ 100
Average rate locked (percent)	0.74%

Derivatives and Risk Management Activities

3 Months Ended

Mar. 31, 2023

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives and Risk Management Activities

We identify the risks that underlie our core business activities and use risk management strategies to mitigate those risks when we determine that there is value in doing so. We use various derivative instruments to optimize our profits while managing our exposure to commodity price risk and interest rate risk. Our commodity price risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our derivative positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. Our interest rate risk management policies and procedures are designed to monitor our derivative positions and ensure that those positions are consistent with our objectives and approved strategies. Our policy is to use derivative instruments for risk management purposes and not for the purpose of speculating on changes in commodity prices or interest rates. When we apply hedge accounting, our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. At the inception of the hedging relationship, we assess whether the derivatives employed are highly effective in offsetting changes in cash flows of anticipated hedged transactions. Throughout the hedging relationship, retrospective and prospective hedge effectiveness is assessed on a qualitative basis.

We record all open derivatives on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives designated as cash flow hedges, changes in fair value are deferred in AOCI and recognized in earnings in the periods during which the underlying hedged transactions are recognized in earnings. Derivatives that are not designated in a hedging relationship for accounting purposes are recognized in earnings each period. Cash settlements associated with our derivative activities are classified within the same category as the related hedged item in our Condensed Consolidated Statements of Cash Flows.

Our financial derivatives, used for hedging risk, are governed through ISDA master agreements and clearing brokerage agreements. These agreements include stipulations regarding the right of set off in the event that we or our counterparty default on performance obligations. If a default were to occur, both parties have the right to net amounts payable and receivable into a single net settlement between parties.

At March 31, 2023 and December 31, 2022, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings. Although we may be required to post margin on our exchange-traded derivatives transacted through a clearing brokerage account, as described below, we do not require our non-cleared derivative counterparties to post collateral with us.

Commodity Price Risk Hedging

Our core business activities involve certain commodity price-related risks that we manage in various ways, including through the use of derivative instruments. Our policy is to (i) only purchase inventory for which we have a sales market, (ii) structure our sales contracts so that price fluctuations do not materially affect our operating income and (iii) not acquire and hold material physical inventory or derivatives for the purpose of speculating on commodity price changes. The material commodity-related risks inherent in our business activities are described below.

In the normal course of our operations, we purchase and sell commodities. We use derivatives to manage the associated risks and to optimize profits. As of March 31, 2023, net derivative positions related to these activities included:

•A net long position of 4.8 million barrels associated with our crude oil purchases, which was unwound ratably during April 2023 to match monthly average pricing.

•A net short time spread position of 5.3 million barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through December 2024.

•A net crude oil basis spread position of 5.1 million barrels at multiple locations through December 2024. These derivatives allow us to lock in grade and location basis differentials.

•A net short position of 14.3 million barrels through June 2024 related to anticipated net sales of crude oil and NGL inventory.

We purchase natural gas for processing and operational needs. Additionally, we purchase NGL mix for fractionation and sell the resulting individual specification products (including ethane, propane, butane and condensate). In conjunction with these activities, we hedge the price risk associated with the purchase of the natural gas and the subsequent sale of the individual specification products. The following table summarizes our open derivative positions utilized to hedge the price risk associated with anticipated purchases and sales related to our natural gas processing and NGL fractionation activities as of March 31, 2023:

Notional Volume

(Short)/Long

Remaining Tenor

Natural gas purchases

56.0 Bcf

December 2024

Propane sales

(10.6) MMbls

December 2024

Butane sales

(1.0) MMbls

December 2024

Condensate sales

(0.7) MMbls

December 2024

Fuel gas requirements (1)

5.7 Bcf

June 2024

Power supply requirements (1)

2.0 TWh

December 2030

(1)Positions to hedge a portion of our power supply and fuel gas requirements at our Canadian natural gas processing and fractionation plants.

Physical commodity contracts that meet the definition of a derivative but are ineligible, or not designated, for the normal purchases and normal sales scope exception are recorded on the balance sheet at fair value, with changes in fair value recognized in earnings. We have determined that substantially all of our physical commodity contracts qualify for the normal purchases and normal sales scope exception.

Our commodity derivatives are not designated in a hedging relationship for accounting purposes; as such, changes in the fair value are reported in earnings. The following table summarizes the impact of our commodity derivatives recognized in earnings (in millions):


	Three Months Ended March 31,
	2023		2022
Product sales revenues	$	(1)	$	(213)
Field operating costs	(19)		13

Net loss from commodity derivative activity	$	(20)	$	(200)

Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through clearing brokerage accounts and are subject to margin requirements as established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. The following table provides the components of our net broker receivable/(payable) (in millions):


	March 31, 2023		December 31, 2022
Initial margin	$	74	$	93
Variation margin returned	(85)		(236)
Letters of credit	(25)		(25)
Net broker payable	$	(36)	$	(168)


	March 31, 2023								December 31, 2022
					Effect of Collateral Netting		Net Carrying Value Presented on the Balance Sheet						Effect of Collateral Netting		Net Carrying Value Presented on the Balance Sheet
	Commodity Derivatives								Commodity Derivatives
	Assets		Liabilities						Assets		Liabilities
Derivative Assets
Other current assets	$	120	$	(33)	$	(36)	$	51	$	300	$	(71)	$	(168)	$	61
Other long-term assets, net	6		—		—		6		9		(5)		—		4
Derivative Liabilities
Other current liabilities	7		(52)		—		(45)		2		(13)		—		(11)
Other long-term liabilities and deferred credits	1		(5)		—		(4)		—		—		—		—
Total	$	134	$	(90)	$	(36)	$	8	$	311	$	(89)	$	(168)	$	54

Interest Rate Risk Hedging

We use interest rate derivatives to hedge the benchmark interest rate associated with interest payments occurring as a result of debt issuances. The derivative instruments we use to manage this risk consist of forward starting interest rate swaps and treasury locks. These derivatives are designated as cash flow hedges. As such, changes in fair value are deferred in AOCI and are reclassified to interest expense as we incur the interest expense associated with the underlying debt.

The following table summarizes the terms of our outstanding interest rate derivatives as of March 31, 2023 (notional amounts in millions):

Hedged Transaction

Number and Types of
Derivatives Employed

Notional
Amount

Expected
Termination Date

Average Rate
Locked

Accounting
Treatment

Anticipated interest payments

8 forward starting swaps

(30-year)

200

6/15/2023

1.38

Cash flow hedge

Anticipated interest payments

4 forward starting swaps

(30-year)

100

6/14/2024

0.74

Cash flow hedge

As of March 31, 2023, there was a net loss of $110 million deferred in AOCI. The deferred net loss recorded in AOCI is expected to be reclassified to future earnings contemporaneously with interest expense accruals associated with underlying debt instruments. We estimate that substantially all of the remaining deferred loss will be reclassified to earnings through 2054 as the underlying hedged transactions impact earnings. A portion of these amounts is based on market prices as of March 31, 2023; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

The following table summarizes the net unrealized gain/(loss) recognized in AOCI for derivatives (in millions):


	Three Months Ended March 31,
	2023		2022
Interest rate derivatives, net	$	(5)	$	32

At March 31, 2023, the net fair value of our interest rate hedges, which were included in “Other current assets” and “Other long-term assets, net” on our Condensed Consolidated Balance Sheet, totaled $71 million and $44 million, respectively. At December 31, 2022, the net fair value of these hedges totaled $75 million and $45 million, which were included in “Other current assets” and “Other long-term assets, net,” respectively.

Preferred Distribution Rate Reset Option

In January 2023, we received notice that the Series A preferred unitholders elected the Preferred Distribution Rate Reset Option. Prior to this election, the Preferred Distribution Rate Reset Option was accounted for as an embedded derivative. A derivative feature embedded in a contract that does not meet the definition of a derivative in its entirety must be bifurcated and accounted for separately if the economic characteristics and risks of the embedded derivative are not clearly and closely related to those of the host contract. The Preferred Distribution Rate Reset Option embedded derivative was required to be bifurcated from the related host contract, the PAA partnership agreement, and recorded at fair value on our Condensed Consolidated Balance Sheet. The fair value of the Preferred Distribution Rate Reset Option, which was included in “Other long-term liabilities and deferred credits” on our Condensed Consolidated Balance Sheet, totaled $189 million at December 31, 2022. The Preferred Distribution Rate Reset Option was settled when we received notice that the Series A preferred unitholders elected the Preferred Distribution Rate Reset Option. The fair value of the Preferred Distribution Rate Reset Option on the settlement date was $131 million. The Preferred Distribution Rate Reset Option embedded derivative was not designated in a hedging relationship for accounting purposes and corresponding changes in fair value were recognized in “Other income/(expense), net” in our Condensed Consolidated Statements of Operations. For the three months ended March 31, 2023, we recognized a gain of $58 million and for the three months ended March 31, 2022, we recognized a loss of $44 million. See Note 6 for additional information regarding the Preferred Distribution Rate Reset Option.

Recurring Fair Value Measurements

Derivative Financial Assets and Liabilities

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis (in millions):


	Fair Value as of March 31, 2023								Fair Value as of December 31, 2022
Recurring Fair Value Measures (1)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Commodity derivatives	$	1	$	43	$	—	$	44	$	(7)	$	229	$	—	$	222
Interest rate derivatives	—		115		—		115		—		120		—		120

Preferred Distribution Rate Reset Option	—		—		—		—		—		—		(189)		(189)
Total net derivative asset/(liability)	$	1	$	158	$	—	$	159	$	(7)	$	349	$	(189)	$	153

(1)Derivative assets and liabilities are presented above on a net basis but do not include related cash margin deposits.

Level 1

Level 1 of the fair value hierarchy includes exchange-traded commodity derivatives and over-the-counter commodity contracts such as futures and swaps. The fair value of exchange-traded commodity derivatives and over-the-counter commodity contracts is based on unadjusted quoted prices in active markets.

Level 2

Level 2 of the fair value hierarchy includes exchange-cleared commodity derivatives and over-the-counter commodity and interest rate derivatives that are traded in observable markets with less volume and transaction frequency than active markets. In addition, it includes certain physical commodity contracts. The fair values of these derivatives are corroborated with market observable inputs.

Level 3

Level 3 of the fair value hierarchy includes the Preferred Distribution Rate Reset Option contained in PAA’s partnership agreement which was classified as an embedded derivative. As discussed above, the Preferred Distribution Rate Reset Option was settled on January 31, 2023. The fair value of the Preferred Distribution Rate Reset Option was based on a Monte Carlo valuation model that estimated the fair value of the Series A preferred units with and without the Preferred Distribution Rate Reset Option. This model relied on assumptions for forecasts for the ten-year U.S. Treasury rate, PAA’s common unit price, and default probabilities which impacted timing estimates as to when the option would be exercised.

Rollforward of Level 3 Net Asset/(Liability)

The following table provides a reconciliation of changes in fair value of the beginning and ending balances for our derivatives classified as Level 3 (in millions):


	Three Months Ended March 31,
	2023		2022
Beginning Balance	$	(189)	$	(2)
Net gains/(losses) for the period included in earnings	58		(44)
Settlements	131		2

Ending Balance	$	—	$	(44)

Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period	$	—	$	(44)

Related Party Transactions

3 Months Ended

Mar. 31, 2023

Related Party Transactions

See Note 17 to our Consolidated Financial Statements included in Part IV of our 2022 Annual Report on Form 10-K for a complete discussion of related parties, including the determination of our related parties and nature of involvement with such related parties.

During the three months ended March 31, 2023 and 2022, we recognized sales and transportation revenues, purchased petroleum products and utilized transportation and storage services from related parties. These transactions were conducted at posted tariff rates or prices that we believe approximate market.

The impact to our Condensed Consolidated Statements of Operations from these transactions is included below (in millions):


	Three Months Ended March 31,
	2023		2022
Revenues from related parties	$	11	$	12

Purchases and related costs from related parties	$	99	$	97

Our receivable and payable amounts with these related parties as reflected on our Condensed Consolidated Balance Sheets were as follows (in millions):


	March 31, 2023		December 31, 2022
Trade accounts receivable and other receivables, net from related parties (1)	$	73	$	45

Trade accounts payable to related parties (1) (2)	$	74	$	79

(1)Includes amounts related to crude oil purchases and sales, transportation and storage services and amounts owed to us or advanced to us related to investment capital projects of equity method investees where we serve as construction manager.

(2)We have agreements to store crude oil at facilities and transport crude oil or utilize capacity on pipelines that are owned by equity method investees. A portion of our commitment to transport is supported by crude oil buy/sell or other agreements with third parties with commensurate quantities.

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Mar. 31, 2023	Dec. 31, 2022	Mar. 31, 2022	Dec. 31, 2021
Class A Shares
Shares outstanding
Shares outstanding (shares)	194,407,642	194,407,642	194,228,477	194,192,777

Net Income Per Class A Share

3 Months Ended

Mar. 31, 2023

Earnings Per Share [Abstract]

Net Income Per Class A Share

Basic net income per Class A share is determined by dividing net income attributable to PAGP by the weighted average number of Class A shares outstanding during the period. Our Class B and Class C shares do not share in the earnings of the Partnership; accordingly, basic and diluted net income per Class B and Class C share has not been presented.

Diluted net income per Class A share is determined by dividing net income attributable to PAGP by the diluted weighted average number of Class A shares outstanding during the period. For purposes of calculating diluted net income per Class A share, both the net income attributable to PAGP and the diluted weighted average number of Class A shares outstanding consider the impact of possible future exchanges of AAP units and the associated Class B shares into our Class A shares. In addition, the calculation of the diluted weighted average number of Class A shares outstanding considers the effect of potentially dilutive awards under the Plains GP Holdings, L.P. Long-Term Incentive Plan (the “PAGP LTIP”).

Exchanges of potentially dilutive AAP units are assumed to have occurred at the beginning of the period and the incremental income attributable to PAGP resulting from the assumed exchanges is representative of the incremental income that would have been attributable to PAGP if the assumed exchanges occurred on that date. See Note 12 to our Consolidated Financial Statements included in Part IV of our 2022 Annual Report on Form 10-K for information regarding exchanges of AAP units. PAGP LTIP awards that are deemed to be dilutive are reduced by a hypothetical share repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. See Note 18 to our Consolidated Financial Statements included in Part IV of our 2022 Annual Report on Form 10-K for information regarding PAGP LTIP awards.

On a weighted-average basis, for each of the three months ended March 31, 2023 and 2022, the possible exchange of 47 million AAP units would not have had a dilutive effect on basic net income per Class A share. For each of the three months ended March 31, 2023 and 2022, our PAGP LTIP awards were dilutive; however, this did not change the presentation of diluted weighted average Class A shares outstanding or diluted net income per Class A share.

The following table sets forth the computation of basic and diluted net income per Class A share (in millions, except per share data):


	Three Months Ended March 31,
	2023		2022
Basic and Diluted Net Income per Class A Share
Net income attributable to PAGP	$	69	$	22
Basic and diluted weighted average Class A shares outstanding	194		194

Basic and diluted net income per Class A share	$	0.35	$	0.11

Partners' Capital and Distributions

3 Months Ended

Mar. 31, 2023

Partners' Capital Notes [Abstract]

Partners' Capital and Distributions

Partners’ Capital and Distributions

Shares Outstanding

The following tables present the activity for our Class A shares, Class B shares and Class C shares:


	Class A Shares	Class B Shares	Class C Shares
Outstanding at December 31, 2022	194,407,642	46,205,947	528,442,538
Conversion of AAP Management Units (1) (2)	—	388,839	—

Redemption Right exercises (1)	—	(181,916)	181,916

Other	—	—	35,508
Outstanding at March 31, 2023	194,407,642	46,412,870	528,659,962


	Class A Shares	Class B Shares	Class C Shares
Outstanding at December 31, 2021	194,192,777	46,645,514	534,596,831
Conversion of AAP Management Units (1)	—	205,024	—
Exchange Right exercises (1)	35,700	(35,700)	—
Redemption Right exercises (1)	—	(11,957)	11,957
Repurchase and cancellation of common units by a subsidiary under the Common Equity Repurchase Program	—	—	(2,375,299)
Other	—	—	51,937
Outstanding at March 31, 2022	194,228,477	46,802,881	532,285,426

(1)See Note 12 to our Consolidated Financial Statements included in Part IV of our 2022 Annual Report on Form 10-K for information regarding conversions of AAP Management Units, Exchange Rights and Redemption Rights.

(2)Following this conversion, no AAP Management Units remain outstanding.

Distributions

The following table details distributions to our Class A shareholders paid during or pertaining to the first three months of 2023 (in millions, except per share data):


Distribution Payment Date	Distributions to Class A Shareholders		Distributions per Class A Share


May 15, 2023 (1)	$	52	$	0.2675
February 14, 2023	$	52	$	0.2675

(1)Payable to shareholders of record at the close of business on May 1, 2023 for the period from January 1, 2023 through March 31, 2023.

Consolidated Subsidiaries

Noncontrolling Interests in Subsidiaries

As of March 31, 2023, noncontrolling interests in our subsidiaries consisted of (i) limited partner interests in PAA including a 69% interest in PAA’s common units and PAA’s Series A preferred units combined and 100% of PAA’s Series B preferred units, (ii) an approximate 19% limited partner interest in AAP, (iii) a 35% interest in Plains Oryx Permian Basin LLC (the “Permian JV”), (iv) a 30% interest in Cactus II Pipeline LLC (“Cactus II”) and (v) a 33% interest in Red River Pipeline Company LLC (“Red River”).

Subsidiary Distributions

PAA Series A Preferred Unit Distributions. After the fifth anniversary of the January 28, 2016 issuance date of PAA’s Series A preferred units, the holders of PAA’s Series A preferred units, acting by majority vote, had the option to make a one-time election to reset the Series A preferred unit distribution rate to equal the then applicable rate of ten-year U.S. Treasury Securities plus 5.85% (the “Preferred Distribution Rate Reset Option”). In January 2023, the Series A preferred unitholders elected the Preferred Distribution Rate Reset Option which resulted in an increase in the quarterly distribution rate to approximately $0.615 per unit. This new distribution rate was effective on January 31, 2023. The quarterly distribution to be paid in May 2023 will reflect a pro-rated amount of approximately $0.585 per unit. The following table details distributions to PAA’s Series A preferred unitholders paid during or pertaining to the first three months of 2023 (in millions, except per unit data):


	Series A Preferred Unitholders
Distribution Payment Date	Cash Distribution		Distribution per Unit


May 15, 2023 (1)	$	42	$	0.585
February 14, 2023	$	37	$	0.525

(1)Payable to unitholders of record at the close of business on May 1, 2023 for the period from January 1, 2023 through March 31, 2023. At March 31, 2023, such amount was accrued as distributions payable in “Other current liabilities” on our Condensed Consolidated Balance Sheet.

PAA Series B Preferred Unit Distributions. Distributions on PAA’s Series B preferred units accumulate and are payable quarterly in arrears on the 15th day of February, May, August and November. The following table details distributions paid or to be paid to PAA’s Series B preferred unitholders (in millions, except per unit data):


	Series B Preferred Unitholders
Distribution Payment Date	Cash Distribution		Distribution per Unit
May 15, 2023 (1)	$	18	$	22.18
February 15, 2023	$	18	$	22.27

(1)Payable to unitholders of record at the close of business on May 1, 2023 for the period from February 15, 2023 through May 14, 2023. At March 31, 2023, approximately $9 million of accrued distributions payable to PAA’s Series B preferred unitholders was included in “Other current liabilities” on our Condensed Consolidated Balance Sheet.

PAA Common Unit Distributions. The following table details distributions to PAA’s common unitholders paid during or pertaining to the first three months of 2023 (in millions, except per unit data):


	Distributions						Cash Distribution per Common Unit
	Common Unitholders				Total Cash Distribution
Distribution Payment Date	Public		AAP


May 15, 2023 (1)	$	122	$	65	$	187	$	0.2675
February 14, 2023	$	122	$	65	$	187	$	0.2675

(1)Payable to unitholders of record at the close of business on May 1, 2023 for the period from January 1, 2023 through March 31, 2023.

AAP Distributions. The following table details the distributions to AAP’s partners paid during or pertaining to the first three months of 2023 from distributions received from PAA (in millions):


	Distributions to AAP’s Partners
Distribution Payment Date	Noncontrolling Interests		PAGP		Total Cash Distribution


May 15, 2023 (1)	$	13	$	52	$	65
February 14, 2023	$	13	$	52	$	65

(1)Payable to unitholders of record at the close of business on May 1, 2023 for the period from January 1, 2023 through March 31, 2023.

Consolidated Joint Venture Distributions. The following table details distributions paid to noncontrolling interests of consolidated joint ventures during the periods presented (in millions):


	Three Months Ended March 31,
	2023		2022
Permian JV	$	58	$	54
Cactus II (1)	14		—
Red River	6		5
	$	78	$	59

(1)In November 2022, we acquired an additional interest in Cactus II which, combined with changes in the governance of this entity, resulted in our obtaining control of the entity. Subsequent to this transaction, we reflect Cactus II as a consolidated subsidiary. See Note 7 to our Consolidated Financial Statements included in Part IV of our 2022 Annual Report on Form 10-K for additional information on the Cactus II transaction.

Derivatives and Risk Management Activities - Financial Impact (Details) - Derivatives Not Designated as a Hedge - Commodity derivatives - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Impact of derivative activities recognized in earnings
Net loss from commodity derivative activity	$ (20)	$ (200)
Product sales revenues
Impact of derivative activities recognized in earnings
Net loss from commodity derivative activity	(1)	(213)
Field operating costs
Impact of derivative activities recognized in earnings
Net loss from commodity derivative activity	$ (19)	$ 13

Derivatives and Risk Management Activities - Fair Value (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022
Level 3
Rollforward of Level 3 Net Asset/(Liability)
Beginning Balance	$ (189)	$ (2)
Net gains/(losses) for the period included in earnings	58	(44)
Settlements	131	2
Ending Balance		(44)
Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period		$ (44)
Recurring Fair Value Measures
Recurring Fair Value Measurements
Total net derivative asset/(liability)	159		$ 153
Recurring Fair Value Measures \| Commodity derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	44		222
Recurring Fair Value Measures \| Interest rate derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	115		120
Recurring Fair Value Measures \| Preferred Distribution Rate Reset Option
Recurring Fair Value Measurements
Total net derivative asset/(liability)			(189)
Recurring Fair Value Measures \| Level 1
Recurring Fair Value Measurements
Total net derivative asset/(liability)	1		(7)
Recurring Fair Value Measures \| Level 1 \| Commodity derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	1		(7)
Recurring Fair Value Measures \| Level 2
Recurring Fair Value Measurements
Total net derivative asset/(liability)	158		349
Recurring Fair Value Measures \| Level 2 \| Commodity derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	43		229
Recurring Fair Value Measures \| Level 2 \| Interest rate derivatives
Recurring Fair Value Measurements
Total net derivative asset/(liability)	$ 115		120
Recurring Fair Value Measures \| Level 3
Recurring Fair Value Measurements
Total net derivative asset/(liability)			(189)
Recurring Fair Value Measures \| Level 3 \| Preferred Distribution Rate Reset Option
Recurring Fair Value Measurements
Total net derivative asset/(liability)			$ (189)

Net Income Per Class A Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Basic and Diluted Net Income per Class A Share
Net income attributable to PAGP	$ 69	$ 22
AAP Units
Basic and Diluted Net Income Per Share
Antidilutive securities excluded from computation of earnings per share (shares)	47	47
Class A Shares
Basic and Diluted Net Income per Class A Share
Basic weighted average Class A shares outstanding (shares)	194	194
Diluted weighted average Class A shares outstanding (shares)	194	194
Basic net income per Class A share (usd per share)	$ 0.35	$ 0.11
Diluted net income per Class A share (usd per share)	$ 0.35	$ 0.11

Divestitures - Narrative (Details) $ in Millions	1 Months Ended	3 Months Ended
Divestitures - Narrative (Details) $ in Millions	Feb. 28, 2023 USD ($)	Mar. 31, 2023 USD ($)	Mar. 31, 2022 USD ($)	Dec. 31, 2022 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Gains/(losses) on asset sales and asset impairments, net		$ 154	$ 42
Keyera Fort Saskatchewan Facility
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Undivided Joint Interest Ownership Percentage, Sold	0.21
Proceeds from sale of undivided joint interest	$ 270
Gains/(losses) on asset sales and asset impairments, net	$ 140
Keyera Fort Saskatchewan Facility \| Other current assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Assets held-for-sale				$ 130

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Changes in Accumulated Other Comprehensive Income/(Loss)
Beginning balance	$ 14,638	$ 14,177
Total period activity	(1)	74
Ending balance	14,764	14,201
Derivative Instruments
Changes in Accumulated Other Comprehensive Income/(Loss)
Beginning balance	(107)	(208)
Reclassification adjustments	2	3
Unrealized gain/(loss) on hedges	(5)	32
Total period activity	(3)	35
Ending balance	(110)	(173)
Translation Adjustments
Changes in Accumulated Other Comprehensive Income/(Loss)
Beginning balance	(846)	(642)
Currency translation adjustments	1	40
Total period activity	1	40
Ending balance	(845)	(602)
Other
Changes in Accumulated Other Comprehensive Income/(Loss)
Beginning balance	(1)	(3)
Other	1	(1)
Total period activity	1	(1)
Ending balance		(4)
Total
Changes in Accumulated Other Comprehensive Income/(Loss)
Beginning balance	(954)	(853)
Reclassification adjustments	2	3
Unrealized gain/(loss) on hedges	(5)	32
Currency translation adjustments	1	40
Other	1	(1)
Total period activity	(1)	74
Ending balance	$ (955)	$ (779)

Partners' Capital and Distributions - Shares Activity (Details) - shares	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Class A Shares
Increase (Decrease) in Partners' Capital
Balance, beginning of period (shares)	194,407,642	194,192,777
Exchange Right exercises (shares)		35,700
Balance, end of period (shares)	194,407,642	194,228,477
Class B Shares
Increase (Decrease) in Partners' Capital
Balance, beginning of period (shares)	46,205,947	46,645,514
Conversion of AAP Management Units (shares)	388,839	205,024
Exchange Right exercises (shares)		(35,700)
Redemption Right exercises (shares)	(181,916)	(11,957)
Balance, end of period (shares)	46,412,870	46,802,881
Class C Shares
Increase (Decrease) in Partners' Capital
Balance, beginning of period (shares)	528,442,538	534,596,831
Redemption Right exercises (shares)	181,916	11,957
Repurchase and cancellation of common units by a subsidiary under the Common Equity Repurchase Program (shares)		(2,375,299)
Other (shares)	35,508	51,937
Balance, end of period (shares)	528,659,962	532,285,426
AAP Management Units \| AAP
Increase (Decrease) in Partners' Capital
Balance, end of period (shares)	0

Debt

3 Months Ended

Mar. 31, 2023

Debt Disclosure [Abstract]

Debt

Debt consisted of the following (in millions):


	March 31, 2023		December 31, 2022
SHORT-TERM DEBT



PAA senior notes:

2.85% senior notes due January 2023 (1)	$	—	$	400
3.85% senior notes due October 2023	700		700
Other	8		59
Total short-term debt	708		1,159

LONG-TERM DEBT
PAA senior notes, net of unamortized discounts and debt issuance costs of $45 and $46, respectively	7,238		7,237


Other	50		50
Total long-term debt	7,288		7,287
Total debt (2)	$	7,996	$	8,446

(1)These senior notes were redeemed on January 31, 2023.

(2)PAA’s fixed-rate senior notes had a face value of approximately $8.0 billion and $8.4 billion as of March 31, 2023 and December 31, 2022, respectively. We estimated the aggregate fair value of these notes as of March 31, 2023 and December 31, 2022 to be approximately $7.3 billion and $7.6 billion, respectively. PAA’s fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near the end of the reporting period. The fair value estimate for PAA’s senior notes is based upon observable market data and is classified in Level 2 of the fair value hierarchy.

Borrowings and Repayments

Total borrowings under the PAA credit facilities and commercial paper program for the three months ended March 31, 2023 and 2022 were approximately $1.5 billion and $5.6 billion, respectively. Total repayments under the PAA credit facilities and commercial paper program were approximately $1.5 billion and $5.2 billion for the three months ended March 31, 2023 and 2022, respectively. The variance in total gross borrowings and repayments is impacted by various business and financial factors including, but not limited to, the timing, average term and method of general partnership borrowing activities.

On January 31, 2023, PAA redeemed its 2.85%, $400 million senior notes due January 2023.

Letters of Credit

In connection with our merchant activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil and NGL. Additionally, we issue letters of credit to support insurance programs, derivative transactions, including hedging-related margin obligations, and construction activities. At March 31, 2023 and December 31, 2022, we had outstanding letters of credit of $144 million and $102 million, respectively.

- Definition

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 6: http://www.xbrl.org/2003/role/disclosureRef
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Reference 7: http://www.xbrl.org/2003/role/disclosureRef
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

Related Party Transactions (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022
Related Party Transactions [Abstract]
Revenues from related parties	$ 11	$ 12
Purchases and related costs from related parties	99	$ 97
Trade accounts receivable and other receivables, net from related parties	73		$ 45
Trade accounts payable to related parties	$ 74		$ 79

- Definition

The aggregate amount of receivables to be collected from related parties where one party can exercise control or significant influence over another party; including affiliates, owners or officers and their immediate families, pension trusts, and so forth, at the financial statement date. which are usually due within one year (or one business cycle).

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- Definition

Carrying amount as of the balance sheet date of obligations due all related parties. For classified balance sheets, represents the current portion of such liabilities (due within one year or within the normal operating cycle if longer).

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- Definition

Amount of revenue, fees and commissions earned from transactions between (a) a parent company and its subsidiaries; (b) subsidiaries of a common parent; (c) an entity and trusts for the benefit of employees, for example, but not limited to, pension and profit-sharing trusts that are managed by or under the trusteeship of the entity's management; (d) an entity and its principal, owners, management, or members of their immediate families; and (e) affiliates.

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+ Details

Related Party Transactions (Tables)

3 Months Ended

Mar. 31, 2023

Schedule of related party transactions

The impact to our Condensed Consolidated Statements of Operations from these transactions is included below (in millions):


	Three Months Ended March 31,
	2023		2022
Revenues from related parties	$	11	$	12

Purchases and related costs from related parties	$	99	$	97

Our receivable and payable amounts with these related parties as reflected on our Condensed Consolidated Balance Sheets were as follows (in millions):


	March 31, 2023		December 31, 2022
Trade accounts receivable and other receivables, net from related parties (1)	$	73	$	45

Trade accounts payable to related parties (1) (2)	$	74	$	79

Derivatives and Risk Management Activities - Net Unrealized Gain/(Loss) Recognized in AOCI (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022
Other current assets
Derivative assets and liabilities
Interest rate fair value hedge liability at fair value	$ 71		$ 75
Other long-term assets, net
Derivative assets and liabilities
Interest rate fair value hedge liability at fair value	44		$ 45
Interest rate derivatives
Derivative assets and liabilities
Net unrealized gain/(loss) recognized in AOCI	(5)	$ 32
AOCI cash flow hedge
Derivative assets and liabilities
Net loss deferred in AOCI	$ 110

- Definition

Accumulated change in equity from transactions and other events and circumstances from non-owner sources, net of tax effect, at period end. Excludes Net Income (Loss), and accumulated changes in equity from transactions resulting from investments by owners and distributions to owners. Includes foreign currency translation items, certain pension adjustments, unrealized gains and losses on certain investments in debt and equity securities, other than temporary impairment (OTTI) losses related to factors other than credit losses on available-for-sale and held-to-maturity debt securities that an entity does not intend to sell and it is not more likely than not that the entity will be required to sell before recovery of the amortized cost basis, as well as changes in the fair value of derivatives related to the effective portion of a designated cash flow hedge.

+ References + Details

Debt - Credit Facilities, Borrowings and Repayments and Letters of Credit (Details) - USD ($) $ in Millions		3 Months Ended
	Jan. 31, 2023	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022
Debt
Repayments of senior notes		$ 400	$ 750
Outstanding letters of credit		144		$ 102
2.85% senior notes due January 2023 \| Senior notes
Debt
Debt instrument, interest rate (as a percent)	2.85%			2.85%
Repayments of senior notes	$ 400
Credit facilities and PAA commercial paper program
Debt
Total borrowings		1,500	5,600
Total repayments		$ 1,500	$ 5,200

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
REVENUES
Total revenues	$ 12,341	$ 13,694
COSTS AND EXPENSES
Purchases and related costs	11,323	12,785
Field operating costs	357	346
General and administrative expenses	87	83
Depreciation and amortization	257	231
(Gains)/losses on asset sales and asset impairments, net	(154)	(42)
Total costs and expenses	11,870	13,403
OPERATING INCOME	471	291
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	89	97
Interest expense (net of capitalized interest of $2 and $1, respectively)	(98)	(107)
Other income/(expense), net	64	(37)
INCOME BEFORE TAX	526	244
Current income tax expense	(61)	(19)
Deferred income tax expense	(22)	(16)
NET INCOME	443	209
Net income attributable to noncontrolling interests	(374)	(187)
NET INCOME ATTRIBUTABLE TO PAGP	$ 69	$ 22
Class A Shares
OTHER INCOME/(EXPENSE)
Basic weighted average Class A shares outstanding (shares)	194	194
Diluted weighted average Class A shares outstanding (shares)	194	194
Basic net income per Class A share (usd per share)	$ 0.35	$ 0.11
Diluted net income per Class A share (usd per share)	$ 0.35	$ 0.11
Product sales revenues
REVENUES
Total revenues	$ 11,943	$ 13,381
Services revenues
REVENUES
Total revenues	$ 398	$ 313

Segment Information - Segment Financial Data (Details) $ in Millions	3 Months Ended
	Mar. 31, 2023 USD ($) segment	Mar. 31, 2022 USD ($)
Segment Reporting Information
Operating segments number \| segment	2
Reportable segments number \| segment	2
Revenues:
Revenues	$ 12,341	$ 13,694
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities	89	97
Segment Adjusted EBITDA	709	614
Maintenance capital expenditures	48	27
Product sales revenues
Revenues:
Revenues	11,943	13,381
Services revenues
Revenues:
Revenues	398	313
Operating Segments
Revenues:
Revenues	12,448	13,814
Intersegment Revenues Elimination
Revenues:
Revenues	(107)	(120)
Intersegment Revenues Elimination \| Product sales revenues
Revenues:
Revenues	(101)	(112)
Intersegment Revenues Elimination \| Services revenues
Revenues:
Revenues	(6)	(8)
Crude Oil
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Equity earnings in unconsolidated entities	89	97
Segment Adjusted EBITDA	517	453
Maintenance capital expenditures	32	19
Crude Oil \| Operating Segments
Revenues:
Revenues	11,758	13,079
Crude Oil \| Operating Segments \| Product sales revenues
Revenues:
Revenues	11,409	12,811
Crude Oil \| Operating Segments \| Services revenues
Revenues:
Revenues	349	268
NGL
Segment Reporting, Disclosure of Other Information about Entity's Reportable Segments
Segment Adjusted EBITDA	192	161
Maintenance capital expenditures	16	8
NGL \| Operating Segments
Revenues:
Revenues	690	735
NGL \| Operating Segments \| Product sales revenues
Revenues:
Revenues	635	682
NGL \| Operating Segments \| Services revenues
Revenues:
Revenues	$ 55	$ 53

Debt (Tables)

3 Months Ended

Mar. 31, 2023

Debt Disclosure [Abstract]

Schedule of debt

Debt consisted of the following (in millions):


	March 31, 2023		December 31, 2022
SHORT-TERM DEBT



PAA senior notes:

2.85% senior notes due January 2023 (1)	$	—	$	400
3.85% senior notes due October 2023	700		700
Other	8		59
Total short-term debt	708		1,159

LONG-TERM DEBT
PAA senior notes, net of unamortized discounts and debt issuance costs of $45 and $46, respectively	7,238		7,237


Other	50		50
Total long-term debt	7,288		7,287
Total debt (2)	$	7,996	$	8,446

(1)These senior notes were redeemed on January 31, 2023.(2)PAA’s fixed-rate senior notes had a face value of approximately $8.0 billion and $8.4 billion as of March 31, 2023 and December 31, 2022, respectively. We estimated the aggregate fair value of these notes as of March 31, 2023 and December 31, 2022 to be approximately $7.3 billion and $7.6 billion, respectively. PAA’s fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near the end of the reporting period. The fair value estimate for PAA’s senior notes is based upon observable market data and is classified in Level 2 of the fair value hierarchy.

Derivatives and Risk Management Activities - Preferred Distribution Rate (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Jan. 31, 2023	Dec. 31, 2022
Derivatives and Risk Management Activities
Gain/(loss) recognized	$ 58	$ (44)
Preferred Distribution Rate Reset Option \| Derivatives Not Designated as a Hedge
Derivatives and Risk Management Activities
Derivative liability			$ 131	$ 189
Derivative liability [Extensible Enumeration]	Other long-term liabilities and deferred credits			Other long-term liabilities and deferred credits
Preferred Distribution Rate Reset Option \| Derivatives Not Designated as a Hedge \| Other income/(expense), net
Derivatives and Risk Management Activities
Gain/(loss) recognized	$ 58	$ (44)

Revenues and Accounts Receivable

3 Months Ended

Mar. 31, 2023

Revenue from Contract with Customer [Abstract]

Revenues and Accounts Receivable

Revenue Recognition

We disaggregate our revenues by segment and type of activity. See Note 3 to our Consolidated Financial Statements included in Part IV of our 2022 Annual Report on Form 10-K for additional information regarding our types of revenues and policies for revenue recognition.

Revenues from Contracts with Customers. The following tables present our revenues from contracts with customers disaggregated by segment and type of activity (in millions):


	Three Months Ended March 31,
	2023		2022
Crude Oil segment revenues from contracts with customers
Sales	$	11,381	$	12,857
Transportation	250		155
Terminalling, Storage and Other	90		90
Total Crude Oil segment revenues from contracts with customers	$	11,721	$	13,102


	Three Months Ended March 31,
	2023		2022
NGL segment revenues from contracts with customers
Sales	$	660	$	845
Transportation	8		9
Terminalling, Storage and Other	28		25
Total NGL segment revenues from contracts with customers	$	696	$	879

Reconciliation to Total Revenues of Reportable Segments. The following disclosures only include information regarding revenues associated with consolidated entities; revenues from entities accounted for by the equity method are not included. The following tables present the reconciliation of our revenues from contracts with customers to total revenues of reportable segments and total revenues as disclosed in our Condensed Consolidated Statements of Operations (in millions):


Three Months Ended March 31, 2023	Crude Oil		NGL		Total
Revenues from contracts with customers	$	11,721	$	696	$	12,417
Other revenues	37		(6)		31
Total revenues of reportable segments	$	11,758	$	690	$	12,448
Intersegment revenues elimination					(107)
Total revenues					$	12,341

Three Months Ended March 31, 2022	Crude Oil		NGL		Total
Revenues from contracts with customers	$	13,102	$	879	$	13,981
Other revenues	(23)		(144)		(167)
Total revenues of reportable segments	$	13,079	$	735	$	13,814
Intersegment revenues elimination					(120)
Total revenues					$	13,694

Minimum Volume Commitments. We have certain agreements that require counterparties to transport or throughput a minimum volume over an agreed upon period. The following table presents counterparty deficiencies associated with contracts with customers and buy/sell arrangements that include minimum volume commitments for which we had remaining performance obligations and the customers still had the ability to meet their obligations (in millions):


Counterparty Deficiencies	Financial Statement Classification	March 31, 2023		December 31, 2022
Billed and collected	Other current liabilities	$	88	$	104
Unbilled (1)	N/A	—		1
Total		$	88	$	105

(1)Amounts were related to deficiencies for which the counterparties had not met their contractual minimum commitments and are not reflected in our Condensed Consolidated Financial Statements as we had not yet billed or collected such amounts.

Contract Balances. Our contract balances consist of amounts received associated with services or sales for which we have not yet completed the related performance obligation. The following table presents the changes in the liability balance associated with contracts with customers (in millions):


	Contract Liabilities
Balance at December 31, 2022	$	229
Amounts recognized as revenue	(31)

Additions	6

Balance at March 31, 2023	$	204

Remaining Performance Obligations. The information below includes the amount of consideration allocated to partially and wholly unsatisfied remaining performance obligations under contracts that existed as of the end of the periods and the timing of revenue recognition of those remaining performance obligations. Certain contracts meet the requirements for the presentation as remaining performance obligations. These contracts include a fixed minimum level of service, typically a set volume of service, and do not contain any variability other than expected timing within a limited range. The following table presents the amount of consideration associated with remaining performance obligations for the population of contracts with external customers meeting the presentation requirements as of March 31, 2023 (in millions):


	Remainder of 2023		2024		2025		2026		2027		2028 and Thereafter
Pipeline revenues supported by minimum volume commitments and capacity agreements (1)	$	253	$	339	$	360	$	131	$	94	$	236
Terminalling, storage and other agreement revenues	195		203		127		99		89		737
Total	$	448	$	542	$	487	$	230	$	183	$	973

(1)Calculated as volumes committed under contracts multiplied by the current applicable tariff rate.

The presentation above does not include (i) expected revenues from legacy shippers not underpinned by minimum volume commitments, including pipelines where there are no or limited alternative pipeline transportation options, (ii) intersegment revenues and (iii) the amount of consideration associated with certain income generating contracts, which include a fixed minimum level of service, that are either not within the scope of ASC 606 or do not meet the requirements for presentation as remaining performance obligations. The following are examples of contracts that are not included in the table above because they are not within the scope of ASC 606 or do not meet the requirements for presentation:

•Minimum volume commitments on certain of our joint venture pipeline systems;

•Acreage dedications;

•Buy/sell arrangements with future committed volumes;

•Short-term contracts and those with variable consideration, due to the election of practical expedients;

•Contracts within the scope of ASC Topic 842, Leases; and

•Contracts within the scope of ASC Topic 815, Derivatives and Hedging.

Trade Accounts Receivable and Other Receivables, Net

Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL. These purchasers include, but are not limited to, refiners, producers, marketing and trading companies and financial institutions. The majority of our accounts receivable relate to our crude oil merchant activities that can generally be described as high volume and low margin activities, in many cases involving exchanges of crude oil volumes.

To mitigate credit risk related to our accounts receivable, we utilize a rigorous credit review process. We closely monitor market conditions and perform credit reviews of each customer to make a determination with respect to the amount, if any, of open credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of advance cash payments, standby letters of credit, credit insurance or parental guarantees. Additionally, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. For a majority of these net-cash arrangements, we also enter into netting agreements (contractual agreements that allow us to offset receivables and payables with those counterparties against each other on our balance sheet).

Accounts receivable from the sale of crude oil are generally settled with counterparties on the industry settlement date, which is typically in the month following the month in which the title transfers. Otherwise, we generally invoice customers within 30 days of when the products or services were provided and generally require payment within 30 days of the invoice date. We review all outstanding accounts receivable balances on a monthly basis and record our receivables net of expected credit losses. We do not write-off accounts receivable balances until we have exhausted substantially all collection efforts. At March 31, 2023 and December 31, 2022, substantially all of our trade accounts receivable were less than 30 days past their invoice date. Our expected credit losses are immaterial. Although we consider our credit procedures to be adequate to mitigate any significant credit losses, the actual amount of current and future credit losses could vary significantly from estimated amounts.

The following is a reconciliation of trade accounts receivable from revenues from contracts with customers to total Trade accounts receivable and other receivables, net as presented on our Condensed Consolidated Balance Sheets (in millions):


	March 31, 2023		December 31, 2022
Trade accounts receivable arising from revenues from contracts with customers	$	4,141	$	4,141
Other trade accounts receivables and other receivables (1)	6,912		7,216
Impact due to contractual rights of offset with counterparties	(7,085)		(7,450)
Trade accounts receivable and other receivables, net	$	3,968	$	3,907

(1)The balance is comprised primarily of accounts receivable associated with buy/sell arrangements that are not within the scope of ASC 606.

- Definition

The entire disclosure of revenue from contract with customer to transfer good or service and to transfer nonfinancial asset. Includes, but is not limited to, disaggregation of revenue, credit loss recognized from contract with customer, judgment and change in judgment related to contract with customer, and asset recognized from cost incurred to obtain or fulfill contract with customer. Excludes insurance and lease contracts.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-URI https://asc.fasb.org/topic&trid=49130388

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 10
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130551-203045

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 13
-Subparagraph (b)(2)
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130556-203045

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (b)
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130554-203045

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 9
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130550-203045

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (e)
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130554-203045

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (a)
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130554-203045

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (d)
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130554-203045

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 15
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130558-203045

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (c)
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130554-203045

+ Details

Divestitures	3 Months Ended
Divestitures	Mar. 31, 2023
Discontinued Operations and Disposal Groups [Abstract]
Divestitures	DivestituresKeyera Fort Saskatchewan Divestiture. In February 2023, we sold our 21% non-operated/undivided joint interest in the Keyera Fort Saskatchewan facility for approximately $270 million. As of December 31, 2022, we classified the assets related to this transaction (primarily “Property and equipment” in our NGL segment), valued at the lower of the carrying amount or fair value less costs to sell, of approximately $130 million as assets held for sale, which is reflected in “Other current assets” on our Condensed Consolidated Balance Sheet. Upon the sale of this facility, we recognized a gain of approximately $140 million which is included in “(Gains)/losses on asset sales and asset impairments, net” on our Condensed Consolidated Statement of Operations.

Inventory, Linefill and Long-term Inventory

3 Months Ended

Mar. 31, 2023

Inventory Disclosure [Abstract]

Inventory, Linefill and Long-term Inventory

Inventory, linefill and long-term inventory consisted of the following (barrels in thousands and carrying value in millions):


	March 31, 2023						December 31, 2022
	Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)		Volumes	Unit of Measure	Carrying Value		Price/ Unit (1)
Inventory
Crude oil	5,373	barrels	$	342	$	63.65	6,713	barrels	$	452	$	67.33
NGL	3,427	barrels	111		$	32.39	7,285	barrels	270		$	37.06

Other	N/A		10		N/A		N/A		7		N/A
Inventory subtotal			463						729

Linefill
Crude oil	15,459	barrels	907		$	58.67	15,480	barrels	906		$	58.53
NGL	1,865	barrels	55		$	29.49	1,876	barrels	55		$	29.32

Linefill subtotal			962						961

Long-term inventory
Crude oil	3,136	barrels	227		$	72.39	3,102	barrels	246		$	79.30
NGL	1,063	barrels	30		$	28.22	1,066	barrels	38		$	35.65
Long-term inventory subtotal			257						284

Total			$	1,682					$	1,974

Revenues and Accounts Receivable - Contract Balances (Details) $ in Millions	3 Months Ended
	Mar. 31, 2023 USD ($)
Change in Contract with Customer, Liability
Beginning balance	$ 229
Amounts recognized as revenue	(31)
Additions	6
Ending balance	$ 204

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 443	$ 209
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	257	231
(Gains)/losses on asset sales and asset impairments, net	(154)	(42)
Deferred income tax expense	22	16
Change in fair value of Preferred Distribution Rate Reset Option (Note 7)	(58)	44
Equity earnings in unconsolidated entities	(89)	(97)
Distributions on earnings from unconsolidated entities	108	96
Other	15	4
Changes in assets and liabilities, net of acquisitions	198	(122)
Net cash provided by operating activities	742	339
CASH FLOWS FROM INVESTING ACTIVITIES
Investments in unconsolidated entities	(4)	(3)
Additions to property, equipment and other	(122)	(101)
Cash paid for purchases of linefill		(39)
Proceeds from sales of assets	284	53
Other investing activities		9
Net cash provided by/(used in) investing activities	158	(81)
CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings under PAA commercial paper program (Note 5)		382
Repayments of PAA senior notes (Note 5)	(400)	(750)
Repurchase of common units by a subsidiary		(25)
Distributions paid to Class A shareholders (Note 6)	(52)	(35)
Distributions paid to noncontrolling interests (Note 6)	(268)	(188)
Other financing activities	(55)	20
Net cash used in financing activities	(775)	(596)
Effect of translation adjustment		3
Net increase/(decrease) in cash and cash equivalents and restricted cash	125	(335)
Cash and cash equivalents and restricted cash, beginning of period	404	456
Cash and cash equivalents and restricted cash, end of period	529	121
Cash paid/(received) for:
Interest, net of amounts capitalized	65	74
Income taxes, net of amounts refunded	$ (18)	$ 23

Revenues and Accounts Receivable - Counterparty Deficiencies (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Minimum Volume Commitments
Counterparty deficiencies billed and collected	$ 204	$ 229
Minimum Volume Commitments
Minimum Volume Commitments
Counterparty deficiencies billed and collected	88	104
Counterparty deficiencies unbilled		1
Counterparty deficiencies	$ 88	$ 105

Revenues and Accounts Receivable (Tables)

3 Months Ended

Mar. 31, 2023

Revenue from Contract with Customer [Abstract]

Disaggregation of revenue

Revenues from Contracts with Customers. The following tables present our revenues from contracts with customers disaggregated by segment and type of activity (in millions):


	Three Months Ended March 31,
	2023		2022
Crude Oil segment revenues from contracts with customers
Sales	$	11,381	$	12,857
Transportation	250		155
Terminalling, Storage and Other	90		90
Total Crude Oil segment revenues from contracts with customers	$	11,721	$	13,102


	Three Months Ended March 31,
	2023		2022
NGL segment revenues from contracts with customers
Sales	$	660	$	845
Transportation	8		9
Terminalling, Storage and Other	28		25
Total NGL segment revenues from contracts with customers	$	696	$	879

The following tables present the reconciliation of our revenues from contracts with customers to total revenues of reportable segments and total revenues as disclosed in our Condensed Consolidated Statements of Operations (in millions):


Three Months Ended March 31, 2023	Crude Oil		NGL		Total
Revenues from contracts with customers	$	11,721	$	696	$	12,417
Other revenues	37		(6)		31
Total revenues of reportable segments	$	11,758	$	690	$	12,448
Intersegment revenues elimination					(107)
Total revenues					$	12,341

Three Months Ended March 31, 2022	Crude Oil		NGL		Total
Revenues from contracts with customers	$	13,102	$	879	$	13,981
Other revenues	(23)		(144)		(167)
Total revenues of reportable segments	$	13,079	$	735	$	13,814
Intersegment revenues elimination					(120)
Total revenues					$	13,694

Contract with customer, counterparty deficiencies

The following table presents counterparty deficiencies associated with contracts with customers and buy/sell arrangements that include minimum volume commitments for which we had remaining performance obligations and the customers still had the ability to meet their obligations (in millions):


Counterparty Deficiencies	Financial Statement Classification	March 31, 2023		December 31, 2022
Billed and collected	Other current liabilities	$	88	$	104
Unbilled (1)	N/A	—		1
Total		$	88	$	105

Contracts with customers, change in asset and liability balance

The following table presents the changes in the liability balance associated with contracts with customers (in millions):


	Contract Liabilities
Balance at December 31, 2022	$	229
Amounts recognized as revenue	(31)

Additions	6

Balance at March 31, 2023	$	204


	March 31, 2023		December 31, 2022
Trade accounts receivable arising from revenues from contracts with customers	$	4,141	$	4,141
Other trade accounts receivables and other receivables (1)	6,912		7,216
Impact due to contractual rights of offset with counterparties	(7,085)		(7,450)
Trade accounts receivable and other receivables, net	$	3,968	$	3,907

(1)The balance is comprised primarily of accounts receivable associated with buy/sell arrangements that are not within the scope of ASC 606.

Remaining performance obligations

The following table presents the amount of consideration associated with remaining performance obligations for the population of contracts with external customers meeting the presentation requirements as of March 31, 2023 (in millions):


	Remainder of 2023		2024		2025		2026		2027		2028 and Thereafter
Pipeline revenues supported by minimum volume commitments and capacity agreements (1)	$	253	$	339	$	360	$	131	$	94	$	236
Terminalling, storage and other agreement revenues	195		203		127		99		89		737
Total	$	448	$	542	$	487	$	230	$	183	$	973

(1)Calculated as volumes committed under contracts multiplied by the current applicable tariff rate.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL - USD ($) $ in Millions	Total	Noncontrolling Interests	Limited Partners Class A Shares Partners’ Capital
Beginning balance at Dec. 31, 2021	$ 14,177	$ 12,644	$ 1,533
Increase (Decrease) in Partners' Capital
Net income	209	187	22
Distributions (Note 6)	(235)	(200)	(35)
Other comprehensive income/(loss)	74	53	21
Repurchase of common units by a subsidiary	(25)	(25)
Other	1	2	(1)
Ending balance at Mar. 31, 2022	14,201	12,661	1,540
Beginning balance at Dec. 31, 2022	14,638	13,114	1,524
Increase (Decrease) in Partners' Capital
Net income	443	374	69
Distributions (Note 6)	(325)	(273)	(52)
Other comprehensive income/(loss)	(1)	(1)
Other	9	6	3
Ending balance at Mar. 31, 2023	$ 14,764	$ 13,220	$ 1,544

- Definition

Amount after tax and reclassification adjustments of other comprehensive income (loss).

+ References

+ Details

- Definition

The consolidated profit or loss for the period, net of income taxes, including the portion attributable to the noncontrolling interest.

+ References

+ Details

Commitments and Contingencies - Legal, Environmental or Regulatory (Details)			1 Months Ended		3 Months Ended		5 Months Ended	9 Months Ended	95 Months Ended
	Oct. 27, 2022 USD ($)	Oct. 14, 2020 USD ($)	Sep. 30, 2021 USD ($)	May 31, 2015 bbl	Mar. 31, 2023 USD ($) lawsuit	Mar. 31, 2022 USD ($)	Mar. 31, 2023 USD ($) lawsuit	Sep. 20, 2022 USD ($)	Mar. 31, 2023 USD ($) lawsuit	Dec. 31, 2022 USD ($)	Apr. 25, 2019 USD ($)	Sep. 07, 2018 count
Line 901 Incident
Legal, Environmental or Regulatory Matters
Estimated size of release (in bbl) \| bbl				2,934
Estimated size of release to reach Pacific Ocean (in bbl) \| bbl				598
Recoveries from insurance carriers									$ 280,000,000
Aggregate total estimated costs					$ 740,000,000		$ 740,000,000		740,000,000
Significant costs related to legal and environmental remediation matters					0	$ 85,000,000
Total release costs probable of recovery					$ 505,000,000		$ 505,000,000		$ 505,000,000
Line 901 Incident \| Civil Penalties \| Judicial Ruling
Legal, Environmental or Regulatory Matters
Amount paid to plaintiff		$ 24,000,000
Line 901 Incident \| Compensation for Injuries to, Destruction of, Loss of Use of, Natural Resources \| Judicial Ruling
Legal, Environmental or Regulatory Matters
Amount paid to plaintiff		$ 22,325,000
Line 901 Incident \| May 2016 Indictment
Legal, Environmental or Regulatory Matters
Number of felony discharges found guilty \| count												1
Number of misdemeanor charges found guilty \| count												8
Number of misdemeanor charges found guilty, reporting \| count												1
Number of misdemeanor charges found guilty, strict liability discharge \| count												1
Number of misdemeanor charges found guilty, strict liability animal takings \| count												6
Number of misdemeanor charges found not guilty, strict liability animal takings \| count												1
Line 901 Incident \| May 2016 Indictment \| Judicial Ruling
Legal, Environmental or Regulatory Matters
Fines or penalties assessed											$ 3,350,000
Line 901 Incident \| May 2016 Indictment \| Judicial Ruling \| Maximum
Legal, Environmental or Regulatory Matters
Amount awarded to claimants by Court			$ 150,000
Line 901 Incident \| Class Action Lawsuits
Legal, Environmental or Regulatory Matters
Number of cases filed \| lawsuit									9
Line 901 Incident \| Class Action Lawsuits \| Pending Litigation
Legal, Environmental or Regulatory Matters
Number of proceedings pending \| lawsuit					2		2		2
Line 901 Incident \| Class Action Lawsuit Claim of Damages \| Pending Litigation
Legal, Environmental or Regulatory Matters
Litigation settlement agreement amount, subject to approval								$ 230,000,000
Line 901 Incident \| Class Action Lawsuit Claim of Damages \| Settled Litigation
Legal, Environmental or Regulatory Matters
Payments for legal settlements	$ 230,000,000
Line 901 2015 Insurance Program
Legal, Environmental or Regulatory Matters
Recoveries from insurance carriers									$ 275,000,000
Coverage limit under insurance program					$ 500,000,000		$ 500,000,000		500,000,000
Exceeded coverage limit under insurance program					240,000,000		240,000,000		240,000,000
Claim for Reimbursement From Insurance
Legal, Environmental or Regulatory Matters
Recoveries from insurance carriers							3,600,000
Receivable for remaining portion of release costs probable of recovery from insurance					225,000,000		225,000,000		225,000,000
Denial of Insurance Coverage
Legal, Environmental or Regulatory Matters
Receivable for remaining portion of release costs probable of recovery from insurance					185,000,000		185,000,000		185,000,000
Response to Request for Reimbursement Not Received
Legal, Environmental or Regulatory Matters
Receivable for remaining portion of release costs probable of recovery from insurance					40,000,000		40,000,000		40,000,000
Arbitration Proceedings Against Insurers
Legal, Environmental or Regulatory Matters
Receivable for remaining portion of release costs probable of recovery from insurance					175,000,000		175,000,000		175,000,000
Other long-term assets, net \| Line 901 Incident
Legal, Environmental or Regulatory Matters
Receivable for remaining portion of release costs probable of recovery from insurance					225,000,000		225,000,000		225,000,000
Current Liabilities \| Line 901 Incident
Legal, Environmental or Regulatory Matters
Remaining undiscounted liability					100,000,000		100,000,000		100,000,000
Excluding Line 901 Incident
Legal, Environmental or Regulatory Matters
Estimated undiscounted reserve for environmental liabilities					55,000,000		55,000,000		55,000,000	$ 55,000,000
Estimated undiscounted reserve for environmental liabilities, short-term					$ 10,000,000		$ 10,000,000		$ 10,000,000	$ 10,000,000
Estimated undiscounted reserve for environmental liabilities, short-term [Extensible Enumeration]					Other current liabilities		Other current liabilities		Other current liabilities	Other current liabilities
Estimated undiscounted reserve for environmental liabilities, long-term					$ 45,000,000		$ 45,000,000		$ 45,000,000	$ 45,000,000
Estimated undiscounted reserve for environmental liabilities, long-term [Extensible Enumeration]					Other long-term liabilities and deferred credits		Other long-term liabilities and deferred credits		Other long-term liabilities and deferred credits	Other long-term liabilities and deferred credits
Amounts probable of recovery under insurance and from third parties under indemnification agreements					$ 6,000,000		$ 6,000,000		$ 6,000,000	$ 4,000,000
Excluding Line 901 Incident \| Other long-term assets, net
Legal, Environmental or Regulatory Matters
Amounts probable of recovery under insurance and from third parties under indemnification agreements					$ 1,000,000		$ 1,000,000		$ 1,000,000	$ 1,000,000

Derivatives and Risk Management Activities - Offsetting Asset and Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Derivative Assets
Effect of Collateral Netting	$ (36)	$ (168)
Commodity derivatives
Derivative Assets
Effect of Collateral Netting	(36)	(168)
Derivative Liabilities
Gross Position - Asset	134	311
Gross Position - Liability	(90)	(89)
Net Carrying Value Presented on the Balance Sheet, Total	8	54
Other current assets \| Commodity derivatives
Derivative Assets
Gross Position - Asset	120	300
Gross Position - Liability	(33)	(71)
Effect of Collateral Netting	(36)	(168)
Net Carrying Value Presented on the Balance Sheet	51	61
Other long-term assets, net \| Commodity derivatives
Derivative Assets
Gross Position - Asset	6	9
Gross Position - Liability		(5)
Net Carrying Value Presented on the Balance Sheet	6	4
Other current liabilities \| Commodity derivatives
Derivative Liabilities
Gross Position - Asset	7	2
Gross Position - Liability	(52)	(13)
Net Carrying Value Presented on the Balance Sheet	(45)	(11)
Other long-term liabilities and deferred credits \| Commodity derivatives
Derivative Liabilities
Gross Position - Asset	1
Gross Position - Liability	(5)
Net Carrying Value Presented on the Balance Sheet	$ (4)	$ 0

Commitments and Contingencies	3 Months Ended
Commitments and Contingencies	Mar. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Loss Contingencies — General To the extent we are able to assess the likelihood of a negative outcome for a contingency, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue an undiscounted liability equal to the estimated amount. If a range of probable loss amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then we accrue an undiscounted liability equal to the minimum amount in the range. In addition, we estimate legal fees that we expect to incur associated with loss contingencies and accrue those costs when they are material and probable of being incurred. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss. Legal Proceedings — General In the ordinary course of business, we are involved in various legal proceedings, including those arising from regulatory and environmental matters. In connection with determining the probability of loss associated with such legal proceedings and whether any potential losses associated therewith are estimable, we take into account what we believe to be all relevant known facts and circumstances, and what we believe to be reasonable assumptions regarding the application of those facts and circumstances to existing agreements, laws and regulations. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully protect us from losses arising from current or future legal proceedings. Accordingly, we can provide no assurance that the outcome of the various legal proceedings that we are currently involved in, or will become involved with in the future, will not, individually or in the aggregate, have a material adverse effect on our consolidated financial condition, results of operations or cash flows. Environmental — General We currently own or lease, and in the past have owned and leased, properties where hazardous liquids, including hydrocarbons, are or have been handled. These properties and the hazardous liquids or associated wastes disposed thereon may be subject to the U.S. federal Comprehensive Environmental Response, Compensation and Liability Act, as amended, and the U.S. federal Resource Conservation and Recovery Act, as amended, as well as state and Canadian federal and provincial laws and regulations. Under such laws and regulations, we could be required to remove or remediate hazardous liquids or associated wastes (including wastes disposed of or released by prior owners or operators) and to clean up contaminated property (including contaminated groundwater). Assets we have acquired or will acquire in the future may have environmental remediation liabilities for which we are not indemnified or insured. Although we have made significant investments in our maintenance and integrity programs, we have experienced (and likely will experience future) releases of hydrocarbon products into the environment from our pipeline, rail, storage and other facility operations. These releases can result from accidents or from unpredictable man-made or natural forces and may reach surface water bodies, groundwater aquifers or other sensitive environments. We also may discover environmental impacts from past releases that were previously unidentified. Damages and liabilities associated with any such releases from our existing or future assets could be significant and could have a material adverse effect on our consolidated financial condition, results of operations or cash flows. We record environmental liabilities when environmental assessments and/or remedial efforts are probable and the amounts can be reasonably estimated. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We do not discount our environmental remediation liabilities to present value. We also record environmental liabilities assumed in business combinations based on the estimated fair value of the environmental obligations caused by past operations of the acquired company. We record receivables for amounts we believe are recoverable from insurance or from third parties under indemnification agreements in the period that we determine the costs are probable of recovery. Environmental expenditures that pertain to current operations or to future revenues are expensed or capitalized consistent with our capitalization policy for property and equipment. Expenditures that result from the remediation of an existing condition caused by past operations and that do not contribute to current or future profitability are expensed. At both March 31, 2023 and December 31, 2022, our estimated undiscounted reserve for environmental liabilities (excluding liabilities related to the Line 901 incident, as discussed further below) totaled $55 million, of which $10 million was classified as short-term and $45 million was classified as long-term for each period. Such short-term liabilities are reflected in “Other current liabilities” and long-term liabilities are reflected in “Other long-term liabilities and deferred credits” on our Condensed Consolidated Balance Sheets. At March 31, 2023 and December 31, 2022, we had recorded receivables (excluding receivables related to the Line 901 incident) totaling $6 million and $4 million, respectively, for amounts probable of recovery under insurance and from third parties under indemnification agreements, $1 million of which for each period is reflected in “Other long-term assets, net” and the remainder is reflected in “Trade accounts receivable and other receivables, net” on our Condensed Consolidated Balance Sheets. In some cases, the actual cash expenditures associated with these liabilities may not occur for three years or longer. Our estimates used in determining these reserves are based on information currently available to us and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment and the possibility of existing or future legal claims giving rise to additional liabilities. Therefore, although we believe that the reserve is adequate, actual costs incurred (which may ultimately include costs for contingencies that are currently not reasonably estimable or costs for contingencies where the likelihood of loss is currently believed to be only reasonably possible or remote) may be in excess of the reserve and may potentially have a material adverse effect on our consolidated financial condition, results of operations or cash flows. Specific Legal, Environmental or Regulatory Matters Line 901 Incident. In May 2015, we experienced a crude oil release from our Las Flores to Gaviota Pipeline (Line 901) in Santa Barbara County, California. A portion of the released crude oil reached the Pacific Ocean at Refugio State Beach through a drainage culvert. Following the release, we shut down the pipeline and initiated our emergency response plan. A Unified Command, which included the United States Coast Guard, the EPA, the State of California Department of Fish and Wildlife (“CDFW”), the California Office of Spill Prevention and Response and the Santa Barbara Office of Emergency Management, was established for the response effort. Clean-up and remediation operations with respect to impacted shoreline and other areas has been determined by the Unified Command to be complete, and the Unified Command has been dissolved. Our estimate of the amount of oil spilled, based on relevant facts, data and information, and as set forth in the Consent Decree described below, is approximately 2,934 barrels; of this amount, we estimate that 598 barrels reached the Pacific Ocean. As a result of the Line 901 incident, several governmental agencies and regulators initiated investigations into the Line 901 incident, various claims have been made against us and a number of lawsuits have been filed against us, the majority of which have been resolved. Set forth below is a brief summary of actions and matters that are currently pending or recently resolved. As the “responsible party” for the Line 901 incident we are liable for various costs and for certain natural resource damages under the Oil Pollution Act. In this regard, following the Line 901 incident, we entered into a cooperative Natural Resource Damage Assessment (“NRDA”) process with the federal and state agencies designated or authorized by law to act as trustees for the natural resources of the United States and the State of California (collectively, the “Trustees”). Additionally, various government agencies sought to collect civil fines and penalties under applicable state and federal regulations. On March 13, 2020, the United States and the People of the State of California filed a civil complaint against Plains All American Pipeline, L.P. and Plains Pipeline L.P. along with a pre-negotiated settlement agreement in the form of a Consent Decree (the “Consent Decree”) that was signed by the United States Department of Justice, Environmental and Natural Resources Division, the United States Department of Transportation, Pipeline and Hazardous Materials Safety Administration, the EPA, CDFW, the California Department of Parks and Recreation, the California State Lands Commission, the California Department of Forestry and Fire Protection’s Office of the State Fire Marshal, Central Coast Regional Water Quality Control Board, and Regents of the University of California. The Consent Decree was approved and entered by the Federal District Court for the Central District of California on October 14, 2020. Pursuant to the terms of the Consent Decree, Plains paid $24 million in civil penalties and $22.325 million as compensation for injuries to, destruction of, loss of, or loss of use of natural resources resulting from the Line 901 incident. The Consent Decree, which resolved all regulatory claims related to the incident, also contains requirements for implementing certain agreed-upon injunctive relief, as well as requirements for potentially restarting Line 901 and the Sisquoc to Pentland portion of Line 903. On October 13, 2022, Plains sold Line 901 and the Sisquoc to Pentland portion of Line 903 to Pacific Pipeline Company, an indirect wholly owned subsidiary of Exxon Mobil Corporation. As required by the terms of the Consent Decree, such purchaser assumed responsibility for compliance with the Consent Decree as it relates to the future ownership and operation of Line 901 and the Sisquoc to Pentland portion of Line 903. Following an investigation and grand jury proceedings, in May of 2016, PAA was charged by a California state grand jury, pursuant to an indictment filed in California Superior Court, Santa Barbara County (the “May 2016 Indictment”), with alleged violations of California law in connection with the Line 901 incident. Fifteen charges from the May 2016 Indictment were the subject of a jury trial in California Superior Court in Santa Barbara County, and the jury returned a verdict on September 7, 2018, pursuant to which we were (i) found guilty on one felony discharge count and eight misdemeanor counts (which included one reporting count, one strict liability discharge count and six strict liability animal takings counts) and (ii) found not guilty on one strict liability animal takings count. The remaining counts were subsequently dismissed by the Court. On April 25, 2019, PAA was sentenced to pay fines and penalties in the aggregate amount of just under $3.35 million for the convictions covered by the September 2018 jury verdict (the “2019 Sentence”). The fines and penalties imposed in connection with the 2019 Sentence have been paid. In September 2021, the Superior Court concluded a series of hearings on the issue of whether there were any “direct victims” of the spill that are entitled to restitution under applicable criminal law. Through a series of final orders issued at the trial court level and without affecting any rights of the claimants under civil law, the Court dismissed the vast majority of the claims and ruled that the claimants were not entitled to restitution under applicable criminal laws. The Court did award an aggregate amount of less than $150,000 to a handful of claimants and we settled with approximately 40 claimants before the hearings for aggregate consideration that is not material. The prosecution and certain separately represented claimants have appealed the Court’s rulings. We also received several individual lawsuits and claims from companies, governmental agencies and individuals alleging damages arising out of the Line 901 incident. These lawsuits and claims generally seek restitution, compensatory and punitive damages, and/or injunctive relief. The majority of these lawsuits have been settled or dismissed by the court. In addition to the other lawsuits disclosed herein, the following lawsuits remain: (i) a lawsuit filed in the United States District Court for the Central District of California that was remanded to the California Superior Court in Santa Barbara County for lost revenue or profit asserted by a former oil producer that declared bankruptcy and shut in its offshore production platform following the Line 901 incident; (ii) a lawsuit filed by the California State Land Commission in California Superior Court in Santa Barbara County, seeking lost royalties following the shut-down of Line 901, as well as costs related to the decommissioning of such platform, and (iii) lawsuits filed in California Superior Court in Santa Barbara County, by various companies and individuals who provided labor, goods, or services associated with oil production activities they claim were disrupted following the Line 901 incident. We are vigorously defending these remaining lawsuits and believe we have strong defenses. Furthermore, shortly following the Line 901 incident, we established a claims line and encouraged any parties that were damaged by the release to contact us to discuss their damage claims. We received a number of claims through the claims line and we have processed those claims and made payments as appropriate. Nine class action lawsuits were filed against us; however, after various claims were either dismissed or consolidated, two proceedings remained pending in the United States District Court for the Central District of California. In the first proceeding, the plaintiffs seek a declaratory judgment that Plains’ right-of-way agreements would not allow Plains to lay a new pipeline to replace Line 901 and/or the non-operating segment of Line 903 without paying additional compensation. The purchaser of Line 901 and the Sisquoc to Pentland portion of Line 903 has joined this proceeding as a co-defendant with respect to its interest in such acquired pipelines. In the second proceeding, the plaintiffs claimed two different classes of claimants were damaged by the release: (i) commercial fishermen who landed fish in certain specified fishing blocks in the waters off the coast of Southern California or persons or businesses who resold commercial seafood caught in those areas; and (ii) owners and lessees of residential beachfront properties, or properties with a private easement to a beach, where plaintiffs claim oil from the spill washed up. In 2022, in order to fully and finally resolve all claims and litigation for both classes, we reached an agreement to settle this case in exchange for a payment of $230 million (the “Class Action Settlement”). The Class Action Settlement was formally approved by the trial court on September 20, 2022, and we made the $230 million settlement payment on October 27, 2022. Plains formally submitted claims for reimbursement of the Class Action Settlement to our insurance carriers on November 7, 2022. To date, we have received payment of approximately $3.6 million from one insurer, which represents the final payment obligation of such insurer and brings the total amount collected from all insurers under such program to $275 million of the $500 million policy limits as of March 31, 2023. Insurers responsible for $185 million of the remaining $225 million of coverage formally communicated a denial of coverage for the Class Action Settlement generally alleging that some or all damages encompassed by the Class Action Settlement are not covered by their policies and that all or some portion of the $275 million for which Plains has already received insurance reimbursement does not properly exhaust the underlying policies that paid those sums. The insurer responsible for the final $40 million of coverage under such insurance program has not yet responded to our reimbursement demand. We have initiated arbitration proceedings against the insurers responsible for $175 million of coverage and intend to vigorously pursue recovery from our insurers of all amounts for which we have claimed reimbursement. We believe that our claim for reimbursement from our insurers of the Class Action Settlement payment is strong and that our ultimate recovery of such amounts is probable. Our belief is based on: (i) our analysis of the terms of the underlying insurance policies as applied to the facts and circumstances that comprise our claim for reimbursement, (ii) our experience with the cost submissions and timely collection of claims for the $275 million collected to date for this incident under the same insurance program as the denied claims, including from some of the same insurers who are now denying claims, (iii) our extensive legal review and assessment of the insurer’s claimed basis for denial of coverage, which review and assessment includes the advice of external legal counsel experienced in these type of matters and solidly supports our belief that our insurers are required to provide coverage based on the terms of the policies and the nature of our claims, and (iv) the financial strength of the insurance carriers as determined by an independent credit ratings agency. Various factors could impact the timing and amount of recovery of our insurance receivable, including future developments that adversely impact our assessment of the strength of our coverage claims, the outcome of any dispute resolution proceedings with respect to our coverage claims and the extent to which insurers may become insolvent in the future. An unfavorable resolution could have a material impact on our results of operations. In connection with the foregoing, including the Class Action Settlement and the Derivative Settlement, we have made adjustments to our total estimated Line 901 costs and the portion of such costs that we believe are probable of recovery from insurance carriers, net of deductibles. Effective as of March 31, 2023, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $740 million, which includes actual and projected emergency response and clean-up costs, natural resource damage assessments, fines and penalties payable pursuant to the Consent Decree, certain third party claims settlements (including the Class Action Settlement and the Derivative Settlement), and estimated costs associated with our remaining Line 901 lawsuits and claims as described above, as well as estimates for certain legal fees and statutory interest where applicable. We accrue such estimates of aggregate total costs to “Field operating costs” in our Condensed Consolidated Statements of Operations. This estimate considers our prior experience in environmental investigation and remediation matters and available data from, and in consultation with, our environmental and other specialists, as well as currently available facts and presently enacted laws and regulations. We have made assumptions for (i) the resolution of certain third party claims and lawsuits, but excluding claims and lawsuits with respect to which losses are not probable and reasonably estimable, and excluding future claims and lawsuits and (ii) the nature, extent and cost of legal services that will be required in connection with all lawsuits, claims and other matters requiring legal or expert advice associated with the Line 901 incident. Our estimate does not include any lost revenue associated with the shutdown of Line 901 or 903 and does not include any liabilities or costs that are not reasonably estimable at this time or that relate to contingencies where we currently regard the likelihood of loss as being only reasonably possible or remote. We believe we have accrued adequate amounts for all probable and reasonably estimable costs; however, this estimate is subject to uncertainties associated with the assumptions that we have made. For example, with respect to potential losses that we regard as only reasonably possible or remote, we have made assumptions regarding the strength of our legal position based on our assessment of the relevant facts and applicable law and precedent; if our assumptions regarding such matters turn out to be inaccurate (i.e., we are found to be liable under circumstances where we regard the likelihood of loss as being only reasonably possible or remote), we could be responsible for significant costs and expenses that are not currently included in our estimates and accruals. In addition, for any potential losses that we regard as probable and for which we have accrued an estimate of the potential losses, our estimates regarding damages, legal fees, court costs and interest could turn out to be inaccurate and the actual losses we incur could be significantly higher than the amounts included in our estimates and accruals. Also, the amount of time it takes for us to resolve all of the current and future lawsuits and claims that relate to the Line 901 incident could turn out to be significantly longer than we have assumed, and as a result the costs we incur for legal services could be significantly higher than we have estimated. Accordingly, our assumptions and estimates may turn out to be inaccurate and our total costs could turn out to be materially higher; therefore, we can provide no assurance that we will not have to accrue significant additional costs in the future with respect to the Line 901 incident. During the three months ended March 31, 2022, we recognized costs, net of amounts probable of recovery from insurance carriers, of $85 million. We did not recognize any such costs during the three months ended March 31, 2023. As of March 31, 2023, we had a remaining undiscounted gross liability of approximately $100 million related to the Line 901 incident, which aggregate amount is reflected in “Current liabilities” on our Condensed Consolidated Balance Sheet. As discussed above, we maintain insurance coverage, which is subject to certain exclusions and deductibles, in the event of such liabilities. As of March 31, 2023, our incurred costs for the Line 901 incident have exceeded our insurance coverage limit of $500 million related to our 2015 insurance program applicable to the Line 901 incident by $240 million. Through March 31, 2023, we had collected, subject to customary reservations, approximately $280 million out of the $505 million of release costs that we believe are probable of recovery from insurance carriers (including the 2015 insurance program and our directors and officers (D&O) insurance policies), net of deductibles. Therefore, as of March 31, 2023, we have recognized a long-term receivable of approximately $225 million for the portion of the release costs that we believe is probable of recovery from insurance, net of deductibles and amounts already collected. We anticipate that the process to enforce our coverage claims with respect to the Class Action Settlement will take time and, accordingly, have recognized such amount as a long-term asset in “Other assets” on our Condensed Consolidated Balance Sheet. We have completed the required clean-up and remediation work as determined by the Unified Command and the Unified Command has been dissolved; however, we expect to make payments for additional legal, professional and regulatory costs during future periods. 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 a material adverse effect on our consolidated financial condition, results of operations or cash flows. Other Litigation Matters. On July 19, 2022 Hartree Natural Gas Storage, LLC (“Hartree”) filed a lawsuit under seal in the Superior Court for the State of Delaware asserting claims against PAA Natural Gas Storage, L.P. and PAA arising out of a Membership Interest Purchase Agreement relating to the 2021 sale of the Pine Prairie Energy Center natural gas storage facility to Hartree. We believe the claims are without merit and that the outcome of the lawsuit will not have a material adverse effect on our financial condition, results of operations or cash flows. We intend to vigorously defend against the claims asserted in this lawsuit. Insurance Pipelines, terminals, trucks or other facilities or equipment may experience damage as a result of an accident, natural disaster, terrorist attack, cyber event or other event. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. Consistent with insurance coverage generally available in the industry, in certain circumstances our insurance policies provide limited coverage for losses or liabilities relating to gradual pollution, with broader coverage for sudden and accidental occurrences. We maintain various types and varying levels of insurance coverage to cover our operations and properties, and we self-insure certain risks, including gradual pollution, cybersecurity and named windstorms. To the extent we do maintain insurance coverage, such insurance does not cover every potential risk that might occur, associated with operating pipelines, terminals and other facilities and equipment, including the potential loss of significant revenues and cash flows. The occurrence of a significant event not fully insured, indemnified or reserved against, or the failure of a party to meet its insurance or indemnification obligations, could materially and adversely affect our operations and financial condition. While we strive to maintain adequate insurance coverage, our actual costs may exceed our coverage levels and insurance will not cover many types of interruptions that might occur, will not cover amounts up to applicable deductibles and will not cover all risks associated with certain of our assets and operations. With respect to our insurance coverage, our policies are subject to deductibles and retention levels that we consider reasonable and not excessive. Additionally, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable. As a result, we may elect to self-insure or utilize higher deductibles in certain other insurance programs. In addition, although we believe that we have established adequate reserves and liquidity to the extent such risks are not insured, costs incurred in excess of these reserves may be higher or we may not receive insurance proceeds in a timely manner, which may potentially have a material adverse effect on our financial conditions, results of operations or cash flows.

Revenues and Accounts Receivable - Trade Accounts Receivable and Other Receivables (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
Trade accounts receivable arising from revenues from contracts with customers	$ 4,141	$ 4,141
Other trade accounts receivables and other receivables	6,912	7,216
Impact due to contractual rights of offset with counterparties	(7,085)	(7,450)
Trade accounts receivable and other receivables, net	$ 3,968	$ 3,907

Partners' Capital and Distributions (Tables)

3 Months Ended

Mar. 31, 2023

Partners' Capital and Distributions

Schedule of activity for Class A shares, Class B shares and Class C shares

The following tables present the activity for our Class A shares, Class B shares and Class C shares:


	Class A Shares	Class B Shares	Class C Shares
Outstanding at December 31, 2022	194,407,642	46,205,947	528,442,538
Conversion of AAP Management Units (1) (2)	—	388,839	—

Redemption Right exercises (1)	—	(181,916)	181,916

Other	—	—	35,508
Outstanding at March 31, 2023	194,407,642	46,412,870	528,659,962


	Class A Shares	Class B Shares	Class C Shares
Outstanding at December 31, 2021	194,192,777	46,645,514	534,596,831
Conversion of AAP Management Units (1)	—	205,024	—
Exchange Right exercises (1)	35,700	(35,700)	—
Redemption Right exercises (1)	—	(11,957)	11,957
Repurchase and cancellation of common units by a subsidiary under the Common Equity Repurchase Program	—	—	(2,375,299)
Other	—	—	51,937
Outstanding at March 31, 2022	194,228,477	46,802,881	532,285,426

(2)Following this conversion, no AAP Management Units remain outstanding.

Summary of distributions made to noncontrolling interests in consolidated joint ventures

The following table details distributions paid to noncontrolling interests of consolidated joint ventures during the periods presented (in millions):


	Three Months Ended March 31,
	2023		2022
Permian JV	$	58	$	54
Cactus II (1)	14		—
Red River	6		5
	$	78	$	59

AAP

Partners' Capital and Distributions

Schedule of distributions

The following table details the distributions to AAP’s partners paid during or pertaining to the first three months of 2023 from distributions received from PAA (in millions):


	Distributions to AAP’s Partners
Distribution Payment Date	Noncontrolling Interests		PAGP		Total Cash Distribution


May 15, 2023 (1)	$	13	$	52	$	65
February 14, 2023	$	13	$	52	$	65

(1)Payable to unitholders of record at the close of business on May 1, 2023 for the period from January 1, 2023 through March 31, 2023.

Class A Shares

Partners' Capital and Distributions

Schedule of distributions

The following table details distributions to our Class A shareholders paid during or pertaining to the first three months of 2023 (in millions, except per share data):


Distribution Payment Date	Distributions to Class A Shareholders		Distributions per Class A Share


May 15, 2023 (1)	$	52	$	0.2675
February 14, 2023	$	52	$	0.2675

(1)Payable to shareholders of record at the close of business on May 1, 2023 for the period from January 1, 2023 through March 31, 2023.

Series A Preferred Units | PAA

Partners' Capital and Distributions

Schedule of distributions

The following table details distributions to PAA’s Series A preferred unitholders paid during or pertaining to the first three months of 2023 (in millions, except per unit data):


	Series A Preferred Unitholders
Distribution Payment Date	Cash Distribution		Distribution per Unit


May 15, 2023 (1)	$	42	$	0.585
February 14, 2023	$	37	$	0.525

Series B Preferred Units | PAA

Partners' Capital and Distributions

Schedule of distributions

The following table details distributions paid or to be paid to PAA’s Series B preferred unitholders (in millions, except per unit data):


	Series B Preferred Unitholders
Distribution Payment Date	Cash Distribution		Distribution per Unit
May 15, 2023 (1)	$	18	$	22.18
February 15, 2023	$	18	$	22.27

Common Units | PAA

Partners' Capital and Distributions

Schedule of distributions

The following table details distributions to PAA’s common unitholders paid during or pertaining to the first three months of 2023 (in millions, except per unit data):


	Distributions						Cash Distribution per Common Unit
	Common Unitholders				Total Cash Distribution
Distribution Payment Date	Public		AAP


May 15, 2023 (1)	$	122	$	65	$	187	$	0.2675
February 14, 2023	$	122	$	65	$	187	$	0.2675

(1)Payable to unitholders of record at the close of business on May 1, 2023 for the period from January 1, 2023 through March 31, 2023.

Partners' Capital and Distributions - Subsidiary Distributions (Details) - USD ($) $ / shares in Units, $ in Millions				2 Months Ended	3 Months Ended
	May 15, 2023	Feb. 15, 2023	Feb. 14, 2023	Mar. 31, 2023	Mar. 31, 2023	Mar. 31, 2022	Jan. 31, 2023
Partners' Capital and Distributions
Total distributions paid					$ 325.0	$ 235.0
AAP
Partners' Capital and Distributions
Noncontrolling interests in subsidiaries (percent)				19.00%	19.00%
Permian JV
Partners' Capital and Distributions
Noncontrolling interests in subsidiaries (percent)				35.00%	35.00%
Cactus II
Partners' Capital and Distributions
Noncontrolling interests in subsidiaries (percent)				30.00%	30.00%
Red River
Partners' Capital and Distributions
Noncontrolling interests in subsidiaries (percent)				33.00%	33.00%
Noncontrolling Interests
Partners' Capital and Distributions
Total distributions paid					$ 273.0	200.0
Common Units and Series A Preferred Units \| PAA
Partners' Capital and Distributions
Noncontrolling interests in subsidiaries (percent)				69.00%	69.00%
Series B Preferred Units \| PAA
Partners' Capital and Distributions
Noncontrolling interests in subsidiaries (percent)				100.00%	100.00%
Cash Distribution \| Noncontrolling Interests \| Consolidated Joint Venture Entities
Partners' Capital and Distributions
Total distributions paid					$ 78.0	59.0
PAA \| Series A Preferred Units
Partners' Capital and Distributions
Distribution rate reset, basis spread on variable rate							5.85%
Quarterly distributions per unit (usd per unit)				$ 0.615
PAA \| Other current liabilities \| Series B Preferred Units
Partners' Capital and Distributions
Amount accrued to distributions payable				$ 9.0	9.0
PAA \| Cash Distribution \| Series B Preferred Units
Partners' Capital and Distributions
Preferred unit distribution amount (usd per unit)		$ 22.27
Preferred unit distribution amount		$ 18.0
PAA \| Cash Distribution \| Series B Preferred Units \| Forecast
Partners' Capital and Distributions
Preferred unit distribution amount (usd per unit)	$ 22.18
Preferred unit distribution amount	$ 18.0
PAA \| Cash Distribution \| Series A Preferred Units
Partners' Capital and Distributions
Preferred unit distribution amount (usd per unit)			$ 0.525
Preferred unit distribution amount			$ 37.0
PAA \| Cash Distribution \| Series A Preferred Units \| Forecast
Partners' Capital and Distributions
Preferred unit distribution amount (usd per unit)	$ 0.585
Preferred unit distribution amount	$ 42.0
PAA \| Cash Distribution \| Common Units
Partners' Capital and Distributions
Total distributions paid			$ 187.0
Distributions per common unit, paid (usd per unit)			$ 0.2675
PAA \| Cash Distribution \| Common Units \| Forecast
Partners' Capital and Distributions
Total distributions paid	$ 187.0
Distributions per common unit, paid (usd per unit)	$ 0.2675
PAA \| Cash Distribution \| Common Units \| Public
Partners' Capital and Distributions
Total distributions paid			$ 122.0
PAA \| Cash Distribution \| Common Units \| Public \| Forecast
Partners' Capital and Distributions
Total distributions paid	$ 122.0
PAA \| Cash Distribution \| Common Units \| AAP
Partners' Capital and Distributions
Total distributions paid			65.0
PAA \| Cash Distribution \| Common Units \| AAP \| Forecast
Partners' Capital and Distributions
Total distributions paid	65.0
AAP \| Cash Distribution
Partners' Capital and Distributions
Distributions to PAGP			52.0
Distributions to noncontrolling interests			13.0
Distributions paid to limited partners			$ 65.0
AAP \| Cash Distribution \| Forecast
Partners' Capital and Distributions
Distributions to PAGP	52.0
Distributions to noncontrolling interests	13.0
Distributions paid to limited partners	$ 65.0
Permian JV \| Cash Distribution \| Noncontrolling Interests
Partners' Capital and Distributions
Total distributions paid					58.0	54.0
Cactus II \| Cash Distribution \| Noncontrolling Interests
Partners' Capital and Distributions
Total distributions paid					14.0
Red River \| Cash Distribution \| Noncontrolling Interests
Partners' Capital and Distributions
Total distributions paid					$ 6.0	$ 5.0

Revenues and Accounts Receivable - Performance Obligations (Details) $ in Millions	Mar. 31, 2023 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2023-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 448
Remaining performance obligations, expected timing of satisfaction, period	9 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 542
Remaining performance obligations, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 487
Remaining performance obligations, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 230
Remaining performance obligations, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 183
Remaining performance obligations, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 973
Remaining performance obligations, expected timing of satisfaction, period
Pipeline revenues supported by minimum volume commitments and capacity agreements \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2023-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 253
Remaining performance obligations, expected timing of satisfaction, period	9 months
Pipeline revenues supported by minimum volume commitments and capacity agreements \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 339
Remaining performance obligations, expected timing of satisfaction, period	1 year
Pipeline revenues supported by minimum volume commitments and capacity agreements \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 360
Remaining performance obligations, expected timing of satisfaction, period	1 year
Pipeline revenues supported by minimum volume commitments and capacity agreements \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 131
Remaining performance obligations, expected timing of satisfaction, period	1 year
Pipeline revenues supported by minimum volume commitments and capacity agreements \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 94
Remaining performance obligations, expected timing of satisfaction, period	1 year
Pipeline revenues supported by minimum volume commitments and capacity agreements \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 236
Remaining performance obligations, expected timing of satisfaction, period
Terminalling, storage and other agreement revenues \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2023-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 195
Remaining performance obligations, expected timing of satisfaction, period	9 months
Terminalling, storage and other agreement revenues \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 203
Remaining performance obligations, expected timing of satisfaction, period	1 year
Terminalling, storage and other agreement revenues \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 127
Remaining performance obligations, expected timing of satisfaction, period	1 year
Terminalling, storage and other agreement revenues \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 99
Remaining performance obligations, expected timing of satisfaction, period	1 year
Terminalling, storage and other agreement revenues \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 89
Remaining performance obligations, expected timing of satisfaction, period	1 year
Terminalling, storage and other agreement revenues \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Remaining performance obligation	$ 737
Remaining performance obligations, expected timing of satisfaction, period