0001276187-26-000013 | 10-K | XBRL Viewer

$ 5,452

$ 3,903

$ 4,019

1,515

$ 730

Business Combination, Recognized Asset Acquired, Asset, Current

$ 186

Business Combination, Recognized Asset Acquired, Property, Plant, and Equipment

6,958

Business Combination, Recognized Asset Acquired, Identifiable Intangible Asset, Excluding Goodwill

^[1]

195

Business Combination, Recognized Asset Acquired to Liability Assumed, Excess (Less), and Goodwill

2,850

Business Combination, Recognized Liability Assumed, Liability, Current

7,618

245

Business Combination, Recognized Liability Assumed, Long-Term Debt, Noncurrent

^[2]

3,500

Business Combination, Recognized Liability Assumed, Other Liability, Noncurrent

3,967

Business Combination, Recognized Asset Acquired, Other Asset, Noncurrent

127

2,823

Business Combination, Recognized Liability Assumed, Deferred Tax Liability

136

Business Combination, Recognized Liability Assumed, Financial Liability

^[2]

801

Business Combination, Recognized Asset Acquired to Liability Assumed, Excess (Less), and Goodwill, Total

136

$ 2,850

Business Combination, Recognized Asset Acquired, Asset, Current

$ 61

Business Combination, Recognized Asset Acquired, Property, Plant, and Equipment

1,263

Business Combination, Recognized Asset Acquired, Asset, Noncurrent

138

Business Combination, Recognized Asset Acquired, Identifiable Intangible Asset, Excluding Goodwill

Business Combination, Recognized Asset Acquired to Liability Assumed, Excess (Less), and Goodwill

1,508

Business Combination, Recognized Liability Assumed, Liability, Current

1,551

Business Combination, Recognized Liability Assumed, Other Liability, Noncurrent

Business Combination, Recognized Asset Acquired, Other Asset, Noncurrent

1,504

Business Combination, Recognized Asset Acquired to Liability Assumed, Excess (Less), and Goodwill, Total

$ 1,508

Business Combination, Recognized Asset Acquired, Asset, Current

$ 657

Business Combination, Recognized Asset Acquired, Property, Plant, and Equipment

4,772

Business Combination, Recognized Asset Acquired, Asset, Noncurrent

Business Combination, Recognized Asset Acquired, Identifiable Intangible Asset, Excluding Goodwill

1,139

Business Combination, Recognized Asset Acquired to Liability Assumed, Excess (Less), and Goodwill

3,657

Business Combination, Recognized Liability Assumed, Liability, Current

8,157

445

Business Combination, Recognized Liability Assumed, Long-Term Debt, Noncurrent

3,461

Business Combination, Recognized Liability Assumed, Other Liability, Noncurrent

322

4,228

Business Combination, Recognized Asset Acquired, Other Asset, Noncurrent

3,645

Business Combination, Recognized Asset Acquired to Liability Assumed, Excess (Less), and Goodwill, Total

3,657

Business Combination, Acquisition of Less than 100 Percent, Noncontrolling Interest, Fair Value

$ 272

Business Combination, Recognized Asset Acquired, Asset, Current

$ 334

Business Combination, Recognized Asset Acquired, Property, Plant, and Equipment

3,109

Business Combination, Recognized Asset Acquired, Identifiable Intangible Asset, Excluding Goodwill

Business Combination, Recognized Asset Acquired to Liability Assumed, Excess (Less), and Goodwill

3,052

Business Combination, Recognized Liability Assumed, Liability, Current

3,471

394

Business Combination, Recognized Liability Assumed, Other Liability, Noncurrent

419

3,007

Business Combination, Recognized Asset Acquired to Liability Assumed, Excess (Less), and Goodwill, Total

$ 3,052

Business Combination, Recognized Asset Acquired, Asset, Current

$ 2,814

Business Combination, Recognized Asset Acquired, Property, Plant, and Equipment

5,612

Business Combination, Recognized Asset Acquired, Asset, Noncurrent

341

Business Combination, Recognized Asset Acquired to Liability Assumed, Excess (Less), and Goodwill

^[3]

1,528

5,015

Business Combination, Recognized Liability Assumed, Liability, Current

13,373

2,490

Business Combination, Recognized Liability Assumed, Long-Term Debt, Noncurrent

3,797

$ 3,650

8,358

Business Combination, Recognized Asset Acquired, Other Asset, Noncurrent

464

266

Business Combination, Recognized Liability Assumed, Deferred Tax Liability

4,551

965

Business Combination, Recognized Asset Acquired, Deferred Tax Asset

731

210

Business Combination, Recognized Asset Acquired, Identifiable Intangible Asset, Indefinite-Lived

^[4]

1,871

Business Combination, Recognized Liability Assumed, Lease Obligation

731

Business Combination, Recognized Liability Assumed, Liability, Noncurrent

375

Business Combination, Recognized Asset Acquired to Liability Assumed, Excess (Less), and Goodwill, Total

$ 5,015

TanQuid Acquisition [Member] | Subsequent Event [Member]

Business Combination, Recognized Liability Assumed, Long-Term Debt, Noncurrent | €

€ 300

Reconciliation Of Net Income (Loss) And Weighted Average Units

$ 540

€ 465

[1]	Intangible assets, net comprised of $151 million of favorable contracts, with a remaining weighted average life of approximately 7 years, and $44 million of customer relationships, with a remaining weighted average life of approximately 15 years.
[2]	Subsequent to the closing of the NuStar acquisition, Sunoco LP redeemed all outstanding NuStar preferred units totaling $784 million, redeemed NuStar’s subordinated notes totaling $403 million and repaid the outstanding balance on the NuStar credit facility totaling $455 million.
[3]	Goodwill represents commercial and operational synergies. Approximately $660 million of the goodwill recorded as a result of this transaction is expected to be deductible for IRC Sec. 951A GILTI and foreign earnings and profits purposes. The goodwill is not deductible for non-US jurisdictions.
[4]	(1)Intangible assets, net comprised of $1.49 billion of customer relationships, with a remaining weighted average life of approximately 20 years, $297 million of indefinite-lived tradenames and $85 million of other intangibles with a remaining weighted average life of approximately 10 years.

Estimates, Significant Accounting Policies and Balance Sheet Detail Estimates (Schedule of Useful Lives) (Details) (Details)	Dec. 31, 2025
Minimum [Member] \| Customer relationships, contracts and agreements (3 to 46 years)
Intangible assets, useful life, minimum (years)	3 years
Minimum [Member] \| Other (5 to 20 years)
Intangible assets, useful life, minimum (years)	5 years
Maximum [Member] \| Customer relationships, contracts and agreements (3 to 46 years)
Intangible assets, useful life, minimum (years)	46 years
Maximum [Member] \| Trade Names [Member]
Intangible assets, useful life, minimum (years)	20 years
Maximum [Member] \| Trade names (20 years)
Intangible assets, useful life, minimum (years)	10 years
Maximum [Member] \| Other (5 to 20 years)
Intangible assets, useful life, minimum (years)	20 years
Right of way (20 to 65 years) \| Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	20 years
Right of way (20 to 65 years) \| Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	83 years
Other (1 to 48 years) \| Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	1 year
Other (1 to 48 years) \| Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	48 years
Buildings and improvements [Member] \| Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	1 year
Buildings and improvements [Member] \| Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	45 years
Pipelines And Equipment [Member] \| Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	5 years
Pipelines And Equipment [Member] \| Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	83 years
Product storage and related facilities \| Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	2 years
Product storage and related facilities \| Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	83 years

Net Income Per Common Unit (Tables)

12 Months Ended

Dec. 31, 2025

Earnings Per Share [Abstract]

A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows:


	Years Ended December 31,
	2025		2024		2023
Net income	$	5,708	$	6,565	$	5,294
Less: Net income attributable to redeemable noncontrolling interests	67		59		60
Less: Net income attributable to noncontrolling interests	1,208		1,692		1,299
Net income, net of noncontrolling interests	4,433		4,814		3,935
Less: General Partner’s interest in income	4		4		3
Less: Preferred Unitholders’ interest in income	248		362		463
Less: Loss on redemption of preferred units	8		54		—
Common Unitholders’ interest in net income	$	4,173	$	4,394	$	3,469
Basic Income per Common Unit:
Weighted average common units	3,432.9		3,395.1		3,161.7
Basic income per common unit	$	1.22	$	1.29	$	1.10

Diluted Income per Common Unit:
Common Unitholders’ interest in net income	$	4,173	$	4,394	$	3,469
Dilutive effect of equity-based compensation of subsidiaries and distributions to convertible units	(1)		(1)		(1)
Diluted income available to Common Unitholders	$	4,172	$	4,393	$	3,468
Weighted average common units	3,432.9		3,395.1		3,161.7

Dilutive effect of unvested unit awards	16.6		25.4		15.5
Weighted average common units, assuming dilutive effect of unvested unit awards	3,449.5		3,420.5		3,177.2
Diluted income per common unit	$	1.21	$	1.28	$	1.09

Estimates (Components Of Intangibles And Other Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Gross Carrying Amount	$ 11,674	$ 9,732
Accumulated Amortization	(4,236)	(3,761)
Customer relationships, contracts and agreements (3 to 46 years)
Gross Carrying Amount	10,859	9,304
Accumulated Amortization	(4,128)	(3,654)
Trade Names [Member]
Gross Carrying Amount	48	48
Accumulated Amortization	(48)	(48)
Trade names (20 years)
Gross Carrying Amount	66	66
Accumulated Amortization	(51)	(48)
Other (5 to 20 years)
Gross Carrying Amount	95	12
Accumulated Amortization	(9)	(11)
Total Amortizable Intangible Assets [Member]
Gross Carrying Amount	11,068	9,430
Accumulated Amortization	(4,236)	(3,761)
Trademarks [Member]
Gross Carrying Amount	606	302
Accumulated Amortization	0	0
Non-amortizable intangible assets [Member]
Gross Carrying Amount	606	302
Accumulated Amortization	$ 0	$ 0

Income Taxes Reconciliation of Income Tax Satutory Rate (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2025

Dec. 31, 2024

Dec. 31, 2023

Income tax expense at United States statutory rate

$ 1,272

$ 1,492

$ 1,175

Effective Income Tax Rate Reconciliation, Tax Exempt Income, Percent

(15.59%)

(15.25%)

(15.79%)

Increase (reduction) in income taxes resulting from:

Non-taxable Partnership earnings

$ (944)

$ (1,084)

$ (884)

State and local income tax, net of federal income tax effect(1)

^[1]

$ 4

$ 113

$ 37

Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Percent

(0.08%)

0.29%

(0.24%)

Changes in valuation allowances

$ (5)

$ 21

$ (14)

Other adjustments

(3)

Income tax expense

$ 350

$ 541

$ 303

Effective Income Tax Rate Reconciliation, Percent

5.79%

7.61%

5.41%

Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent

21.00%

Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent

^[1]

0.07%

1.59%

0.65%

Effective Income Tax Rate Reconciliation, Other Reconciling Items, Percent

0.03%

0.00%

(0.05%)

Effective Income Tax Rate Reconciliation, Tax Credit, Foreign, Amount

$ (4)

$ 0

Effective Income Tax Rate Reconciliation, Tax Settlement, Foreign, Percent

(0.06%)

0.00%

Effective Income Tax Rate Reconciliation, Cross-Border Tax Effect, Amount

$ 6

$ 0

Effective Income Tax Rate Reconciliation, Cross-Border Tax Effect, Percent

0.10%

0.00%

Effective Income Tax Rate Reconciliation, Other Adjustments, Amount

$ 19

$ (1)

$ (8)

Effective Income Tax Rate Reconciliation, Other Adjustments, Percent

0.32%

(0.02%)

(0.16%)

[1]	State taxes that made up the majority (greater than 50 percent) of the tax effect in this category were Texas in 2025, Pennsylvania, Texas, New Jersey and New York in 2024 and Texas in 2023.

Estimates, Significant Accounting Policies and Balance Sheet Detail (Narrative) (Details) - USD ($)
$ in Millions

12 Months Ended

May 03, 2024

Dec. 31, 2025

Dec. 31, 2024

Dec. 31, 2023

Asset Retirement Obligation

$ 285

$ 52

$ 12

589

418

Oil and Gas, Cost Incurred, Asset Retirement Obligation

Long-term Debt, Fair Value

68,550

59,010

1,528

5,452

3,903

4,019

68,333

59,760

Inventory Write-down

156

Goodwill, Written off Related to Sale of Business Unit

85,536

82,671

78,586

138

Caribbean

Inventory, LIFO Reserve

Other (5 to 20 years)

Asset Retirement Obligation

Related Party

Minimum [Member] | Product storage and related facilities

$ 568

603

626

Property, plant and equipment, useful life, minimum (years)

2 years

Maximum [Member] | Product storage and related facilities

Property, plant and equipment, useful life, minimum (years)

83 years

$ 0

Goodwill, Written off Related to Sale of Business Unit

617

601

All Other

Goodwill, Written off Related to Sale of Business Unit

1,528

Goodwill, Written off Related to Sale of Business Unit

3,026

1,477

1,599

138

Goodwill, Written off Related to Sale of Business Unit

841

853

NGL and Refined Products Transportation and Services

Goodwill, Written off Related to Sale of Business Unit

886

884

13,389

7,485

Inventory, LIFO Reserve

472

316

$ 12

Lake Charles LNG

$ 256

Nustar Acquisition | Investment in Sunoco LP

^[1]

$ 16

Net Income Per Common Unit

$ 16

[1]	Goodwill primarily represents expected commercial and operational synergies. None of the goodwill recorded as a result of this transaction is deductible for tax purposes.

Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Statement of Comprehensive Income [Abstract]
NET INCOME	$ 5,708	$ 6,565	$ 5,294
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities	10	7	4
Actuarial gain relating to pension and other postretirement benefits	9	39	13
Foreign currency translation adjustment	0	(1)	(6)
Change in other comprehensive income from unconsolidated affiliates	(4)	0	1
Other comprehensive income (loss), net of tax, total	15	45	12
Comprehensive income	5,723	6,610	5,306
Less: Comprehensive income attributable to noncontrolling interests	1,208	1,692	1,299
Less: Comprehensive income attributable to redeemable noncontrolling interests	67	59	60
Comprehensive income attributable to partners	$ 4,448	$ 4,859	$ 3,947

Net Income Per Common Unit

12 Months Ended

Dec. 31, 2025

Earnings Per Share [Abstract]

NET INCOME PER COMMON UNIT:

Basic net income per common unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding. Diluted net income per common unit is computed by dividing net income (as adjusted as discussed herein), after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding. For the diluted earnings per share computation, income allocable to the limited partners is reduced, where applicable, for the decrease in earnings from Energy Transfer’s limited partner unit ownership in Sunoco LP and USAC that would have resulted assuming the incremental units related to Sunoco LP’s and USAC’s respective long-term incentive plans, as applicable, had been issued during the respective periods. Such units have been determined based on the treasury stock method.

A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows:


	Years Ended December 31,
	2025		2024		2023
Net income	$	5,708	$	6,565	$	5,294
Less: Net income attributable to redeemable noncontrolling interests	67		59		60
Less: Net income attributable to noncontrolling interests	1,208		1,692		1,299
Net income, net of noncontrolling interests	4,433		4,814		3,935
Less: General Partner’s interest in income	4		4		3
Less: Preferred Unitholders’ interest in income	248		362		463
Less: Loss on redemption of preferred units	8		54		—
Common Unitholders’ interest in net income	$	4,173	$	4,394	$	3,469
Basic Income per Common Unit:
Weighted average common units	3,432.9		3,395.1		3,161.7
Basic income per common unit	$	1.22	$	1.29	$	1.10

Diluted Income per Common Unit:
Common Unitholders’ interest in net income	$	4,173	$	4,394	$	3,469
Dilutive effect of equity-based compensation of subsidiaries and distributions to convertible units	(1)		(1)		(1)
Diluted income available to Common Unitholders	$	4,172	$	4,393	$	3,468
Weighted average common units	3,432.9		3,395.1		3,161.7

Dilutive effect of unvested unit awards	16.6		25.4		15.5
Weighted average common units, assuming dilutive effect of unvested unit awards	3,449.5		3,420.5		3,177.2
Diluted income per common unit	$	1.21	$	1.28	$	1.09

Estimates (Schedule Of Property, Plant And Equipment Depreciation And Capitalized Interest Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
2025	$ 558
2026	542
2027	539
2028	533
2029	516
Depreciation, depletion and amortization expense	5,203	$ 4,701	$ 3,986
Capitalized interest	$ 150	$ 120	$ 77

Income Taxes Changes in Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Changes in Unrecognized Tax Benefits [Abstract]
Balance at beginning of year	$ 74	$ 40	$ 52
Reduction attributable to tax positions taken in prior years	(8)	0	(9)
Tax Adjustments, Settlements, and Unusual Provisions	0	0	(3)
Balance at end of year	$ 66	$ 74	$ 40

Derivative Assets And Liabilities (Fair Value Of Derivative Instruments) (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Asset Derivatives	$ 618	$ 263
Liability Derivatives	(454)	(293)
Designated as Hedging Instrument [Member]
Asset Derivatives	31	3
Liability Derivatives	(2)	(7)
Not Designated as Hedging Instrument [Member]
Asset Derivatives	587	260
Liability Derivatives	(452)	(286)
Broker cleared derivative contracts [Member]
Asset Derivatives	516	212
Liability Derivatives	(394)	(236)
Commodity Derivatives [Member] \| Not Designated as Hedging Instrument [Member]
Asset Derivatives	102	51
Liability Derivatives	(60)	(57)
Commodity Derivatives (Margin Deposits) [Member] \| Designated as Hedging Instrument [Member]
Asset Derivatives	31	3
Liability Derivatives	(2)	(7)
Commodity Derivatives (Margin Deposits) [Member] \| Not Designated as Hedging Instrument [Member]
Asset Derivatives	485	209
Liability Derivatives	$ (392)	$ (229)

Fair value, before effects of master netting arrangements, of a financial asset or other contract with one or more underlyings, notional amount or payment provision or both, and the contract can be net settled by means outside the contract or delivery of an asset. Includes assets elected not to be offset. Excludes assets not subject to a master netting arrangement.

Fair value, before effects of master netting arrangements, of a financial liability or contract with one or more underlyings, notional amount or payment provision or both, and the contract can be net settled by means outside the contract or delivery of an asset. Includes liabilities elected not to be offset. Excludes liabilities not subject to a master netting arrangement.

Consolidated Statements Of Operations - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2025

Dec. 31, 2024

Dec. 31, 2023

REVENUES:

$ 85,536

$ 82,671

$ 78,586

COSTS AND EXPENSES:

Cost of products sold

63,495

61,975

60,541

Operating expenses

5,867

5,164

4,368

Selling, general and administrative

5,682

5,165

4,385

1,180

1,177

985

Interest expense, net of interest capitalized

285

Total costs and expenses

76,509

73,533

70,291

OPERATING INCOME

9,027

9,138

8,295

OTHER INCOME (EXPENSE):

(3,474)

(3,125)

(2,578)

Gains (losses) on extinguishments of debt

^[1]

419

379

383

(34)

(12)

Gain (Loss) from Litigation Settlement

(627)

586

Income (Loss), Including Portion Attributable to Noncontrolling Interest, before Tax, Total

120

140

122

6,058

7,106

5,597

Income tax expense

350

541

303

NET INCOME

5,708

6,565

5,294

Less: Net income attributable to noncontrolling interests

1,208

1,692

1,299

Less: Net income attributable to redeemable noncontrolling interests

NET INCOME ATTRIBUTABLE TO PARTNERS

4,433

4,814

3,935

Less: General Partner’s interest in net income

Less: Preferred Unitholders’ interest in net income

248

362

463

Preferred Stock Redemption Premium

Limited Partners’ interest in net income

$ 4,173

$ 4,394

$ 3,469

NET INCOME PER COMMON UNIT:

Basic

$ 1.22

$ 1.29

$ 1.10

Diluted

$ 1.21

$ 1.28

$ 1.09

Refined product sales

REVENUES:

$ 24,211

$ 22,051

$ 23,389

Crude sales

REVENUES:

23,487

25,368

23,492

Natural gas sales

REVENUES:

Gathering, transportation and other fees

4,655

2,737

3,259

REVENUES:

12,423

12,027

11,428

NGL sales

REVENUES:

19,038

19,105

15,957

REVENUES:

$ 1,722

$ 1,383

$ 1,061

[1]	Amounts reflected above exclude Sunoco LP’s earnings from the ET-S Permian and J.C. Nolan joint ventures, which are eliminated in consolidation.

Reportable Segments

12 Months Ended

Dec. 31, 2025

Reportable Segments [Abstract]

Reportable Segments

REPORTABLE SEGMENTS:

Our reportable segments currently reflect the following segments, which conduct their business primarily in the United States:

•intrastate transportation and storage;

•interstate transportation and storage;

•midstream;

•NGL and refined products transportation and services;

•crude oil transportation and services;

•investment in Sunoco LP;

•investment in USAC; and

•all other.

Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.

Revenues from our intrastate transportation and storage segment are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from our interstate transportation and storage segment are primarily reflected in gathering, transportation and other fees. Revenues from our midstream segment are primarily reflected in natural gas sales, NGL sales and gathering, transportation and other fees. Revenues from our NGL and refined products transportation and services segment are primarily reflected in NGL sales and gathering, transportation and other fees. Revenues from our crude oil transportation and services segment are reflected in crude sales and gathering, transportation and other fees. Revenues from our investment in Sunoco LP segment are primarily reflected in refined product sales. Revenues from our investment in USAC segment are primarily reflected in gathering, transportation and other fees. Revenues from our all other segment are primarily reflected in natural gas sales.

We report Segment Adjusted EBITDA (defined below) as the measure of segment performance reviewed by our chief operating decision maker (“CODM”). The role of the CODM is held by the Partnership’s co-chief executive officers (“co-

CEOs”). Both of the co-CEOs fulfill specific functions that impact the allocation of resources and assessment of performance among our reportable segments, including the approval of budgets and the evaluation of growth projects and acquisitions. The Partnership’s co-CEOs receive and review the same information with respect to the Partnership’s segment operating results.

The co-CEOs use Segment Adjusted EBITDA to allocate resources (including employees, property, and financial or capital resources) for each segment predominantly in the annual budget and forecasting process. The co-CEOs also use Segment Adjusted EBITDA to assess the performance for each segment and in the compensation of certain employees. The co-CEOs consider forecast-to-actual variances on a monthly basis when making decisions about allocating capital and personnel to the segments. Assets by segment are not a measure used to assess our performance by the co-CEOs and thus are not reported in our disclosures.

We define Segment Adjusted EBITDA as total Partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt, certain foreign currency transaction gains and losses and other non-operating income or expense items, as well as certain non-recurring gains and losses. Inventory valuation adjustments that are excluded from the calculation of Adjusted EBITDA represent only the changes in lower of cost or market reserves on inventory that is carried at LIFO. These amounts are unrealized valuation adjustments applied to Sunoco LP’s fuel volumes remaining in inventory at the end of the period. Segment Adjusted EBITDA and consolidated Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.

The following tables present financial information by segment:


	Years Ended December 31,
	2025		2024		2023
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	3,544	$	2,750	$	3,222
Intersegment revenues	452		303		740
	3,996		3,053		3,962
Interstate transportation and storage:
Revenues from external customers	2,416		2,270		2,328
Intersegment revenues	29		26		47
	2,445		2,296		2,375
Midstream:
Revenues from external customers	3,356		3,283		2,911
Intersegment revenues	9,147		7,916		7,495
	12,503		11,199		10,406
NGL and refined products transportation and services:
Revenues from external customers	21,183		20,981		18,413
Intersegment revenues	3,670		3,549		3,490
	24,853		24,530		21,903
Crude oil transportation and services:
Revenues from external customers	26,479		28,528		26,534
Intersegment revenues	(1)		11		2
	26,478		28,539		26,536
Investment in Sunoco LP:
Revenues from external customers	25,178		22,666		23,026
Intersegment revenues	23		27		42
	25,201		22,693		23,068
Investment in USAC:
Revenues from external customers	933		909		824
Intersegment revenues	65		41		22
	998		950		846
All other:
Revenues from external customers	2,447		1,284		1,328
Intersegment revenues	1,462		463		470
	3,909		1,747		1,798
Eliminations	(14,847)		(12,336)		(12,308)
Total revenues	$	85,536	$	82,671	$	78,586


	Years Ended December 31,
	2025		2024		2023
Cost of products sold:
Intrastate transportation and storage	$	2,525	$	1,390	$	2,616
Interstate transportation and storage	9		9		6
Midstream	7,391		6,637		6,503
NGL and refined products transportation and services	19,505		19,406		17,049
Crude oil transportation and services	22,465		24,407		23,071
Investment in Sunoco LP	22,409		20,595		21,703
Investment in USAC	148		146		137
All other	3,821		1,709		1,740
Eliminations	(14,778)		(12,324)		(12,284)
Total cost of products sold	$	63,495	$	61,975	$	60,541


	Years Ended December 31,
	2025		2024		2023
Operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses:
Intrastate transportation and storage	$	257	$	246	$	279
Interstate transportation and storage	887		807		746
Midstream	1,784		1,550		1,204
NGL and refined products transportation and services	1,066		957		892
Crude oil transportation and services	927		852		699
Investment in Sunoco LP	873		611		420
Investment in USAC	180		166		147
All other	32		20		40
Eliminations	(208)		(112)		(112)
Total operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses	$	5,798	$	5,097	$	4,315


	Years Ended December 31,
	2025		2024		2023
Depreciation, depletion and amortization:
Intrastate transportation and storage	$	205	$	216	$	214
Interstate transportation and storage	572		575		563
Midstream	1,826		1,719		1,451
NGL and refined products transportation and services	1,029		1,026		915
Crude oil transportation and services	1,014		965		740
Investment in Sunoco LP	688		368		187
Investment in USAC	285		265		246
All other	63		31		69
Total depreciation, depletion and amortization	$	5,682	$	5,165	$	4,385


	Years Ended December 31,
	2025		2024		2023
Selling, general and administrative expenses, excluding non-cash compensation and accretion expenses:
Intrastate transportation and storage	$	46	$	50	$	51
Interstate transportation and storage	121		129		115
Midstream	193		199		199
NGL and refined products transportation and services	172		160		157
Crude oil transportation and services	152		149		120
Investment in Sunoco LP	283		266		113
Investment in USAC	56		54		51
All other	53		62		85
Total selling, general and administrative expenses, excluding non-cash compensation and accretion expenses	$	1,076	$	1,069	$	891


	Years Ended December 31,
	2025		2024		2023
Equity in earnings of unconsolidated affiliates (1) :
Intrastate transportation and storage	$	18	$	16	$	17
Interstate transportation and storage	280		241		260
Midstream	15		13		15
NGL and refined products transportation and services	77		83		76
Crude oil transportation and services	23		21		11
Investment in Sunoco LP	2		—		—

All other	4		5		4
Total equity in earnings of unconsolidated affiliates	$	419	$	379	$	383

(1)Amounts reflected above exclude Sunoco LP’s earnings from the ET-S Permian and J.C. Nolan joint ventures, which are eliminated in consolidation.


	Years Ended December 31,
	2025		2024		2023
Other income (expense) (1) :
Intrastate transportation and storage	$	45	$	(9)	$	95
Interstate transportation and storage	508		477		501
Midstream	29		97		25
NGL and refined products transportation and services	33		172		89
Crude oil transportation and services	8		46		35
Investment in Sunoco LP	411		236		132
Investment in USAC	—		—		1
All other	(3)		35		(8)
Eliminations	(214)		(101)		(11)
Total other income (expense)	$	817	$	953	$	859

(1)Other income and expense include, if applicable to a segment, Adjusted EBITDA related to unconsolidated affiliates, unrealized gains and losses on commodity risk management activities and other items. For the investment in Sunoco LP segment, this also includes inventory valuation adjustments.


	Years Ended December 31,
	2025		2024		2023
Additions to property, plant and equipment (1):
Intrastate transportation and storage	$	1,572	$	118	$	93
Interstate transportation and storage	359		332		383
Midstream	1,616		1,323		832
NGL and refined products transportation and services	1,723		1,424		679
Crude oil transportation and services	90		423		266
Investment in Sunoco LP	651		344		215
Investment in USAC	157		276		300
All other	244		342		100
Total additions to property, plant and equipment	$	6,412	$	4,582	$	2,868

(1)Amounts are presented on the accrual basis, net of contributions in aid of constructions costs. Amounts exclude acquisitions and include only the Partnership’s proportionate share of capital expenditures related to joint ventures.


	December 31,
	2025		2024		2023
Investments in unconsolidated affiliates (1):
Intrastate transportation and storage	$	151	$	150	$	144
Interstate transportation and storage	2,353		2,350		2,179
Midstream	130		132		141
NGL and refined products transportation and services	362		383		390
Crude oil transportation and services	190		193		187
Investment in Sunoco LP	342		—		—

All other	61		58		56
Total investments in unconsolidated affiliates	$	3,589	$	3,266	$	3,097

(1)Amounts reflected above exclude Sunoco LP’s investments in the ET-S Permian and J.C. Nolan joint ventures, which are eliminated in consolidation.


	Years Ended December 31,
	2025		2024		2023
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	1,213	$	1,358	$	1,111
Interstate transportation and storage	1,936		1,828		2,009
Midstream	3,164		2,910		2,525
NGL and refined products transportation and services	4,143		4,179		3,894
Crude oil transportation and services	2,942		3,177		2,681
Investment in Sunoco LP	2,047		1,457		964
Investment in USAC	614		584		512
All Other	(75)		(10)		2
Adjusted EBITDA (consolidated)	$	15,984	$	15,483	$	13,698


	Years Ended December 31,
	2025		2024		2023
Reconciliation of net income to Adjusted EBITDA:
Net income	$	5,708	$	6,565	$	5,294
Depreciation, depletion and amortization	5,682		5,165		4,385
Interest expense, net of interest capitalized	3,474		3,125		2,578
Income tax expense	350		541		303
Impairment losses and other	285		52		12
Non-cash compensation expense	148		151		130
Unrealized (gains) losses on commodity risk management activities	(130)		56		(3)
Inventory valuation adjustments (Sunoco LP)	156		86		114
(Gains) losses on extinguishments of debt	34		12		(2)
Adjusted EBITDA related to unconsolidated affiliates	726		692		691
Equity in earnings of unconsolidated affiliates	(419)		(379)		(383)
Non-operating litigation-related loss	—		—		627
Gain on sale of West Texas assets (Sunoco LP)	—		(586)		—
Other, net	(30)		3		(48)
Adjusted EBITDA (consolidated)	$	15,984	$	15,483	$	13,698

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.

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 21
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-21

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 21
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-21

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-32

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 31
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-31

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 15
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-15

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 42
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-42

Reference 7: http://www.xbrl.org/2003/role/exampleRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 48
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482785/280-10-55-48

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (f)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-32

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 270
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (i)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482964/270-10-50-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (ee)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-32

Reference 11: http://fasb.org/us-gaap/role/ref/otherTransitionRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-32

Reference 12: http://www.xbrl.org/2003/role/exampleRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 54
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482785/280-10-55-54

Reference 13: http://www.xbrl.org/2003/role/exampleRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 47
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482785/280-10-55-47

Reference 14: http://www.xbrl.org/2003/role/exampleRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 54
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482785/280-10-55-54

Reference 15: http://www.xbrl.org/2003/role/exampleRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 47
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482785/280-10-55-47

Reference 16: http://www.xbrl.org/2003/role/exampleRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 54
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482785/280-10-55-54

Reference 17: http://www.xbrl.org/2003/role/exampleRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 47
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482785/280-10-55-47

Reference 18: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 22
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-22

Reference 19: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 34
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-34

Reference 20: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 26C
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-26C

Reference 21: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 26B
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-26B

Reference 22: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 40
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-40

Reference 23: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org/280/tableOfContent

Reference 24: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 26
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-26

Reference 25: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 41
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-41

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

Operations And Organization	12 Months Ended
Operations And Organization	Dec. 31, 2025
Operations And Organization [Abstract]
Operations And Organization	OPERATIONS AND BASIS OF PRESENTATION: The consolidated financial statements presented herein contain the results of Energy Transfer LP and its subsidiaries (the “Partnership,” “we,” “us,” “our” or “Energy Transfer”). Our consolidated financial statements reflect the following reportable segments: •intrastate transportation and storage; •interstate transportation and storage; •midstream; •NGL and refined products transportation and services; •crude oil transportation and services; •investment in Sunoco LP; •investment in USAC; and •all other. The Partnership owns and operates intrastate natural gas pipeline systems and storage facilities that are engaged in the business of purchasing, gathering, transporting, processing and marketing natural gas and NGLs in the states of Texas, Oklahoma and Louisiana. The Partnership also owns and operates interstate pipelines, either directly or through equity method investments, that transport natural gas to various markets in the United States. The Partnership is also engaged in midstream services, focusing on providing gathering, processing, compression, treating and transportation of natural gas in some of the most prolific natural gas producing regions in the United States, including the Permian, Anadarko, Arkoma, Hugoton, Powder River and Williston basins, as well as the Eagle Ford, Haynesville, Barnett, Marcellus and Utica shales. The Partnership’s operations also include crude oil, NGL and refined products transportation, terminalling services, and acquisition and marketing activities, as well as NGL storage and fractionation and LNG regasification. The Partnership owns a controlling interest in Sunoco LP which is engaged in energy infrastructure and distribution of motor fuels across 32 countries and territories in North America, the Greater Caribbean and Europe. Sunoco LP’s midstream operations include an extensive network of over 14,000 miles of pipeline and over 160 terminals. Sunoco LP’s fuel distribution operations serve approximately 11,000 Sunoco and partner branded locations, as well as additional independent dealers and commercial customers. As of December 31, 2025, our interest in Sunoco LP consisted of 100% of the general partner and IDRs, as well as 28.5 million common units. In addition, the Partnership controls SunocoCorp Management LLC, which controls SunocoCorp. SunocoCorp’s only cash-generating assets are Sunoco LP’s Class D units. The Partnership owns a controlling interest in USAC which provides compression services to producers, processors, gatherers and transporters of natural gas and crude oil. As of December 31, 2025, our interest in USAC consisted of 100% of the general partner and 46.1 million common units. Basis of Presentation. The consolidated financial statements of Energy Transfer LP presented herein have been prepared in accordance with GAAP and pursuant to the rules and regulations of the SEC. We consolidate all subsidiaries in which we have a controlling financial interest and limited partnerships in which we control the general partner. All significant intercompany transactions and accounts are eliminated in consolidation. The consolidated financial statements of Energy Transfer presented herein include the results of operations of our controlled subsidiaries, including SunocoCorp, Sunoco LP and USAC. We also consolidate SunocoCorp as its primary beneficiary under the variable interest model, based on the Partnership’s interests in its subsidiary, Sunoco LP. The operations of certain pipelines and terminals in which we own an undivided interest are proportionately consolidated in the accompanying consolidated financial statements.

Retirement Benefits (Benefit Payments) (Details) $ in Millions	Dec. 31, 2025 USD ($)
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2026	$ 13
2027	13
2028	12
2029	11
2030	11
2031 – 2035	45
Defined Benefit Plan, Funded Plan \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2026	0
2027	0
2028	0
2029	0
2030	0
2031 – 2035	0
Defined Benefit Plan, Unfunded Plan \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2026	2
2027	2
2028	2
2029	2
2030	1
2031 – 2035	$ 4

Consolidated Statement Of Equity - USD ($) $ in Millions	Total	Nustar	General Partner	General Partner Nustar	Accumulated Other Comprehensive Income	Accumulated Other Comprehensive Income Nustar	Non- controlling Interests	Non- controlling Interests Nustar	Preferred Unitholders	Preferred Unitholders Nustar	Common Units	Common Units Nustar	Lotus Midstream Acquisition	Lotus Midstream Acquisition General Partner	Lotus Midstream Acquisition Accumulated Other Comprehensive Income	Lotus Midstream Acquisition Non- controlling Interests	Lotus Midstream Acquisition Preferred Unitholders	Lotus Midstream Acquisition Common Units	Crestwood Acquisition	Crestwood Acquisition General Partner	Crestwood Acquisition Accumulated Other Comprehensive Income	Crestwood Acquisition Non- controlling Interests	Crestwood Acquisition Preferred Unitholders	Crestwood Acquisition Common Units	WTG Midstream	WTG Midstream General Partner	WTG Midstream Accumulated Other Comprehensive Income	WTG Midstream Non- controlling Interests	WTG Midstream Preferred Unitholders	WTG Midstream Common Units	Nustar Acquisition	Nustar Acquisition General Partner	Nustar Acquisition Accumulated Other Comprehensive Income	Nustar Acquisition Non- controlling Interests	Nustar Acquisition Preferred Unitholders	Nustar Acquisition Common Units
Balance at Dec. 31, 2022	$ 40,659		$ (2)		$ 16		$ 7,634		$ 6,051		$ 26,960
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners	(4,248)		(3)		0		0		(468)		(3,777)
Distributions to noncontrolling interests	(1,691)		0		0		(1,691)		0		0
Capital contributions from noncontrolling interests	3		0		0		3		0		0
Other, net	30		0		0		12		0		18
Partners' Capital Account, Acquisitions	3,940												$ 574	$ 0	$ 0	$ 0	$ 0	$ 574	$ 3,366	$ 0	$ 0	$ 0	$ 413	$ 2,953
Other comprehensive income, net of tax	12		0		12		0		0		0
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest	5,234		3		0		1,299		463		3,469
Balance at Dec. 31, 2023	43,939		(2)		28		7,257		6,459		30,197
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners	(4,623)		(4)		0		0		(378)		(4,241)
Distributions to noncontrolling interests	(1,780)		0		0		(1,780)		0		0
Capital contributions from noncontrolling interests	638		0		0		638		0		0
Other, net	(64)		0		0		(76)		54		(42)
Partners' Capital Account, Acquisitions	833																								$ 833	$ 0	$ 0	$ 0	$ 0	$ 833	$ 3,651	$ 0	$ 0	$ 3,651	$ 0	$ 0
Common units repurchased	(2,645)	$ (784)	0	$ 0	0	$ 0	0	$ (784)	(2,645)	$ 0	0	$ 0
Partners' Capital Account, Exchanges and Conversions	301		0		0		301		0		0
Other comprehensive income, net of tax	45		0		45		0		0		0
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest	6,506		4		0		1,692		362		4,448
Balance at Dec. 31, 2024	46,017		(2)		73		10,899		3,852		31,195
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners	(4,725)		(4)		0		0		(252)		(4,469)
Distributions to noncontrolling interests	(1,734)		0		0		(1,734)		0		0
Capital contributions from noncontrolling interests	27		0		0		27		0		0
Other, net	71		0		(6)		46		8		23
Partners' Capital Account, Acquisitions	0																														$ 2,547	$ 0	$ 0	$ 2,547	$ 0	$ 0
Common units repurchased	(500)		0		0		0		(500)		0
Units issued	1,487		0		0		1,487		0		0
Partners' Capital Account, Exchanges and Conversions	164		0		0		164		0		0
Other comprehensive income, net of tax	15		0		15		0		0		0
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest	5,641		4		0		1,208		248		4,181
Balance at Dec. 31, 2025	$ 49,010		$ (2)		$ 82		$ 14,644		$ 3,356		$ 30,930

Retirement Benefits (Tables)

12 Months Ended

Dec. 31, 2025

Retirement Benefits [Abstract]

Certain of the Partnership’s subsidiaries sponsor pension and/or other postretirement benefit plans that provide benefits to a defined group of retirees. The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis:


	December 31, 2025						December 31, 2024
	Pension Benefits						Pension Benefits
	Funded Plans		Unfunded Plans		Other Postretirement Benefits		Funded Plans		Unfunded Plans		Other Postretirement Benefits
Change in benefit obligation:
Benefit obligation at beginning of period	$	158	$	16	$	127	$	23	$	17	$	138
Service cost	—		—		2		1		—		—
Interest cost	4		1		7		6		1		7
Amendments	—		—		7		—		—		(11)
Benefits paid, net	(137)		(3)		(11)		(37)		(3)		(13)

Actuarial gain and other	(4)		1		(1)		13		1		(6)
Settlements	(21)		—		—		—		—		—
NuStar acquisition	—		—		—		152		—		12
Benefit obligation at end of period	—		15		131		158		16		127

Change in plan assets:
Fair value of plan assets at beginning of period	182		—		295		22		—		277
Return on plan assets and other	3		—		34		13		—		29
Employer contributions	1		—		3		5		—		2
Benefits paid, net	(137)		—		(11)		(36)		—		(13)
Settlements	(21)		—		—		—		—		—
NuStar acquisition	—		—		—		178		—		—
Fair value of plan assets at end of period	28		—		321		182		—		295

Amount underfunded (overfunded) at end of period	$	(28)	$	15	$	(190)	$	(24)	$	16	$	(168)

Amounts recognized in the consolidated balance sheets consist of:
Current assets	$	28	$	—	$	—	$	—	$	—	$	—
Non-current assets	—		—		208		24		—		185
Current liabilities	—		(2)		(3)		—		(3)		(3)
Non-current liabilities	—		(13)		(15)		—		(13)		(14)
	$	28	$	(15)	$	190	$	24	$	(16)	$	168

Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial gain (loss)	$	—	$	—	$	(73)	$	(9)	$	(1)	$	(59)
Prior service credit	—		—		17		—		—		25
	$	—	$	—	$	(56)	$	(9)	$	(1)	$	(34)

Defined Benefit Plan, Plan with Projected Benefit Obligation in Excess of Plan Assets [Table Text Block]

The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets:


	December 31, 2025						December 31, 2024
	Pension Benefits						Pension Benefits
	Funded Plans		Unfunded Plans		Other Postretirement Benefits		Funded Plans		Unfunded Plans		Other Postretirement Benefits
Projected benefit obligation	$	—	$	15	N/A		$	22	$	16	N/A
Accumulated benefit obligation	—		15		$	131	158		16		$	127
Fair value of plan assets	28		—		321		182		—		295

Schedule of Net Benefit Costs [Table Text Block]

Components of Net Periodic Benefit Cost


	December 31, 2025				December 31, 2024
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Net periodic benefit cost:
Service cost	$	—	$	2	$	1	$	—
Interest cost	1		7		6		7
Expected return on plan assets	—		(14)		(8)		(13)
Prior service cost amortization	(2)		3		(2)		2
Actuarial gain amortization	—		(3)		—		(1)


Settlements	—		—		2		—
Net periodic benefit cost	$	(1)	$	(5)	$	(1)	$	(5)

Defined Benefit Plan, Assumptions [Table Text Block]

The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the following table:


	December 31, 2025				December 31, 2024
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Discount rate	5.40	%	4.89	%	4.80	%	4.40	%

The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the following table:


	December 31, 2025				December 31, 2024
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Discount rate	5.40	%	4.89	%	5.40	%	4.40	%
Expected return on assets:
Tax exempt accounts	7.00	%	7.00	%	7.00	%	7.00	%
Taxable accounts	—	%	4.75	%	4.26	%	4.75	%

Schedule of Health Care Cost Trend Rates [Table Text Block]

The assumed health care cost trend weighted-average rates used to measure the expected cost of benefits covered by the plans are shown in the following table:


	December 31,
	2025		2024
Health care cost trend rate	7.49	%	7.44	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.18	%	5.09	%
Year that the rate reaches the ultimate trend rate	2033		2032

Schedule of Changes in Fair Value of Plan Assets

The fair value of the pension plan assets by asset category at the dates indicated is as follows:


			Fair Value Measurements at December 31, 2025
	Fair Value Total		Level 1		Level 2		Level 3
Asset Category:
Cash and cash equivalents	$	28	$	28	$	—	$	—


			Fair Value Measurements at December 31, 2024
	Fair Value Total		Level 1		Level 2		Level 3
Asset Category:
Cash and cash equivalents	$	81	$	81	$	—	$	—
Mutual funds (1)	65		21		44		—
Fixed income securities	36		36		—		—
Total	$	182	$	138	$	44	$	—

(1)Comprised of approximately 100% equities as of December 31, 2024.

The fair value of other postretirement plan assets by asset category at the dates indicated is as follows:


			Fair Value Measurements at December 31, 2025
	Fair Value Total		Level 1		Level 2		Level 3
Asset category:
Cash and cash equivalents	$	4	$	4	$	—	$	—
Mutual funds(1)	216		216		—		—
Fixed income securities	101		—		101		—
Total	$	321	$	220	$	101	$	—

(1)Primarily composed of market index funds as of December 31, 2025.


			Fair Value Measurements at December 31, 2024
	Fair Value Total		Level 1		Level 2		Level 3
Asset category:
Cash and cash equivalents	$	8	$	8	$	—	$	—
Mutual funds(1)	189		189		—		—
Fixed income securities	98		—		98		—
Total	$	295	$	197	$	98	$	—

(1)Primarily composed of market index funds as of December 31, 2024.

Schedule of Expected Benefit Payments [Table Text Block]

Benefit Payments

The Partnership’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the following table:


	Pension Benefits - Funded Plans		Pension Benefits - Unfunded Plans		Other Postretirement Benefits (Gross, Before Medicare Part D)
2026	$	—	$	2	$	13
2027	—		2		13
2028	—		2		12
2029	—		2		11
2030	—		1		11
2031 – 2035	—		4		45

Investments in Unconsolidated Affiliates (Summarized Income Statement Information) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Schedule of Equity Method Investments [Line Items]
Revenues	$ 85,536	$ 82,671	$ 78,586
Net income	5,708	6,565	5,294
Equity Method Investments [Member]
Schedule of Equity Method Investments [Line Items]
Revenues	1,862	1,898	1,914
Equity Method Investments Summarized Financial Information, Operating Income	988	1,009	1,079
Net income	$ 759	$ 750	$ 786

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

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 235
-Name Accounting Standards Codification
-Section S50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478671/942-235-S50-1

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 235
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-05(b)(2))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477314/942-235-S99-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(g)(1)(i))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(k)(2))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 825
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 28
-Subparagraph (f)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482907/825-10-50-28

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 105
-SubTopic 10
-Name Accounting Standards Codification
-Section 65
-Paragraph 9
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479343/105-10-65-9

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
-SubTopic 10
-Name Accounting Standards Codification
-Section 65
-Paragraph 17
-Subparagraph (d)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480336/718-10-65-17

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 250
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 6
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483443/250-10-50-6

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 250
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 9
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483443/250-10-50-9

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 805
-SubTopic 60
-Name Accounting Standards Codification
-Section 65
-Paragraph 1
-Subparagraph (g)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147476176/805-60-65-1

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 323
-Name Accounting Standards Codification
-Section 65
-Paragraph 2
-Subparagraph (g)(3)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478666/740-323-65-2

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(g)(1)(ii))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 323
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 3
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481687/323-10-50-3

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
-Topic 250
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (b)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483443/250-10-50-1

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 40
-Name Accounting Standards Codification
-Section 65
-Paragraph 1
-Subparagraph (f)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480175/815-40-65-1

Reference 17: http://www.xbrl.org/2003/role/disclosureRef
-Topic 250
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 8
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483443/250-10-50-8

Reference 18: http://www.xbrl.org/2003/role/exampleRef
-Topic 946
-SubTopic 830
-Name Accounting Standards Codification
-Section 55
-Paragraph 11
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479168/946-830-55-11

Reference 19: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 205
-Name Accounting Standards Codification
-Section 45
-Paragraph 3
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478009/946-205-45-3

Reference 20: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 220
-Name Accounting Standards Codification
-Section 45
-Paragraph 7
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479105/946-220-45-7

Reference 21: http://www.xbrl.org/2003/role/disclosureRef
-Topic 944
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04(16))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477250/944-220-S99-1

Reference 22: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.6-07(9))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479134/946-220-S99-1

Reference 23: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 3
-Subparagraph (SX 210.6-09(1)(d))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479134/946-220-S99-3

Reference 24: http://www.xbrl.org/2003/role/disclosureRef
-Topic 810
-SubTopic 10
-Name Accounting Standards Codification
-Section 45
-Paragraph 19
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481231/810-10-45-19

Reference 25: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 220
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 6
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482765/220-10-50-6

Reference 26: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(4)(i))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1A

Reference 27: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(4)(ii))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1A

Reference 28: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(4)(iii)(A))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1A

Reference 29: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(4)(iv))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1A

Reference 30: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(5))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1A

Reference 31: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(i))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1B

Reference 32: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(iii)(A))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1B

Reference 33: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(iii)(B))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1B

Reference 34: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(iv))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1B

Reference 35: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(5))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1B

Reference 36: http://www.xbrl.org/2003/role/disclosureRef
-Topic 205
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 7
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483499/205-20-50-7

Reference 37: http://www.xbrl.org/2003/role/exampleRef
-Topic 810
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 4J
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481175/810-10-55-4J

Reference 38: http://www.xbrl.org/2003/role/exampleRef
-Topic 810
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 4K
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481175/810-10-55-4K

Reference 39: http://www.xbrl.org/2003/role/disclosureRef
-Topic 220
-SubTopic 10
-Name Accounting Standards Codification
-Section 45
-Paragraph 1A
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482790/220-10-45-1A

Reference 40: http://www.xbrl.org/2003/role/disclosureRef
-Topic 220
-SubTopic 10
-Name Accounting Standards Codification
-Section 45
-Paragraph 1B
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482790/220-10-45-1B

Reference 41: http://www.xbrl.org/2003/role/disclosureRef
-Topic 230
-SubTopic 10
-Name Accounting Standards Codification
-Section 45
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482740/230-10-45-2

Reference 42: http://www.xbrl.org/2003/role/disclosureRef
-Topic 810
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1A
-Subparagraph (a)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481203/810-10-50-1A

Reference 43: http://www.xbrl.org/2003/role/disclosureRef
-Topic 810
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1A
-Subparagraph (c)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481203/810-10-50-1A

Reference 44: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 65
-Paragraph 4
-Subparagraph (f)(4)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481538/470-20-65-4

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).

Reference 1: http://www.xbrl.org/2003/role/exampleRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4A
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4A

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 235
-Name Accounting Standards Codification
-Section S50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478671/942-235-S50-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 235
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-05(b)(2))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477314/942-235-S99-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 41
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-41

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 42
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-42

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-1

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(g)(1)(i))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 825
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 28
-Subparagraph (f)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482907/825-10-50-28

Reference 9: http://www.xbrl.org/2003/role/exampleRef
-Topic 944
-SubTopic 605
-Name Accounting Standards Codification
-Section 55
-Paragraph 14
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477548/944-605-55-14

Reference 10: http://www.xbrl.org/2003/role/exampleRef
-Topic 944
-SubTopic 605
-Name Accounting Standards Codification
-Section 55
-Paragraph 11
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477548/944-605-55-11

Reference 11: http://www.xbrl.org/2003/role/exampleRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 48
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482785/280-10-55-48

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 270
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (i)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482964/270-10-50-1

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (ee)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-32

Reference 14: http://fasb.org/us-gaap/role/ref/otherTransitionRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-32

Reference 15: http://fasb.org/us-gaap/role/ref/otherTransitionRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-32

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(g)(1)(ii))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 17: http://www.xbrl.org/2003/role/disclosureRef
-Topic 323
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 3
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481687/323-10-50-3

Reference 18: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(4)(i))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1A

Reference 19: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(4)(ii))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1A

Reference 20: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(4)(iii)(A))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1A

Reference 21: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(4)(iv))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1A

Reference 22: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(5))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1A

Reference 23: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(i))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1B

Reference 24: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(iii)(A))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1B

Reference 25: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(iii)(B))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1B

Reference 26: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(iv))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1B

Reference 27: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(5))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1B

Reference 28: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 30
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-30

Reference 29: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 22
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-22

Reference 30: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 40
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-40

Reference 31: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 22
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-22

Reference 32: http://www.xbrl.org/2003/role/disclosureRef
-Topic 220
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03(1))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483621/220-10-S99-2

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

Schedule Of Aggregated Selected Balance Sheet And Income Statement Data For Our Unconsolidated Affiliates

Investments in Unconsolidated Affiliates (Tables)

12 Months Ended

Dec. 31, 2025

Investment In Affiliates [Abstract]

The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2025 and 2024 were as follows:


	December 31,
	2025		2024
Citrus	$	1,843	$	1,818

MEP	279		309
White Cliffs	177		196
Explorer	65		66
SESH	231		223
Other	994		654
Total	$	3,589	$	3,266

The following table presents equity in earnings (losses) of unconsolidated affiliates:


	Years Ended December 31,
	2025		2024		2023
Citrus	$	153	$	136	$	146
MEP	74		63		87
White Cliffs	17		19		10
Explorer	26		34		37
SESH	57		45		31
Other	92		82		72
Total equity in earnings of unconsolidated affiliates	$	419	$	379	$	383

Schedule of Investments in and Advances to Affiliates, Schedule of Investments [Table Text Block]

The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, Citrus, MEP, White Cliffs, Explorer and SESH (on a 100% basis) for all periods presented:


	December 31,
	2025		2024
Current assets	$	462	$	446
Property, plant and equipment, net	8,397		8,478
Other assets	109		105
Total assets	$	8,968	$	9,029

Current liabilities	$	365	$	1,160
Non-current liabilities	4,319		3,541
Equity	4,284		4,328
Total liabilities and equity	$	8,968	$	9,029


	Years Ended December 31,
	2025		2024		2023
Revenue	$	1,862	$	1,898	$	1,914
Operating income	988		1,009		1,079
Net income	759		750		786

Reportable Segments (Selling General and Administrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Segment Reporting Information [Line Items]
Selling, General and Administrative Expense	$ 1,076	$ 1,069	$ 891
Intrastate Transportation and Storage
Segment Reporting Information [Line Items]
Selling, General and Administrative Expense	46	50	51
Interstate Transportation and Storage
Segment Reporting Information [Line Items]
Selling, General and Administrative Expense	121	129	115
Midstream
Segment Reporting Information [Line Items]
Selling, General and Administrative Expense	193	199	199
NGL and Refined Products Transportation and Services
Segment Reporting Information [Line Items]
Selling, General and Administrative Expense	172	160	157
Crude Oil Transportation and Services
Segment Reporting Information [Line Items]
Selling, General and Administrative Expense	152	149	120
Investment in Sunoco LP
Segment Reporting Information [Line Items]
Selling, General and Administrative Expense	283	266	113
Investment in USAC
Segment Reporting Information [Line Items]
Selling, General and Administrative Expense	56	54	51
Corporate Segment and Other Operating Segment [Member]
Segment Reporting Information [Line Items]
Selling, General and Administrative Expense	$ 53	$ 62	$ 85

Lease Accounting - Lessor (Details) - Sunoco LP [Member] $ in Millions	Dec. 31, 2025 USD ($)
2026	$ 154
2027	124
2028	98
Lessor, Operating Lease, Payment to be Received, Year Four	78
Lessor, Operating Lease, Payment to be Received, Year Five	68
Thereafter	369
Total undiscounted cash flows	$ 891

Equity Incentive Plans (Tables)

12 Months Ended

Dec. 31, 2025

Schedule of Subsidiary Awards Granted To Employees And Non-Employee Directors

The following table shows the activity of the awards granted to employees and non-employee directors:


	Number of Units	Weighted Average Grant-Date Fair Value Per Unit
Unvested awards as of December 31, 2024	36.1	$	13.18

Awards granted	9.4	16.85
Awards vested	(9.5)	10.20
Awards forfeited	(0.8)	13.70
Unvested awards as of December 31, 2025	35.2	$	14.98

Subsidiaries [Member]

Schedule of Subsidiary Awards Granted To Employees And Non-Employee Directors

The following table summarizes the activity of the Subsidiary Unit Awards:


	SunocoCorp			Sunoco LP			USAC
	Number of Units	Weighted Average Grant-Date Fair Value Per Unit		Number of Units	Weighted Average Grant-Date Fair Value Per Unit		Number of Phantom Units	Weighted Average Grant-Date Fair Value Per Phantom Unit		Number of Restricted Units	Weighted Average Grant-Date Fair Value Per Restricted Unit
Unvested awards as of December 31, 2024	—	$	—	1,542,700	$	46.83	1,320,316	$	18.59	323,390	22.25
Awards granted	183,813	51.24		730,078	54.79		—	—		392,422	24.26
Awards vested	—	—		(442,386)	36.60		(797,412)	17.03		—	—
Awards forfeited	—	—		(59,020)	48.22		(220,570)	18.82		(69,430)	22.25
Unvested awards as of December 31, 2025	183,813	$	51.24	1,771,372	$	52.49	302,334	$	20.16	646,382	23.84

Revenue Narrative (Details) - USD ($) $ in Millions	12 Months Ended
Revenue Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Sunoco LP [Member]
Capitalized Contract Cost, Amortization	$ 41	$ 35	$ 29

Cover Page Cover Page - USD ($) $ in Millions	12 Months Ended
Cover Page Cover Page - USD ($) $ in Millions	Dec. 31, 2025	Feb. 13, 2026	Jun. 30, 2025
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2025
Document Transition Report	false
Entity File Number	1-32740
Entity Registrant Name	ENERGY TRANSFER LP
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	30-0108820
Entity Address, Address Line One	8111 Westchester Drive
Entity Address, Address Line Two	Suite 600
Entity Address, City or Town	Dallas
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	75225
City Area Code	214
Local Phone Number	981-0700
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 55,980
Entity Common Stock, Shares Outstanding		3,440,314,575
Documents Incorporated by Reference	None
Entity Central Index Key	0001276187
Document Fiscal Year Focus	2025
Document Fiscal Period Focus	FY
Amendment Flag	false
ICFR Auditor Attestation Flag	true
Document Information [Line Items]
Document Transition Report	false
Document Annual Report	true
Document Period End Date	Dec. 31, 2025
Current Fiscal Year End Date	--12-31
Auditor Firm ID	248
Auditor Location	Dallas, Texas
Auditor Name	GRANT THORNTON LLP
Document Financial Statement Error Correction [Flag]	false
Common Stock
Cover [Abstract]
Title of 12(b) Security	Common Units
Trading Symbol	ET
Security Exchange Name	NYSE
Document Information [Line Items]
Title of 12(b) Security	Common Units
Trading Symbol	ET
Security Exchange Name	NYSE
ETprI
Cover [Abstract]
Title of 12(b) Security	9.250% Series I Fixed Rate Perpetual Preferred Units
Trading Symbol	ETprI
Security Exchange Name	NYSE
Document Information [Line Items]
Title of 12(b) Security	9.250% Series I Fixed Rate Perpetual Preferred Units
Trading Symbol	ETprI
Security Exchange Name	NYSE

Debt Obligations Debt Obligations (Covenants Related To Credit Agrrements) (Narrative) (Details)	12 Months Ended
	Dec. 31, 2025
Five Year Credit Facility \| ET [Member]
Debt Instrument [Line Items]
Leverage Ratio Maximum	5.00
Maximum Leverage Ratio Permitted	5.50
Supplementary Leverage Ratio	0.0321
Five Year Credit Facility \| Minimum [Member] \| ET [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.125%
Five Year Credit Facility \| Minimum [Member] \| ET [Member] \| Eurodollar [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.125%
Five Year Credit Facility \| Minimum [Member] \| ET [Member] \| Base Rate
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.125%
Five Year Credit Facility \| Maximum [Member] \| ET [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.30%
Five Year Credit Facility \| Maximum [Member] \| ET [Member] \| Eurodollar [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.00%
Five Year Credit Facility \| Maximum [Member] \| ET [Member] \| Base Rate
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%
USAC Credit Facility
Debt Instrument [Line Items]
Debt Instrument, Covenant Description	The USAC Credit Facility is also subject to the following financial covenants, including covenants requiring USAC to maintain:•a minimum EBITDA to interest coverage ratio;•a ratio of total secured indebtedness to EBITDA within a specified range; and •a maximum funded debt to EBITDA ratio.
Sunoco LP Credit Facility
Debt Instrument [Line Items]
Debt Instrument, Covenant Description	Sunoco LP’s Credit Facility requires Sunoco LP to maintain a specified net leverage ratio and interest coverage ratio.

Estimates (Aggregate Amortization Expense Of Intangibles And Other Assets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Accounting Policies [Abstract]
Reported in depreciation and amortization	$ 479	$ 464	$ 399

The aggregate expense charged against earnings to allocate the cost of intangible assets (nonphysical assets not used in production) in a systematic and rational manner to the periods expected to benefit from such assets.

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Section 45
-Paragraph 28
-Subparagraph (b)
-SubTopic 10
-Topic 230
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482740/230-10-45-28

Reference 2: http://www.xbrl.org/2003/role/exampleRef
-Topic 220
-SubTopic 40
-Name Accounting Standards Codification
-Section 55
-Paragraph 18
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147476153/220-40-55-18

Reference 3: http://www.xbrl.org/2003/role/exampleRef
-Topic 220
-SubTopic 40
-Name Accounting Standards Codification
-Section 55
-Paragraph 11
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147476153/220-40-55-11

Reference 4: http://www.xbrl.org/2003/role/exampleRef
-Topic 220
-SubTopic 40
-Name Accounting Standards Codification
-Section 55
-Paragraph 24
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147476153/220-40-55-24

Reference 5: http://www.xbrl.org/2003/role/exampleRef
-Topic 220
-SubTopic 40
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147476148/220-40-50-12

Reference 6: http://www.xbrl.org/2003/role/exampleRef
-Name Accounting Standards Codification
-Section 55
-Paragraph 40
-SubTopic 30
-Topic 350
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482640/350-30-55-40

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 350
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (a)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482665/350-30-50-2

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 350
-SubTopic 30
-Name Accounting Standards Codification
-Section 45
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482686/350-30-45-2

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 220
-SubTopic 40
-Name Accounting Standards Codification
-Section 50
-Paragraph 6
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147476148/220-40-50-6

Redeemable Noncontrolling Interest, Equity, Carrying Amount [Abstract]

Redeemable Noncontrolling Interests (Tables)

12 Months Ended

Dec. 31, 2025

Redeemable Noncontrolling Interest

Redeemable noncontrolling interests consisted of the following:


	December 31, 2025		December 31, 2024
USAC Series A preferred units	$	—	$	169
Crestwood Niobrara LLC preferred units	225		225
Other (1)	25		23
Total redeemable noncontrolling interests	$	250	$	417

(1) Relates to noncontrolling interest holders in one of the Partnership’s consolidated subsidiaries that have the option to sell their interests to the Partnership.

Debt Obligations

12 Months Ended

Dec. 31, 2025

Debt Obligations [Abstract]

Debt Obligations

DEBT OBLIGATIONS:

Our debt obligations consist of the following:


	December 31,
	2025	2024
Energy Transfer Indebtedness
4.05% senior notes due March 15, 2025(1)	—	1,000
2.90% senior notes due May 15, 2025(1)	—	1,000
5.95% senior notes due December 1, 2025(1)	—	400
4.75% senior notes due January 15, 2026(2)(3)	1,000	1,000
3.90% senior notes due July 15, 2026(2)	550	550
6.05% senior notes due December 1, 2026(2)	1,000	1,000
4.40% senior notes due March 15, 2027	700	700
4.20% senior notes due April 15, 2027	600	600
5.625% senior notes due May 1, 2027(3)	600	600
5.50% senior notes due June 1, 2027	44	44
5.50% senior notes due June 1, 2027	956	956
4.00% senior notes due October 1, 2027	750	750
5.55% senior notes due February 15, 2028	1,000	1,000
4.95% senior notes due May 15, 2028	800	800
4.95% senior notes due June 15, 2028	1,000	1,000
6.10% senior notes due December 1, 2028	500	500
6.00% senior notes due February 1, 2029	700	700
5.25% senior notes due April 15, 2029	1,500	1,500
5.25% senior notes due July 1, 2029	1,000	1,000
7.00% senior notes due July 15, 2029	66	66
4.15% senior notes due September 15, 2029	547	547
8.25% senior notes due November 15, 2029	33	33
8.25% senior notes due November 15, 2029	267	267
5.20% senior notes due April 1, 2030	650	—
3.75% senior note due May 15, 2030	1,500	1,500
6.40% senior notes due December 1, 2030	1,000	1,000
7.375% senior notes due April 1, 2031	600	600
5.75% senior notes due February 15, 2033	1,500	1,500
4.05% tax-exempt bonds due June 1, 2033	225	225
6.55% senior notes due December 1,2033	1,500	1,500
5.55% senior notes due May 15, 2034	1,250	1,250
5.60% senior notes due September 1, 2034	1,250	1,250
4.90% senior notes due March 15, 2035	500	500
5.70% senior notes due April 1, 2035	1,250	—
6.625% senior notes due October 15, 2036	400	400
5.80% senior notes due June 15, 2038	500	500
7.50% senior notes due July 1, 2038	550	550
6.85% senior notes due February 15, 2040	250	250
6.05% senior notes due June 1, 2041	700	700
6.50% senior notes due February 1, 2042	1,000	1,000
6.10% senior notes due February 15, 2042	300	300
4.95% senior notes due January 15, 2043	350	350
5.15% senior notes due February 1, 2043	450	450


5.95% senior notes due October 1, 2043	450	450
5.30% senior notes due April 1, 2044	700	700
5.00% senior notes due May 15, 2044	531	531
5.15% senior notes due March 15, 2045	1,000	1,000
5.35% senior notes due May 15, 2045	800	800
6.125% senior notes due December 15, 2045	1,000	1,000
5.30% senior notes due April 15, 2047	900	900
5.40% senior notes due October 1, 2047	1,500	1,500
6.00% senior notes due June 15, 2048	1,000	1,000
6.25% senior notes due April 15, 2049	1,750	1,750
5.00% senior notes due May 15, 2050	2,000	2,000
5.95% senior notes due May 15, 2054	1,750	1,750
6.05% senior notes due September 1, 2054	1,250	1,250
8.00% fixed-to-fixed reset rate junior subordinated notes due May 15, 2054	800	800
7.125% fixed-to-fixed reset rate junior subordinated notes due October 1, 2054	400	400
6.20% senior notes due April 1, 2055	1,100	—
6.50% Series 2025A junior subordinated notes due February 15, 2056	1,200	—
6.75% Series 2025B junior subordinated notes due February 15, 2056	800	—
Floating rate junior subordinated notes due November 1, 2066	600	600
Five-year credit facility due April 11, 2029	2,856	2,759
Unamortized premiums, discounts and fair value adjustments, net	30	62
Deferred debt issuance costs	(277)	(250)
	51,478	48,840
Subsidiary Indebtedness
Transwestern Debt
6.16% senior notes due May 24, 2037	75	75
	75	75
Bakken Project Debt
4.625% senior notes due April 1, 2029	850	850

Deferred debt issuance costs	(2)	(3)
	848	847
Sunoco LP Debt
5.750% senior notes due 2025 (1)	—	600
6.000% senior notes due 2026 (2)	500	500
3.875% CAD senior notes due 2026 (2) (4)	400	—
Parkland 3.875% CAD senior notes due 2026 (2)(5)	37	—
6.000% senior notes due 2027	600	600
5.625% senior notes due 2027	550	550
5.875% senior notes due 2027 (4)	499	—
Parkland 5.875% senior notes due 2027 (5)	1	—
5.875% senior notes due 2028	400	400
7.000% senior notes due 2028	500	500
6.000% CAD senior notes due 2028 (4)	277	—
Parkland 6.000% CAD senior notes due 2028 (5)	14	—
4.500% senior notes due 2029	800	800
7.000% senior notes due 2029	750	750
4.375% CAD senior notes due 2029 (4)	397	—
Parkland 4.375% CAD senior notes due 2029 (5)	40	—
4.500% senior notes due 2029 (4)	790	—


Parkland 4.500% senior notes due 2029 (5)	10		—
4.500% senior notes due 2030	800		800
6.375% senior notes due 2030	600		600
4.625% senior notes due 2030 (4)	798		—
Parkland 4.625% senior notes due 2030 (5)	2		—
5.625% senior notes due 2031	1,000		—
7.250% senior notes due 2032	750		750
6.625% senior notes due 2032 (4)	493		—
Parkland 6.625% senior notes due 2032 (5)	7		—
6.250% senior notes due 2033	1,000		—
5.875% senior notes due 2034	900		—
GoZone bonds	322		322
Sunoco LP credit facility due June 17, 2030	—		203
Lease-related obligations and other Sunoco LP subsidiary debt	233		132
Unamortized premiums, discounts and fair value adjustments, net	2		15
Deferred debt issuance costs	(83)		(37)
	13,389		7,485
USAC Debt
6.875% senior notes due September 1, 2027(1)	—		750
7.125% senior notes due March 15, 2029	1,000		1,000
6.250% senior notes due October 1, 2033	750		—
USAC credit facility due August 27, 2030	795		772
Deferred debt issuance costs	(21)		(20)
	2,524		2,502

Other long-term debt	19		11

Total debt	68,333		59,760
Less: Current maturities of long-term debt	25		8
Long-term debt, less current maturities	$	68,308	$	59,752

(1)These notes were redeemed in 2025.

(2)As of December 31, 2025, these obligations were classified as long-term as management had the intent and ability to refinance the borrowings on a long-term basis.

(3)These notes were redeemed in 2026.

(4)These senior notes, totaling $3.65 billion as of December 31, 2025, were assumed by Sunoco LP in connection with the closing of the Parkland acquisition. For additional information, see “Sunoco LP Parkland Senior Note Exchange” below.

(5)These senior notes, totaling $111 million as of December 31, 2025, represent the aggregate principal amounts not tendered in the private exchange offers and remain outstanding obligations of Parkland. For additional information, see “Sunoco LP Parkland Senior Note Exchange” below.

The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $351 million in unamortized premiums, fair value adjustments and deferred debt issuance costs, net:


2026	$	3,512
2027	5,314
2028	4,505
2029	11,619
2030	6,154
Thereafter	37,581
Total	$	68,685

Notes and Debentures

Senior Notes

The Energy Transfer senior notes are the Partnership’s senior obligations, ranking equally in right of payment with our other existing and future unsubordinated debt and senior to any of its future subordinated debt. The Energy Transfer senior notes are not guaranteed by any of its subsidiaries.

The covenants related to the Energy Transfer senior notes include a limitation on liens, a limitation on transactions with affiliates, a restriction on sale-leaseback transactions and limitations on mergers and sales of all or substantially all of the Partnership’s assets.

Energy Transfer Notes Issuances and Redemptions

In March 2025, the Partnership issued $650 million aggregate principal amount of 5.20% senior notes due April 2030, $1.25 billion aggregate principal amount of 5.70% senior notes due April 2035 and $1.10 billion aggregate principal amount of 6.20% senior notes due April 2055. The Partnership used the net proceeds to refinance existing indebtedness, including to repay commercial paper and borrowings under its Five-Year Credit Facility (described below), and for general partnership purposes.

In March 2025, the Partnership redeemed its $1.00 billion aggregate principal amount of 4.05% senior notes due March 2025 using cash on hand and commercial paper borrowings.

In May 2025, the Partnership redeemed its $1.00 billion aggregate principal amount of 2.90% senior notes due May 2025 using cash on hand and commercial paper borrowings.

In August 2025, the Partnership issued $1.20 billion aggregate principal amount of its Series 2025A junior subordinated notes due 2056 and $800 million aggregate principal amount of its Series 2025B junior subordinated notes due 2056. The Partnership used the net proceeds to repay borrowings under its Five-Year Credit Facility and for general partnership purposes.

In September 2025, the Partnership redeemed its $400 million aggregate principal amount of 5.95% senior notes due December 2025 using cash on hand and commercial paper borrowings.

In January 2026, the Partnership issued $1.00 billion aggregate principal amount of 4.55% senior notes due 2031, $1.00 billion aggregate principal amount of 5.35% senior notes due 2036 and $1.00 billion aggregate principal amount of 6.30% senior notes due 2056. The Partnership used the net proceeds to refinance existing indebtedness, including to repay commercial paper and borrowings under its Five-Year Credit Facility.

In January 2026, the Partnership redeemed its $1.00 billion aggregate principal amount of 4.75% senior notes due January 2026 using cash on hand and commercial paper borrowings.

In February 2026, the Partnership redeemed its $600 million aggregate principal amount of 5.625% senior notes due May 2027 using cash on hand and commercial paper borrowings.

Sunoco LP Senior Notes Issuances and Redemption

In March 2025, Sunoco LP issued $1.00 billion aggregate principal amount of 6.25% senior notes due 2033 in a private offering. These notes will mature on July 1, 2033 and interest is payable semi-annually on January 1 and July 1 of each year. Sunoco LP used the net proceeds from the private offering to repay its $600 million aggregate principal amount of

5.75% senior notes due 2025 and to repay a portion of the outstanding borrowings under Sunoco LP’s revolving credit facility.

In September 2025, Sunoco LP issued $1.00 billion aggregate principal amount of 5.625% senior notes due 2031 and $900 million aggregate principal amount of 5.875% senior notes due 2034 in a private offering. These notes will mature on March 15, 2031 and March 15, 2034, respectively, and interest is payable semi-annually on March 15 and September 15 of each year, commencing on March 15, 2026. Sunoco LP used the net proceeds from this private offering (i) on the closing date of the Parkland acquisition to fund a portion of the cash consideration for the Parkland acquisition and related transaction costs, with the remaining proceeds used for general corporate purposes, and (ii) prior to the closing date of the Parkland acquisition, to temporarily reduce the borrowings outstanding under its revolving credit facility and to pay interest and fees in connection therewith.

The 5.625% senior notes due 2031 and 5.875% senior notes due 2034 were originally subject to a special mandatory redemption requirement, which was eliminated upon closing of the Parkland acquisition.

Sunoco LP Parkland Senior Note Exchange

In October 2025, in connection with Sunoco LP’s Parkland acquisition, Sunoco LP commenced a private offering to exchange up to C$1.60 billion Canadian dollar denominated notes issued by Parkland (collectively, the “PKI CAD Notes”) and up to $2.60 billion U.S. dollar denominated notes issued by Parkland (collectively, the “PKI USD Notes”) for new notes issued by the Partnership. The exchange offer closed on November 7, 2025, with approximately C$1.47 billion of the PKI CAD Notes and approximately $2.58 billion of the PKI USD Notes being validly tendered and not validly withdrawn.

USAC Senior Notes Issuance and Redemption

In September 2025, USAC issued $750 million aggregate principal amount of 6.250% senior notes due 2033. USAC used the net proceeds from this issuance, together with borrowings under USAC’s credit facility, to redeem its $750 million aggregate principal amount of 6.875% senior notes due 2027 in October 2025.

Sunoco LP GoZone Bonds

Sunoco LP’s obligations also include revenue bonds issued by the Parish of St. James, Louisiana pursuant to the Gulf Opportunity Zone Act of 2005 (the “GoZone Bonds”).

As reflected in the table below, the holders of the Series 2008, Series 2010B and Series 2011 GoZone Bonds are required to tender their bonds at the applicable mandatory purchase date in exchange for 100% of the principal plus accrued and unpaid interest, after which these bonds are expected to be remarketed with a new interest rate established. Each of the Series 2010 and Series 2010A GoZone Bonds is subject to redemption on or after June 1, 2030 by the Parish of St. James, at our option, in whole or in part, at a redemption price of 100% of the principal amount to be redeemed plus accrued and unpaid interest. Interest on the GoZone Bonds is payable semi-annually on June 1 and December 1 of each year.

The following table summarizes the GoZone Bonds outstanding as of December 31, 2025:

Series

Date Issued

Amount Outstanding

Interest Rate

Mandatory Purchase Date

Original Redemption Date

Maturity Date

Series 2008

June 26, 2008

6.10

June 1, 2030

n/a

June 1, 2038

Series 2010

July 15, 2010

100

6.35

n/a

June 1, 2030

July 1, 2040

Series 2010A

October 7, 2010

6.35

n/a

June 1, 2030

October 1, 2040

Series 2010B

December 29, 2010

6.10

June 1, 2030

n/a

December 1, 2040

Series 2011

October 1, 2025

3.70

June 1, 2030

n/a

August 1, 2041

During 2025, the Sunoco LP completed the remarketing of $75 million principal amount of Series 2011 GoZone Bonds, which were previously repurchased on the mandatory purchase date of June 1, 2025 but were not remarketed at that time. The remarketed bonds were issued on October 1, 2025 and have a 3.70% interest rate, a mandatory purchase date of June 1, 2030, and a maturity of August 1, 2041.

Sunoco LP’s agreements with the Parish of St. James related to the GoZone Bonds contain: (i) customary restrictive covenants that limit the ability of Sunoco LP and its subsidiaries to, among other things, create liens, enter into certain sale leaseback transactions, and engage in certain consolidations, mergers or asset sales; and (ii) a repurchase provision which provides that if Sunoco LP undergoes a change of control that is followed by a ratings decline that occurs within 60 days of the change of control, then each holder may require the trustee, with funds provided by Sunoco LP, to repurchase all or a

portion of that holder’s GoZone Bonds at a price equal to 101% of the aggregate principal amount repurchased, plus any accrued and unpaid interest.

Credit Facilities and Commercial Paper

Five-Year Credit Facility

The Partnership’s Five-Year Credit Facility allows for unsecured borrowings up to $5.00 billion until April 11, 2027, and, following the Partnership’s exercise of its option to extend the maturity date on December 18, 2024, up to $4.84 billion until April 11, 2029. The Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $7.00 billion under certain conditions.

As of December 31, 2025, the Five-Year Credit Facility had $2.86 billion of outstanding borrowings, of which $2.57 billion consisted of commercial paper. The amount available for future borrowings was $2.12 billion, after accounting for outstanding letters of credit in the amount of $21 million. The weighted average interest rate on the total amount outstanding as of December 31, 2025 was 4.00%.

Sunoco LP Credit Facility

Sunoco LP maintains a $2.50 billion revolving credit facility, which matures on June 17, 2030 (the “Sunoco LP Credit Facility”), which date may be extended in accordance with the terms of Sunoco LP’s revolving credit facility. Sunoco LP’s revolving credit facility can be increased from time to time upon Sunoco LP’s written request, subject to certain conditions, up to an aggregate amount of $3.50 billion. As of December 31, 2025, the Sunoco LP Credit Facility had no outstanding borrowings and $26 million in standby letters of credit. The amount available for future borrowings was $2.47 billion at December 31, 2025. The weighted average interest rate on the total amount outstanding as of December 31, 2025 was 6.38%.

Sunoco LP Receivables Financing Agreement

Upon the closing of the NuStar acquisition, the commitments under NuStar’s receivables financing agreement were reduced to zero during a suspension period, for which the period end has not been determined. As of December 31, 2025, this facility had no outstanding borrowings.

Sunoco LP Lease-Related Financing Obligations

Southside Oil, LLC, a subsidiary of Sunoco LP, is a party to a sale leaseback transaction that did not meet the criteria for sale leaseback accounting. This transaction was accounted for as a financing arrangement over the course of the lease agreement. The obligations mature in varying dates through 2058, require monthly interest and principal payments, and bear interest at 11.865%. As of December 31, 2025 and 2024, the balance of the sale leaseback financing obligation were $145 million and $85 million, respectively.

Lease-related financing obligations also include finance lease obligations of $87 million and $47 million as of December 31, 2025 and 2024, respectively.

USAC Credit Facility

USAC maintains a $1.75 billion revolving credit facility (the “USAC Credit Facility”) which matures on August 27, 2030, except that if more than $50 million principal amount of USAC’s existing 7.125% senior notes due 2029 are outstanding on December 14, 2028, its credit facility will mature on December 14, 2028. As of December 31, 2025, USAC had $795 million of outstanding borrowings and $1 million in outstanding letters of credit under the credit agreement. As of December 31, 2025, USAC had $954 million of remaining unused availability, all of which was available to be drawn. The weighted average interest rate on the total amount outstanding as of December 31, 2025 was 5.74%.

Covenants Related to Our Credit Agreements

The agreements relating to the senior notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.

The Five-Year Credit Facility contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things:

•incur indebtedness;

•grant liens;

•enter into mergers;

•dispose of assets;

•make certain investments;

•make Distributions (as defined in the Five-Year Credit Facility) during certain Defaults (as defined in the Five-Year Credit Facility) and during any Event of Default (as defined in the Five-Year Credit Facility);

•engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;

•engage in transactions with affiliates; and

•enter into restrictive agreements.

The applicable margin and rate used in connection with the interest rates and commitment fees, respectively, are based on the credit ratings assigned to our senior, unsecured, non-credit enhanced long-term debt. The applicable margin for eurodollar rate loans under the Five-Year Credit Facility ranges from 1.125% to 2.000% and the applicable margin for base rate loans ranges from 0.125% to 1.000%. The applicable rate for commitment fees under the Five-Year Credit Facility ranges from 0.125% to 0.300%.

The Five-Year Credit Facility contains various covenants including limitations on the creation of indebtedness and liens and related to the operation and conduct of our business. The Five-Year Credit Facility also limits us, on a rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the underlying credit agreement, of 5.00 to 1.00, which can generally be increased to 5.50 to 1.00 during a Specified Acquisition Period. Our Leverage Ratio was 3.21 to 1.00 at December 31, 2025, as calculated in accordance with the credit agreement.

Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Partnership’s or our subsidiaries’ ability to incur additional debt and/or our ability to pay distributions to Unitholders.

Covenants Related to Transwestern

The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.

Covenants Related to Sunoco LP

The Sunoco LP Credit Facility contains various customary representations, warranties, covenants and events of default, including a change of control event of default, as defined therein. Sunoco LP’s Credit Facility requires Sunoco LP to maintain a specified net leverage ratio and interest coverage ratio.

Covenants Related to USAC

The USAC Credit Facility contains covenants that limit (subject to certain exceptions) USAC’s ability to, among other things:

•grant liens;

•make certain loans or investments;

•incur additional indebtedness or guarantee other indebtedness;

•enter into transactions with affiliates;

•merge or consolidate;

•sell our assets; and

•make certain acquisitions.

The USAC Credit Facility is also subject to the following financial covenants, including covenants requiring USAC to maintain:

•a minimum EBITDA to interest coverage ratio;

•a ratio of total secured indebtedness to EBITDA within a specified range; and

•a maximum funded debt to EBITDA ratio.

Compliance with our Covenants

Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities and note agreements could require us or our subsidiaries to pay debt balances prior to scheduled maturity and could negatively impact the subsidiaries ability to incur additional debt and/or our ability to pay distributions.

We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2025.

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.

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 8A
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-8A

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(c))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 6
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481544/470-10-50-6

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 6
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481544/470-10-50-6

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 405
-SubTopic 40
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477092/405-40-50-1

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 405
-SubTopic 40
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)(3)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477092/405-40-50-1

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 405
-SubTopic 40
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477092/405-40-50-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 405
-SubTopic 40
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477092/405-40-50-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 405
-SubTopic 40
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477092/405-40-50-1

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Subparagraph (h)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1B

Reference 12: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 470
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org/470/tableOfContent

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 835
-SubTopic 30
-Name Accounting Standards Codification
-Section 45
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482925/835-30-45-2

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1B

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Subparagraph (g)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1B

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Subparagraph (i)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1B

Reference 17: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1C
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1C

Reference 18: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1C
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1C

Reference 19: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1C
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1C

Reference 20: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1E
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1E

Reference 21: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1I
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1I

Reference 22: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1I
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1I

Reference 23: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1I
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1I

Revenue from Contract with Customer [Abstract]

Revenue

12 Months Ended

Dec. 31, 2025

Revenue

REVENUE:

Disaggregation of revenue

The major types of revenue within our reportable segments are as follows:

•intrastate transportation and storage;

•interstate transportation and storage;

•midstream;

•NGL and refined products transportation and services;

•crude oil transportation and services;

•investment in Sunoco LP;

◦fuel distribution;

◦pipeline systems; and

◦terminals

•investment in USAC;

◦contract operations; and

◦retail parts and services; and

•all other.

Note 16 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606.

Intrastate transportation and storage revenue

Our intrastate transportation and storage segment’s revenues are determined primarily by the volume of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected or withdrawn into or out of our storage facilities. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity they transport or store. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected/withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject/withdraw into or out of our storage facilities. Payment for services under these contracts are typically due the month after the services have been performed.

The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.

The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.

Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead.

Interstate transportation and storage revenue

Our interstate transportation and storage segment’s revenues are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected into or withdrawn out of our storage facilities. Our interstate transportation and storage segment’s contracts can be firm or interruptible. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity transported or stored. In exchange for such fees, we must stand ready to perform a contractually agreed-upon minimum volume of services whenever the customer requests such services. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected or withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject into or withdraw out of our storage facilities. Consequently, we are not required to stand ready to provide any contractually agreed-upon volume of service, but instead provides the services based on existing capacity at the time the customer requests the services. Payment for services under these contracts are typically due the month after the services have been performed.

The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.

Lake Charles LNG’s revenues are primarily derived from terminalling services for shippers by receiving LNG at the facility for storage and delivering such LNG to shippers, either in liquid state or gaseous state after regasification. Lake Charles LNG derives all of its revenue from a series of long-term contracts with a wholly owned subsidiary of Royal Dutch Shell plc (“Shell”). Terminalling revenue is generated from fees paid by Shell for storage and other associated services at the terminal. Payment for services under these contracts are typically due the month after the services have been performed.

The terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volumes transported by Shell or services provided at the terminal.

The performance obligation with respect to firm contracts is a promise to provide a single type of service (terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.

Midstream revenue

Our midstream segment’s revenues are derived primarily from margins we earn for natural gas volumes that are gathered, processed and/or transported. The various types of revenue contracts our midstream segment enters into include:

Fixed fee gathering and processing: Contracts under which we provide gathering and processing services in exchange for a fixed cash fee per unit of volume. Revenue for cash fees is recognized when the service is performed.

Keepwhole: Contracts under which we gather raw natural gas from a third-party producer, process the gas to convert it to pipeline quality natural gas, and redeliver to the producer a thermal-equivalent volume of pipeline quality natural gas. In exchange for these services, we retain the NGLs extracted from the raw natural gas received from the producer as well as cash fees paid by the producer. The value of NGLs retained as well as cash fees is recognized as revenue when the services are performed.

Percent of Proceeds (“POP”): Contracts under which we provide gathering and processing services in exchange for a specified percentage of the producer’s commodity (“POP percentage”) and also in some cases additional cash fees. The two types of POP revenue contracts are described below:

•In-Kind POP: We retain our POP percentage (non-cash consideration) and also any additional cash fees in exchange for providing the services. We recognize revenue for the non-cash consideration and cash fees at the time the services are performed.

•Mixed POP: We purchase NGLs from the producer and retain a portion of the residue gas as non-cash consideration for services provided. We may also receive cash fees for such services. Under Topic 606, these agreements were determined to be hybrid agreements which were partially supply agreements (for the NGLs we purchased) and customer agreements (for the services provided related to the product that was returned to the customer). Given that these are hybrid agreements, we split the cash and non-cash consideration between revenue and a reduction of costs based on the value of the service provided vs. the value of the supply received.

Payment for services under these contracts are typically due the month after the services have been performed.

The performance obligations with respect to our midstream segment’s contracts are to provide gathering, transportation and processing services, each of which would be completed on or about the same time, and each of which would be recognized on the same line item on the income statement, therefore identification of separate performance obligations would not impact the timing or geography of revenue recognition.

Certain contracts of our midstream segment include throughput commitments under which customers commit to purchasing a certain minimum volume of service over a specified time period. If such volume of service is not purchased by the customer, deficiency fees are billed to the customer. In some cases, the customer is allowed to apply any deficiency fees paid to future purchases of services. In such cases, we defer revenue recognition until the customer uses the deficiency fees for services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints.

Our midstream segment also generates revenues from the sale of residue gas and NGLs at the tailgate of our processing facilities primarily to affiliates and some third-party customers.

NGL and refined products transportation and services revenue

Our NGL and refined products transportation and services segment’s revenues are primarily derived from transportation, fractionation, blending and storage of NGL and refined products as well as acquisition and marketing activities. Revenues are generated utilizing a complementary network of pipelines, storage and blending facilities, and strategic offtake locations that provide access to multiple NGL markets. Transportation, fractionation and storage revenue is generated from fees charged to customers under a combination of firm and interruptible contracts. Firm contracts are in the form of take-or-pay arrangements where certain fees will be charged to customers regardless of the volume of service they request for any given period. Under interruptible contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of service provided for any given period. Payment for services under these contracts are typically due the month after the services have been performed.

The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation, fractionation, blending, or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.

Crude oil transportation and services revenue

Our crude oil transportation and services segment’s revenues are primarily derived from providing transportation, terminalling and acquisition and marketing services to crude oil markets throughout the Southwest, Midwest and Northeast United States. Crude oil transportation revenue is generated from tariffs paid by shippers utilizing our transportation services and is generally recognized as the related transportation services are provided. Crude oil terminalling revenue is generated from fees paid by customers for storage and other associated services at the terminal. Crude oil acquisition and marketing revenue is generated from sale of crude oil acquired from a variety of suppliers to third parties. Payment for services under these contracts are typically due the month after the services have been performed.

Certain transportation and terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volume of crude oil transported by the customer or services provided at the terminal. For these agreements, any fixed fees billed in excess of services provided are not recognized as revenue until the earlier of (i) the time at which the customer applies the fees against cost of service provided in a later period, or (ii) the customer becomes unable to apply the fees against cost of future service due to capacity constraints or contractual terms.

The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the

transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.

The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and/or product and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.

Sunoco LP’s fuel distribution revenue

Revenues from Sunoco LP’s fuel distribution segment are derived from the sale of fuel, non-fuel and lease income. Fuel sales consist primarily of the sale of motor fuel under supply agreements with third-party customers and affiliates. Fuel supply contracts with Sunoco LP’s customers generally provide that it distributes motor fuel at a price based on a formula which includes published rates, volume-based profit margin and other terms specific to the agreement. The customer is invoiced the agreed-upon price with most payment terms ranging less than 30 days. If the consideration promised in a contract includes a variable amount, Sunoco LP estimates the variable consideration amount and factors in such estimate to determine the transaction price under the expected value method. Revenue is recognized under the motor fuel contracts at the point in time the customer takes control of the fuel. At the time control is transferred to the customer the sale is considered final, because the agreements do not grant customers the right to return motor fuel. To determine when control transfers to the customer, the shipping terms of the contract are assessed as a primary indicator of the transfer of control. For free on board ("FOB") shipping point terms, revenue is recognized at the time of shipment. The performance obligation with respect to the sale of goods is satisfied at the time of shipment since the customer gains control at this time under the terms. Shipping and/or handling costs that occur before the customer obtains control of the goods are deemed to be fulfillment activities and are accounted for as fulfillment costs. Once the goods are shipped, Sunoco LP is precluded from redirecting the shipment to another customer and revenue is recognized. Non-fuel revenue includes merchandise revenue that comprises the in-store merchandise and food service sales at company-operated retail stores and other revenue such as credit card processing, car washes, lottery and other services. Lease revenue is derived from the leasing or subleasing of real estate used in the retail distribution of motor fuels.

Sunoco LP’s pipeline systems revenue

Revenues from Sunoco LP’s pipeline systems segment are derived from interstate and intrastate pipeline transportation of refined products, crude oil and anhydrous ammonia and the applicable pipeline tariff on a per barrel basis for crude oil or refined products and on a per ton basis for ammonia.

Sunoco LP’s terminals revenue

Revenues from Sunoco LP’s terminals segment include fees for tank storage agreements, under which a customer agrees to pay for a certain amount of storage in a tank over a period of time (storage terminal revenues) and throughput agreements, under which a customer pays a fee per barrel for volumes moving through Sunoco LP’s terminals (throughput terminal revenues). Sunoco LP’s terminals also provide blending, additive injections, handling and filtering services for which Sunoco LP charges additional fees. Additionally, Sunoco LP leases certain of its storage tanks in exchange for a fixed fee, subject to an annual consumer price index adjustment.

Sunoco LP’s refinery revenue

Revenues from Sunoco LP’s refinery segment are derived from refined products, generated environmental compliance credits and excess crude oil sales are recognized when delivered and the customer obtains control of such inventory, which is typically when title passes and the customer is billed. All revenues are reported inclusive of shipping and handling costs billed and exclusive of any sales taxes billed to customers where applicable. Shipping and handling costs incurred are reported in cost of sales.

USAC’s contract operations revenue

USAC’s revenue from contracted compression, natural gas treating and maintenance services is recognized ratably under its fixed-fee contracts over the term of the contract as services are provided to its customers. Initial contract terms typically range from six months to five years; however, USAC usually continues to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. USAC primarily enters into fixed-fee contracts whereby its customers are required to pay the monthly fee even during periods of limited or disrupted throughput. Services are generally billed monthly, one month in advance of the commencement of the

service month, except for certain customers who are billed at the beginning of the service month, and payment is generally due 30 days after receipt of the invoice. Amounts invoiced in advance are recorded as deferred revenue until earned, at which time they are recognized as revenue. The amount of consideration USAC receives and revenue it recognizes is based upon the fixed fee rate stated in each service contract.

Variable consideration exists in select contracts when billing rates vary based on actual equipment availability or volume of total installed horsepower.

USAC’s contracts with customers may include multiple performance obligations. For such arrangements, USAC allocates revenues to each performance obligation based on its relative standalone service fee. USAC generally determines standalone service fees based on the service fees charged to customers or using expected cost plus margin.

The majority of USAC’s service performance obligations are satisfied over time as services are rendered at selected customer locations on a monthly basis and based upon specific performance criteria identified in the applicable contract. The monthly service for each location is substantially the same service month to month and is promised consecutively over the service contract term. USAC measures progress and performance of the service consistently using a straight-line, time-based method as each month passes, because its performance obligations are satisfied evenly over the contract term as the customer simultaneously receives and consumes the benefits provided by its service. If variable consideration exists, it is allocated to the distinct monthly service within the series to which such variable consideration relates. USAC has elected to apply the invoicing practical expedient to recognize revenue for such variable consideration, as the invoice corresponds directly to the value transferred to the customer based on its performance completed to date.

There are typically no material obligations for returns or refunds. USAC’s standard contracts do not usually include material non-cash consideration.

USAC’s retail parts and services revenue

USAC’s retail parts and services revenue is primarily earned on directly reimbursable freight and crane charges that are the financial responsibility of USAC’s customers and maintenance work on units at its customers’ locations that are outside the scope of its core maintenance activities. Revenue from retail parts and services is recognized at the point in time the part is transferred or service is provided and control is transferred to the customer. At such time, the customer has the ability to direct the use of the benefits of such part or service after USAC has performed its services. USAC bills upon completion of the service or transfer of the parts, and payment is generally due 30 days after receipt of the invoice. The amount of consideration USAC receives and revenue it recognizes is based on the invoice amount. There are typically no material obligations for returns, refunds, or warranties. USAC’s standard contracts do not usually include material variable or non-cash consideration.

All other revenue

Our all other segment primarily includes our compression equipment business which provides full-service compression design and manufacturing services for the oil and gas industry. It also includes the management of coal and natural resources properties and the related collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities and collecting oil and gas royalties. These operations also include end-user coal handling facilities.

Contract Balances with Customers

The Partnership satisfies its obligations by transferring goods or services in exchange for consideration from customers. The timing of performance may differ from the timing the associated consideration is paid to or received from the customer, thus resulting in the recognition of a contract asset or a contract liability.

The Partnership recognizes a contract asset when making upfront consideration payments to certain customers or when providing services to customers prior to the time at which the Partnership is contractually allowed to bill for such services.

The Partnership recognizes a contract liability if the customer’s payment of consideration precedes the Partnership’s fulfillment of the performance obligations. Certain contracts contain provisions requiring customers to pay a fixed minimum fee, but allows customers to apply such fees against services to be provided at a future point in time. These amounts are reflected as deferred revenue until the customer applies the deficiency fees to services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. Additionally, Sunoco LP maintains some franchise agreements requiring dealers to make one-time upfront payments for long-term license agreements. Sunoco LP recognizes a contract liability when the upfront payment is received and recognizes revenue over the term of the license.

The following table summarizes the consolidated activity of our contract liabilities:


	Contract Liabilities
Balance, December 31, 2023	$	749
Additions	1,256
Revenue recognized	(1,246)

Balance, December 31, 2024	759
Additions	478
Parkland acquisition by Sunoco LP	84
Revenue recognized	(576)

Balance, December 31, 2025	$	745

The balances of Sunoco LP’s contract assets and contract liabilities as of December 31, 2025, 2024 and 2023 were as follows:


	December 31,
	2025		2024		2023
Contract Balances
Contract assets	$	480	$	288	$	256
Accounts receivable from contracts with customers	1,686		1,084		809
Contract liabilities	125		39		—

Costs to Obtain or Fulfill a Contract

Sunoco LP recognizes an asset from the costs incurred to obtain a contract (e.g. sales commissions) only if it expects to recover those costs. On the other hand, the costs to fulfill a contract are capitalized if the costs are specifically identifiable to a contract, would result in enhancing resources that will be used in satisfying performance obligations in the future and are expected to be recovered. These capitalized costs are recorded as a part of other current assets and other non-current assets and are amortized on a systematic basis consistent with the pattern of transfer of the goods or services to which such costs relate. The amount of amortization expense that Sunoco LP recognized for the years ended December 31, 2025, 2024 and 2023 was $41 million, $35 million and $29 million, respectively. Sunoco LP has also made a policy election of expensing the costs to obtain a contract, as and when they are incurred, in cases where the expected amortization period is one year or less.

Performance Obligations

At contract inception, the Partnership assesses the goods and services promised in its contracts with customers and identifies a performance obligation for each promise to transfer a good or service (or bundle of goods or services) that is distinct. To identify the performance obligations, the Partnership considers all the goods or services promised in the contract, whether explicitly stated or implied based on customary business practices. For a contract that has more than one performance obligation, the Partnership allocates the total contract consideration it expects to be entitled to, to each distinct performance obligation based on a standalone-selling price basis. Revenue is recognized when (or as) the performance obligations are satisfied, that is, when the customer obtains control of the good or service. Certain of our contracts contain variable components, which, when combined with the fixed component are considered a single performance obligation. For these types of contracts, only the fixed component of the contracts are included in the following table.

Sunoco LP distributes fuel under long-term contracts to branded distributors, branded and unbranded third-party dealers, and branded and unbranded retail fuel outlets. Sunoco LP branded supply contracts with distributors generally have both time and volume commitments that establish contract duration. These contracts have an initial term of approximately ten years, with an estimated volume-weighted term remaining of approximately five years.

Sunoco LP is party to a 15-year take-or-pay fuel supply agreement in which the distributor is required to purchase a volume of fuel that provides Sunoco LP a minimum amount of gross profit annually. Sunoco LP expects to recognize this revenue in accordance with the contract as Sunoco LP transfers control of the product to the customer. However, in case of annual shortfall, Sunoco LP will recognize the amount payable by the distributor at the sooner of the time at which the distributor makes up the shortfall or becomes contractually or operationally unable to do so. The transaction price of the

contract is variable in nature, fluctuating based on market conditions. The Partnership has elected to take the practical expedient not to estimate the amount of variable consideration allocated to wholly unsatisfied performance obligations.

In some contractual arrangements, Sunoco LP grants dealers a franchise license to operate Sunoco LP’s retail stores over the life of a franchise agreement. In return for the grant of the retail store license, the dealer makes a one-time nonrefundable franchise fee payment to Sunoco LP plus sales based royalties payable to Sunoco LP at a contractual rate during the period of the franchise agreement. Under the requirements of ASC Topic 606, the franchise license is deemed to be a symbolic license for which recognition of revenue over time is the most appropriate measure of progress toward complete satisfaction of the performance obligation. Revenue from this symbolic license is recognized evenly over the life of the franchise agreement.

As of December 31, 2025, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations was $33.61 billion, and the Partnership expects to recognize this amount as revenue within the time bands illustrated below:


	Years Ending December 31,
	2026		2027		2028		Thereafter		Total
Revenue expected to be recognized on contracts with customers existing as of December 31, 2025	$	7,895	$	6,379	$	4,808	$	14,523	$	33,605

Practical Expedients Utilized by the Partnership

The Partnership elected the following practical expedients in accordance with Topic 606:

•Right to invoice: The Partnership elected to utilize an output method to recognize revenue that is based on the amount to which the Partnership has a right to invoice a customer for services performed to date, if that amount corresponds directly with the value provided to the customer for the related performance or its obligation completed to date. As such, the Partnership recognized revenue in the amount to which it had the right to invoice customers.

•Significant financing component: The Partnership elected not to adjust the promised amount of consideration for the effects of significant financing component if the Partnership expects, at contract inception, that the period between the transfer of a promised good or service to a customer and when the customer pays for that good or service will be one year or less.

•Unearned variable consideration: The Partnership elected to only disclose the unearned fixed consideration associated with unsatisfied performance obligations related to our various customer contracts which contain both fixed and variable components.

•Incremental costs of obtaining a contract: The Partnership generally expenses sales commissions when incurred because the amortization period would have been less than one year. We record these costs within general and administrative expenses. The Partnership elected to expense the incremental costs of obtaining a contract when the amortization period for such contracts would have been one year or less.

•Shipping and handling costs: The Partnership elected to account for shipping and handling activities that occur after the customer has obtained control of a good as fulfillment activities (i.e., an expense) rather than as a promised service.

•Measurement of transaction price: The Partnership has elected to exclude from the measurement of transaction price all taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction and collected by the Partnership from a customer (i.e., sales tax, value added tax, etc.).

•Variable consideration of wholly unsatisfied performance obligations: The Partnership has elected to exclude the estimate of variable consideration to the allocation of wholly unsatisfied performance obligations.

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.

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 7
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-7

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 9
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-9

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 10
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-10

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 15
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-15

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (b)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-13

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Name Accounting Standards Codification
-Topic 606
-Publisher FASB
-URI https://asc.fasb.org/606/tableOfContent

Estimates (Schedule Of Goodwill) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Goodwill [Roll Forward]
Goodwill	$ 3,903	$ 4,019
Goodwill, Acquired During Period	1,528	16
Goodwill	5,452	3,903
Goodwill, Other Changes	21	6
Goodwill, Written off Related to Sale of Business Unit		(138)
Midstream
Goodwill [Roll Forward]
Goodwill	617	601
Goodwill, Acquired During Period	0	0
Goodwill	617	617
Goodwill, Other Changes	0	16
Goodwill, Written off Related to Sale of Business Unit		0
NGL and Refined Products Transportation and Services
Goodwill [Roll Forward]
Goodwill	886	884
Goodwill, Acquired During Period	0	0
Goodwill	886	886
Goodwill, Other Changes	0	2
Goodwill, Written off Related to Sale of Business Unit		0
Crude Oil Transportation and Services
Goodwill [Roll Forward]
Goodwill	841	853
Goodwill, Acquired During Period	0	0
Goodwill	841	841
Goodwill, Other Changes	0	(12)
Goodwill, Written off Related to Sale of Business Unit		0
Investment in Sunoco LP
Goodwill [Roll Forward]
Goodwill	1,477	1,599
Goodwill, Acquired During Period	1,528	16
Goodwill	3,026	1,477
Goodwill, Other Changes	21	0
Goodwill, Written off Related to Sale of Business Unit		(138)
All Other
Goodwill [Roll Forward]
Goodwill	82	82
Goodwill, Acquired During Period	0	0
Goodwill	82	82
Goodwill, Other Changes	$ 0	0
Goodwill, Written off Related to Sale of Business Unit		$ 0

Retirement Benefits (Accumulated Benefit Obligation In Excess of Plan Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation		$ 158	$ 23
Fair value of plan assets		182
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	$ 131	127	138
Fair value of plan assets	321	295	277
Funded Plans [Member] \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	0	22
Accumulated benefit obligation	0	158
Fair value of plan assets	28	182	22
Unfunded Plans [Member] \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	15	16
Accumulated benefit obligation	15	16	17
Fair value of plan assets	$ 0	$ 0	$ 0

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (k)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (i)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (l)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (g)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (j)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (j)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (j)(4)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (j)(3)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (c)(iv)(02)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (c)(ii)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 7
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-7

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (q)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (m)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 17: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (h)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 18: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (f)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 19: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 20: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Amount of asset segregated and restricted to provide benefit under defined benefit plan. Asset includes, but is not limited to, stock, bond, other investment, earning from investment, and contribution by employer and employee.

Reference 1: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (c)(ii)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 3: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (c)(iv)(01)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (c)(iv)(01)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (c)(ii)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 6: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 17
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480482/715-20-55-17

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(iv)(02)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(ii)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(iv)(01)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 11: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(ii)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 12: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(iv)(01)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Redeemable Noncontrolling Interest, Equity, Carrying Amount

Redeemable Noncontrolling Interests (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2024

Dec. 31, 2025

Dec. 02, 2025

Jun. 03, 2025

$ 417

$ 250

Convertible Preferred Stock, Shares Issued upon Conversion

80,000

100,000

3,997,700

4,997,126

Crestwood Niobrara preferred units

Proceeds from (Repurchase of) Redeemable Preferred Stock

(37)

USAC Series A preferred units

Redeemable Noncontrolling Interest, Equity, Carrying Amount

169

Crestwood Niobrara preferred units

Redeemable Noncontrolling Interest, Equity, Carrying Amount

225

Redeemable Noncontrolling Interest, Equity, Carrying Amount

^[1]

$ 23

$ 25

[1]	Relates to noncontrolling interest holders in one of the Partnership’s consolidated subsidiaries that have the option to sell their interests to the Partnership.

Income Taxes Components of Net Deferred Tax Liability (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Components of Net Deferred Income Tax [Abstract]
Deferred Income Tax Liabilities, Net	$ 5,307	$ 4,190
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Deferred Income Tax Liabilities, Net	5,307	4,190
Net of deferred income tax receivable
Components of Net Deferred Income Tax [Abstract]
Total deferred income tax assets	518	239
Valuation allowance	(64)	0
Deferred Tax Liabilities, Net	(5,130)	(4,183)
Net deferred income tax assets	454	239
Deferred Income Tax Liabilities, Net	5,130	4,183	$ 3,931
Increase (Decrease) in Deferred Liabilities	(192)	(249)
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Deferred Income Tax Liabilities, Net	5,130	4,183	$ 3,931
Increase (Decrease) in Deferred Liabilities	192	249
Net operating losses and other carryforwards	443	197
Other	75	42
Total deferred income tax assets	518	239
Valuation allowance	64	0
Net deferred income tax assets	454	239
Property, plant and equipment	(1,083)	(224)
Investments in affiliates	(4,200)	(4,098)
Trademarks	(240)	(82)
Other	(61)	(18)
Deferred Tax Liabilities, Gross	(5,584)	(4,422)
Deferred Tax Liabilities, Net	5,130	4,183
Parkland Acquisition [Member] \| Net of deferred income tax receivable
Components of Net Deferred Income Tax [Abstract]
Increase (Decrease) in Deferred Liabilities	(755)	0
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Increase (Decrease) in Deferred Liabilities	755	0
NuStar Acquisition \| Net of deferred income tax receivable
Components of Net Deferred Income Tax [Abstract]
Increase (Decrease) in Deferred Liabilities	0	(3)
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Increase (Decrease) in Deferred Liabilities	$ 0	$ 3

Reportable Segments (Advances to and investments in affiliates) (Details) - USD ($)
$ in Millions

Dec. 31, 2025

Dec. 31, 2024

Dec. 31, 2023

Intrastate Transportation and Storage

^[1]

$ 3,589

$ 3,266

$ 3,097

Interstate Transportation and Storage

^[1]

151

150

144

^[1]

2,353

2,350

2,179

NGL and Refined Products Transportation and Services

^[1]

130

132

141

^[1]

362

383

390

^[1]

190

193

187

^[1]

342

All Other

Financial Information By Segment

^[1]

$ 61

$ 58

$ 56

[1]	Amounts reflected above exclude Sunoco LP’s investments in the ET-S Permian and J.C. Nolan joint ventures, which are eliminated in consolidation.

Reportable Segments Revenue (Details) $ in Millions	12 Months Ended
Reportable Segments Revenue (Details) $ in Millions	Dec. 31, 2025 USD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Revenue from External Customer [Line Items]
Revenues	$ (85,536)	$ (82,671)	$ (78,586)
Number of Reportable Segments	8
Intersegment Eliminations [Member]
Revenue from External Customer [Line Items]
Revenues	$ (14,847)	(12,336)	(12,308)
Investment in USAC \| Operating Segments
Revenue from External Customer [Line Items]
Revenues	(998)	(950)	(846)
Investment in USAC \| Operating Segments \| External Customers [Member]
Revenue from External Customer [Line Items]
Revenues	(933)	(909)	(824)
Investment in USAC \| Operating Segments \| Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues	(65)	(41)	(22)
All Other \| Operating Segments
Revenue from External Customer [Line Items]
Revenues	(3,909)	(1,747)	(1,798)
All Other \| Operating Segments \| External Customers [Member]
Revenue from External Customer [Line Items]
Revenues	(2,447)	(1,284)	(1,328)
All Other \| Operating Segments \| Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues	(1,462)	(463)	(470)
Crude Oil Transportation and Services \| Operating Segments
Revenue from External Customer [Line Items]
Revenues	(26,478)	(28,539)	(26,536)
Crude Oil Transportation and Services \| Operating Segments \| External Customers [Member]
Revenue from External Customer [Line Items]
Revenues	(26,479)	(28,528)	(26,534)
Crude Oil Transportation and Services \| Operating Segments \| Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues	1	(11)	(2)
NGL and Refined Products Transportation and Services \| Operating Segments
Revenue from External Customer [Line Items]
Revenues	(24,853)	(24,530)	(21,903)
NGL and Refined Products Transportation and Services \| Operating Segments \| External Customers [Member]
Revenue from External Customer [Line Items]
Revenues	(21,183)	(20,981)	(18,413)
NGL and Refined Products Transportation and Services \| Operating Segments \| Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues	(3,670)	(3,549)	(3,490)
Midstream \| Operating Segments
Revenue from External Customer [Line Items]
Revenues	(12,503)	(11,199)	(10,406)
Midstream \| Operating Segments \| External Customers [Member]
Revenue from External Customer [Line Items]
Revenues	(3,356)	(3,283)	(2,911)
Midstream \| Operating Segments \| Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues	(9,147)	(7,916)	(7,495)
Interstate Transportation and Storage \| Operating Segments
Revenue from External Customer [Line Items]
Revenues	(2,445)	(2,296)	(2,375)
Interstate Transportation and Storage \| Operating Segments \| External Customers [Member]
Revenue from External Customer [Line Items]
Revenues	(2,416)	(2,270)	(2,328)
Interstate Transportation and Storage \| Operating Segments \| Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues	(29)	(26)	(47)
Intrastate Transportation and Storage \| Operating Segments
Revenue from External Customer [Line Items]
Revenues	(3,996)	(3,053)	(3,962)
Intrastate Transportation and Storage \| Operating Segments \| External Customers [Member]
Revenue from External Customer [Line Items]
Revenues	(3,544)	(2,750)	(3,222)
Intrastate Transportation and Storage \| Operating Segments \| Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues	(452)	(303)	(740)
Investment in Sunoco LP \| Operating Segments
Revenue from External Customer [Line Items]
Revenues	(25,201)	(22,693)	(23,068)
Investment in Sunoco LP \| Operating Segments \| External Customers [Member]
Revenue from External Customer [Line Items]
Revenues	(25,178)	(22,666)	(23,026)
Investment in Sunoco LP \| Operating Segments \| Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues	$ (23)	$ (27)	$ (42)

Reportable Segments (Tables)

12 Months Ended

Dec. 31, 2025

Reportable Segments [Abstract]

The following tables present financial information by segment:


	Years Ended December 31,
	2025		2024		2023
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	3,544	$	2,750	$	3,222
Intersegment revenues	452		303		740
	3,996		3,053		3,962
Interstate transportation and storage:
Revenues from external customers	2,416		2,270		2,328
Intersegment revenues	29		26		47
	2,445		2,296		2,375
Midstream:
Revenues from external customers	3,356		3,283		2,911
Intersegment revenues	9,147		7,916		7,495
	12,503		11,199		10,406
NGL and refined products transportation and services:
Revenues from external customers	21,183		20,981		18,413
Intersegment revenues	3,670		3,549		3,490
	24,853		24,530		21,903
Crude oil transportation and services:
Revenues from external customers	26,479		28,528		26,534
Intersegment revenues	(1)		11		2
	26,478		28,539		26,536
Investment in Sunoco LP:
Revenues from external customers	25,178		22,666		23,026
Intersegment revenues	23		27		42
	25,201		22,693		23,068
Investment in USAC:
Revenues from external customers	933		909		824
Intersegment revenues	65		41		22
	998		950		846
All other:
Revenues from external customers	2,447		1,284		1,328
Intersegment revenues	1,462		463		470
	3,909		1,747		1,798
Eliminations	(14,847)		(12,336)		(12,308)
Total revenues	$	85,536	$	82,671	$	78,586


	Years Ended December 31,
	2025		2024		2023
Cost of products sold:
Intrastate transportation and storage	$	2,525	$	1,390	$	2,616
Interstate transportation and storage	9		9		6
Midstream	7,391		6,637		6,503
NGL and refined products transportation and services	19,505		19,406		17,049
Crude oil transportation and services	22,465		24,407		23,071
Investment in Sunoco LP	22,409		20,595		21,703
Investment in USAC	148		146		137
All other	3,821		1,709		1,740
Eliminations	(14,778)		(12,324)		(12,284)
Total cost of products sold	$	63,495	$	61,975	$	60,541


	Years Ended December 31,
	2025		2024		2023
Operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses:
Intrastate transportation and storage	$	257	$	246	$	279
Interstate transportation and storage	887		807		746
Midstream	1,784		1,550		1,204
NGL and refined products transportation and services	1,066		957		892
Crude oil transportation and services	927		852		699
Investment in Sunoco LP	873		611		420
Investment in USAC	180		166		147
All other	32		20		40
Eliminations	(208)		(112)		(112)
Total operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses	$	5,798	$	5,097	$	4,315


	Years Ended December 31,
	2025		2024		2023
Depreciation, depletion and amortization:
Intrastate transportation and storage	$	205	$	216	$	214
Interstate transportation and storage	572		575		563
Midstream	1,826		1,719		1,451
NGL and refined products transportation and services	1,029		1,026		915
Crude oil transportation and services	1,014		965		740
Investment in Sunoco LP	688		368		187
Investment in USAC	285		265		246
All other	63		31		69
Total depreciation, depletion and amortization	$	5,682	$	5,165	$	4,385


	Years Ended December 31,
	2025		2024		2023
Selling, general and administrative expenses, excluding non-cash compensation and accretion expenses:
Intrastate transportation and storage	$	46	$	50	$	51
Interstate transportation and storage	121		129		115
Midstream	193		199		199
NGL and refined products transportation and services	172		160		157
Crude oil transportation and services	152		149		120
Investment in Sunoco LP	283		266		113
Investment in USAC	56		54		51
All other	53		62		85
Total selling, general and administrative expenses, excluding non-cash compensation and accretion expenses	$	1,076	$	1,069	$	891


	Years Ended December 31,
	2025		2024		2023
Equity in earnings of unconsolidated affiliates (1) :
Intrastate transportation and storage	$	18	$	16	$	17
Interstate transportation and storage	280		241		260
Midstream	15		13		15
NGL and refined products transportation and services	77		83		76
Crude oil transportation and services	23		21		11
Investment in Sunoco LP	2		—		—

All other	4		5		4
Total equity in earnings of unconsolidated affiliates	$	419	$	379	$	383

(1)Amounts reflected above exclude Sunoco LP’s earnings from the ET-S Permian and J.C. Nolan joint ventures, which are eliminated in consolidation.


	Years Ended December 31,
	2025		2024		2023
Other income (expense) (1) :
Intrastate transportation and storage	$	45	$	(9)	$	95
Interstate transportation and storage	508		477		501
Midstream	29		97		25
NGL and refined products transportation and services	33		172		89
Crude oil transportation and services	8		46		35
Investment in Sunoco LP	411		236		132
Investment in USAC	—		—		1
All other	(3)		35		(8)
Eliminations	(214)		(101)		(11)
Total other income (expense)	$	817	$	953	$	859


	Years Ended December 31,
	2025		2024		2023
Additions to property, plant and equipment (1):
Intrastate transportation and storage	$	1,572	$	118	$	93
Interstate transportation and storage	359		332		383
Midstream	1,616		1,323		832
NGL and refined products transportation and services	1,723		1,424		679
Crude oil transportation and services	90		423		266
Investment in Sunoco LP	651		344		215
Investment in USAC	157		276		300
All other	244		342		100
Total additions to property, plant and equipment	$	6,412	$	4,582	$	2,868


	December 31,
	2025		2024		2023
Investments in unconsolidated affiliates (1):
Intrastate transportation and storage	$	151	$	150	$	144
Interstate transportation and storage	2,353		2,350		2,179
Midstream	130		132		141
NGL and refined products transportation and services	362		383		390
Crude oil transportation and services	190		193		187
Investment in Sunoco LP	342		—		—

All other	61		58		56
Total investments in unconsolidated affiliates	$	3,589	$	3,266	$	3,097

(1)Amounts reflected above exclude Sunoco LP’s investments in the ET-S Permian and J.C. Nolan joint ventures, which are eliminated in consolidation.


	Years Ended December 31,
	2025		2024		2023
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	1,213	$	1,358	$	1,111
Interstate transportation and storage	1,936		1,828		2,009
Midstream	3,164		2,910		2,525
NGL and refined products transportation and services	4,143		4,179		3,894
Crude oil transportation and services	2,942		3,177		2,681
Investment in Sunoco LP	2,047		1,457		964
Investment in USAC	614		584		512
All Other	(75)		(10)		2
Adjusted EBITDA (consolidated)	$	15,984	$	15,483	$	13,698


	Years Ended December 31,
	2025		2024		2023
Reconciliation of net income to Adjusted EBITDA:
Net income	$	5,708	$	6,565	$	5,294
Depreciation, depletion and amortization	5,682		5,165		4,385
Interest expense, net of interest capitalized	3,474		3,125		2,578
Income tax expense	350		541		303
Impairment losses and other	285		52		12
Non-cash compensation expense	148		151		130
Unrealized (gains) losses on commodity risk management activities	(130)		56		(3)
Inventory valuation adjustments (Sunoco LP)	156		86		114
(Gains) losses on extinguishments of debt	34		12		(2)
Adjusted EBITDA related to unconsolidated affiliates	726		692		691
Equity in earnings of unconsolidated affiliates	(419)		(379)		(383)
Non-operating litigation-related loss	—		—		627
Gain on sale of West Texas assets (Sunoco LP)	—		(586)		—
Other, net	(30)		3		(48)
Adjusted EBITDA (consolidated)	$	15,984	$	15,483	$	13,698

Reportable Segments Reportable Segments (Segment Adjusted EBITDA) (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2025

Dec. 31, 2024

Dec. 31, 2023

$ 15,984

$ 15,483

$ 13,698

Interest expense, net of interest capitalized

5,682

5,165

4,385

3,474

3,125

2,578

Non-cash compensation expense

285

148

151

130

Unrealized Gain (Loss) on Derivatives

(130)

(3)

(Gains) losses on extinguishments of debt

(2)

Inventory valuation adjustments

156

114

Adjusted EBITDA related to unconsolidated affiliates

726

692

691

^[1]

(419)

(379)

(383)

Income tax expense (benefit) from continuing operations

(30)

(48)

(350)

(541)

(303)

NET INCOME

5,708

6,565

5,294

Gain (Loss) from Litigation Settlement

627

Intrastate Transportation and Storage

(586)

1,213

1,358

1,111

205

216

214

^[1]

(18)

(16)

(17)

2,047

1,457

964

688

368

187

^[1]

(2)

Investment in USAC

614

584

512

Corporate Segment and Other Operating Segment [Member]

285

265

246

Interstate Transportation and Storage

(75)

(10)

1,936

1,828

2,009

572

575

563

^[1]

(280)

(241)

(260)

3,164

2,910

2,525

1,826

1,719

1,451

NGL and Refined Products Transportation and Services

^[1]

(15)

(13)

(15)

4,143

4,179

3,894

1,029

1,026

915

^[1]

(77)

(83)

(76)

2,942

3,177

2,681

1,014

965

740

Business Combination, Pro Forma Information [Table Text Block]

^[1]

$ (23)

$ (21)

$ (11)

[1]	Amounts reflected above exclude Sunoco LP’s earnings from the ET-S Permian and J.C. Nolan joint ventures, which are eliminated in consolidation.

Acquisitions, Divestitures and Related Transactions (Tables)

12 Months Ended

Dec. 31, 2025

The following unaudited pro forma consolidated results of operations for the year ended December 31, 2025 and 2024 are presented as if the Parkland and NuStar acquisitions and the West Texas Sale had been completed on January 1, 2024.


	Year Ended December 31,
	2025		2024
Revenues	$	101,791	$	103,675
Net income	5,494		5,679

Business Combination, Recognized Asset Acquired and Liability Assumed [Table Text Block]

The following table summarizes the assumed allocation of the purchase price among the assets acquired and liabilities assumed:


	At July 15, 2024
Total current assets	$	334
Property, plant and equipment, net	3,109
Lease right-of-use assets, net	8

Intangible assets, net	20

Total assets	3,471

Total current liabilities	394

Non-current operating lease liabilities	5

Other non-current liabilities	20
Total liabilities	419

Total consideration	3,052
Cash received	45
Total consideration, net of cash received	$	3,007

Business Combination, Recognized Asset Acquired and Liability Assumed [Table Text Block]

The following table summarizes the allocation of the purchase price among the assets acquired and liabilities assumed:


	At November 3, 2023
Total current assets	$	657
Property, plant and equipment, net	4,772
Investments in unconsolidated affiliates	95
Lease right-of-use assets, net	27
Other non-current assets	12
Intangible assets, net	1,139
Goodwill	1,455
Total assets	8,157

Total current liabilities	445
Long-term debt, less current maturities	3,461
Other non-current liabilities	322
Total liabilities	4,228

Noncontrolling interests	272

Total consideration	3,657
Cash received	12
Total consideration, net of cash received	$	3,645

Business Combination, Recognized Asset Acquired and Liability Assumed [Table Text Block]

The following table summarizes the allocation of the purchase price among the assets acquired and liabilities assumed:


	At May 2, 2023
Total current assets	$	61
Property, plant and equipment, net	1,263
Investments in unconsolidated affiliates	138
Lease right-of-use assets, net	10
Other non-current assets	4
Intangible assets, net	75

Total assets	1,551

Total current liabilities	27

Other non-current liabilities	16
Total liabilities	43



Total consideration	1,508
Cash received	4
Total consideration, net of cash received	$	1,504

Business Combination, Recognized Asset Acquired and Liability Assumed [Table Text Block]

The following table summarizes the allocation of the purchase price among assets acquired and liabilities assumed:


	At October 31, 2025
Total current assets	$	2,814
Property, plant and equipment, net	5,612
Investments in unconsolidated affiliates	341
Lease right-of-use assets, net	731
Deferred tax assets	210
Other non-current assets	266
Intangible assets, net (1)	1,871
Goodwill (2)	1,528
Total assets	13,373

Total current liabilities	2,490
Long-term debt, less current maturities	3,797
Non-current operating lease liabilities	731
Deferred income taxes	965
Other non-current liabilities	375
Total liabilities	8,358

Total consideration	5,015
Cash received	464
Total consideration, net of cash received	$	4,551

(1)Intangible assets, net comprised of $1.49 billion of customer relationships, with a remaining weighted average life of approximately 20 years, $297 million of indefinite-lived tradenames and $85 million of other intangibles with a remaining weighted average life of approximately 10 years.

(2)Goodwill represents commercial and operational synergies. Approximately $660 million of the goodwill recorded as a result of this transaction is expected to be deductible for IRC Sec. 951A GILTI and foreign earnings and profits purposes. The goodwill is not deductible for non-US jurisdictions.

Business Combination, Recognized Asset Acquired and Liability Assumed [Table Text Block]

The following table summarizes the assumed allocation of the purchase price among the assets acquired and liabilities assumed:


	At May 3, 2024
Total current assets	$	186
Property, plant and equipment, net	6,958
Lease right-of-use assets, net	136
Goodwill (1)	16
Intangible assets, net (2)	195
Other non-current assets	127
Total assets	7,618

Total current liabilities	245
Long-term debt, less current maturities (3)	3,500
Non-current operating lease liabilities	136
Deferred income taxes	4
Other non-current liabilities	82
Total liabilities	3,967

Preferred units (3)	801

Total consideration	2,850
Cash received	27
Total consideration, net of cash received	$	2,823

(1)Goodwill primarily represents expected commercial and operational synergies. None of the goodwill recorded as a result of this transaction is deductible for tax purposes.

(2)Intangible assets, net comprised of $151 million of favorable contracts, with a remaining weighted average life of approximately 7 years, and $44 million of customer relationships, with a remaining weighted average life of approximately 15 years.

(3)Subsequent to the closing of the NuStar acquisition, Sunoco LP redeemed all outstanding NuStar preferred units totaling $784 million, redeemed NuStar’s subordinated notes totaling $403 million and repaid the outstanding balance on the NuStar credit facility totaling $455 million.

Insider Trading Policies and Procedures	12 Months Ended
Insider Trading Policies and Procedures	Dec. 31, 2025
Insider Trading Policies and Procedures [Line Items]
Insider Trading Policies and Procedures Adopted	true

Revenue Contracts with customers (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Jan. 01, 2019
Contract with Customer, Liability	$ 745	$ 759	$ 749
Additions	478	1,256
Deferred Revenue, Revenue Recognized	(576)	(1,246)
Parkland Acquisition [Member]
Additions	$ 84
Sunoco LP [Member]
Contract with Customer, Liability		39	0	$ 125
Accounts receivable from contracts with customers		1,084	809	1,686
Contract assets		$ 288	$ 256	$ 480

Reportable Segments (Other Income Expense) (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2025

Dec. 31, 2024

Dec. 31, 2023

Intersegment Eliminations [Member]

^[1]

$ 817

$ 953

$ 859

Intrastate Transportation and Storage | Operating Segments

^[1]

(214)

(101)

(11)

Interstate Transportation and Storage | Operating Segments

^[1]

(9)

Midstream | Operating Segments

^[1]

508

477

501

NGL and Refined Products Transportation and Services | Operating Segments

^[1]

Crude Oil Transportation and Services | Operating Segments

^[1]

172

Investment in Sunoco LP | Operating Segments

^[1]

Investment in USAC | Operating Segments

^[1]

411

236

132

Corporate Segment and Other Operating Segment [Member] | Operating Segments

^[1]

^[1]

$ (3)

$ 35

$ (8)

[1]	Other income and expense include, if applicable to a segment, Adjusted EBITDA related to unconsolidated affiliates, unrealized gains and losses on commodity risk management activities and other items. For the investment in Sunoco LP segment, this also includes inventory valuation adjustments.

Retirement Benefits (Benefit Assumptions) (Details)	12 Months Ended
Retirement Benefits (Benefit Assumptions) (Details)	Dec. 31, 2025 Rate	Dec. 31, 2024 Rate
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate	7.49%	7.44%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.18%	5.09%
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.40%	4.80%
Discount rate	5.40%	5.40%
Tax exempt accounts	7.00%	7.00%
Taxable accounts	0.00%	4.26%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.89%	4.40%
Discount rate	4.89%	4.40%
Tax exempt accounts	7.00%	7.00%
Taxable accounts	4.75%	4.75%

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

Acquisitions, Divestitures and Related Transactions

Derivative Assets And Liabilities (Outstanding Commodity-Related Derivatives) (Details)	12 Months Ended
	Dec. 31, 2025 BBtu MW MB_bls	Dec. 31, 2024 BBtu MW MB_bls
Description of Derivative Activity Volume	Forward contracts consisting of 54 million RINs maturing in 2026 and emission credits of 747,038 metric tons maturing through 2042.
Natural Gas [Member] \| Short [Member] \| Fair Value Hedging [Member]
Derivative, Nonmonetary Notional Amount, Volume	(100,346)	(94,340)
Natural Gas [Member] \| Short [Member] \| Mark-To-Market Derivatives [Member]
Derivative, Nonmonetary Notional Amount, Volume	(233,645)	(146,700)
Power [Member] \| Short [Member] \| Mark-To-Market Derivatives [Member]
Derivative, Nonmonetary Notional Amount, Volume \| MW	(461,896)	(151,697)
Crude, NGL and refined products \| Short [Member] \| Mark-To-Market Derivatives [Member]
Derivative, Nonmonetary Notional Amount, Volume \| MB_bls	(59,247)	(39,361)
Other \| Short [Member] \| Mark-To-Market Derivatives [Member]
Derivative, Nonmonetary Notional Amount, Volume		0

Income Taxes - Cash Paid for Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Income Tax Paid, by Individual Jurisdiction [Line Items]
Income Taxes Paid, Net	$ 103	$ 206	$ 103
Cash paid for federal tax credits purchased from non-governmental third parties	97	47	0
TEXAS
Income Tax Paid, by Individual Jurisdiction [Line Items]
Income Taxes Paid, Net	26	14	16
PENNSYLVANIA
Income Tax Paid, by Individual Jurisdiction [Line Items]
Income Taxes Paid, Net			6
NEW JERSEY
Income Tax Paid, by Individual Jurisdiction [Line Items]
Income Taxes Paid, Net		13	6
Other domestic
Income Tax Paid, by Individual Jurisdiction [Line Items]
Income Taxes Paid, Net	12	29	11
CANADA
Income Tax Paid, by Individual Jurisdiction [Line Items]
Income Taxes Paid, Net	62	0	0
Other Foreign
Income Tax Paid, by Individual Jurisdiction [Line Items]
Income Taxes Paid, Net	3	0	0
Federal \| Excluding federal tax credits purchased from non-governmental third parties
Income Tax Paid, by Individual Jurisdiction [Line Items]
Income Taxes Paid, Net	$ 0	$ 150	$ 64

Revenue from Contract with Customer - Performance Obligation (Details) $ in Millions	Dec. 31, 2025 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 33,605
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 7,895
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2026
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 6,379
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2027
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	2 years
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 4,808
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2028
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	3 years
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 14,523
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	4 years

Acquisitions, Divestitures and Related Transactions

12 Months Ended

Dec. 31, 2025

Business Combination [Abstract]

ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:

Terminal Facilities Acquisition

In the third quarter of 2025, Energy Transfer completed the acquisition of two terminal facilities for total cash consideration of approximately $176 million.

WTG Midstream Acquisition

On July 15, 2024, Energy Transfer completed the acquisition of 100% of the membership interest in WTG Midstream. Consideration for the transaction was comprised of $2.28 billion in cash and approximately 50.8 million newly issued Energy Transfer common units, which had a fair value of approximately $833 million.

The acquired assets include approximately 6,000 miles of complementary gas gathering pipelines that extended Energy Transfer’s network in the Midland Basin. Also, as part of the transaction, the Partnership added eight gas processing plants with a total capacity of approximately 1.3 Bcf/d, and two additional processing plants that were under construction at closing. Since closing the transaction, one of these 200 MMcf/d processing plants was placed into service.

The WTG Midstream acquisition was recorded using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their estimated fair values on the date of acquisition with any excess purchase price over the fair value of net assets acquired recorded to goodwill. Determining the fair value of acquired assets requires management’s judgment and the utilization of a third-party valuation specialist, if applicable, and involves the use of significant estimates and assumptions. Acquired assets were valued based on a combination of the discounted cash flow, the guideline company and the reproduction and replacement methods.

The following table summarizes the assumed allocation of the purchase price among the assets acquired and liabilities assumed:


	At July 15, 2024
Total current assets	$	334
Property, plant and equipment, net	3,109
Lease right-of-use assets, net	8

Intangible assets, net	20

Total assets	3,471

Total current liabilities	394

Non-current operating lease liabilities	5

Other non-current liabilities	20
Total liabilities	419

Total consideration	3,052
Cash received	45
Total consideration, net of cash received	$	3,007

Crestwood Acquisition

On November 3, 2023, Energy Transfer acquired Crestwood, which owns gathering and processing assets located in the Williston, Delaware and Powder River basins. Under the terms of the merger agreement, holders of Crestwood common units received 2.07 Energy Transfer common units for each Crestwood common unit held by them (the “Common Unit Merger Consideration”). Additionally, each outstanding Crestwood preferred unit was, at the election of the holder of such Crestwood preferred unit, either, (i) converted into a Series I Preferred Unit, which is a new preferred unit of Energy Transfer that has substantially similar terms, including with respect to economics and structural protections, as the Crestwood preferred units; (ii) redeemed in exchange for $9.857484 in cash plus accrued and unpaid distributions to the date of such redemption; or (iii) converted into a Crestwood common unit at the then-applicable conversion ratio of one Crestwood common unit for ten Crestwood preferred units, and such Crestwood common units then received the Common Unit Merger Consideration.

In total, consideration issued in the transaction included approximately 216 million Energy Transfer common units, 41 million Series I Preferred Units and $300 million in cash. Concurrent with the closing of the Crestwood acquisition, the Partnership assumed $2.85 billion aggregate principal amount of Crestwood senior notes and terminated its revolving credit facility, which included the repayment of $613 million in outstanding borrowings.

The Crestwood acquisition was recorded using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their estimated fair values on the date of acquisition with any excess purchase price over the fair value of net assets acquired recorded to goodwill. Determining the fair value of acquired assets requires management’s judgment and the utilization of an independent valuation specialist, if applicable, and involves the use of significant estimates and assumptions. Acquired assets were valued based on a combination of the discounted cash flow, the guideline company and the reproduction and replacement methods.

The following table summarizes the allocation of the purchase price among the assets acquired and liabilities assumed:


	At November 3, 2023
Total current assets	$	657
Property, plant and equipment, net	4,772
Investments in unconsolidated affiliates	95
Lease right-of-use assets, net	27
Other non-current assets	12
Intangible assets, net	1,139
Goodwill	1,455
Total assets	8,157

Total current liabilities	445
Long-term debt, less current maturities	3,461
Other non-current liabilities	322
Total liabilities	4,228

Noncontrolling interests	272

Total consideration	3,657
Cash received	12
Total consideration, net of cash received	$	3,645

Lotus Midstream Acquisition

On May 2, 2023, Energy Transfer acquired Lotus Midstream for total consideration of $1.50 billion, including working capital. Consideration included $930 million in cash and approximately 44.5 million newly issued Energy Transfer common units, which had an aggregate acquisition-date fair value of $574 million. Lotus Midstream owns and operates Centurion Pipeline Company LLC, an integrated crude midstream platform located in the Permian Basin.

The following table summarizes the allocation of the purchase price among the assets acquired and liabilities assumed:


	At May 2, 2023
Total current assets	$	61
Property, plant and equipment, net	1,263
Investments in unconsolidated affiliates	138
Lease right-of-use assets, net	10
Other non-current assets	4
Intangible assets, net	75

Total assets	1,551

Total current liabilities	27

Other non-current liabilities	16
Total liabilities	43



Total consideration	1,508
Cash received	4
Total consideration, net of cash received	$	1,504

Sunoco LP

Parkland Acquisition

On October 31, 2025, Sunoco LP completed the previously announced acquisition of Parkland whereby Sunoco Retail LLC, a wholly owned corporate subsidiary of Sunoco LP, indirectly acquired all the outstanding shares of Parkland, in exchange for cash and SunocoCorp units that were contributed by SunocoCorp to Sunoco LP at the close of the acquisition. Under the terms of the agreement, Parkland shareholders received 0.295 SunocoCorp units and C$19.80 for each Parkland share. Parkland shareholders could elect, in the alternative, to receive C$44.00 per Parkland share in cash or 0.536 SunocoCorp units for each Parkland share, subject to proration to ensure that the aggregate consideration payable in connection with the transaction would not exceed C$19.80 in cash per Parkland share outstanding as of immediately before close and 0.295 SunocoCorp units per Parkland share outstanding as of immediately before close. In connection with the closing of the Parkland acquisition, Sunoco LP paid approximately $2.6 billion to Parkland’s shareholders and transferred 51,517,198 SunocoCorp common units, which Sunoco LP had received from SunocoCorp in exchange for its issuance of 51,517,198 Class D Units to SunocoCorp.

Parkland is a leading international fuel distributor, marketer and convenience retailer with operations in 26 countries across the Americas. Parkland’s functional currency is the Canadian dollar, and its consolidated structure includes subsidiaries with multiple other functional currencies.

As part of the transaction, Sunoco LP repurposed and renamed an existing subsidiary as SunocoCorp. Prior to the Parkland acquisition, SunocoCorp did not have any significant assets, liabilities or operations; in connection with the Parkland Acquisition, Sunoco LP deconsolidated SunocoCorp and SunocoCorp became a publicly traded entity classified as a corporation for U.S. federal income tax purposes. SunocoCorp’s common units began trading on the New York Stock Exchange effective November 6, 2025. Subsequent to the Parkland acquisition, SunocoCorp holds limited partnership units of Sunoco LP that are generally economically equivalent to Sunoco LP’s publicly traded common units on the basis of one Sunoco LP common unit for each outstanding SunocoCorp unit. For a period of two years following closing of the transaction, Sunoco LP will ensure that SunocoCorp unitholders receive distributions on a per unit basis that are equivalent to the per unit distributions to Sunoco LP unitholders.

The acquisition was recorded using the acquisition method of accounting which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their estimated fair values as of the date of acquisition, with any excess purchase price over the fair value of net assets acquired recorded to goodwill. Determining the fair value of acquired assets requires management’s judgment and the utilization of a third-party valuation specialist, if applicable, and involves the use of significant estimates and assumptions. Acquired assets were valued based on a combination of the discounted cash flow, the guideline company and the reproduction and replacement methods.

As of the date these financial statements were issued, management and the third-party valuation specialist continue to evaluate certain assumptions, which could result in a change to the allocation of the fair value among reporting units or

between line items on the consolidated balance sheet, potentially impacting deferred tax balances and/or goodwill. The following table summarizes the allocation of the purchase price among assets acquired and liabilities assumed:


	At October 31, 2025
Total current assets	$	2,814
Property, plant and equipment, net	5,612
Investments in unconsolidated affiliates	341
Lease right-of-use assets, net	731
Deferred tax assets	210
Other non-current assets	266
Intangible assets, net (1)	1,871
Goodwill (2)	1,528
Total assets	13,373

Total current liabilities	2,490
Long-term debt, less current maturities	3,797
Non-current operating lease liabilities	731
Deferred income taxes	965
Other non-current liabilities	375
Total liabilities	8,358

Total consideration	5,015
Cash received	464
Total consideration, net of cash received	$	4,551

TanQuid Acquisition

On January 16, 2026, Sunoco LP completed the previously announced acquisition of TanQuid for approximately €465 million (approximately $540 million as of January 16, 2026), including approximately €300 million of assumed debt, less approximately €39 million of cash acquired. TanQuid owns and operates 15 fuel terminals in Germany and one fuel terminal in Poland. The transaction was funded using cash on hand and amounts available under Sunoco LP’s credit facility. As of the date of this Form 10-K filing, the initial accounting for this business combination is incomplete due to the timing of the close of the acquisition and therefore has not been included herein.

NuStar Acquisition

On May 3, 2024, Sunoco LP completed the acquisition of all of the common units of NuStar. Under the terms of the merger agreement, NuStar common unitholders received 0.400 Sunoco LP common units for each NuStar common unit. In connection with the acquisition, Sunoco LP issued approximately 51.5 million common units, which had a fair value of approximately $2.85 billion, assumed debt totaling approximately $3.5 billion, including approximately $56 million of lease related financing obligations, and assumed preferred units with a fair value of approximately $800 million. NuStar has approximately 9,500 miles of pipeline and 63 terminal and storage facilities that store and distribute crude oil, refined products, renewable fuels, ammonia and specialty liquids.

The NuStar acquisition was recorded using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their estimated fair values on the date of acquisition with any excess purchase price over the fair value of net assets acquired recorded to goodwill. Determining the fair value of acquired assets requires management’s judgment and the utilization of a third-party valuation specialist, if

applicable, and involves the use of significant estimates and assumptions. Acquired assets were valued based on a combination of the discounted cash flow, the guideline company and the reproduction and replacement methods.

The following table summarizes the assumed allocation of the purchase price among the assets acquired and liabilities assumed:


	At May 3, 2024
Total current assets	$	186
Property, plant and equipment, net	6,958
Lease right-of-use assets, net	136
Goodwill (1)	16
Intangible assets, net (2)	195
Other non-current assets	127
Total assets	7,618

Total current liabilities	245
Long-term debt, less current maturities (3)	3,500
Non-current operating lease liabilities	136
Deferred income taxes	4
Other non-current liabilities	82
Total liabilities	3,967

Preferred units (3)	801

Total consideration	2,850
Cash received	27
Total consideration, net of cash received	$	2,823

(1)Goodwill primarily represents expected commercial and operational synergies. None of the goodwill recorded as a result of this transaction is deductible for tax purposes.

Subsequent to the NuStar acquisition, Sunoco LP purchased a property previously leased by NuStar and cancelled the lease, resulting in an impairment of $50 million based on the value of comparable real property.

Zenith European Terminals Acquisition

On March 13, 2024, Sunoco LP completed the acquisition of liquid fuels terminals in Amsterdam, Netherlands and Bantry Bay, Ireland from Zenith Energy for approximately €170 million ($185 million), including working capital. The acquisition is expected to supply optimization for Sunoco LP’s existing East Coast business and continues its focus on growing its portfolio of stable midstream income. The purchase price was allocated $6 million to other current assets, $204 million to property, plant and equipment, $36 million to other non-current assets and $6 million to deferred tax assets. In connection with this transaction, Sunoco LP also assumed $14 million in current liabilities, $4 million in deferred tax liabilities and $43 million in other non-current liabilities. Sunoco LP also recognized a $6 million bargain purchase gain related to the acquisition.

Other 2025 Acquisitions

In the first quarter of 2025, Sunoco LP acquired fuel equipment, motor fuel inventory and supply agreements in two separate transactions for total consideration of approximately $17 million. Aggregate consideration included $12 million in

cash and 91,776 newly issued Sunoco LP common units, which had an aggregate acquisition-date fair value of approximately $5 million.

In the second quarter of 2025, Sunoco LP acquired a total of 151 fuel distribution consignment sites in three separate transactions for total consideration of approximately $105 million plus working capital. Aggregate consideration included $92 million in cash and 251,646 newly issued Sunoco LP common units which had an aggregate acquisition-date fair value of approximately $13 million.

In the third quarter of 2025, Sunoco LP acquired approximately 70 fuel distribution consignment sites and 100 supply agreements in five separate transactions for total cash consideration of approximately $85 million, plus working capital.

In the fourth quarter of 2025, Sunoco LP acquired a total of 27 fuel distribution consignment sites and 36 dealer sites, as well as commercial customers, in four separate transactions for total cash consideration of approximately $64 million, plus working capital.

Other 2024 Acquisition

On August 30, 2024, Sunoco LP acquired a terminal in Portland, Maine for approximately $24 million, including working capital. The purchase price was primarily allocated to property, plant and equipment.

Other 2023 Acquisition

On May 1, 2023, Sunoco LP completed the acquisition of 16 refined product terminals located across the East Coast and Midwest from Zenith Energy for $111 million, including working capital. The purchase price was primarily allocated to property and equipment.

West Texas Sale

On April 16, 2024, Sunoco LP completed the sale of 204 convenience stores located in West Texas, New Mexico and Oklahoma to 7-Eleven, Inc. for approximately $1.00 billion, including customary adjustments for fuel and merchandise inventory. As part of the sale, Sunoco LP also amended its existing take-or-pay fuel supply agreement with 7-Eleven, Inc. to incorporate additional fuel gross profit. As a result of the sale, Sunoco LP recorded a $586 million gain ($442 million, net of tax).

USAC

J-W Power Company Acquisition

On January 12, 2026, USAC completed the J-W Power Company acquisition, a large privately-held provider of compression services in the United States, for total consideration of approximately $860 million, consisting of approximately $430 million in cash and approximately 18.2 million newly issued USAC common units. As of the date of this Form 10-K filing, the initial accounting for this business combination is incomplete due to the timing of the close of the acquisition and therefore has not been included herein.

Joint Venture Transaction

ET-S Permian

Effective July 1, 2024, Energy Transfer and Sunoco LP formed ET-S Permian, a joint venture combining their respective crude oil and produced water gathering assets in the Permian Basin. Pursuant to the contribution agreement by and among Sunoco LP, SUN Pipeline Holdings LLC, NuStar Permian Transportation and Storage LLC, NuStar Permian Crude Logistics LLC, NuStar Permian Holdings LLC, NuStar Logistics, L.P., ET-S Permian Holdings Company LP, ET-S Permian Pipeline Company LLC, ET-S Permian Marketing Company LLC, Energy Transfer and Energy Transfer Crude Marketing, LLC dated July 14, 2024, in a cashless transaction, Energy Transfer contributed its Permian crude oil and produced water gathering assets and operations to ET-S Permian. Sunoco LP contributed all of its Permian crude oil gathering assets and operations to ET-S Permian. Energy Transfer’s long-haul crude pipeline network that provides transportation of crude oil out of the Permian Basin to Nederland, Houston and Cushing is excluded from ET-S Permian.

ET-S Permian operates more than 5,000 miles of crude oil and water gathering pipelines with crude oil storage capacity in excess of 11 million barrels.

Energy Transfer holds a 67.5% interest, with Sunoco LP holding the remaining 32.5% interest in ET-S Permian. Energy Transfer is the operator of ET-S Permian.

Pro Forma Results of Operations


	Year Ended December 31,
	2025		2024
Revenues	$	101,791	$	103,675
Net income	5,494		5,679

The pro forma consolidated results of operations include adjustments to:

•include the results of Parkland and NuStar for all periods presented;

•include incremental expenses associated with the fair value adjustments recorded as a result of applying the acquisition method of accounting for Parkland and NuStar;

•include incremental interest expense related to financing the transactions;

•include $175 million of expenses representing one-time costs associated with completing the transaction;

•adjust for relative changes in ownership resulting from the acquisition;

•exclude the results from the convenience stores sold in the West Texas Sale; and

•exclude the gain on sale and related tax impact related to the West Texas Sale.

The pro forma information is not necessarily indicative of the results of operations that would have occurred had the Parkland acquisition been made at the beginning of the periods presented or the future results of the combined operations.

Parkland's revenue and net income, excluding intercompany transactions, since the acquisition date to December 31, 2025 included in our consolidated statement of operations were $3.17 billion and $195 million, respectively.

The entire disclosure for business combination.

Reference 1: http://www.xbrl.org/2003/role/exampleRef
-Topic 805
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 8
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479328/805-10-50-8

Reference 2: http://www.xbrl.org/2003/role/exampleRef
-Topic 805
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 38
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479303/805-10-55-38

Reference 3: http://www.xbrl.org/2003/role/exampleRef
-Topic 805
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 46
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479303/805-10-55-46

Reference 4: http://www.xbrl.org/2003/role/exampleRef
-Topic 805
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 43
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479303/805-10-55-43

Reference 5: http://www.xbrl.org/2003/role/exampleRef
-Topic 805
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 45
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479303/805-10-55-45

Reference 6: http://www.xbrl.org/2003/role/exampleRef
-Topic 805
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 29
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479303/805-10-55-29

Reference 7: http://www.xbrl.org/2003/role/exampleRef
-Topic 805
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 29
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479303/805-10-55-29

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 805
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479907/805-20-50-5

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 805
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(1)(ii)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479907/805-20-50-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 805
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 3
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479907/805-20-50-3

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 805
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 3
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479581/805-30-50-3

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 805
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479328/805-10-50-2

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 805
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479907/805-20-50-2

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 805
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479581/805-30-50-2

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
-Topic 805
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479581/805-30-50-1

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Topic 805
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (f)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479581/805-30-50-1

Reference 17: http://www.xbrl.org/2003/role/disclosureRef
-Topic 805
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 3
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479328/805-10-50-3

Reference 18: http://www.xbrl.org/2003/role/disclosureRef
-Topic 805
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (c)(3)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479581/805-30-50-1

Reference 19: http://www.xbrl.org/2003/role/disclosureRef
-Topic 805
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (h)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479328/805-10-50-2

Reference 20: http://www.xbrl.org/2003/role/disclosureRef
-Topic 805
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479328/805-10-50-4

Reference 21: http://www.xbrl.org/2003/role/disclosureRef
-Topic 805
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 4
-Subparagraph (a)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479581/805-30-50-4

Reference 22: http://www.xbrl.org/2003/role/disclosureRef
-Topic 805
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)(3)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479907/805-20-50-1

Reference 23: http://www.xbrl.org/2003/role/disclosureRef
-Topic 805
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479907/805-20-50-1

Reference 24: http://www.xbrl.org/2003/role/disclosureRef
-Topic 805
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (h)(4)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479328/805-10-50-2

Reference 25: http://www.xbrl.org/2003/role/disclosureRef
-Topic 805
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (e)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479328/805-10-50-2

Reference 26: http://www.xbrl.org/2003/role/disclosureRef
-Topic 805
-SubTopic 40
-Name Accounting Standards Codification
-Section 45
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479326/805-40-45-1

Reference 27: http://www.xbrl.org/2003/role/disclosureRef
-Topic 805
-SubTopic 30
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org/805-30/tableOfContent

Reference 28: http://www.xbrl.org/2003/role/disclosureRef
-Topic 805
-SubTopic 20
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org/805-20/tableOfContent

Reference 29: http://www.xbrl.org/2003/role/disclosureRef
-Topic 805
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 7
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479328/805-10-50-7

Reference 30: http://www.xbrl.org/2003/role/disclosureRef
-Topic 805
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479328/805-10-50-5

Reference 31: http://www.xbrl.org/2003/role/disclosureRef
-Topic 805
-SubTopic 10
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org/805-10/tableOfContent

Equity

12 Months Ended

Dec. 31, 2024

Partners' Capital Notes [Abstract]

Environmental Exit Costs by Cost [Table Text Block]

EQUITY:

Limited Partners

Limited partner interests in the Partnership are represented by Common Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. The Partnership’s Common Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for trading on the NYSE. Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the Limited Partners for a vote. In addition, if at any time any person or group (other than the Partnership’s General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding

when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described at “Quarterly Distributions of Available Cash.”

Our Partnership Agreement contains specific provisions for the allocation of net earnings and losses to the partners for purposes of maintaining the partner capital accounts. For any fiscal year that the Partnership has net profits, such net profits are first allocated to the General Partner (which currently holds an approximately 0.1% general partner interest) until the aggregate amount of net profits for the current and all prior fiscal years equals the aggregate amount of net losses allocated to the General Partner for the current and all prior fiscal years. Second, such net profits shall be allocated to the Limited Partners pro rata in accordance with their respective sharing ratios. For any fiscal year in which the Partnership has net losses, such net losses shall be first allocated to the Limited Partners in proportion to their respective adjusted capital account balances, as defined by the Partnership Agreement, (before taking into account such net losses) until their adjusted capital account balances have been reduced to zero. Second, all remaining net losses shall be allocated to the General Partner. The General Partner may distribute to the Limited Partners funds of the Partnership that the General Partner reasonably determines are not needed for the payment of existing or foreseeable Partnership obligations and expenditures.

Common Units

The changes in Energy Transfer Common Units during the years ended December 31, 2025, 2024 and 2023 were as follows:


	Years Ended December 31,
	2025	2024	2023
Number of Common Units, beginning of period	3,431.0	3,367.5	3,094.4

Common Units issued in mergers and acquisitions (1)	—	50.8	260.2

Issuance of Common Units (2)	9.0	12.7	12.9
Number of Common Units, end of period	3,440.0	3,431.0	3,367.5

(1)Includes common units issued related to our acquisitions of WTG Midstream in 2024 and of Crestwood and Lotus Midstream in 2023.

(2)Includes common units issued in connection with the distribution reinvestment program and restricted unit vestings.

Energy Transfer Class A Units

As of December 31, 2025, the Partnership had outstanding 851,420,597 Class A units (“Energy Transfer Class A Units”) representing limited partner interests in the Partnership to the General Partner. The Energy Transfer Class A Units are entitled to vote together with the Partnership’s common units, as a single class, except as required by law. Additionally, Energy Transfer’s Partnership Agreement provides that, under certain circumstances, upon the issuance by the Partnership of additional common units or any securities that have voting rights that are pari passu with the Partnership common units, the Partnership will issue to any holder of Energy Transfer Class A Units additional Energy Transfer Class A Units such that the holder maintains a voting interest in the Partnership that is identical to its voting interest in the Partnership prior to such issuance. The Energy Transfer Class A Units are not entitled to distributions and otherwise have no economic attributes.

Energy Transfer Repurchase Program

In February 2015, the Partnership announced a common unit repurchase program, whereby the Partnership may repurchase up to $2 billion of Energy Transfer Common Units in the open market at the Partnership’s discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements. The Partnership did not repurchase any Energy Transfer Common Units under this program in 2025 or 2024. As of December 31, 2025, $880 million remained available to repurchase under the current program.

Energy Transfer Distribution Reinvestment Program

During the year ended December 31, 2025, distributions of $45 million were reinvested under the distribution reinvestment program. As of December 31, 2025, a total of 36.4 million Energy Transfer common units remained available to be issued under currently effective registration statements in connection with the distribution reinvestment program.

Energy Transfer Preferred Units

As of December 31, 2025, Energy Transfer’s outstanding preferred units included 550,000 Series B Preferred Units, 1,484,780 Series G Preferred Units, 900,000 Series H Preferred Units and 41,464,179 Series I Preferred Units. As of December 31, 2024, Energy Transfer’s outstanding preferred units also included 500,000 Series F Preferred Units, which were redeemed in May 2025. Energy Transfer’s Series A Preferred Units, Series C Preferred Units. Series D Preferred Units and Series E Preferred Units were previously redeemed as indicated in the tables below.

The following table summarizes changes in the Energy Transfer Preferred Units:


	Preferred Unitholders
	Series A		Series B		Series C		Series D		Series E		Series F		Series G		Series H		Series I		Total










Balance, December 31, 2022	$	958	$	556	$	440	$	434	$	786	$	496	$	1,488	$	893	$	—	$	6,051
Distributions to partners	(96)		(36)		(40)		(36)		(61)		(34)		(106)		(59)		—		(468)
Units issued in Crestwood acquisition	—		—		—		—		—		—		—		—		413		413
Net income	86		36		38		37		61		34		106		59		6		463
Balance, December 31, 2023	948		556		438		435		786		496		1,488		893		419		6,459
Distributions to partners	(56)		(36)		(11)		(11)		(30)		(34)		(106)		(59)		(35)		(378)
Redemption of Preferred Units	(950)		—		(450)		(445)		(800)		—		—		—		—		(2,645)
Other, net	13		—		11		10		20		—		—		—		—		54
Net Income	45		36		12		11		24		34		106		59		35		362
Balance, December 31, 2024	—		556		—		—		—		496		1,488		893		419		3,852
Distributions to partners	—		(36)		—		—		—		(16)		(106)		(59)		(35)		(252)
Redemption of Preferred Units	—		—		—		—		—		(500)		—		—		—		(500)
Other, net	—		—		—		—		—		8		—		—		—		8
Net Income	—		36		—		—		—		12		106		59		35		248
Balance, December 31, 2025	$	—	$	556	$	—	$	—	$	—	$	—	$	1,488	$	893	$	419	$	3,356

The following is a description of the distribution requirements for each currently outstanding series of preferred units.

Series B Preferred Units

Distributions on the Series B Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2028, at a rate of 6.625% per annum of the stated liquidation preference of $1,000. On and after February 15, 2028, distributions on the Series B Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate based on the three-month SOFR, plus a tenor spread adjustment of 0.26161%, plus a spread of 4.155% per annum. The Series B Preferred Units are redeemable at Energy Transfer’s option on or after February 15, 2028 at a redemption price of $1,000 per Series B Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

Series G Preferred Units

Distributions on the Series G Preferred Units are cumulative from and including the original issue date and will be payable semi-annually in arrears on the 15th day of May and November of each year, commencing on May 15, 2020 to, but excluding, May 15, 2030, at a rate equal to 7.125% per annum of the $1,000 liquidation preference. On and after May 15, 2030, the distribution rate on the Series G Preferred Units will equal a percentage of the $1,000 liquidation preference equal to the five-year U.S. treasury rate plus a spread of 5.306% per annum. The Series G Preferred Units are redeemable at Energy Transfer’s option on or after May 15, 2030 at a redemption price of $1,000 per Series G Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

Series H Preferred Units

Distributions on the Series H Preferred Units will accrue and be cumulative to, but excluding, November 15, 2026, at a rate equal to 6.500% per annum of the $1,000 liquidation preference. On and after November 15, 2026 and each fifth anniversary thereafter, the distribution rate on the Series H Preferred Units will reset to be a percentage of the $1,000 liquidation preference equal to the five-year U.S. treasury rate plus a spread of 5.694% per annum. Distributions on the Series H Preferred Units will be payable semi-annually in arrears on the 15th day of May and November of each year. The Series H Preferred Units are redeemable at Energy Transfer’s option during the three-month period prior to, and including, each distribution reset date at a redemption price of $1,000 per Series H Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

Series I Preferred Units

On November 3, 2023, Energy Transfer, in connection with its acquisition of Crestwood, issued 41,464,179 of its Series I Preferred Units in exchange for a commensurate number of Crestwood preferred units. Subject to certain conditions, the holders of the Series I Preferred Units will have the right to convert preferred units into (i) common units on a 10-for-2.07 basis, or (ii) a number of common units determined pursuant to a conversion ratio set forth in the Partnership Agreement upon the occurrence of certain events, such as a change in control. The Series I Preferred Units, on an as converted basis, have voting rights that are identical to the voting rights of the common units and will vote with the common units as a single class, except that the preferred units are entitled to vote as a separate class on any matter on which all unitholders are entitled to vote that adversely affects the rights, powers, privileges or preferences of the preferred units in relation to Energy Transfer’s other securities outstanding

The holders of the Series I Preferred Units are entitled to receive fixed quarterly distributions of $0.2111 per unit. Distributions on the preferred units are paid in cash unless, subject to certain exceptions, (i) there is no distribution being paid on our common units; and (ii) our available cash (as defined in our Partnership Agreement) is insufficient to make a cash distribution to Series I Preferred Unitholders.

Sale of Common Units by Subsidiaries

Energy Transfer on a stand-alone basis (the “Parent Company”) accounts for the difference between the carrying amount of its investment in subsidiaries and the underlying book value arising from issuance of units by subsidiaries (excluding unit issuances to the Parent Company) as a capital transaction. If a subsidiary issues units at a price less than the Parent Company’s carrying value per unit, the Parent Company assesses whether the investment has been impaired, in which case a provision would be reflected in our statement of operations. The Parent Company did not recognize any impairment related to the issuances of subsidiary common units during the periods presented.

Subsidiary Equity Transactions

Sunoco LP’s Class D Units

In connection with the closing of the Parkland Acquisition, Sunoco LP issued 51,517,198 Class D Units to SunocoCorp.

Class D Units (i) except as required by law and in addition to the voting rights established in Sunoco LP’s partnership agreement, are entitled to vote; (ii) shall represent limited partner interests and common unit interests in the Sunoco LP and shall be economically equivalent to other Sunoco LP common units and no distribution may be made in respect of the Sunoco LP’s common units unless an equal distribution is simultaneously made on the Class D Units; and (iii) provide dividend equalization rights for the period beginning on October 31, 2025 and ended December 31, 2027 (the “Equalization Period”), Sunoco LP shall ensure that SunocoCorp shall have cash necessary and sufficient to pay distributions on each SunocoCorp common unit for each quarter during the Equalization Period in an amount equal to 100% of the distributions paid by the Sunoco LP on each Sunoco LP common unit during such quarter.

Sunoco LP’s Series A Preferred Units

In September 2025, Sunoco LP closed a private offering of 1.5 million of its 7.875% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units (the “Sunoco LP Series A Preferred Units”) at an offering price of $1,000 per unit. Sunoco LP received net proceeds of approximately $1.47 billion from the sale of the Sunoco LP Series A Preferred Units after deducting the initial purchasers' discount and other estimated offering expenses. Sunoco LP used the net proceeds from this private offering (i) on the closing date of the Parkland Acquisition to fund a portion of the cash consideration for the Parkland Acquisition, and (ii) prior to the closing date of the Parkland Acquisition, to temporarily reduce the borrowings outstanding under Sunoco LP’s credit facility and to pay interest and fees in connection therewith.

Distributions on the Sunoco LP Series A Preferred Units are cumulative from the date of original issuance and will be payable semi-annually in arrears commencing on March 18, 2026, when, as, and if declared by Sunoco LP’s general partner out of legally available funds for such purpose. An initial distribution on the Sunoco LP Series A Preferred Units will be paid on March 18, 2026 in an amount equal to approximately $39.38 per Sunoco LP Series A Preferred Unit.

USAC’s Distribution Reinvestment Program

During the years ended December 31, 2025, 2024 and 2023, USAC issued 7,832, 65,352 and 87,808 USAC common units, respectively, under the USAC distribution reinvestment program.

Energy Transfer Common Unit Distributions

Our distribution policy is consistent with the terms of our Partnership Agreement, which requires that we distribute all of our available cash quarterly.

Our distributions declared and paid with respect to our common units were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2022

February 7, 2023

February 21, 2023

0.3050

March 31, 2023

May 8, 2023

May 22, 2023

0.3075

June 30, 2023

August 14, 2023

August 21, 2023

0.3100

September 30, 2023

October 30, 2023

November 20, 2023

0.3125

December 31, 2023

February 7, 2024

February 20, 2024

0.3150

March 31, 2024

May 13, 2024

May 20, 2024

0.3175

June 30, 2024

August 9, 2024

August 19, 2024

0.3200

September 30, 2024

November 8, 2024

November 19, 2024

0.3225

December 31, 2024

February 7, 2025

February 19, 2025

0.3250

March 31, 2025

May 9, 2025

May 20, 2025

0.3275

June 30, 2025

August 8, 2025

August 19, 2025

0.3300

September 30, 2025

November 7, 2025

November 19, 2025

0.3325

December 31, 2025

February 6, 2026

February 19, 2026

0.3350

Energy Transfer Preferred Unit Distributions

Distributions on Energy Transfer’s preferred units declared and/or paid by Energy Transfer were as follows:


Period Ended	Record Date (1)	Payment Date (1)	Series A		Series B (2)		Series C		Series D		Series E		Series F		Series G (2)		Series H (2)		Series I (1)







December 31, 2022	February 1, 2023	February 15, 2023	$	31.25	$	33.125	$	0.4609	$	0.4766	$	0.4750	$	—	$	—	$	—	$	—
March 31, 2023	May 1, 2023	May 15, 2023	21.98		—		0.4609		0.4766		0.4750		33.7500		35.63		32.50		—
June 30, 2023	August 1, 2023	August 15, 2023	23.89		33.125		0.6294		0.4766		0.4750		—		—		—		—
September 30, 2023	November 1, 2023	November 15, 2023	24.67		—		0.6489		0.6622		0.4750		33.7500		35.63		32.50		—
December 31, 2023	February 1, 2024	February 15, 2024	24.71		33.125		0.6075		0.6199		0.4750		—		—		—		0.2111
March 31, 2024	May 1, 2024	May 15, 2024	23.99		—		—		—		0.4750		33.7500		35.63		32.50		0.2111
June 30, 2024	August 1, 2024	August 15, 2024	9.88		33.125		—		—		—		—		—		—		0.2111
September 30, 2024	November 1, 2024	November 15, 2024	—		—		—		—		—		33.7500		35.63		32.50		0.2111
December 31, 2024	February 1, 2025	February 17, 2025	—		33.125		—		—		—		—		—		—		0.2111
March 31, 2025	May 1, 2025	May 15, 2025	—		—		—		—		—		33.7500		35.63		32.50		0.2111
June 30, 2025	August 1, 2025	August 15, 2025	—		33.125		—		—		—		—		—		—		0.2111
September 30, 2025	November 1, 2025	November 14, 2025	—		—		—		—		—		—		35.63		32.50		0.2111
December 31, 2025	February 1, 2026	February 15, 2026	—		33.125		—		—		—		—		—		—		0.2111

(1)The record date and payment date shown above apply to all Energy Transfer Preferred Units, except for the Series I Preferred Units. For the period ended December 31, 2025, the cash distribution for the Series I Preferred Units was paid on February 17, 2026 to unitholders of record as of the close of business on February 4, 2026. For the period ended September 30, 2025, the cash distribution for the Series I Preferred Units were paid on November 14, 2025 to unitholders of record as of the close of business on November 4, 2025. For the period ended June 30, 2025, the cash distribution for the Series I Preferred Units was paid on August 14, 2025 to unitholders of record as of the close of business on August 4, 2025. For the period ended March 31, 2025, the cash distribution for the Series I Preferred Units was paid on May 15, 2025 to unitholders of record as of the close of business on May 2, 2025. For the period ended December 31, 2024, the cash distribution for the Series I Preferred Units was paid on February 14, 2025 to unitholders of record as of the close of business on February 4, 2025. For the period ended September 30, 2024, the cash distribution for the Series I Preferred Units was paid on November 14, 2024 to unitholders of record as of the close of business on November 4, 2024. For the period ended June 30, 2024, the cash distribution for the Series I Preferred Units was paid on August 14, 2024 to unitholders of record as of the close of business on August 2, 2024.

(2)Series B, Series G and Series H distributions are currently paid on a semi-annual basis. Distributions on the Series B Preferred Units will begin to be paid quarterly on February 15, 2028.

SunocoCorp Cash Distributions

SunocoCorp’s company agreement sets forth its policy for paying regular quarterly cash distributions. For the quarter ended December 31, 2025, SunocoCorp declared a cash distribution of $0.9317 to be paid on February 19, 2026 to unitholders of record as of February 6, 2026.

Sunoco LP Cash Distributions

Energy Transfer owns approximately 28.5 million Sunoco LP common units and all of Sunoco LP’s IDRs. As of December 31, 2025, Sunoco LP had approximately 136.9 million common units outstanding and 51,517,198 Class D Units outstanding.

The following table illustrates the percentage allocations of available cash from operating surplus between Sunoco LP’s common unitholders and the holder of its IDRs based on the specified target distribution levels, after the payment of distributions to Class C unitholders. The amounts set forth under “marginal percentage interest in distributions” are the

percentage interests of the IDR holder and the common unitholders in any available cash from operating surplus which Sunoco LP distributes up to and including the corresponding amount in the column “total quarterly distribution per unit target amount.” The percentage interests shown for common unitholders and IDR holder for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.


		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Target Amount	Common Unitholders	Holder of IDRs
Minimum Quarterly Distribution	$0.4375	100%	—%
First Target Distribution	$0.4375 to $0.503125	100%	—%
Second Target Distribution	$0.503125 to $0.546875	85%	15%
Third Target Distribution	$0.546875 to $0.656250	75%	25%
Thereafter	Above $0.656250	50%	50%

Distributions on Sunoco LP’s common units and Class D Units declared and/or paid by Sunoco LP were as follows:


Quarter Ended	Payment Date	Per Common Unit Rate		Per Class D Unit Rate




























December 31, 2022	February 21, 2023	$	0.8255	$	—
March 31, 2023	May 22, 2023	0.8420		—
June 30, 2023	August 21, 2023	0.8420		—
September 30, 2023	November 20, 2023	0.8420		—
December 31, 2023	February 20, 2024	0.8420		—
March 31, 2024	May 20, 2024	0.8756		—
June 30, 2024	August 19, 2024	0.8756		—
September 30, 2024	November 19, 2024	0.8756		—
December 31, 2024	February 19, 2025	0.8865		—
March 31, 2025	May 20, 2025	0.8976		—
June 30, 2025	August 19, 2025	0.9088		—
September 30, 2025	November 19, 2025	0.9202		—
December 31, 2025	February 19, 2026	0.9317		0.9317

USAC Cash Distributions

Energy Transfer owns approximately 46.1 million USAC common units. As of December 31, 2025, USAC had approximately 127 million common units outstanding. USAC currently has a non-economic general partner interest and no outstanding IDRs.

Distributions on USAC’s units declared and/or paid by USAC were as follows:

Quarter Ended

Payment Date

Rate

December 31, 2022

February 3, 2023

0.5250

March 31, 2023

May 5, 2023

0.5250

June 30, 2023

August 4, 2023

0.5250

September 30, 2023

November 3, 2023

0.5250

December 31, 2023

February 2, 2024

0.5250

March 31, 2024

May 3, 2024

0.5250

June 30, 2024

August 2, 2024

0.5250

September 30, 2024

November 1, 2024

0.5250

December 31, 2024

February 7, 2025

0.5250

March 31, 2025

May 9, 2025

0.5250

June 30, 2025

August 8, 2025

0.5250

September 30, 2025

November 7, 2025

0.5250

December 31, 2025

February 6, 2026

0.5250

Accumulated Other Comprehensive Income

The following table presents the components of AOCI, net of tax:


	December 31,
	2025		2024
Available-for-sale securities	$	30	$	20
Foreign currency translation adjustment	(12)		(6)

Actuarial gain related to pensions and other postretirement benefits	54		45
Investments in unconsolidated affiliates, net	10		14
Total AOCI, net of tax	$	82	$	73

The following table sets forth the tax amounts included in the respective components of other comprehensive income:


	December 31,
	2025		2024
Available-for-sale securities	$	(3)	$	(3)
Foreign currency translation adjustment	2		2

Total	$	(1)	$	(1)

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Tables)

12 Months Ended

Dec. 31, 2025

The following table reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.


	December 31,
	2025		2024
Current	$	62	$	51
Non-current	354		227
Total environmental liabilities	$	416	$	278

Right of way (20 to 65 years)

Other Commitments

The following table reflects ROW expense included in operating expenses in the accompanying consolidated statements of operations:


	Years Ended December 31,
	2025		2024		2023
ROW expense	$	87	$	72	$	68

Equity (Narrative) (Details) - USD ($)
$ / shares in Units, $ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2025

Sep. 30, 2025

Jun. 30, 2025

Mar. 31, 2025

Dec. 31, 2024

Sep. 30, 2024

Jun. 30, 2024

Mar. 31, 2024

Dec. 31, 2023

Sep. 30, 2023

Jun. 30, 2023

Mar. 31, 2023

Dec. 31, 2022

Dec. 31, 2025

Dec. 31, 2024

Dec. 31, 2023

Dec. 02, 2025

Jun. 03, 2025

Share Repurchase Program, Authorized, Amount

$ 2,000

Share Repurchase Program, Remaining Authorized, Amount

$ 880

Minimum beneficial percentage ownership, other than the Partnership's General Partner and its affiliates, no voting rights, not considered outstanding

20.00%

Limited Partners' Capital Account, Units Outstanding

3,439,986,779

3,431,088,022

3,439,986,779

3,431,088,022

Stock Issued During Period, Value, Dividend Reinvestment Plan

$ 45

$ 89

$ 90

Common Units Remaining Available to be Issued Under Distribution Reinvestment Plan

36,400,000

Incentive Distribution Rights

0.00%

Parent Company [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.3350

$ 0.3325

$ 0.3300

$ 0.3275

$ 0.3250

$ 0.3225

$ 0.3200

$ 0.3175

$ 0.3150

$ 0.3125

$ 0.3100

$ 0.3075

$ 0.3050

SunocoCorp

Distribution Made to Limited Partner, Distributions Paid, Per Unit

0.9317

Series A Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

9.88

23.99

24.71

24.67

23.89

21.98

31.25

Series C Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

0.6075

0.6489

0.6294

0.4609

Series D Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

0.6199

0.6622

0.4766

Series E Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

0.4750

Series F Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0

33.7500

500,000

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[1]

$ 0

35.63

1,484,780

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[1]

$ 33.125

33.125

550,000

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[1]

$ 0

32.50

Distribution Made to Limited Partner, Distributions Paid, Per Unit

900,000

Series I Preferred Units

$ 0.2111

^[2]

0.2111

^[2]

0.2111

^[2]

0.2111

^[2]

0.2111

^[2]

0.2111

^[2]

0.2111

^[2]

0.2111

^[2]

0.2111

^[2]

$ 0.2111

LE GP, LLC, the general partner of Energy Transfer

41,464,179

Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest

0.10%

Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.

28,500,000

Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.

46,100,000

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.5250

Limited Partners' Capital Account, Units Outstanding

127,000,000

Stock Issued During Period, Shares, Dividend Reinvestment Plan

7,832

65,352

87,808

80,000

100,000

6.625%

Preferred Units, Liquidation Spread, Percent

$ 1,000

4.155%

A tenor spread adjustment

0.26161%

7.125%

Preferred Units, Liquidation Spread, Percent

$ 1,000

5.306%

6.50%

Preferred Units, Liquidation Spread, Percent

$ 1,000

5.694%

Sunoco LP Series A Preferred Units | Sunoco LP [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 39.38

7.875%

Partners' Capital Account, Units, Sold in Private Placement

$ 1,000

1,500,000

Proceeds from Issuance of Preferred Stock and Preference Stock

$ 1,470

Common Units

Issuance of Common Units (2)

^[3]

9,000,000.0

12,700,000

12,900,000

Limited Partners' Capital Account, Units Outstanding

3,440,000,000

3,431,000,000

3,367,500,000

3,094,400,000

3,440,000,000

3,431,000,000

3,367,500,000

Class A Units

Limited Partners' Capital Account, Units Outstanding

851,420,597

Common Units | Sunoco LP [Member]

Limited Partners' Capital Account, Units Outstanding

136,900,000

Class D Units [Member] | Sunoco LP [Member]

Limited Partners' Capital Account, Units Outstanding

51,517,198

[1]	Series B, Series G and Series H distributions are currently paid on a semi-annual basis. Distributions on the Series B Preferred Units will begin to be paid quarterly on February 15, 2028.
[2]	The record date and payment date shown above apply to all Energy Transfer Preferred Units, except for the Series I Preferred Units. For the period ended December 31, 2025, the cash distribution for the Series I Preferred Units was paid on February 17, 2026 to unitholders of record as of the close of business on February 4, 2026. For the period ended September 30, 2025, the cash distribution for the Series I Preferred Units were paid on November 14, 2025 to unitholders of record as of the close of business on November 4, 2025. For the period ended June 30, 2025, the cash distribution for the Series I Preferred Units was paid on August 14, 2025 to unitholders of record as of the close of business on August 4, 2025. For the period ended March 31, 2025, the cash distribution for the Series I Preferred Units was paid on May 15, 2025 to unitholders of record as of the close of business on May 2, 2025. For the period ended December 31, 2024, the cash distribution for the Series I Preferred Units was paid on February 14, 2025 to unitholders of record as of the close of business on February 4, 2025. For the period ended September 30, 2024, the cash distribution for the Series I Preferred Units was paid on November 14, 2024 to unitholders of record as of the close of business on November 4, 2024. For the period ended June 30, 2024, the cash distribution for the Series I Preferred Units was paid on August 14, 2024 to unitholders of record as of the close of business on August 2, 2024.
[3]	Includes common units issued in connection with the distribution reinvestment program and restricted unit vestings.

Investments in Unconsolidated Affiliates (Summarized Balance Sheet Information) (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Schedule of Investments [Line Items]
Assets, Current	$ 18,233	$ 14,202
Other non-current assets, net	2,591	2,017
Total assets	141,286	125,380
Current Liabilities	14,955	12,656
Equity	49,010	46,017	$ 43,939	$ 40,659
Total liabilities and equity	141,286	125,380
Equity Method Investments [Member]
Schedule of Investments [Line Items]
Assets, Current	462	446
Property, plant and equipment, net	8,397	8,478
Other non-current assets, net	109	105
Total assets	8,968	9,029
Current Liabilities	365	1,160
Non-current liabilities	4,319	3,541
Equity	4,284	4,328
Total liabilities and equity	$ 8,968	$ 9,029

Income Taxes

12 Months Ended

Dec. 31, 2025

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES:

As a partnership, we are not subject to United States federal income tax and most state income taxes. However, the Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes.

The Partnership’s income (loss) before income tax expense by geographic area is shown in the table below:


	Years Ended December 31,
	2025		2024		2023

United States	$	5,869	$	7,101	$	5,602
Foreign	189		5		(5)
Total	$	6,058	$	7,106	$	5,597

The components of the federal and state income tax expense (benefit) of our taxable subsidiaries are summarized as follows:


	Years Ended December 31,
	2025		2024		2023
Current expense:
Federal	$	164	$	198	$	56
State	1		66		44
Foreign	7		1		—
Total	172		265		100
Deferred expense (benefit):
Federal	177		175		227
State	(23)		101		(24)
Foreign	24		—		—
Total	178		276		203
Total income tax expense	$	350	$	541	$	303

Historically, our effective tax rate has differed from the statutory rate primarily due to partnership earnings that are not subject to United States federal and most state income taxes at the partnership level. A reconciliation of income tax expense

at the United States statutory rate to the Partnership’s income tax benefit for the years ended December 31, 2025, 2024 and 2023 is as follows:


	Years Ended December 31,
	2025			2024			2023
	Amount		Percent	Amount		Percent	Amount		Percent
Income tax expense at United States statutory rate	$	1,272	21.00%	$	1,492	21.00%	$	1,175	21.00%
Increase (reduction) in income taxes resulting from:
Non-taxable Partnership earnings	(944)		(15.59)%	(1,084)		(15.25)%	(884)		(15.79)%

State and local income tax, net of federal income tax effect(1)	4		0.07%	113		1.59%	37		0.65%
Foreign tax effects	(4)		(0.06)%	—		—	—		—
Effect of cross-border tax laws	6		0.10%	—		—	—		—
Changes in valuation allowances	2		0.03%	—		—	(3)		(0.05)%
Changes in unrecognized tax benefits	(5)		(0.08)%	21		0.29%	(14)		(0.24)%






Other adjustments	19		0.32%	(1)		(0.02)%	(8)		(0.16)%
Income tax expense	$	350	5.79%	$	541	7.61%	$	303	5.41%

(1)State taxes that made up the majority (greater than 50 percent) of the tax effect in this category were Texas in 2025, Pennsylvania, Texas, New Jersey and New York in 2024 and Texas in 2023.

The One Big Beautiful Bill Act (“OBBBA”), enacted in July 2025, is expected to impact the Partnership primarily through the ability to take higher tax depreciation deductions via 100% expensing on eligible property and higher interest expense deductions via more favorable interest expense limitation calculations. We will continue to monitor regulatory guidance and interpretations, which could have a material impact on our financials condition and results of operations.

Cash paid for income taxes were as follows:


	Year Ended December 31,
	2025		2024		2023
Cash paid for income taxes, net of refunds (excluding federal tax credits purchased from non-governmental third parties):
Federal:	$	—	$	150	$	64
State:
Texas	26		14		16
Pennsylvania	*		*		6
New Jersey	*		13		6
Other	12		29		11

Foreign:
Canada	62		—		—
Other	3		—		—

Total	$	103	$	206	$	103

Cash paid for federal tax credits purchased from non-governmental third parties	$	97	$	47	$	—

*Amount of income taxes paid during the year did not meet the 5% disaggregation threshold.

Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The following table summarizes the principal components of the deferred tax assets (liabilities) as follows:


	December 31,
	2025		2024
Deferred income tax assets:
Net operating losses and other carryforwards	$	443	$	197


Other	75		42
Total deferred income tax assets	518		239
Valuation allowance	(64)		—
Net deferred income tax assets	454		239

Deferred income tax liabilities:
Property, plant and equipment	(1,083)		(224)

Investments in affiliates	(4,200)		(4,098)
Trademarks	(240)		(82)
Other	(61)		(18)
Total deferred income tax liabilities	(5,584)		(4,422)
Net deferred income taxes	$	(5,130)	$	(4,183)

The completion of the Parkland transaction significantly increased the deferred tax assets (liabilities). The table below provides a rollforward of the net deferred income tax liability:


	December 31,
	2025		2024
Net deferred income tax liability, beginning of year	$	(4,183)	$	(3,931)
Acquired in Parkland acquisition	(755)		—
Acquired in NuStar acquisition	—		(3)
Tax accrual	(192)		(249)
Net deferred income tax liability	$	(5,130)	$	(4,183)

As of December 31, 2025, ETP Holdco had federal net operating loss (NOL) carryforwards of $325 million, which are limited under IRC §382 and may be carried forward indefinitely. Although these federal NOLs are expected to be fully utilized, the amount utilized in a particular year may be limited. Sunoco Retail, LLC had federal NOL carryforwards of $287 million, that may be carried forward indefinitely. Of this amount, $206 million is subject to limitations under IRC §382 (ownership-change limitation) and $35 million is limited under Separate Return Limitation Year (SRLY) rules. Although these federal NOLs are expected to be fully utilized, the amount utilized in a particular year may be limited. SunocoCorp, LLC had federal NOL carryforwards of $9 million that may be carried forward indefinitely. Sunoco Retail, LLC's foreign subsidiaries had NOL carryforwards of $425 million, of which, $279 million expire between 2026 and 2045. Evergreen Capital Holdings, LLC had federal NOL carryforwards of $30 million that may be carried forward indefinitely. Our corporate subsidiaries have state NOL carryforward benefits of $69 million, net of federal tax, with some expiring between 2026 and 2044 and others carried forward indefinitely. Our corporate subsidiaries have cumulative excess business interest expense carryforwards of $181 million available for indefinite carryforward, of which, $159 million is limited under IRC §382. Although the excess business interest expense carryforwards are expected to be fully utilized, the amount utilized in a particular year may be limited. For the year ended December 31, 2025, the net change in the total valuation allowances was an increase of $64 million, and for the year ended December 31, 2024, there was no net change. Valuation allowances totaling $52 million and $12 million are attributable to foreign and federal NOLs, respectively.

The following table sets forth the changes in unrecognized tax benefits:


	Years Ended December 31,
	2025		2024		2023
Balance at beginning of year	$	74	$	40	$	52


Additions attributable to tax positions taken in prior years	—		34		—
Reduction attributable to tax positions taken in prior years	(8)		—		(9)
Settlements	—		—		(3)

Balance at end of year	$	66	$	74	$	40

As of December 31, 2025, we had $66 million ($59 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate.

Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2025, we recognized an interest and penalty benefit of $2 million. At December 31, 2025, we have interest and penalties accrued of $7 million, net of tax.

Pennsylvania Case

In November 2015, the Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“Nextel”) that the Pennsylvania limitation on NOL carryforward deductions violated the uniformity clause of the Pennsylvania Constitution and struck the NOL limitation in its entirety. In October 2017, the Pennsylvania Supreme Court affirmed the decision with respect to the uniformity clause violation; however, the Court reversed with respect to the remedy and instead severed the flat-dollar limitation, leaving the percentage-based limitation intact. ETC Sunoco previously recognized approximately $67 million ($53 million after federal income tax benefits) in tax benefit based on previously filed tax returns and certain previously filed protective claims held pending the Nextel matter. Based upon the Pennsylvania Supreme Court’s October 2017 decision, and because of uncertainty in the breadth of the application of the decision, ETC Sunoco reserved $34 million ($27 million after federal income tax benefits) against the receivable. On December 22, 2021, the Pennsylvania Supreme Court found in General Motors Corporation v. Commonwealth (“GM”) that the taxpayer was entitled to meaningful backwards looking relief under the Due Process Clause, meaning the Commonwealth must equalize the taxpayer’s position with taxpayers who were not affected by the NOL cap in place for the year at issue. The Court therefore held the taxpayer was entitled to a refund by calculating its tax for that year with an uncapped NOL deduction. We believed the Pennsylvania Supreme Court’s ruling in GM would more likely than not be upheld if challenged by the Commonwealth, and we reversed the reserve thereby recognizing the entire tax benefit of $34 million ($27 million after federal income tax benefit).

On November 20, 2024, the Pennsylvania Supreme Court reversed its earlier holding in GM and determined taxpayers are not entitled to refunds for excess taxes paid in earlier years. Following the reversal of the GM decision, we reinstated the reserve. Certain Pennsylvania taxpayers filed suit against the Commonwealth following the reversal of the GM decision on the basis that the court’s ruling should not apply to taxpayers who did not claim refunds in prior years but who, instead, took uncapped NOL positions on their tax returns and were subsequently assessed by the Department of Revenue. The lead case in this challenge remains pending before the Pennsylvania Commonwealth Court.

IRS Audits

The IRS audit of the Partnership’s 2020 U.S. Federal income tax return closed with no changes proposed. In general, Energy Transfer and its subsidiaries are no longer subject to examination by the IRS, and most state jurisdictions, for the 2020 and prior tax years. Energy Transfer and its other subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations.

USAC is currently under examination by the IRS for years 2019 and 2020. The IRS has issued preliminary partnership examination changes, resulting in imputed underpayment computations of approximately $30 million, including interest, for the 2019 and 2020 tax years. Under the Bipartisan Budget Act of 2015, there are several procedural steps to complete before a final imputed underpayment, if any, is determined. Based on discussions with the IRS, USAC accrued $2.9 million, which USAC believes is a reasonable estimate of the potential loss from the aggregate final imputed underpayment for the years 2019 and 2020. However, USAC’s final imputed underpayment, if any, has not been determined. Once determined, USAC’s general partner may either elect to pay the imputed underpayment, if any,

(including any applicable penalties and interest) directly to the IRS or, if eligible, issue a revised information statement to each unitholder, or former unitholder as applicable, of USAC with respect to an audited and adjusted return.

The entire disclosure for income tax.

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 740
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477617/942-740-50-1

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 944
-SubTopic 740
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478822/944-740-50-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-12

Reference 5: http://www.xbrl.org/2003/role/exampleRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 231
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482663/740-10-55-231

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12C
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-12C

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12B
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-12B

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 270
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477891/740-270-50-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SAB Topic 6.I.5.Q1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479360/740-10-S99-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480990/946-20-50-13

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(h)(2))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org/740/tableOfContent

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 14
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-14

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 21
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-21

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 17
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-17

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Subparagraph (SAB Topic 11.C)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479360/740-10-S99-2

Reference 17: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482603/740-30-50-2

Other Postretirement Benefits

Retirement Benefits (Fair Value of Plan Assets) (Details) - USD ($)
$ in Millions

Dec. 31, 2025

Dec. 31, 2024

Dec. 31, 2023

$ 131

$ 127

$ 138

321

295

277

Pension Benefits

158

Cash and Cash Equivalents [Member] | Other Postretirement Benefits

182

Cash and Cash Equivalents [Member] | Pension Benefits

Mutual Fund [Member] | Other Postretirement Benefits

Mutual Fund [Member] | Pension Benefits

216

^[1]

189

^[2]

Fixed Income Securities [Member] | Other Postretirement Benefits

^[3]

Fixed Income Securities [Member] | Pension Benefits

101

Level 1 [Member] | Other Postretirement Benefits

Level 1 [Member] | Pension Benefits

220

197

Level 1 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefits

138

Level 1 [Member] | Cash and Cash Equivalents [Member] | Pension Benefits

Level 1 [Member] | Mutual Fund [Member] | Other Postretirement Benefits

Level 1 [Member] | Mutual Fund [Member] | Pension Benefits

216

^[1]

189

^[2]

Level 1 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefits

^[3]

Level 1 [Member] | Fixed Income Securities [Member] | Pension Benefits

Level 2 [Member] | Other Postretirement Benefits

Level 2 [Member] | Pension Benefits

101

Level 2 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefits

Level 2 [Member] | Cash and Cash Equivalents [Member] | Pension Benefits

Level 2 [Member] | Mutual Fund [Member] | Other Postretirement Benefits

Level 2 [Member] | Mutual Fund [Member] | Pension Benefits

^[1]

^[2]

Level 2 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefits

^[3]

Level 2 [Member] | Fixed Income Securities [Member] | Pension Benefits

101

Level 3 [Member] | Other Postretirement Benefits

Level 3 [Member] | Pension Benefits

Level 3 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefits

Level 3 [Member] | Cash and Cash Equivalents [Member] | Pension Benefits

Level 3 [Member] | Mutual Fund [Member] | Other Postretirement Benefits

Level 3 [Member] | Mutual Fund [Member] | Pension Benefits

^[1]

^[2]

Level 3 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefits

^[3]

Level 3 [Member] | Fixed Income Securities [Member] | Pension Benefits

Funded Plans [Member] | Pension Benefits

Projected benefit obligation

158

Unfunded Plans [Member] | Pension Benefits

182

Projected benefit obligation

Cash and cash equivalents

$ 0

[1]	Primarily composed of market index funds as of December 31, 2025.
[2]	Primarily composed of market index funds as of December 31, 2024.
[3]	Comprised of approximately 100% equities as of December 31, 2024.

Operations And Organization (Narrative) (Details)	12 Months Ended
Operations And Organization (Narrative) (Details)	Dec. 31, 2025 shares
Incentive Distribution Rights	0.00%
Number of convenience stores	11,000
Number of Countries in which Entity Operates	32
Miles of pipeline	14,000
Terminals
Number of Real Estate Properties	160
Sunoco LP [Member]
Incentive Distribution Rights	10000.00%
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.	28,500,000
USAC [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.	46,100,000
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest	100.00%

Consolidated Balance Sheets - USD ($)
$ in Millions

Dec. 31, 2025

Dec. 31, 2024

ASSETS

$ 1,272

$ 312

Inventories

4,770

3,070

Income taxes receivable

Derivative assets

Other current assets

688

477

Total current assets

18,233

14,202

Property, plant and equipment

141,283

129,242

Accumulated depreciation and depletion

(39,141)

(34,030)

Property, Plant and Equipment, Net

102,142

95,212

^[1]

3,589

3,266

Other non-current assets, net

1,841

809

2,591

2,017

Intangible assets, net

7,438

5,971

Operating lease current liabilities

5,452

3,903

Total assets

141,286

125,380

LIABILITIES AND EQUITY

Derivative liabilities

245

Accrued and other current liabilities

5,165

4,241

Current maturities of long-term debt

Total current liabilities

14,955

12,656

Long-term debt, less current maturities

68,308

59,752

Deferred Income Tax Liabilities, Net

1,515

730

5,307

4,190

Other non-current liabilities

1,941

1,618

Commitments and contingencies

Redeemable noncontrolling interests

250

417

Limited Partners:

Preferred Unitholders (44,398,959 and 44,898,959 units authorized, issued and outstanding as of December 31, 2025 and 2024, respectively)

3,356

3,852

Common Unitholders (3,439,986,779 and 3,431,088,022 units authorized, issued and outstanding as of December 31, 2025 and 2024, respectively)

30,930

31,195

General Partner

(2)

Accumulated other comprehensive income

Total partners’ capital

34,366

35,118

Noncontrolling interests

14,644

10,899

Total equity

49,010

46,017

Total liabilities and equity

141,286

125,380

Related Party

ASSETS

Accounts receivable from related companies

119

LIABILITIES AND EQUITY

Accounts payable

Nonrelated Party

ASSETS

Accounts receivable, net

11,275

10,191

LIABILITIES AND EQUITY

Accounts payable

$ 9,469

$ 8,306

[1]	Amounts reflected above exclude Sunoco LP’s investments in the ET-S Permian and J.C. Nolan joint ventures, which are eliminated in consolidation.

Lease Accounting

12 Months Ended

Dec. 31, 2025

Leases [Abstract]

Lease Accounting

LEASE ACCOUNTING:

Lessee Accounting

The Partnership leases terminal facilities, tank cars, office space, land and equipment under non-cancelable operating leases whose initial terms are typically five to 15 years, with some real estate leases having terms of 40 years or more, along with options that permit renewals for additional periods. At the inception of each, we determine if the arrangement is a lease or contains an embedded lease and review the facts and circumstances of the arrangement to classify lease assets as operating or finance leases under Topic 842. The Partnership has elected not to record any leases with terms of 12 months or less on our consolidated balance sheets.

At present, the majority of the Partnership’s active leases are classified as operating in accordance with Topic 842. Balances related to operating leases are included in operating lease ROU assets, accrued and other current liabilities, operating lease current liabilities and non-current operating lease liabilities in our consolidated balance sheets. Finance leases represent a small portion of the active lease agreements and are included in finance lease ROU assets, current maturities of long-term debt and long-term debt, less current maturities in our consolidated balance sheets. The ROU assets represent the Partnership’s right to use an underlying asset for the lease term and lease liabilities represent the obligation of the Partnership to make minimum lease payments arising from the lease for the duration of the lease term.

Most leases include one or more options to renew, with renewal terms that can extend the lease term from one to 20 years or greater. The exercise of lease renewal options is typically at the sole discretion of the Partnership and lease extensions are evaluated on a lease-by-lease basis. Leases containing early termination clauses typically require the agreement of both parties to the lease. At the inception of a lease, all renewal options reasonably certain to be exercised are considered when determining the lease term. Presently, the Partnership does not have leases that include options to purchase or automatic transfer of ownership of the leased property to the Partnership. The depreciable life of lease assets and leasehold improvements are limited by the expected lease term.

To determine the present value of future minimum lease payments, we use the implicit rate when readily determinable. Presently, because many of our leases do not provide an implicit rate, the Partnership applies its incremental borrowing rate based on the information available at the lease commencement date to determine the present value of minimum lease payments. The operating and finance lease ROU assets include any lease payments made and exclude lease incentives.

Minimum rent payments are expensed on a straight-line basis over the term of the lease. In addition, some leases require additional contingent or variable lease payments, which are based on the factors specific to the individual agreement. Variable lease payments the Partnership is typically responsible for include payment of real estate taxes, maintenance expenses and insurance.

For short-term leases (leases that have term of twelve months or less upon commencement), lease payments are recognized on a straight-line basis and no ROU assets are recorded.

The components of operating and finance lease amounts recognized in the accompanying consolidated balance sheets as of December 31, 2025 and 2024 were as follows:


	December 31,
	2025		2024
Operating leases:
Lease right-of-use assets, net	$	1,736	$	753
Operating lease current liabilities	245		67
Accrued and other current liabilities
Non-current operating lease liabilities	1,515		730
Finance leases:
Property, plant and equipment, net	$	1	$	1
Lease right-of-use assets, net	104		56

Current maturities of long-term debt	25		8
Long-term debt, less current maturities	82		50
Other non-current liabilities	1		1

The components of lease expense for the years ended December 31, 2025 and 2024 were as follows:


		Year Ended December 31,
	Income Statement Location	2025		2024
Operating lease costs:
Operating lease cost	Cost of goods sold	$	—	$	1
Operating lease cost	Operating expenses	116		71
Operating lease cost	Selling, general and administrative	21		19
Total operating lease costs		137		91
Finance lease costs:
Amortization of lease assets	Depreciation, depletion and amortization	5		2
Interest on lease liabilities	Interest expense, net of capitalized interest	3		2
Total finance lease costs		8		4
Short-term lease cost	Operating expenses	105		69
Variable lease cost	Operating expenses	12		19
Lease costs, gross		262		183
Less: Sublease income	Other revenue	35		45
Lease costs, net		$	227	$	138

The weighted-average remaining lease terms and weighted-average discount rates as of December 31, 2025 and 2024 were as follows:


	December 31,
	2025		2024
Weighted-average remaining lease term (years):
Operating leases	20		18
Finance leases	14		15
Weighted-average discount rate (%):
Operating leases	6	%	6	%
Finance leases	5	%	6	%

Cash flows and non-cash activity related to leases for the years ended December 31, 2025 and 2024 were as follows:


	Year Ended December 31,
	2025		2024


Operating cash flows from operating leases	$	(113)	$	(94)
Operating cash flows from finance leases	(3)		(2)
Financing cash flows from finance leases	(9)		(6)

Lease assets obtained in exchange for new finance lease liabilities	15		1
Lease assets obtained in exchange for new operating lease liabilities	281		6

Maturities of lease liabilities as of December 31, 2025 are as follows:


	Operating leases		Finance leases		Total
2026	$	288	$	26	$	314
2027	236		19		255
2028	210		18		228
2029	183		14		197
2030	165		9		174
Thereafter	1,661		53		1,714
Total lease payments	2,743		139		2,882
Less: present value discount	983		31		1,014
Present value of lease liabilities	$	1,760	$	108	$	1,868

Lessor Accounting

Sunoco LP leases or subleases a portion of its real estate portfolio to third-party companies as a stable source of long-term revenue. Sunoco LP’s lessor and sublease portfolio consists mainly of operating leases with convenience store operators. At this time, most lessor agreements contain five-year terms with renewal options to extend and early termination options based on established terms specific to the individual agreement. Additionally, Sunoco LP leases certain of its storage tanks in exchange for a fixed fee, subject to an annual consumer price index adjustment.

Sunoco LP’s future minimum operating lease payments receivable as of December 31, 2025 are as follows:


	Lease Payments
2026	$	154
2027	124
2028	98
2029	78
2030	68
Thereafter	369
Total undiscounted cash flows	$	891

Cybersecurity Risk Management and Strategy Disclosure	12 Months Ended
Cybersecurity Risk Management and Strategy Disclosure	Dec. 31, 2025
Cybersecurity Risk Management, Strategy, and Governance [Line Items]
Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]	ITEM 1C. CYBERSECURITY Description of Processes for Assessing, Identifying and Managing Cybersecurity Risks The information and operational technology infrastructure we use is important to the operation of our business and to our ability to perform day-to-day operations. In the normal course of business, we may collect and store certain sensitive information of the Partnership, including proprietary and confidential business information, trade secrets, intellectual property, sensitive third-party and employee information, and certain personally identifiable information. The Partnership maintains a shared services cybersecurity program for assessing, identifying and managing material risks from cybersecurity threats. This program includes processes that are modeled after the National Institute of Standards and Technology’s Cybersecurity Framework and focuses on using business drivers to guide cybersecurity activities. This program is managed by our Chief Information Officer, who is supported by a team of full-time employees tasked with conducting our day-to-day information technology (“IT”) operations (collectively, the “IT team”). Furthermore, the Partnership considers cybersecurity risks as part of, and has incorporated its cybersecurity program into, the Partnership’s overall risk management processes. Through engagement with the guidance of the Federal Bureau of Investigation (FBI), Cybersecurity and Infrastructure Security Agency (CISA), Transportation Security Administration (TSA) and the U.S. Coast Guard (USCG), we seek to follow industry cybersecurity standards and protect our infrastructure against cyber attacks from domestic and international threats. We seek to use a defense-in-depth approach for cybersecurity management, layers of technology, policies and training at all levels of the enterprise designed to keep the Partnership’s assets secure and operational. We use various processes as part of our efforts to maintain the confidentiality, integrity and availability of our systems, including security threat intelligence, incident response, identity and access management, supply-chain security assessments, endpoint extended detection and response protection, network segmentation, data encryption, event monitoring and a Security Operations Center (SOC). In an effort to validate the effectiveness of our cybersecurity program and assess such program’s compliance with legal and regulatory requirements, we engage third-party service providers to perform audits, assessments and penetration tests. Cybersecurity awareness among our employees is promoted with regular training and awareness programs. All employees who have access to our systems are required to undergo annual cybersecurity training and, each year, our employees must review and acknowledge our cybersecurity policies. Further, our IT team is trained to understand how to manage, use and protect personally identifiable information. User access controls have been implemented to limit unauthorized access to sensitive information and critical systems. Employees are required to use multifactor authentication and keep their passwords confidential, among other measures. We recognize that third-party service providers may introduce cybersecurity risks. In an effort to mitigate these risks, before contracting with certain technology service providers, when possible, we conduct due diligence to evaluate their cybersecurity capabilities. Additionally, we endeavor to include cybersecurity requirements in our contracts with these providers and endeavor to require them to adhere to security standards and protocols. Further, we also endeavor to engage with any third-party service providers with access to personally identifiable employee information to evaluate their security controls. Finally, the Partnership maintains cybersecurity insurance coverage. Impact of Risks from Cybersecurity Threats The energy industry’s increasing dependence on information technology and operational technology to support critical functions, such as energy distribution and management activities, has heightened its vulnerability to cybersecurity incidents. Consequently, the global surge in cybersecurity incidents, whether caused by intentional attacks or accidental events, presents a significant challenge to our sector. As cybersecurity threats grow in complexity and scale, preventing, detecting, mitigating and remediating these incidents remains a continuous and increasingly demanding task for the industry. Compliance with evolving cybersecurity reporting requirements, such as those mandated by FERC, presents significant challenges. These regulations necessitate timely and detailed reporting of cyber incidents, demanding substantial resources and robust internal processes to ensure adherence. Failure to comply could result in legal penalties, increased regulatory scrutiny and reputational damage. Moreover, the dynamic nature of these requirements may lead to overlapping or inconsistent obligations, further complicating compliance efforts. Monitoring these developments and integrating them into our cybersecurity and compliance frameworks is essential to mitigate potential risks. As of the date of this Annual Report on Form 10-K, though the Partnership and our service providers have experienced certain cybersecurity incidents, we are not aware of any cybersecurity threats that have materially affected, or are reasonably likely to materially affect, the Partnership, either financially or operationally. Cybersecurity incident response is a component of both the Partnership’s cybersecurity program and the Partnership’s business continuity plans, which are designed to limit service interruptions and provide for continued business operation in the event of disaster, whether physical, environmental or cyber in nature. However, we recognize that cybersecurity threats are continually evolving, and there remains a risk that a cybersecurity incident could potentially negatively impact the Partnership. Despite the implementation of our cybersecurity processes, we cannot guarantee that a significant cybersecurity attack will not occur. A successful attack on our information system or operational technology system could have significant consequences to our business, including the interruption of key services that our customers depend on. While we devote resources to our security measures to protect our systems and information, these measures cannot provide absolute security. Due to the number of acquisitions made by the Partnership over the past few years and the time it takes to implement technology standards across the enterprise, certain assets may be in different stages of integration and may have incomplete cybersecurity controls applied. For additional information on cybersecurity risks, see “Item 1A. Risk Factors—Cybersecurity attacks, data breaches and other disruptions affecting us, or our service providers, could materially and adversely affect our business, operations, reputation, and financial results; and —Our operations could be disrupted if our information systems fail, causing increased expenses and loss of sales.” Board of Directors’ Oversight and Management’s Role Our Chief Information Officer is responsible for assessing and managing the Partnership’s material risks from cybersecurity threats, including cybersecurity threat prevention, detection, mitigation and remediation for the combined organization, and oversees the Partnership’s functions of IT, cybersecurity, infrastructure and IT governance (including the Partnership’s IT team). Our Chief Information Officer has more than 35 years of experience leading business technology functions. The Partnership’s IT team supports the Chief Information Officer in our efforts to comply with applicable cybersecurity standards, establish effective cybersecurity protocols and protect the integrity, confidentiality and availability of our IT infrastructure. The members of this team have over 50 years of combined experience in the field of IT, including 20 years dedicated to cybersecurity, and hold various certifications, including Global Industrial Cyber Security Professional (GICSP), Certified Information Systems Security Professional (CISSP) and Certified Ethical Hacker (CEH) certifications. Our cyber incident response plan requires IT team members who detect suspicious activity in our IT environment to escalate that activity to a supervisor who then evaluates the threat. If necessary, the suspicious activity is reported to the Chief Information Officer. Management (including representatives from the legal, human resources, IT and corporate security departments) is notified by the IT team whenever a discovered cybersecurity incident may potentially have a significant impact on our business operations. The Partnership’s Board of Directors has delegated the responsibility for the oversight of cybersecurity risks to the Audit Committee. The IT team provides periodic cybersecurity program updates to senior management and to the Audit Committee. Management also updates the Audit Committee as new risks are identified and regarding the steps taken to mitigate such risks. The Audit Committee reviews periodic reporting and updates regarding our cybersecurity risk management.
Cybersecurity Risk Management Processes Integrated [Flag]	true
Cybersecurity Risk Management Third Party Engaged [Flag]	true
Cybersecurity Risk Third Party Oversight and Identification Processes [Flag]	true
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag]	false
Cybersecurity Risk Board of Directors Oversight [Text Block]	Board of Directors’ Oversight and Management’s Role Our Chief Information Officer is responsible for assessing and managing the Partnership’s material risks from cybersecurity threats, including cybersecurity threat prevention, detection, mitigation and remediation for the combined organization, and oversees the Partnership’s functions of IT, cybersecurity, infrastructure and IT governance (including the Partnership’s IT team). Our Chief Information Officer has more than 35 years of experience leading business technology functions. The Partnership’s IT team supports the Chief Information Officer in our efforts to comply with applicable cybersecurity standards, establish effective cybersecurity protocols and protect the integrity, confidentiality and availability of our IT infrastructure. The members of this team have over 50 years of combined experience in the field of IT, including 20 years dedicated to cybersecurity, and hold various certifications, including Global Industrial Cyber Security Professional (GICSP), Certified Information Systems Security Professional (CISSP) and Certified Ethical Hacker (CEH) certifications. Our cyber incident response plan requires IT team members who detect suspicious activity in our IT environment to escalate that activity to a supervisor who then evaluates the threat. If necessary, the suspicious activity is reported to the Chief Information Officer. Management (including representatives from the legal, human resources, IT and corporate security departments) is notified by the IT team whenever a discovered cybersecurity incident may potentially have a significant impact on our business operations. The Partnership’s Board of Directors has delegated the responsibility for the oversight of cybersecurity risks to the Audit Committee. The IT team provides periodic cybersecurity program updates to senior management and to the Audit Committee. Management also updates the Audit Committee as new risks are identified and regarding the steps taken to mitigate such risks. The Audit Committee reviews periodic reporting and updates regarding our cybersecurity risk management.
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block]	The IT team provides periodic cybersecurity program updates to senior management and to the Audit Committee. Management also updates the Audit Committee as new risks are identified and regarding the steps taken to mitigate such risks. The Audit Committee reviews periodic reporting and updates regarding our cybersecurity risk management.
Cybersecurity Risk Management Positions or Committees Responsible [Flag]	true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block]	The Partnership’s Board of Directors has delegated the responsibility for the oversight of cybersecurity risks to the Audit Committee.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block]	Our Chief Information Officer is responsible for assessing and managing the Partnership’s material risks from cybersecurity threats, including cybersecurity threat prevention, detection, mitigation and remediation for the combined organization, and oversees the Partnership’s functions of IT, cybersecurity, infrastructure and IT governance (including the Partnership’s IT team). Our Chief Information Officer has more than 35 years of experience leading business technology functions. The Partnership’s IT team supports the Chief Information Officer in our efforts to comply with applicable cybersecurity standards, establish effective cybersecurity protocols and protect the integrity, confidentiality and availability of our IT infrastructure. The members of this team have over 50 years of combined experience in the field of IT, including 20 years dedicated to cybersecurity, and hold various certifications, including Global Industrial Cyber Security Professional (GICSP), Certified Information Systems Security Professional (CISSP) and Certified Ethical Hacker (CEH) certifications.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block]	Our cyber incident response plan requires IT team members who detect suspicious activity in our IT environment to escalate that activity to a supervisor who then evaluates the threat. If necessary, the suspicious activity is reported to the Chief Information Officer. Management (including representatives from the legal, human resources, IT and corporate security departments) is notified by the IT team whenever a discovered cybersecurity incident may potentially have a significant impact on our business operations.
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag]	true

Income Taxes Components of Income Tax (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Income (Loss), Including Portion Attributable to Noncontrolling Interest, before Tax	$ 6,058	$ 7,106	$ 5,597
Current expense:
Federal	164	198	56
State	1	66	44
Current Foreign Tax Expense (Benefit)	7	1	0
Total	172	265	100
Deferred expense (benefit):
Federal	177	175	227
State	(23)	101	(24)
Deferred Foreign Income Tax Expense (Benefit)	24	0	0
Total	178	276	203
Income tax expense	350	541	303
Additions attributable to tax positions taken in prior years	0	34	0
UNITED STATES
Income (Loss), Including Portion Attributable to Noncontrolling Interest, before Tax	5,869	7,101	5,602
Non-US
Income (Loss), Including Portion Attributable to Noncontrolling Interest, before Tax	$ 189	$ 5	$ (5)

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingencies And Environemental Liabilities (Environmental Liabilities) (Details) $ in Millions	Dec. 31, 2025 USD ($)	Dec. 31, 2024 USD ($)
Environmental Remediation Obligations [Abstract]
Current	$ 62	$ 51
Non-current	354	227
Total environmental liabilities	$ 416	$ 278
Site Contingency, Number of Sites Needing Remediation	31

Equity Tax amounts in components of other comprehensive income (loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Statement of Comprehensive Income [Abstract]
Available-for-sale securities	$ (3)	$ (3)
Foreign currency translation adjustment	2	2
Other Comprehensive Income (Loss), Tax	$ (1)	$ (1)

Amount of tax expense (benefit) allocated to other comprehensive income (loss).

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Section 45
-Paragraph 12
-SubTopic 10
-Topic 220
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482790/220-10-45-12

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 220
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482765/220-10-50-4

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 830
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481674/830-30-50-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 830
-SubTopic 30
-Name Accounting Standards Codification
-Section 45
-Paragraph 17
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481694/830-30-45-17

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 830
-SubTopic 30
-Name Accounting Standards Codification
-Section 45
-Paragraph 20
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481694/830-30-45-20

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 944
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04(19))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477250/944-220-S99-1

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 10
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-10

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 20
-Name Accounting Standards Codification
-Section 45
-Paragraph 11
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482659/740-20-45-11

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 220
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03(21))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483621/220-10-S99-2

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-04(23))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478524/942-220-S99-1

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 20
-Name Accounting Standards Codification
-Section 45
-Paragraph 2
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482659/740-20-45-2

Contract with Customer, Asset and Liability [Table Text Block]

Revenue (Tables)

12 Months Ended

Dec. 31, 2025

The following table summarizes the consolidated activity of our contract liabilities:


	Contract Liabilities
Balance, December 31, 2023	$	749
Additions	1,256
Revenue recognized	(1,246)

Balance, December 31, 2024	759
Additions	478
Parkland acquisition by Sunoco LP	84
Revenue recognized	(576)

Balance, December 31, 2025	$	745

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block]


	Years Ending December 31,
	2026		2027		2028		Thereafter		Total
Revenue expected to be recognized on contracts with customers existing as of December 31, 2025	$	7,895	$	6,379	$	4,808	$	14,523	$	33,605

Contract with Customer, Asset and Liability [Table Text Block]

The balances of Sunoco LP’s contract assets and contract liabilities as of December 31, 2025, 2024 and 2023 were as follows:


	December 31,
	2025		2024		2023
Contract Balances
Contract assets	$	480	$	288	$	256
Accounts receivable from contracts with customers	1,686		1,084		809
Contract liabilities	125		39		—

Equity (Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Partners' Capital Notes [Abstract]
Available-for-sale securities	$ 30	$ 20
Foreign currency translation adjustment	(12)	(6)
Actuarial gain related to pensions and other postretirement benefits	54	45
Investments in unconsolidated affiliates, net	10	14
Total AOCI, net of tax	$ 82	$ 73

Amount after tax, before reclassification adjustments of gain (loss) on foreign currency translation adjustments, foreign currency transactions designated and effective as economic hedges of a net investment in a foreign entity and intra-entity foreign currency transactions that are of a long-term-investment nature.

Investments in Unconsolidated Affiliates (Carrying Values) (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2025

Dec. 31, 2024

Dec. 31, 2023

^[1]

$ 3,589

$ 3,266

$ 3,097

Other Affiliates [Member]

^[2]

419

379

383

Citrus [Member]

1,843

1,818

153

136

146

MEP [Member]

279

309

White Cliffs

177

196

994

654

Explorer

SESH

231

223

$ 57

$ 45

$ 31

[1]	Amounts reflected above exclude Sunoco LP’s investments in the ET-S Permian and J.C. Nolan joint ventures, which are eliminated in consolidation.
[2]	Amounts reflected above exclude Sunoco LP’s earnings from the ET-S Permian and J.C. Nolan joint ventures, which are eliminated in consolidation.

Amount of income (loss) for proportionate share of equity method investee's income (loss).

Schedule of Income before Income Tax, Domestic and Foreign

Debt Obligations Debt Obligations (Future Maturities of Long-Term Debt) (Details) $ in Millions	Dec. 31, 2025 USD ($)
Debt Obligations [Abstract]
2025	$ 3,512
2026	5,314
2027	4,505
2028	11,619
2029	6,154
Thereafter	37,581
Long-term Debt	$ 68,685

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2025

Income Tax Disclosure [Abstract]

The Partnership’s income (loss) before income tax expense by geographic area is shown in the table below:


	Years Ended December 31,
	2025		2024		2023

United States	$	5,869	$	7,101	$	5,602
Foreign	189		5		(5)
Total	$	6,058	$	7,106	$	5,597

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

The components of the federal and state income tax expense (benefit) of our taxable subsidiaries are summarized as follows:


	Years Ended December 31,
	2025		2024		2023
Current expense:
Federal	$	164	$	198	$	56
State	1		66		44
Foreign	7		1		—
Total	172		265		100
Deferred expense (benefit):
Federal	177		175		227
State	(23)		101		(24)
Foreign	24		—		—
Total	178		276		203
Total income tax expense	$	350	$	541	$	303

Cash paid for income taxes were as follows:


	Year Ended December 31,
	2025		2024		2023
Cash paid for income taxes, net of refunds (excluding federal tax credits purchased from non-governmental third parties):
Federal:	$	—	$	150	$	64
State:
Texas	26		14		16
Pennsylvania	*		*		6
New Jersey	*		13		6
Other	12		29		11

Foreign:
Canada	62		—		—
Other	3		—		—

Total	$	103	$	206	$	103

Cash paid for federal tax credits purchased from non-governmental third parties	$	97	$	47	$	—

*Amount of income taxes paid during the year did not meet the 5% disaggregation threshold.

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

at the United States statutory rate to the Partnership’s income tax benefit for the years ended December 31, 2025, 2024 and 2023 is as follows:


	Years Ended December 31,
	2025			2024			2023
	Amount		Percent	Amount		Percent	Amount		Percent
Income tax expense at United States statutory rate	$	1,272	21.00%	$	1,492	21.00%	$	1,175	21.00%
Increase (reduction) in income taxes resulting from:
Non-taxable Partnership earnings	(944)		(15.59)%	(1,084)		(15.25)%	(884)		(15.79)%

State and local income tax, net of federal income tax effect(1)	4		0.07%	113		1.59%	37		0.65%
Foreign tax effects	(4)		(0.06)%	—		—	—		—
Effect of cross-border tax laws	6		0.10%	—		—	—		—
Changes in valuation allowances	2		0.03%	—		—	(3)		(0.05)%
Changes in unrecognized tax benefits	(5)		(0.08)%	21		0.29%	(14)		(0.24)%






Other adjustments	19		0.32%	(1)		(0.02)%	(8)		(0.16)%
Income tax expense	$	350	5.79%	$	541	7.61%	$	303	5.41%

(1)State taxes that made up the majority (greater than 50 percent) of the tax effect in this category were Texas in 2025, Pennsylvania, Texas, New Jersey and New York in 2024 and Texas in 2023.

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]


	December 31,
	2025		2024
Deferred income tax assets:
Net operating losses and other carryforwards	$	443	$	197


Other	75		42
Total deferred income tax assets	518		239
Valuation allowance	(64)		—
Net deferred income tax assets	454		239

Deferred income tax liabilities:
Property, plant and equipment	(1,083)		(224)

Investments in affiliates	(4,200)		(4,098)
Trademarks	(240)		(82)
Other	(61)		(18)
Total deferred income tax liabilities	(5,584)		(4,422)
Net deferred income taxes	$	(5,130)	$	(4,183)

The completion of the Parkland transaction significantly increased the deferred tax assets (liabilities). The table below provides a rollforward of the net deferred income tax liability:


	December 31,
	2025		2024
Net deferred income tax liability, beginning of year	$	(4,183)	$	(3,931)
Acquired in Parkland acquisition	(755)		—
Acquired in NuStar acquisition	—		(3)
Tax accrual	(192)		(249)
Net deferred income tax liability	$	(5,130)	$	(4,183)

Schedule Of Unrecognized Tax Benefits [Table Text Block]

The following table sets forth the changes in unrecognized tax benefits:


	Years Ended December 31,
	2025		2024		2023
Balance at beginning of year	$	74	$	40	$	52


Additions attributable to tax positions taken in prior years	—		34		—
Reduction attributable to tax positions taken in prior years	(8)		—		(9)
Settlements	—		—		(3)

Balance at end of year	$	66	$	74	$	40

Retirement Benefits

12 Months Ended

Dec. 31, 2025

Retirement Benefits [Abstract]

Retirement Benefits

RETIREMENT BENEFITS:

Savings and Profit Sharing Plans

We and our subsidiaries sponsor defined contribution savings and profit sharing plans, which collectively cover virtually all eligible employees, including those of Sunoco LP and USAC. Employer matching contributions are calculated using a formula based on employee contributions. We and our subsidiaries made matching contributions of $122 million, $103 million and $86 million to these 401(k) savings plans for the years ended December 31, 2025, 2024 and 2023, respectively.

Pension and Other Postretirement Benefit Plans


	December 31, 2025						December 31, 2024
	Pension Benefits						Pension Benefits
	Funded Plans		Unfunded Plans		Other Postretirement Benefits		Funded Plans		Unfunded Plans		Other Postretirement Benefits
Change in benefit obligation:
Benefit obligation at beginning of period	$	158	$	16	$	127	$	23	$	17	$	138
Service cost	—		—		2		1		—		—
Interest cost	4		1		7		6		1		7
Amendments	—		—		7		—		—		(11)
Benefits paid, net	(137)		(3)		(11)		(37)		(3)		(13)

Actuarial gain and other	(4)		1		(1)		13		1		(6)
Settlements	(21)		—		—		—		—		—
NuStar acquisition	—		—		—		152		—		12
Benefit obligation at end of period	—		15		131		158		16		127

Change in plan assets:
Fair value of plan assets at beginning of period	182		—		295		22		—		277
Return on plan assets and other	3		—		34		13		—		29
Employer contributions	1		—		3		5		—		2
Benefits paid, net	(137)		—		(11)		(36)		—		(13)
Settlements	(21)		—		—		—		—		—
NuStar acquisition	—		—		—		178		—		—
Fair value of plan assets at end of period	28		—		321		182		—		295

Amount underfunded (overfunded) at end of period	$	(28)	$	15	$	(190)	$	(24)	$	16	$	(168)

Amounts recognized in the consolidated balance sheets consist of:
Current assets	$	28	$	—	$	—	$	—	$	—	$	—
Non-current assets	—		—		208		24		—		185
Current liabilities	—		(2)		(3)		—		(3)		(3)
Non-current liabilities	—		(13)		(15)		—		(13)		(14)
	$	28	$	(15)	$	190	$	24	$	(16)	$	168

Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial gain (loss)	$	—	$	—	$	(73)	$	(9)	$	(1)	$	(59)
Prior service credit	—		—		17		—		—		25
	$	—	$	—	$	(56)	$	(9)	$	(1)	$	(34)

The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets:


	December 31, 2025						December 31, 2024
	Pension Benefits						Pension Benefits
	Funded Plans		Unfunded Plans		Other Postretirement Benefits		Funded Plans		Unfunded Plans		Other Postretirement Benefits
Projected benefit obligation	$	—	$	15	N/A		$	22	$	16	N/A
Accumulated benefit obligation	—		15		$	131	158		16		$	127
Fair value of plan assets	28		—		321		182		—		295

Components of Net Periodic Benefit Cost


	December 31, 2025				December 31, 2024
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Net periodic benefit cost:
Service cost	$	—	$	2	$	1	$	—
Interest cost	1		7		6		7
Expected return on plan assets	—		(14)		(8)		(13)
Prior service cost amortization	(2)		3		(2)		2
Actuarial gain amortization	—		(3)		—		(1)


Settlements	—		—		2		—
Net periodic benefit cost	$	(1)	$	(5)	$	(1)	$	(5)

Assumptions

The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the following table:


	December 31, 2025				December 31, 2024
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Discount rate	5.40	%	4.89	%	4.80	%	4.40	%

The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the following table:


	December 31, 2025				December 31, 2024
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Discount rate	5.40	%	4.89	%	5.40	%	4.40	%
Expected return on assets:
Tax exempt accounts	7.00	%	7.00	%	7.00	%	7.00	%
Taxable accounts	—	%	4.75	%	4.26	%	4.75	%

The long-term expected rate of return on plan assets was estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. Current market factors such as inflation and

interest rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness.

The assumed health care cost trend weighted-average rates used to measure the expected cost of benefits covered by the plans are shown in the following table:


	December 31,
	2025		2024
Health care cost trend rate	7.49	%	7.44	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.18	%	5.09	%
Year that the rate reaches the ultimate trend rate	2033		2032

Changes in the health care cost trend rate assumptions are not expected to have a significant impact on postretirement benefits.

Plan Assets

The fair value of the pension plan assets by asset category at the dates indicated is as follows:


			Fair Value Measurements at December 31, 2025
	Fair Value Total		Level 1		Level 2		Level 3
Asset Category:
Cash and cash equivalents	$	28	$	28	$	—	$	—


			Fair Value Measurements at December 31, 2024
	Fair Value Total		Level 1		Level 2		Level 3
Asset Category:
Cash and cash equivalents	$	81	$	81	$	—	$	—
Mutual funds (1)	65		21		44		—
Fixed income securities	36		36		—		—
Total	$	182	$	138	$	44	$	—

(1)Comprised of approximately 100% equities as of December 31, 2024.

The fair value of other postretirement plan assets by asset category at the dates indicated is as follows:


			Fair Value Measurements at December 31, 2025
	Fair Value Total		Level 1		Level 2		Level 3
Asset category:
Cash and cash equivalents	$	4	$	4	$	—	$	—
Mutual funds(1)	216		216		—		—
Fixed income securities	101		—		101		—
Total	$	321	$	220	$	101	$	—

(1)Primarily composed of market index funds as of December 31, 2025.


			Fair Value Measurements at December 31, 2024
	Fair Value Total		Level 1		Level 2		Level 3
Asset category:
Cash and cash equivalents	$	8	$	8	$	—	$	—
Mutual funds(1)	189		189		—		—
Fixed income securities	98		—		98		—
Total	$	295	$	197	$	98	$	—

(1)Primarily composed of market index funds as of December 31, 2024.

The Level 1 plan assets are valued based on active market quotes. The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines.

Contributions

We expect to contribute $2 million to pension plans and $1 million to other postretirement plans in 2026. The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.

Benefit Payments


	Pension Benefits - Funded Plans		Pension Benefits - Unfunded Plans		Other Postretirement Benefits (Gross, Before Medicare Part D)
2026	$	—	$	2	$	13
2027	—		2		13
2028	—		2		12
2029	—		2		11
2030	—		1		11
2031 – 2035	—		4		45

The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.

The Partnership does not expect to receive any Medicare Part D subsidies in any future periods.

The entire disclosure for retirement benefits.

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (o)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (p)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (q)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 60
-Name Accounting Standards Codification
-Section 50
-Paragraph 3
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480266/715-60-50-3

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480126/715-20-S99-2

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 70
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480794/715-70-50-1

Reference 7: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 17
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480482/715-20-55-17

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(iv)(03)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(i)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (l)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org/715/tableOfContent

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(iii)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (r)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (r)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Change In ETE Common Units

Estimates (Schedule of Inventory) (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Inventory, Net [Abstract]
Natural gas, NGLs and refined products	$ 3,506	$ 1,989
Crude oil	286	400
Spare parts and other	978	681
Total inventories	$ 4,770	$ 3,070

Equity (Tables)

12 Months Ended

Dec. 31, 2025

The changes in Energy Transfer Common Units during the years ended December 31, 2025, 2024 and 2023 were as follows:


	Years Ended December 31,
	2025	2024	2023
Number of Common Units, beginning of period	3,431.0	3,367.5	3,094.4

Common Units issued in mergers and acquisitions (1)	—	50.8	260.2

Issuance of Common Units (2)	9.0	12.7	12.9
Number of Common Units, end of period	3,440.0	3,431.0	3,367.5

(1)Includes common units issued related to our acquisitions of WTG Midstream in 2024 and of Crestwood and Lotus Midstream in 2023.

(2)Includes common units issued in connection with the distribution reinvestment program and restricted unit vestings.

Schedule of Preferred Units

The following table summarizes changes in the Energy Transfer Preferred Units:


	Preferred Unitholders
	Series A		Series B		Series C		Series D		Series E		Series F		Series G		Series H		Series I		Total










Balance, December 31, 2022	$	958	$	556	$	440	$	434	$	786	$	496	$	1,488	$	893	$	—	$	6,051
Distributions to partners	(96)		(36)		(40)		(36)		(61)		(34)		(106)		(59)		—		(468)
Units issued in Crestwood acquisition	—		—		—		—		—		—		—		—		413		413
Net income	86		36		38		37		61		34		106		59		6		463
Balance, December 31, 2023	948		556		438		435		786		496		1,488		893		419		6,459
Distributions to partners	(56)		(36)		(11)		(11)		(30)		(34)		(106)		(59)		(35)		(378)
Redemption of Preferred Units	(950)		—		(450)		(445)		(800)		—		—		—		—		(2,645)
Other, net	13		—		11		10		20		—		—		—		—		54
Net Income	45		36		12		11		24		34		106		59		35		362
Balance, December 31, 2024	—		556		—		—		—		496		1,488		893		419		3,852
Distributions to partners	—		(36)		—		—		—		(16)		(106)		(59)		(35)		(252)
Redemption of Preferred Units	—		—		—		—		—		(500)		—		—		—		(500)
Other, net	—		—		—		—		—		8		—		—		—		8
Net Income	—		36		—		—		—		12		106		59		35		248
Balance, December 31, 2025	$	—	$	556	$	—	$	—	$	—	$	—	$	1,488	$	893	$	419	$	3,356

Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]

The following table presents the components of AOCI, net of tax:


	December 31,
	2025		2024
Available-for-sale securities	$	30	$	20
Foreign currency translation adjustment	(12)		(6)

Actuarial gain related to pensions and other postretirement benefits	54		45
Investments in unconsolidated affiliates, net	10		14
Total AOCI, net of tax	$	82	$	73

The following table sets forth the tax amounts included in the respective components of other comprehensive income:


	December 31,
	2025		2024
Available-for-sale securities	$	(3)	$	(3)
Foreign currency translation adjustment	2		2

Total	$	(1)	$	(1)

ET [Member]

Distributions Made to Limited Partner, by Distribution [Table Text Block]

Our distributions declared and paid with respect to our common units were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2022

February 7, 2023

February 21, 2023

0.3050

March 31, 2023

May 8, 2023

May 22, 2023

0.3075

June 30, 2023

August 14, 2023

August 21, 2023

0.3100

September 30, 2023

October 30, 2023

November 20, 2023

0.3125

December 31, 2023

February 7, 2024

February 20, 2024

0.3150

March 31, 2024

May 13, 2024

May 20, 2024

0.3175

June 30, 2024

August 9, 2024

August 19, 2024

0.3200

September 30, 2024

November 8, 2024

November 19, 2024

0.3225

December 31, 2024

February 7, 2025

February 19, 2025

0.3250

March 31, 2025

May 9, 2025

May 20, 2025

0.3275

June 30, 2025

August 8, 2025

August 19, 2025

0.3300

September 30, 2025

November 7, 2025

November 19, 2025

0.3325

December 31, 2025

February 6, 2026

February 19, 2026

0.3350

Distributions Made to Limited Partner, by Distribution [Table Text Block]

Distributions on Sunoco LP’s common units and Class D Units declared and/or paid by Sunoco LP were as follows:


Quarter Ended	Payment Date	Per Common Unit Rate		Per Class D Unit Rate




























December 31, 2022	February 21, 2023	$	0.8255	$	—
March 31, 2023	May 22, 2023	0.8420		—
June 30, 2023	August 21, 2023	0.8420		—
September 30, 2023	November 20, 2023	0.8420		—
December 31, 2023	February 20, 2024	0.8420		—
March 31, 2024	May 20, 2024	0.8756		—
June 30, 2024	August 19, 2024	0.8756		—
September 30, 2024	November 19, 2024	0.8756		—
December 31, 2024	February 19, 2025	0.8865		—
March 31, 2025	May 20, 2025	0.8976		—
June 30, 2025	August 19, 2025	0.9088		—
September 30, 2025	November 19, 2025	0.9202		—
December 31, 2025	February 19, 2026	0.9317		0.9317

Schedule of Incentive Distributions Made to Managing Members or General Partners by Distribution [Table Text Block]


		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Target Amount	Common Unitholders	Holder of IDRs
Minimum Quarterly Distribution	$0.4375	100%	—%
First Target Distribution	$0.4375 to $0.503125	100%	—%
Second Target Distribution	$0.503125 to $0.546875	85%	15%
Third Target Distribution	$0.546875 to $0.656250	75%	25%
Thereafter	Above $0.656250	50%	50%

Distributions Made to Limited Partner, by Distribution [Table Text Block]

USAC Cash Distributions

Distributions on USAC’s units declared and/or paid by USAC were as follows:

Quarter Ended

Payment Date

Rate

December 31, 2022

February 3, 2023

0.5250

March 31, 2023

May 5, 2023

0.5250

June 30, 2023

August 4, 2023

0.5250

September 30, 2023

November 3, 2023

0.5250

December 31, 2023

February 2, 2024

0.5250

March 31, 2024

May 3, 2024

0.5250

June 30, 2024

August 2, 2024

0.5250

September 30, 2024

November 1, 2024

0.5250

December 31, 2024

February 7, 2025

0.5250

March 31, 2025

May 9, 2025

0.5250

June 30, 2025

August 8, 2025

0.5250

September 30, 2025

November 7, 2025

0.5250

December 31, 2025

February 6, 2026

0.5250

Preferred Units [Member]

Distributions Made to Limited Partner, by Distribution [Table Text Block]

Distributions on Energy Transfer’s preferred units declared and/or paid by Energy Transfer were as follows:


Period Ended	Record Date (1)	Payment Date (1)	Series A		Series B (2)		Series C		Series D		Series E		Series F		Series G (2)		Series H (2)		Series I (1)







December 31, 2022	February 1, 2023	February 15, 2023	$	31.25	$	33.125	$	0.4609	$	0.4766	$	0.4750	$	—	$	—	$	—	$	—
March 31, 2023	May 1, 2023	May 15, 2023	21.98		—		0.4609		0.4766		0.4750		33.7500		35.63		32.50		—
June 30, 2023	August 1, 2023	August 15, 2023	23.89		33.125		0.6294		0.4766		0.4750		—		—		—		—
September 30, 2023	November 1, 2023	November 15, 2023	24.67		—		0.6489		0.6622		0.4750		33.7500		35.63		32.50		—
December 31, 2023	February 1, 2024	February 15, 2024	24.71		33.125		0.6075		0.6199		0.4750		—		—		—		0.2111
March 31, 2024	May 1, 2024	May 15, 2024	23.99		—		—		—		0.4750		33.7500		35.63		32.50		0.2111
June 30, 2024	August 1, 2024	August 15, 2024	9.88		33.125		—		—		—		—		—		—		0.2111
September 30, 2024	November 1, 2024	November 15, 2024	—		—		—		—		—		33.7500		35.63		32.50		0.2111
December 31, 2024	February 1, 2025	February 17, 2025	—		33.125		—		—		—		—		—		—		0.2111
March 31, 2025	May 1, 2025	May 15, 2025	—		—		—		—		—		33.7500		35.63		32.50		0.2111
June 30, 2025	August 1, 2025	August 15, 2025	—		33.125		—		—		—		—		—		—		0.2111
September 30, 2025	November 1, 2025	November 14, 2025	—		—		—		—		—		—		35.63		32.50		0.2111
December 31, 2025	February 1, 2026	February 15, 2026	—		33.125		—		—		—		—		—		—		0.2111

(2)Series B, Series G and Series H distributions are currently paid on a semi-annual basis. Distributions on the Series B Preferred Units will begin to be paid quarterly on February 15, 2028.

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Narrative) (Details)							12 Months Ended
	Nov. 17, 2025 USD ($)	Dec. 17, 2024 USD ($)	Sep. 28, 2023 USD ($) Rate	Jan. 09, 2023 USD ($)	Oct. 24, 2022 USD ($)	Aug. 01, 2020 USD ($)	Dec. 31, 2025 USD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2019 USD ($)
Operating Leases, Rent Expense							$ 87,000,000	$ 72,000,000	$ 68,000,000
Payments for Environmental Liabilities							29,000,000	11,000,000
Total environmental liabilities							$ 416,000,000	$ 278,000,000
Site Contingency, Number of Sites Needing Remediation							31
Loss Contingency, Estimate of Possible Loss							$ 58,000,000
Litigation Settlement, Fee Expense							$ 161,000,000
Environmental Loss Contingency, Statement of Financial Position [Extensible Enumeration]							Other non-current liabilities	Other non-current liabilities
NEW YORK
Excise Taxes Collected							$ 20,000,000
Cline Class Action
Interest Statutory Rate \| Rate			12.00%
Cline Class Action \| Actual Damages
Payments for Legal Settlements						$ 75,000,000
Cline Class Action \| Punitive Damages [Member]
Payments for Legal Settlements						75,000,000
Cline Class Action \| Amended Actual Damages
Payments for Legal Settlements						$ 81,000,000
Ohio EPA
Loss Contingency, Damages Sought, Value										$ 3,000,000
Proposed Civil Penalty
Litigation Settlement, Fee Expense							40,000,000
Pending Litigation \| Rover - FERC Stoneman House
Loss Contingency, Damages Sought, Value							20,000,000
Crestwood \| Linde Engineering North America Inc.
Loss Contingency, Damages Paid, Value				$ 21,000,000
Loss Contingency, Reversal of Damages Awarded, Value		$ 22,000,000
Punitive Damages [Member] \| Cline Class Action
Loss Contingency, Damages Awarded, Value			$ 75,000,000
Punitive Damages [Member] \| Crestwood \| Linde Engineering North America Inc.
Loss Contingency, Damages Awarded, Value		21,000,000			$ 21,000,000
Loss Contingency, Reversal of Damages Awarded, Value		18,000,000
Related To Deductibles [Member]
Loss Contingency Accrual							324,000,000	$ 281,000,000
pre-judgement interest award \| Crestwood \| Linde Engineering North America Inc.
Loss Contingency, Damages Awarded, Value					18,000,000
other costs \| Crestwood \| Linde Engineering North America Inc.
Loss Contingency, Damages Awarded, Value					$ 5,000,000
Loss Contingency, Reversal of Damages Awarded, Value		$ 5,000,000
Legal Fees \| Massachusetts Attorney General v. New England Gas Company
Loss Contingency, Damages Sought, Value							$ 18,000,000
Actual Damages \| Cline Class Action
Loss Contingency, Damages Awarded, Value			104,000,000
Additional Interest \| Cline Class Action
Loss Contingency, Damages Awarded, Value			$ 23,000,000
Punitive Damages Vacated by Judge \| Cline Class Action
Loss Contingency, Damages Awarded, Value	$ 75,000,000

Lease Accounting - Cash flow (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Lessee, Lease, Description [Line Items]
Operating cash flows from finance leases	$ (3)	$ (2)
Financing cash flows from finance leases	(9)	(6)
Lease assets obtained in exchange for new finance lease liabilities	15	1
Lease assets obtained in exchange for new operating lease liabilities	281	6
Operating Leases [Member]
Lessee, Lease, Description [Line Items]
Net cash provided by operating activities	$ (113)	$ (94)

Derivative Assets And Liabilities (Derivative Amount Of Gain (Loss) Recognized) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ 241	$ 63	$ 83
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Cost of products sold, Other, net
Cost of goods sold
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ 241	57	47
Other, net
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ 0	$ 6	$ 36

Debt Obligations GoZone Bonds (Details) $ in Millions	12 Months Ended
Debt Obligations GoZone Bonds (Details) $ in Millions	Dec. 31, 2025 USD ($)
GoZone Series 2008
Debt Instrument [Line Items]
Debt Instrument, Issuance Date	Jun. 26, 2008
Senior Notes	$ 56
Debt Instrument, Interest Rate, Stated Percentage	6.10%
Debt Instrument, Maturity Date	Jun. 01, 2038
GoZone Series 2010
Debt Instrument [Line Items]
Debt Instrument, Issuance Date	Jul. 15, 2010
Senior Notes	$ 100
Debt Instrument, Interest Rate, Stated Percentage	6.35%
Debt Instrument, Maturity Date	Jul. 01, 2040
GoZone Series 2010A
Debt Instrument [Line Items]
Debt Instrument, Issuance Date	Oct. 07, 2010
Senior Notes	$ 43
Debt Instrument, Interest Rate, Stated Percentage	6.35%
Debt Instrument, Maturity Date	Oct. 01, 2040
GoZone Series 2010B
Debt Instrument [Line Items]
Debt Instrument, Issuance Date	Dec. 29, 2010
Senior Notes	$ 48
Debt Instrument, Interest Rate, Stated Percentage	6.10%
Debt Instrument, Maturity Date	Dec. 01, 2040
GoZone Series 2011
Debt Instrument [Line Items]
Debt Instrument, Issuance Date	Oct. 01, 2025
Senior Notes	$ 75
Debt Instrument, Interest Rate, Stated Percentage	3.70%
Debt Instrument, Maturity Date	Aug. 01, 2041

Lease Accounting (Tables)

12 Months Ended

Dec. 31, 2025

Leases [Abstract]

Schedule of Property Subject to or Available for Operating Lease [Table Text Block]

The components of operating and finance lease amounts recognized in the accompanying consolidated balance sheets as of December 31, 2025 and 2024 were as follows:


	December 31,
	2025		2024
Operating leases:
Lease right-of-use assets, net	$	1,736	$	753
Operating lease current liabilities	245		67
Accrued and other current liabilities
Non-current operating lease liabilities	1,515		730
Finance leases:
Property, plant and equipment, net	$	1	$	1
Lease right-of-use assets, net	104		56

Current maturities of long-term debt	25		8
Long-term debt, less current maturities	82		50
Other non-current liabilities	1		1

Lease, Cost [Table Text Block]

The components of lease expense for the years ended December 31, 2025 and 2024 were as follows:


		Year Ended December 31,
	Income Statement Location	2025		2024
Operating lease costs:
Operating lease cost	Cost of goods sold	$	—	$	1
Operating lease cost	Operating expenses	116		71
Operating lease cost	Selling, general and administrative	21		19
Total operating lease costs		137		91
Finance lease costs:
Amortization of lease assets	Depreciation, depletion and amortization	5		2
Interest on lease liabilities	Interest expense, net of capitalized interest	3		2
Total finance lease costs		8		4
Short-term lease cost	Operating expenses	105		69
Variable lease cost	Operating expenses	12		19
Lease costs, gross		262		183
Less: Sublease income	Other revenue	35		45
Lease costs, net		$	227	$	138

Lessee, Operating Lease, Liability, Maturity [Table Text Block]

The weighted-average remaining lease terms and weighted-average discount rates as of December 31, 2025 and 2024 were as follows:


	December 31,
	2025		2024
Weighted-average remaining lease term (years):
Operating leases	20		18
Finance leases	14		15
Weighted-average discount rate (%):
Operating leases	6	%	6	%
Finance leases	5	%	6	%

Maturities of lease liabilities as of December 31, 2025 are as follows:


	Operating leases		Finance leases		Total
2026	$	288	$	26	$	314
2027	236		19		255
2028	210		18		228
2029	183		14		197
2030	165		9		174
Thereafter	1,661		53		1,714
Total lease payments	2,743		139		2,882
Less: present value discount	983		31		1,014
Present value of lease liabilities	$	1,760	$	108	$	1,868

Schedule of additional lease information [Table Text Block]

Cash flows and non-cash activity related to leases for the years ended December 31, 2025 and 2024 were as follows:


	Year Ended December 31,
	2025		2024


Operating cash flows from operating leases	$	(113)	$	(94)
Operating cash flows from finance leases	(3)		(2)
Financing cash flows from finance leases	(9)		(6)

Lease assets obtained in exchange for new finance lease liabilities	15		1
Lease assets obtained in exchange for new operating lease liabilities	281		6

Lessor, Operating Lease, Payments to be Received, Maturity [Table Text Block]

Sunoco LP’s future minimum operating lease payments receivable as of December 31, 2025 are as follows:


	Lease Payments
2026	$	154
2027	124
2028	98
2029	78
2030	68
Thereafter	369
Total undiscounted cash flows	$	891

Retirement Benefits (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Retirement Benefits [Line Items]
Defined Contribution Plan, Cost	$ 122	$ 103	$ 86
Pension Benefits
Retirement Benefits [Line Items]
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year	2
Large Cap US Equitiies		100.00%
Other Postretirement Benefits
Retirement Benefits [Line Items]
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year	$ 1

Retirement Benefits (Obligations and Funded Status) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Defined Benefit Plan, Benefit Obligation, Business Combination	$ 0	$ 12
Settlements	0	0
Nustar Acquisition
Change in plan assets:
Return on plan assets and other	0	0
Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	158	23
Service cost	0	1
Interest cost	1	6
Defined Benefit Plan, Benefit Obligation		158
Change in plan assets:
Defined Benefit Plan, Plan Assets, Amount	182
Defined Benefit Plan, Plan Assets, Amount		182
Amounts recognized in the consolidated balance sheets consist of:
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position		24
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax		(9)
Settlements	0	2
Other Postretirement Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	127	138
Service cost	2	0
Interest cost	7	7
Defined Benefit Plan, Accumulated Benefit Obligation, Increase (Decrease) for Plan Amendment	7	(11)
Benefits paid, net	(11)	(13)
Actuarial gain and other	(1)	(6)
Defined Benefit Plan, Benefit Obligation	131	127
Change in plan assets:
Defined Benefit Plan, Plan Assets, Amount	295	277
Return on plan assets and other	34	29
Employer contributions	3	2
Benefits paid, net	(11)	(13)
Defined Benefit Plan, Plan Assets, Amount	321	295
Amount underfunded (overfunded) at end of period	(190)	(168)
Amounts recognized in the consolidated balance sheets consist of:
Current liabilities	(3)	(3)
Non-current liabilities	(15)	(14)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position	190	168
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial gain (loss)	(73)	(59)
Prior service credit	17	25
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax	(56)	(34)
Settlements	0	0
Other Postretirement Benefits \| Current assets
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	0	0
Other Postretirement Benefits \| Non-current assets
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	208	185
Funded Plans [Member] \| Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	158
Interest cost	4	6
Defined Benefit Plan, Accumulated Benefit Obligation, Increase (Decrease) for Plan Amendment	0	0
Benefits paid, net	(137)	(37)
Actuarial gain and other	(4)	13
Defined Benefit Plan, Benefit Obligation	0	158
Change in plan assets:
Defined Benefit Plan, Plan Assets, Amount	182	22
Return on plan assets and other	3	13
Employer contributions	1	5
Benefits paid, net	(137)	(36)
Defined Benefit Plan, Plan Assets, Amount	28	182
Amount underfunded (overfunded) at end of period	(28)	(24)
Amounts recognized in the consolidated balance sheets consist of:
Current liabilities	0	0
Non-current liabilities	0	0
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position	28
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial gain (loss)	0	(9)
Prior service credit	0	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax	0
Defined Benefit Plan, Benefit Obligation, Business Combination	0	152
Settlements	(21)	0
Funded Plans [Member] \| Pension Benefits \| Current assets
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	28	0
Funded Plans [Member] \| Pension Benefits \| Non-current assets
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	0	24
Funded Plans [Member] \| Pension Benefits \| Nustar Acquisition
Change in plan assets:
Return on plan assets and other	0	178
Unfunded Plans [Member]
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Defined Benefit Plan, Benefit Obligation, Business Combination	0	0
Settlements	0	0
Unfunded Plans [Member] \| Nustar Acquisition
Change in plan assets:
Return on plan assets and other	0	0
Unfunded Plans [Member] \| Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	16	17
Service cost	0	0
Interest cost	1	1
Defined Benefit Plan, Accumulated Benefit Obligation, Increase (Decrease) for Plan Amendment	0	0
Benefits paid, net	(3)	(3)
Actuarial gain and other	1	1
Defined Benefit Plan, Benefit Obligation	15	16
Change in plan assets:
Defined Benefit Plan, Plan Assets, Amount	0	0
Return on plan assets and other	0	0
Employer contributions	0	0
Benefits paid, net	0	0
Defined Benefit Plan, Plan Assets, Amount	0	0
Amount underfunded (overfunded) at end of period	15	16
Amounts recognized in the consolidated balance sheets consist of:
Current liabilities	(2)	(3)
Non-current liabilities	(13)	(13)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position	(15)	(16)
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial gain (loss)	0	(1)
Prior service credit	0	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax	0	(1)
Unfunded Plans [Member] \| Pension Benefits \| Current assets
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	0	0
Unfunded Plans [Member] \| Pension Benefits \| Non-current assets
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	$ 0	$ 0

Estimates (Schedule of Other Non-Current Assets, net) (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Accounting Policies [Abstract]
Crude pipeline linefill and tank bottoms	$ 787	$ 743
Regulatory assets	40	39
Pension assets	209	188
Deferred charges	146	151
Restricted funds	210	216
Other	1,199	680
Total other non-current assets, net	$ 2,591	$ 2,017

Acquisitions, Divestitures and Related Transactions (Details)
$ / shares in Units, € in Millions

2 Months Ended

3 Months Ended

12 Months Ended

24 Months Ended

Jan. 16, 2026

USD ($)

Jan. 16, 2026

EUR (€)

Jan. 12, 2026

USD ($)

Oct. 31, 2025

USD ($)

conversionRatioOfUnitsInAcquisition

sites

Aug. 30, 2024

USD ($)

Jul. 15, 2024

USD ($)

Jul. 01, 2024

May 03, 2024

USD ($)

Apr. 16, 2024

USD ($)

Mar. 13, 2024

USD ($)

Mar. 13, 2024

EUR (€)

Nov. 03, 2023

USD ($)

$ / shares

May 02, 2023

USD ($)

May 01, 2023

USD ($)

Dec. 31, 2025

USD ($)

Dec. 31, 2025

USD ($)

Sep. 30, 2025

USD ($)

conversionRatioOfUnitsInAcquisition

Jun. 30, 2025

USD ($)

Mar. 31, 2025

USD ($)

Dec. 31, 2025

USD ($)

transactions

Dec. 31, 2024

USD ($)

Dec. 31, 2023

USD ($)

Dec. 31, 2025

USD ($)

Oct. 31, 2025

$ / shares

$ 1,528,000,000

$ 16,000,000

$ 108,000,000

108,000,000

$ 108,000,000

Number of Countries in which Entity Operates

$ 0

586,000,000

$ 0

Dealer Sites

Cash Acquired from Acquisition

$ 0

27,000,000

NET INCOME ATTRIBUTABLE TO PARTNERS

749,000,000

4,433,000,000

4,814,000,000

3,935,000,000

Payments for Merger Related Costs

85,536,000,000

82,671,000,000

78,586,000,000

$ 175,000,000

ET-S Permian Joint Venture [Member]

Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest

67.50%

Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest

100.00%

Contractual Rights [Member]

Finite-Lived Contractual Rights, Gross

$ 151,000,000

Acquired Finite-Lived Intangible Assets, Weighted Average Useful Life

7 years

Acquired Finite-Lived Intangible Assets, Weighted Average Useful Life

7 years

Customer Relationships [Member]

Acquired Finite-Lived Intangible Assets, Weighted Average Useful Life

15 years

Finite-Lived Customer Relationships, Gross

$ 44,000,000

Acquired Finite-Lived Intangible Assets, Weighted Average Useful Life

15 years

Sunoco LP [Member] | ET-S Permian Joint Venture [Member]

Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest

32.50%

7-Eleven | Sunoco LP [Member]

Number of Units in Real Estate Property

$ 1,000,000,000.00

204

7-Eleven | Sunoco LP [Member] | Net of current tax expense [Member]

$ 586,000,000

$ 442,000,000

Business Combination, Recognized Asset Acquired, Identifiable Intangible Asset, Excluding Goodwill

$ 1,455,000,000

1,139,000,000

8,157,000,000

3,645,000,000

Business Combination, Consideration Transferred, Equity Interest, Share Issued, Number of Shares | shares

$ 12,000,000

216,000,000

Business Combination, Recognized Asset Acquired, Asset, Current

$ 657,000,000

Business Combination, Recognized Asset Acquired, Property, Plant, and Equipment

4,772,000,000

Business Combination, Recognized Asset Acquired, Asset, Noncurrent

95,000,000

27,000,000

4,228,000,000

Payments to Acquire Businesses, Net of Cash Acquired

300,000,000

288,000,000

Business Combination, Recognized Liability Assumed, Long-Term Debt, Noncurrent

3,461,000,000

Business Combination, Recognized Asset Acquired, Other Asset, Noncurrent

12,000,000

Business Combination, Recognized Liability Assumed, Liability, Current

445,000,000

Business Combination, Recognized Liability Assumed, Other Liability, Noncurrent

322,000,000

Crestwood Acquisition | Senior Notes [Member]

Business Combination, Recognized Liability Assumed, Long-Term Debt, Noncurrent

2,850,000,000

Crestwood Acquisition | Revolving Credit Facility

Business Combination, Recognized Liability Assumed, Long-Term Debt, Noncurrent

$ 613,000,000

Crestwood Acquisition | Series I Preferred Units

Business Combination, Consideration Transferred, Equity Interest, Share Issued, Number of Shares | shares

41,000,000

Crestwood

Business Combination, Consideration Transferred, Equity Interest, Share Issued, Number of Shares | shares

2.07

Crestwood | Series I Preferred Units

Preferred Stock, Redemption Price Per Share | $ / shares

$ 9.857484

Business Combination, Recognized Asset Acquired, Identifiable Intangible Asset, Excluding Goodwill

$ 75,000,000

1,551,000,000

1,504,000,000

Business Combination, Consideration Transferred, Equity Interest, Share Issued, Number of Shares | shares

$ 4,000,000

44,500,000

Business Combination, Recognized Asset Acquired, Asset, Current

$ 61,000,000

Business Combination, Recognized Asset Acquired, Property, Plant, and Equipment

1,263,000,000

Business Combination, Recognized Asset Acquired, Asset, Noncurrent

138,000,000

10,000,000

43,000,000

Equity Issued in Business Combination, Fair Value Disclosure

930,000,000

574,000,000

Payments to Acquire Businesses, Net of Cash Acquired

930,000,000

Business Combination, Recognized Asset Acquired, Other Asset, Noncurrent

4,000,000

Business Combination, Recognized Liability Assumed, Liability, Current

27,000,000

Business Combination, Recognized Liability Assumed, Other Liability, Noncurrent

$ 16,000,000

Zenith Energy | Sunoco LP [Member]

Other Payments to Acquire Businesses

$ 111,000,000

Business Combination, Recognized Asset Acquired, Property, Plant, and Equipment

$ 185,000,000

€ 170

204,000,000

Number of Units in Real Estate Property

Business Combination, Recognized Asset Acquired, Other Asset, Noncurrent

36,000,000

Business Combination, Recognized Liability Assumed, Liability, Current

14,000,000

Business Combination, Recognized Liability Assumed, Other Liability, Noncurrent

43,000,000

Business Combination, Recognized Asset Acquired, Other Asset, Current

6,000,000

Business Combination, Bargain Purchase, Gain Recognized, Amount

6,000,000

Business Combination, Recognized Liability Assumed, Deferred Tax Liability

4,000,000

Net deferred income tax assets

$ 6,000,000

Business Combination, Recognized Asset Acquired, Identifiable Intangible Asset, Excluding Goodwill

^[1]

$ 16,000,000

^[2]

195,000,000

7,618,000,000

2,823,000,000

Business Combination, Recognized Asset Acquired, Asset, Current

27,000,000

186,000,000

Business Combination, Recognized Asset Acquired, Property, Plant, and Equipment

6,958,000,000

136,000,000

Business Combination, Reason for Business Combination

$ 3,967,000,000

NuStar has approximately 9,500 miles of pipeline and 63 terminal and storage facilities that store and distribute crude oil, refined products, renewable fuels, ammonia and specialty liquids.

Business Combination, Recognized Liability Assumed, Long-Term Debt, Noncurrent

^[3]

$ 3,500,000,000

Proceeds from (Repurchase of) Redeemable Preferred Stock

784,000,000

Business Combination, Recognized Asset Acquired, Other Asset, Noncurrent

127,000,000

Business Combination, Recognized Liability Assumed, Liability, Current

245,000,000

Business Combination, Recognized Liability Assumed, Other Liability, Noncurrent

$ 82,000,000

Business Acquisition, Equity Interest Issued or Issuable, Conversion Ratio of Shares

0.400

Repayments of Lines of Credit

$ 455,000,000

Impairment of Real Estate

50,000,000

Business Combination, Recognized Liability Assumed, Deferred Tax Liability

4,000,000

Nustar Acquisition | Sunoco LP [Member]

$ 403,000,000

Business Combination, Consideration Transferred, Equity Interest, Share Issued, Number of Shares | shares

51,500,000

Business Combination, Consideration Transferred, Equity Interest, Share Issued, Value

$ 2,850,000,000

Business Combination, Recognized Liability Assumed, Long-Term Debt, Noncurrent

3,500,000,000

Proceeds from (Repurchase of) Redeemable Preferred Stock

56,000,000

$ 800,000,000

Other acquisitions [Member]

Payments to Acquire Businesses, Net of Cash Acquired

4,000,000

250,000,000

111,000,000

Other acquisitions [Member] | Sunoco LP [Member]

Payments to Acquire Businesses, Net of Cash Acquired

$ 176,000,000

$ 24,000,000

Number of transactions in a business acquisition | transactions

ET-S Permian Joint Venture [Member]

Business Combination, Reason for Business Combination

ET-S Permian operates more than 5,000 miles of crude oil and water gathering pipelines with crude oil storage capacity in excess of 11 million barrels.

Business Combination, Recognized Asset Acquired, Identifiable Intangible Asset, Excluding Goodwill

$ 20,000,000

3,471,000,000

3,007,000,000

Business Combination, Consideration Transferred, Equity Interest, Share Issued, Number of Shares | shares

$ 45,000,000

50,800,000

Business Combination, Recognized Asset Acquired, Asset, Current

$ 334,000,000

Business Combination, Recognized Asset Acquired, Property, Plant, and Equipment

3,109,000,000

8,000,000

Business Combination, Consideration Transferred, Equity Interest, Share Issued, Value

419,000,000

833,000,000

Payments to Acquire Businesses, Net of Cash Acquired

$ 2,280,000,000

$ 0

2,174,000,000

Business Combination, Reason for Business Combination

Business Combination, Recognized Liability Assumed, Liability, Current

$ 394,000,000

Business Combination, Recognized Liability Assumed, Other Liability, Noncurrent

$ 20,000,000

$ 13,373,000,000

4,551,000,000

Business Combination, Recognized Asset Acquired, Asset, Current

464,000,000

2,814,000,000

Business Combination, Recognized Asset Acquired, Property, Plant, and Equipment

5,612,000,000

Business Combination, Recognized Asset Acquired, Asset, Noncurrent

341,000,000

731,000,000

Payments to Acquire Businesses, Net of Cash Acquired

8,358,000,000

2,004,000,000

$ 0

Business Combination, Recognized Liability Assumed, Long-Term Debt, Noncurrent

3,797,000,000

$ 3,650,000,000

Business Combination, Recognized Asset Acquired, Other Asset, Noncurrent

266,000,000

Business Combination, Recognized Liability Assumed, Liability, Current

2,490,000,000

Business Combination, Recognized Liability Assumed, Deferred Tax Liability

965,000,000

Business Combination, Recognized Asset Acquired, Identifiable Intangible Asset, Indefinite-Lived

^[4]

1,871,000,000

NET INCOME ATTRIBUTABLE TO PARTNERS

195,000,000

Business Combination, Goodwill, Expected Tax Deductible, Amount

$ 3,170,000,000

660,000,000

Parkland Acquisition [Member] | Trade Names [Member]

Business Combination, Recognized Asset Acquired, Identifiable Intangible Asset, Indefinite-Lived

$ 297,000,000

Parkland Acquisition [Member] | Customer Relationships [Member]

Acquired Finite-Lived Intangible Assets, Weighted Average Useful Life

20 years

Business Combination, Recognized Asset Acquired, Identifiable Intangible Asset, Finite-Lived

$ 1,490,000,000

Acquired Finite-Lived Intangible Assets, Weighted Average Useful Life

20 years

Parkland Acquisition [Member] | Other Intangible Assets [Member]

Acquired Finite-Lived Intangible Assets, Weighted Average Useful Life

10 years

Business Combination, Recognized Asset Acquired, Identifiable Intangible Asset, Finite-Lived

$ 85,000,000

Acquired Finite-Lived Intangible Assets, Weighted Average Useful Life

10 years

Parkland Acquisition [Member] | Sunoco LP [Member]

Business Combination, Consideration Transferred, Equity Interest, Share Issued, Number of Shares | shares

$ 2,600,000,000

51,517,198

Number of Countries in which Entity Operates | sites

Parkland Acquisition [Member] | Sunoco LP [Member] | C$19.80 limit per Parkland share [Member]

Business Acquisition, Equity Interest Issued or Issuable, Conversion Ratio of Shares | conversionRatioOfUnitsInAcquisition

0.295

Business Combination, Price Per Share | $ / shares

$ 19.80

Parkland Acquisition [Member] | Sunoco LP [Member] | Parkland exchange amounts [Member]

Business Acquisition, Equity Interest Issued or Issuable, Conversion Ratio of Shares | conversionRatioOfUnitsInAcquisition

0.295

Business Combination, Price Per Share | $ / shares

19.80

Parkland Acquisition [Member] | Sunoco LP [Member] | Alternative Parkland exchange amounts [Member]

Business Acquisition, Equity Interest Issued or Issuable, Conversion Ratio of Shares | conversionRatioOfUnitsInAcquisition

0.536

Business Combination, Price Per Share | $ / shares

$ 44

TanQuid Acquisition [Member] | Subsequent Event [Member]

Business Combination, Recognized Liability Assumed, Long-Term Debt, Noncurrent | €

$ 540,000,000

€ 465

300

Cash Acquired from Acquisition | €

€ 39

Acquisition of fuel equipment, motor fuel inventory and supply agreements [Member] | Sunoco LP [Member]

Business Combination, Consideration Transferred, Equity Interest, Share Issued, Number of Shares | shares

$ 17,000,000

91,776

Equity Issued in Business Combination, Fair Value Disclosure

$ 12,000,000

$ 5,000,000

151 fuel distribution consignment site [Member] | Sunoco LP [Member]

Business Combination, Consideration Transferred, Equity Interest, Share Issued, Number of Shares | shares

$ 105,000,000

251,646

Equity Issued in Business Combination, Fair Value Disclosure

$ 92,000,000

$ 13,000,000

Fuel distribution sites acquired

151

170 fuel distribution sites [Member] | Sunoco LP [Member]

Fuel distribution sites acquired

$ 85,000,000

Number of supply agreements | conversionRatioOfUnitsInAcquisition

100

J-W Power Company [Member] | USAC [Member] | Subsequent Event [Member]

Business Combination, Consideration Transferred, Equity Interest, Share Issued, Number of Shares | shares

$ 860,000,000

18,200,000

27 fuel distribution consignment sites and 36 dealer sites [Member] | Sunoco LP [Member]

$ 430,000,000

Fuel distribution sites acquired

$ 64,000,000

[1]	Goodwill primarily represents expected commercial and operational synergies. None of the goodwill recorded as a result of this transaction is deductible for tax purposes.
[2]	Intangible assets, net comprised of $151 million of favorable contracts, with a remaining weighted average life of approximately 7 years, and $44 million of customer relationships, with a remaining weighted average life of approximately 15 years.
[3]	Subsequent to the closing of the NuStar acquisition, Sunoco LP redeemed all outstanding NuStar preferred units totaling $784 million, redeemed NuStar’s subordinated notes totaling $403 million and repaid the outstanding balance on the NuStar credit facility totaling $455 million.
[4]	(1)Intangible assets, net comprised of $1.49 billion of customer relationships, with a remaining weighted average life of approximately 20 years, $297 million of indefinite-lived tradenames and $85 million of other intangibles with a remaining weighted average life of approximately 10 years.

Redeemable Noncontrolling Interests

12 Months Ended

Dec. 31, 2025

Redeemable Noncontrolling Interest, Equity, Carrying Amount [Abstract]

Redeemable Noncontrolling Interests

REDEEMABLE NONCONTROLLING INTERESTS:

Certain redeemable noncontrolling interests in the Partnership’s subsidiaries are reflected as mezzanine equity on the consolidated balance sheets.

Redeemable noncontrolling interests consisted of the following:


	December 31, 2025		December 31, 2024
USAC Series A preferred units	$	—	$	169
Crestwood Niobrara LLC preferred units	225		225
Other (1)	25		23
Total redeemable noncontrolling interests	$	250	$	417

(1) Relates to noncontrolling interest holders in one of the Partnership’s consolidated subsidiaries that have the option to sell their interests to the Partnership.

USAC Series A Preferred Units

On June 3, 2025, the holders of USAC preferred units elected to convert 100,000 preferred units into 4,997,126 common units. On December 2, 2025, the holders of USAC preferred units elected to convert the remaining 80,000 preferred units into 3,997,700 common units. As of December 31, 2025, all of USAC preferred units had been converted to common units.

Niobrara Preferred Units

Crestwood Niobrara LLC (“Crestwood Niobrara”), a subsidiary acquired in the Crestwood acquisition in November 2023, has outstanding two series of preferred units (collectively, the “Niobrara Preferred Units”) held by a third-party. The Niobrara Preferred Units are redeemable by the Partnership or the preferred interest holder and are also convertible by the preferred interest holder into Crestwood Niobrara common units. The preferred interest holder also has the option to contribute additional capital to Crestwood Niobrara to increase their common ownership percentage in Crestwood Niobrara to 50% upon the conversion.

On February 23, 2024, the Partnership paid approximately $37 million in cash to redeem a portion of the outstanding Crestwood Niobrara LLC preferred units.

Estimates (Property, Plant and Equipment) (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 141,283	$ 129,242
Less - Accumulated depreciation	(39,141)	(34,030)
Property, plant and equipment, net	$ 102,142	95,212
Minimum [Member] \| Customer relationships, contracts and agreements (3 to 46 years)
Property, Plant and Equipment, Net [Abstract]
Finite-Lived Intangible Asset, Useful Life	3 years
Minimum [Member] \| Other (5 to 20 years)
Property, Plant and Equipment, Net [Abstract]
Finite-Lived Intangible Asset, Useful Life	5 years
Maximum [Member] \| Customer relationships, contracts and agreements (3 to 46 years)
Property, Plant and Equipment, Net [Abstract]
Finite-Lived Intangible Asset, Useful Life	46 years
Maximum [Member] \| Trade Names [Member]
Property, Plant and Equipment, Net [Abstract]
Finite-Lived Intangible Asset, Useful Life	20 years
Maximum [Member] \| Trade names (20 years)
Property, Plant and Equipment, Net [Abstract]
Finite-Lived Intangible Asset, Useful Life	10 years
Maximum [Member] \| Other (5 to 20 years)
Property, Plant and Equipment, Net [Abstract]
Finite-Lived Intangible Asset, Useful Life	20 years
Land and improvements
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 3,051	1,675
Buildings and improvements (1 to 40 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	8,448	4,688
Pipelines and equipment (5 to 65 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	101,506	97,078
Right of way (20 to 65 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 9,344	9,239
Right of way (20 to 65 years) \| Minimum [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, useful life, minimum (years)	20 years
Right of way (20 to 65 years) \| Maximum [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, useful life, minimum (years)	83 years
Other (1 to 48 years) \| Minimum [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, useful life, minimum (years)	1 year
Other (1 to 48 years) \| Maximum [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, useful life, minimum (years)	48 years
Construction work-in-process
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 5,841	4,633
Product storage and related facilities
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 8,399	7,869
Product storage and related facilities \| Minimum [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, useful life, minimum (years)	2 years
Product storage and related facilities \| Maximum [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, useful life, minimum (years)	83 years
Other
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 4,694	$ 4,060

Equity (Change In ETE Common Units) (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2025

Dec. 31, 2024

Dec. 31, 2023

Dec. 31, 2022

Outstanding

3,439,986,779

3,431,088,022

Number of Common Units, end of period

3,439,986,779

3,431,088,022

$ 49,010

$ 46,017

$ 43,939

$ 40,659

(4,725)

(4,623)

$ (4,248)

Issuance of Common Units (2)

$ (500)

$ (2,645)

Common Units

^[1]

9,000,000.0

12,700,000

12,900,000

Outstanding

3,440,000,000

3,431,000,000

3,367,500,000

3,094,400,000

Issuance of restricted Common Units under long-term incentive plans

^[2]

(50,800,000)

(260,200,000)

Number of Common Units, end of period

3,440,000,000

3,431,000,000

3,367,500,000

Series A Preferred Units [Member]

$ 0

$ 948

$ 958

(56)

(96)

(950)

Series A Preferred Units [Member] | Crestwood Acquisition

556

(36)

Series B Preferred Units [Member] | Crestwood Acquisition

Series C Preferred Units [Member]

438

440

(11)

(40)

(450)

Series C Preferred Units [Member] | Crestwood Acquisition

Series D Preferred Units [Member]

435

434

(11)

(36)

(445)

Series D Preferred Units [Member] | Crestwood Acquisition

Series E Preferred Units [Member]

786

(30)

(61)

(800)

Series E Preferred Units [Member] | Crestwood Acquisition

Series F Preferred Units [Member]

496

(16)

(34)

(500)

Series F Preferred Units [Member] | Crestwood Acquisition

1,488

(106)

Series G Preferred Units [Member] | Crestwood Acquisition

106

893

(59)

Series H Preferred Units | Crestwood Acquisition

Preferred Units [Member]

3,356

3,852

6,459

6,051

(252)

(378)

(468)

(500)

(2,645)

Preferred Units [Member] | Crestwood Acquisition

248

362

463

413

Series I Preferred Units

419

$ 0

(35)

Series I Preferred Units | Crestwood Acquisition

$ 35

$ 413

[1]	Includes common units issued in connection with the distribution reinvestment program and restricted unit vestings.
[2]	Includes common units issued related to our acquisitions of WTG Midstream in 2024 and of Crestwood and Lotus Midstream in 2023.

Lease Accounting - Lease Maturities (Details) $ in Millions	Dec. 31, 2025 USD ($)
Lessee, Lease, Description [Line Items]
2026	$ 288
2026	26
2026	314
2027	236
2027	19
2027	255
2028	210
2028	18
2028	228
Lessee, Operating Lease, Liability, to be Paid, Year Four	183
Finance Lease, Liability, to be Paid, Year Four	14
2029	197
Lessee, Operating Lease, Liability, to be Paid, Year Five	165
Finance Lease, Liability, to be Paid, Year Five	9
Lease Liabilities, Due Year Five	174
Thereafter	1,661
Thereafter	53
Thereafter	1,714
Total lease payments	2,743
Total lease payments	139
Lease Liabilities, Due	2,882
Less: present value discount	983
Less: present value discount	31
Less: present value discount	$ 1,014
Finance Lease, Liability, Statement of Financial Position [Extensible Enumeration]	Non-current operating lease liabilities
Operating Lease, Liability	$ 1,760
Finance Lease, Liability	108
Lease, Liabilities	$ 1,868

Lease Accounting Narrative (Details)	Dec. 31, 2025
Real estate leases
Lessee, Operating Lease, Term of Contract	40 years
Minimum [Member]
Lessee, Operating Lease, Renewal Term	1 year
Minimum [Member] \| Terminal facilities, tank cars, office space, land and equipment
Lessee, Operating Lease, Term of Contract	5 years
Maximum [Member]
Lessee, Operating Lease, Renewal Term	20 years
Maximum [Member] \| Terminal facilities, tank cars, office space, land and equipment
Lessee, Operating Lease, Term of Contract	15 years

Reporting Segments (Additions To Property Plant And Equipment Including Acquisitions Net Of Contributions In Aid Of Construction Costs Segments) (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2025

Dec. 31, 2024

Dec. 31, 2023

^[1]

$ 6,412

$ 4,582

$ 2,868

Intrastate Transportation and Storage

^[1]

651

344

215

Interstate Transportation and Storage

^[1]

1,572

118

^[1]

359

332

383

NGL and Refined Products Transportation and Services

^[1]

1,616

1,323

832

^[1]

1,723

1,424

679

^[1]

423

266

Investment in USAC

^[1]

157

276

300

All Other

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]

^[1]

$ 244

$ 342

$ 100

[1]	Amounts are presented on the accrual basis, net of contributions in aid of constructions costs. Amounts exclude acquisitions and include only the Partnership’s proportionate share of capital expenditures related to joint ventures.

Derivative Assets And Liabilities Derivative Assets and Lianilities (Offsetting Agreements Netting Table) (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Asset Derivatives	$ 618	$ 263
Derivative Liabilities	(454)	(293)
Derivative Asset, Fair Value, Amount Offset Against Collateral	(50)	(42)
Derivative Liability, Fair Value, Amount Offset Against Collateral	50	42
Derivative Asset, Collateral, Obligation to Return Cash, Offset	(384)	(204)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	384	204
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	184	17
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	20	47
OTC Contracts [Member]
Asset Derivatives	102	51
Derivative Liabilities	(60)	(57)
Broker cleared derivative contracts [Member]
Asset Derivatives	516	212
Derivative Liabilities	$ (394)	$ (236)

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

12 Months Ended

Dec. 31, 2025

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:

FERC Proceedings

Rover – FERC – Stoneman House

In late 2016, FERC Enforcement Staff began a non-public investigation related to Rover’s purchase and removal of a potentially historic home (known as the Stoneman House) while Rover’s application for permission to construct the new 711-mile interstate natural gas pipeline and related facilities was pending. On March 18, 2021, FERC issued an Order to Show Cause and Notice of Proposed Penalty (Docket No. IN19-4-000), ordering Rover to explain why it should not pay a $20 million civil penalty for alleged violations of FERC regulations requiring certificate holders to be forthright in their submissions of information to the FERC. Rover filed its answer and denial to the order on June 21, 2021, and a surreply on September 15, 2021. FERC issued an order on January 20, 2022, setting the matter for hearing before an administrative law judge. The hearing was set to commence on March 6, 2023; as explained below, this FERC proceeding has been stayed.

On February 1, 2022, Energy Transfer and Rover filed a Complaint for Declaratory Relief in the U.S. District Court for the Northern District of Texas (the “Federal District Court”) seeking an order declaring that FERC must bring its enforcement action in federal district court (instead of before an administrative law judge). Also on February 1, 2022, Energy Transfer and Rover filed an expedited request to stay the proceedings before the FERC administrative law judge pending the outcome of the Federal District Court case. On May 24, 2022, the Federal District Court ordered a stay of the FERC’s enforcement case and the Federal District Court case pending the resolution of two cases pending before the U.S. Supreme Court. Arguments were heard in those cases on November 7, 2022. On April 14, 2023, the U.S. Supreme Court held against the government in both cases, finding that the federal district courts had jurisdiction to hear those suits and to resolve the parties’ constitutional challenges. The cases were remanded to the federal district courts for further proceedings.

On September 13, 2023, the Federal District Court ordered that the Federal District Court case would be stayed pending the resolution of another case pending before the U.S. Supreme Court and that the FERC enforcement case would remain stayed. On November 13, 2023, the FERC appealed the Federal District Court order to the U.S. Court of Appeals for the Fifth Circuit. On December 11, 2023, FERC filed a motion to withdraw that appeal, which the Fifth Circuit granted on December 12, 2023. The FERC and the Federal District Court proceedings were stayed pending resolution of the case pending before the U.S. Supreme Court. The Supreme Court issued a decision in that case on June 27, 2024. The Federal District Court set a status conference for December 16, 2025. The parties filed a motion to continue the status conference on December 10, 2025 and on January 20, 2026 to extend the status conference to mid-February 2026. At the Department of Justice’s request, the parties requested that the court extend the status conference again to March 2026 for the purposes of the parties engaging in settlement discussions. Notwithstanding the foregoing, Energy Transfer and Rover intend to vigorously defend against this claim.

Rover – FERC – Tuscarawas

In mid-2017, FERC Enforcement Staff began a non-public investigation regarding allegations that diesel fuel may have been included in the drilling mud at the Tuscarawas River horizontal directional drilling (“HDD”) operations. Rover and the Partnership are cooperating with the investigation. In 2019, Enforcement Staff provided Rover with a notice pursuant to Section 1b.19 of the FERC regulations that Enforcement Staff intended to recommend that the FERC pursue an enforcement action against Rover and the Partnership. On December 16, 2021, FERC issued an Order to Show Cause and Notice of Proposed Penalty (Docket No. IN17-4-000), ordering Rover and Energy Transfer to show cause why they should not be found to have violated Section 7(e) of the NGA Section 157.20 of FERC’s regulations, and the Rover Pipeline Certificate Order, and assessed civil penalties of $40 million.

Rover and Energy Transfer filed their answer to this order on March 21, 2022, and Enforcement Staff filed a reply on April 20, 2022. Rover and Energy Transfer filed their surreply to this order on May 13, 2022. FERC has taken no further action on the case since that time.

The primary contractor (and one of the subcontractors) responsible for the HDD operations of the Tuscarawas River site have agreed to indemnify Rover and the Partnership for any and all losses, including any fines and penalties from government agencies, resulting from their actions in conducting such HDD operations. Given the stage of the proceedings, the Partnership is unable at this time to provide an assessment of the potential outcome or range of potential liability, if any; however, the Partnership believes the indemnity described above will be applicable to the penalty proposed by Enforcement Staff and intends to vigorously defend itself against the subject claims.

Other FERC Proceedings

By an order issued on January 16, 2019, the FERC initiated a review of Panhandle’s then-existing rates pursuant to Section 5 of the NGA to determine whether the rates charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the NGA. The NGA Section 5 and Section 4 proceedings were consolidated by order of the Chief Judge on October 1, 2019. The initial decision by the administrative law judge was issued on March 26, 2021, and on December 16, 2022, the FERC issued its order on the initial decision. On January 17, 2023, Panhandle and the Michigan Public Service Commission each filed a request for rehearing of FERC’s order on the initial decision, which were denied by operation of law as of February 17, 2023. On March 23, 2023, Panhandle appealed these orders to the D.C. Circuit, and the Michigan Public Service Commission also subsequently appealed these orders. On April 25, 2023, the D.C. Circuit consolidated Panhandle’s and Michigan Public Service Commission’s appeals and stayed the consolidated appeal proceeding while the FERC further considered the requests for rehearing of its December 16, 2022 order. On September 25, 2023, the FERC issued its order addressing arguments raised on rehearing and compliance, which denied our requests for rehearing. Panhandle filed its Petition for Review with the D.C. Circuit regarding the September 25, 2023 order. On October 25, 2023, Panhandle filed a limited request for rehearing of the September 25 order addressing arguments raised on rehearing and compliance, which was subsequently denied by operation of law on November 27, 2023. On November 17, 2023, Panhandle provided refunds to shippers and on November 30, 2023, Panhandle submitted a refund report regarding the consolidated rate proceedings, which was protested by several parties. On January 5, 2024, the FERC issued a second order addressing arguments raised on rehearing in which it modified certain discussion from its September 25, 2023 order and sustained its prior conclusions. Panhandle has timely filed its Petition for Review with the D.C. Circuit regarding the January 5, 2024 order. On May 28, 2024, the FERC issued an order rejecting Panhandle’s refund report. On June 27, 2024, Panhandle filed a revised refund report in compliance with the FERC’s May 28, 2024 order rejecting Panhandle’s refund report and a request for rehearing of the FERC’s May 28, 2024 order rejecting Panhandle’s refund report, and provided revised refunds to shippers, or in the case of shippers whose revised refunds are less than the original amounts refunded, notices of upcoming debits. One party protested Panhandle’s revised refund report, and Panhandle submitted a response to the protest on July 24, 2024. By notice issued July 29, 2024, Panhandle’s rehearing request was deemed denied. In an ordered issued September 9, 2024, FERC addressed arguments raised on rehearing, modified the discussion in the May 28, 2024 order and continued to reach the same result. On September 18, 2024, Panhandle petitioned the D.C. Circuit for review of the September 9, 2024, July 29, 2024, and May 28, 2024 orders. On December 5, 2024, the FERC issued an order rejecting Panhandle’s June 27, 2024, refund report, ordering a corrected refund report and directing the issuance of additional refunds. On January 3, 2025, Panhandle submitted an adjusted refund report as well as a request for rehearing of the FERC’s December 5, 2024 order. The FERC approved the adjusted refund report by letter order dated January 23, 2025. On February 3, 2025, the FERC issued a Notice of Denial of Rehearing by Operation of Law and Providing for Further Consideration. On March 24, 2025, Panhandle petitioned the D.C. Circuit for review of the December 5, 2024 and February 3, 2025 orders. On April 4, 2025, the FERC issued an Order on Rehearing and Clarification. On May 16, 2025, Panhandle petitioned the D.C. Circuit for review of the April 4, 2025 order. On May 19, 2025, the D.C. Circuit consolidated all cases before it and placed the consolidated cases in abeyance pending further order of the D.C. Circuit. On August 12, 2025, the D.C. Circuit issued an order returning all cases to the court’s active docket and issued a briefing schedule. Panhandle filed its initial brief on November 10, 2025, and FERC’s brief is due on February 9, 2026.

Commitments

In the normal course of business, Energy Transfer purchases, processes and sells natural gas pursuant to long-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. Energy Transfer believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on the Partnership’s financial position or results of operations.

Our joint venture agreements require that we fund our proportionate share of capital contributions to our unconsolidated affiliates. Such contributions will depend upon the unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.

We have certain non-cancelable rights-of-way (“ROW”) commitments which require fixed payments and either expire upon our chosen abandonment or at various dates in the future. The following table reflects ROW expense included in operating expenses in the accompanying consolidated statements of operations:


	Years Ended December 31,
	2025		2024		2023
ROW expense	$	87	$	72	$	68

Litigation and Contingencies

We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Due to the flammable and combustible nature of natural gas and crude oil, the potential exists for personal injury and/or property damage to occur in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.

We or our subsidiaries are parties to various legal proceedings, arbitrations and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.

As of December 31, 2025 and 2024, accruals of approximately $324 million and $281 million, respectively, were reflected on our consolidated balance sheets related to contingent obligations that met both the probable and reasonably estimable criteria. In addition, we may recognize additional contingent losses in the future related to (i) contingent matters for which a loss is currently considered reasonably possible but not probable and/or (ii) losses in excess of amounts that have already been accrued for such contingent matters. In some of these cases, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. For such matters where additional contingent losses can be reasonably estimated, the range of additional losses is estimated to be up to approximately $58 million.

The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts or our estimates of reasonably possible losses prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.

The following sections include descriptions of certain matters that could impact the Partnership’s financial position, results of operations and/or cash flows in future periods. The following sections also include updates to certain matters that have previously been disclosed, even if those matters are not anticipated to have a potentially significant impact on future periods. In addition to the matters disclosed in the following sections, the Partnership is also involved in multiple other matters that could impact future periods, including other lawsuits and arbitration related to the Partnership’s commercial agreements. With respect to such matters, contingencies that met both the probable and reasonably estimable criteria have been included in the accruals disclosed above, and the range of additional losses disclosed above also reflects any relevant amounts for such matters.

Dakota Access Pipeline

On July 27, 2016, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the U.S. District Court for the District of Columbia (“District Court”) challenging permits issued by the United States Army Corps of Engineers (“USACE”) that allowed Dakota Access to cross the Missouri River at Lake Oahe in North Dakota. The case was subsequently amended to challenge an easement issued by the USACE that allowed the pipeline to cross land owned by the USACE adjacent to the Missouri River. Dakota Access and the Cheyenne River Sioux Tribe (“CRST”) intervened. Separate lawsuits filed by the Oglala Sioux Tribe (“OST”) and the Yankton Sioux Tribe (“YST”) were consolidated with this action and several individual tribal members intervened (collectively, with SRST and CRST, the “Tribes”). On March 25, 2020, the D.C. District Court remanded the case back to the USACE for preparation of an Environment Impact Statement (“EIS”). On July 6, 2020, the D.C. District Court vacated the easement and ordered the Dakota Access Pipeline to be shut down and emptied of oil by August 5, 2020. Dakota Access and the USACE appealed to the D.C. Circuit which granted an administrative stay of the District Court’s July 6 order and ordered further briefing on whether to fully stay the July 6 order. On August 5, 2020, the D.C. Circuit (1) granted a stay of the portion of the D.C. District Court order that required Dakota Access to shut the pipeline down and empty it of oil, (2) denied a motion to stay the March 25 order pending a decision on the merits by the D.C. Circuit as to whether the USACE would be required to prepare an EIS and (3) denied a motion to stay the D.C. District Court’s order to vacate the easement during this appeal process. The August 5 order also states that the D.C. Circuit expected the USACE to clarify its position with respect to whether the USACE intended to allow the continued

operation of the pipeline notwithstanding the vacatur of the easement and that the D.C. District Court may consider additional relief, if necessary.

On August 10, 2020, the D.C. District Court ordered the USACE to submit a status report by August 31, 2020, clarifying its position with regard to its decision-making process with respect to the continued operation of the pipeline. On August 31, 2020, the USACE submitted a status report that indicated that it considered the presence of the pipeline at the Lake Oahe crossing without an easement to constitute an encroachment on federal land, and that it was still considering whether to exercise its enforcement discretion regarding this encroachment. The Tribes subsequently filed a motion seeking an injunction to stop the operation of the pipeline and both the USACE and Dakota Access filed briefs in opposition of the motion for injunction. The motion for injunction was fully briefed as of January 8, 2021.

On January 26, 2021, the D.C. Circuit affirmed the D.C. District Court’s March 25, 2020 order requiring an EIS and its July 6, 2020 order vacating the easement. In this same January 26 order, the D.C. Circuit also overturned the D.C. District Court’s July 6, 2020 order that the pipeline shut down and be emptied of oil. Dakota Access filed for rehearing en banc on April 12, 2021, which the D.C. Circuit denied. On September 20, 2021, Dakota Access filed a petition with the U.S. Supreme Court to hear the case. Oppositions were filed by the Solicitor General on December 17, 2021 and the Tribes (December 16, 2021). Dakota Access filed their reply on January 4, 2022. On February 22, 2022, the U.S. Supreme Court declined to hear the case.

The D.C. District Court scheduled a status conference for February 10, 2021 to discuss the effects of the D.C. Circuit’s January 26, 2021 order on the pending motion for injunctive relief, as well as the USACE’s expectations as to how it will proceed regarding its enforcement discretion regarding the easement. On May 3, 2021, the USACE advised the D.C. District Court that it had not changed its position with respect to its opposition to the Tribes’ motion for injunction. On May 21, 2021, the D.C. District Court denied the plaintiffs’ request for an injunction. On June 22, 2021, the D.C. District Court terminated the consolidated lawsuits and dismissed all remaining outstanding counts without prejudice.

On September 8, 2023, the USACE published the Draft EIS. Comments on the Draft EIS were due on December 13, 2023. In December 2025, the USACE issued a Final EIS concluding that the USACE’s preferred alternative is that the USACE reissue its easement to DAPL subject to additional easement conditions. The USACE has not yet issued a Record of Decision with DAPL’s easement, but it is expected to issue in early 2026. The pipeline continues to operate. Energy Transfer cannot determine when or how future lawsuits will be resolved or the impact they may have on the Bakken Pipeline; however, Energy Transfer expects that after the law and complete record are fully considered, any such proceeding will be resolved in a manner that will allow the pipeline to continue to operate.

In addition, lawsuits and/or regulatory proceedings or actions of this or a similar nature could result in interruptions to construction or operations of current or future projects, delays in completing those projects and/or increased project costs, all of which could have an adverse effect on our business and results of operations.

Standing Rock Sioux Tribe in Federal Court in District of Columbia

Dakota Access is the subject of litigation in the D.C. District Court. The SRST sued the USACE arguing that the USACE’s alleged failure to stop Dakota Access from operating violates numerous laws, including the Mineral Leasing Act, the Government Acquisition and Streamlining Act, the National Environmental Policy Act, the Clean Water Act, the National Historic Preservation Act, the Administrative Procedure Act as well as the 1868 Fort Laramie Treaty. The SRST requests a permanent injunction or writ of mandamus that would compel the USACE to shut Dakota Access down pending the completion of the USACE’s EIS and decision on whether to grant Dakota Access an easement under the Mineral Leasing Act.

On October 15, 2024, the SRST filed the above referenced complaint. A summons to the USACE was issued on October 17, 2024. Dakota Access, the state of North Dakota and numerous other states have intervened in the lawsuit in support of the USACE.

On January 17, 2025, the USACE, Dakota Access and state intervenors (including North Dakota and thirteen other states) each filed a motion to dismiss all of the claims in the new SRST litigation. Also, on January 17, 2025, the SRST filed a motion for partial summary judgment on certain of their claims. Briefing on the motions to dismiss is complete. The D.C. District Court has held briefing on the motion for partial summary judgment in abeyance pending the D.C. District Court’s decision on the motions to dismiss. On March 28, 2025, the D.C. District Court granted the motions to dismiss. On May 27, 2025, the SRST appealed the dismissal to the D.C. Circuit. Briefing at the D.C. Circuit is currently underway. Dakota Access intends to vigorously defend against this claim.

Williams Antitrust Litigation

On June 28, 2024, Louisiana Energy Gateway LLC, The Williams Companies, Inc., and Williams Fields Services Group, LLC (collectively, “Williams”) filed a Petition for Damages against Energy Transfer and Gulf Run Transmission, LLC (“Gulf Run”) in the 42nd Judicial District Court, Parish of DeSoto, State of Louisiana (“District Court”), alleging that Energy Transfer and/or Gulf Run have monopolized, conspired to monopolize and/or attempted to monopolize, the relevant product and geographic market for the movement of natural gas from the Haynesville Shale in northwestern Louisiana south to natural gas facilities in the Louisiana Gulf Coast (the “Relevant Market”), engaged in acquisitions that have directly enabled and incentivized to substantially lessen competition, and engaged in unfair methods of competition and unfair trade practices.

On September 16, 2024, Energy Transfer and Gulf Run removed the case to the U.S. District Court for the Western District of Louisiana (“Federal Court”). On October 4, 2024, Williams filed a Motion to Remand with the Federal Court, seeking to remand the case back to the District Court. On October 21, 2024, Energy Transfer and Gulf Run filed a consent to remand based on a subsequent change in circumstances. After the case was remanded, on November 18, 2024, Energy Transfer and Gulf Run filed a Peremptory Exception of No Cause, asserting that Williams failed to state a cause of action. The Peremptory Exception was heard on February 10, 2025 and denied. The District Court initially set the case for trial on September 14, 2026, but indicated that trial will be continued to 2027.

Mont Belvieu Incident

On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL Mont Belvieu LP’s (“Lone Star,” now known as Energy Transfer Mont Belvieu NGLs LP) facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations resumed at the facilities in the fall of 2016, with the exception of one of Lone Star’s storage wells at the North Terminal that has not been returned to service. Lone Star has obtained payment for most of the losses it has submitted to the adjacent operator. Lone Star continues to quantify and seek reimbursement for outstanding losses.

MTBE Litigation

ETC Sunoco and Energy Transfer R&M (collectively, “Sunoco Defendants”) are defendants in lawsuits alleging methyl tertiary butyl ether (“MTBE”) contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability, nuisance, trespass, negligence, violation of environmental laws and/or deceptive business practices claims. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages and attorneys’ fees.

As of December 31, 2025, Sunoco Defendants are defendants in two cases: one case initiated by the State of Maryland and one by the Commonwealth of Pennsylvania. The actions brought also named as defendants ETO, ETP Holdco Corporation and Sunoco Partners Marketing & Terminals L.P., now known as Energy Transfer Marketing & Terminals L.P. ETP Holdco Corporation and Energy Transfer Marketing & Terminals L.P. are wholly owned subsidiaries of Energy Transfer.

It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.

Rover - State of Ohio

On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and other defendants seeking to recover approximately $3 million in civil penalties allegedly owed and certain injunctive relief related to permit compliance. The defendants filed several motions to dismiss, which were granted on all counts. The Ohio EPA appealed, and on December 9, 2019, the Ohio’s Fifth District Court of Appeals entered a unanimous judgment affirming the trial court. The Ohio EPA sought review from the Ohio Supreme Court. On April 22, 2020, the Ohio Supreme Court granted the review. On March 17, 2022, the Ohio Supreme Court reversed in part and remanded to the Ohio trial court. The Ohio Supreme Court agreed with Rover that the State of Ohio had waived its rights under Section 401 of the Clean Water Act but remanded to the trial court to determine whether any of the allegations fell outside the scope of the waiver.

On remand, the Ohio EPA voluntarily dismissed four of the other five defendants and dismissed one of its counts against Rover. In its Fourth Amended Complaint, the Ohio EPA removed all paragraphs that alleged violations by the four dismissed defendants, including those where the dismissed defendants were alleged to have acted jointly with Rover or others. At a June 2, 2022 status conference, the trial judge set a schedule for Rover and the other remaining defendant to file motions to dismiss the Fourth Amended Complaint. On August 1, 2022, Rover and the other remaining defendant each filed their respective motions. Briefing on those motions was completed on November 4, 2022. By order issued on October 20, 2023, the trial judge dismissed the Ohio EPA’s Fourth Amended Complaint.

On November 17, 2023, the State of Ohio appealed the trial judge’s decision to Ohio’s Fifth District Court of Appeals. The State filed its initial brief on January 8, 2024. Energy Transfer and Rover filed a responsive brief on February 20, 2024. The State filed a reply brief on February 26, 2024. Oral argument on the appeal was held on August 27, 2024. On October 1, 2024, Ohio’s Fifth District Court of Appeals affirmed the trial judge’s decision. The State of Ohio sought permission to appeal this decision from the Ohio Supreme Court. Energy Transfer and Rover have opposed such permission. On January 28, 2025, the Ohio Supreme Court declined to hear the State’s appeal. On April 25, 2025, the State of Ohio filed a Petition for Writ of Certiorari with the U.S. Supreme Court. Rover filed a Brief in Opposition on June 30, 2025. The State of Ohio filed a reply brief on July 11, 2025. On October 6, 2025, the U.S. Supreme Court denied the State of Ohio’s Petition for Writ of Certiorari, concluding this matter.

Unitholder Litigation Regarding Pipeline Construction

Various purported unitholders of Energy Transfer have filed derivative actions against various past and current officers and members of Energy Transfer’s Board of Directors, LE GP, LLC, and Energy Transfer, as a nominal defendant that assert claims for breach of fiduciary duties, unjust enrichment, waste of corporate assets, breach of Energy Transfer’s Partnership Agreement, tortious interference, abuse of control and gross mismanagement related primarily to matters involving the construction of pipelines in Pennsylvania and Ohio. They also seek damages and changes to Energy Transfer’s corporate governance structure. See Bettiol v. LE GP, Case No. 3:19-cv-02890-X (N.D. Tex.); Davidson v. Kelcy L. Warren, Cause No. DC-20-02322 (44th Judicial District of Dallas County, Texas); Harris v. Kelcy L. Warren, Case No. 2:20-cv-00364-GAM (E.D. Pa.); Barry King v. LE GP, Case No. 3:20-cv-00719-X (N.D. Tex.); Inter-Marketing Group USA, Inc. v. LE GP, et al., Case No. 2022-0139-SG (Del. Ch.); Elliot v. LE GP LLC, Case No. 3:22-cv-01527-B (N.D. Tex.); Chapa v. Kelcy L. Warren, et al., Index No. 611307/2022 (N.Y. Sup. Ct.); Elliott v. LE GP et al, Cause No. DC-22-14194 (Dallas County, Tex.); and Charles King v. LE GP, LLC et al, Cause No. DC-22-14159 (Dallas County, Texas). The Barry King action that was filed in the U.S. District Court for the Northern District of Texas (Case No. 3:20-cv-00719-X) has been consolidated with the Bettiol action. On August 9, 2022, the Elliot action that was filed in the U.S. District Court for the Northern District of Texas (Case No. 3:22-cv-01527-B) was voluntarily dismissed.

Another purported unitholder of Energy Transfer, Allegheny County Employees’ Retirement System (“ACERS”), individually and on behalf of all others similarly situated, filed a suit under the federal securities laws purportedly on behalf of a class, against Energy Transfer and three of Energy Transfer’s directors: Kelcy L. Warren, John W. McReynolds and Thomas E. Long. See Allegheny County Emps.’ Ret. Sys. v. Energy Transfer LP, Case No. 2:20-00200-GAM (E.D. Pa.). On June 15, 2020, ACERS filed an amended complaint and added as additional defendants Energy Transfer directors Marshall S. McCrea and Matthew S. Ramsey, as well as Michael J. Hennigan and Joseph McGinn. The amended complaint asserts claims for violations of Sections 10(b) and 20(a) of the Exchange Act and Rule 10b-5 promulgated thereunder related primarily to matters involving the construction of pipelines in Pennsylvania. On August 14, 2020, the defendants filed a motion to dismiss ACERS’ amended complaint. On April 6, 2021, the court granted in part and denied in part the defendants’ motion to dismiss. The court held that ACERS could proceed with its claims regarding certain statements put at issue by the amended complaint while also dismissing claims based on other statements. The court also dismissed without prejudice the claims against defendants McReynolds, McGinn and Hennigan. On August 23, 2022, the court granted in part and denied in part ACERS’ motion for class certification. The court certified a class consisting of those who purchased or otherwise acquired common units of Energy Transfer between February 25, 2017 and November 11, 2019. On January 19, 2024, the defendants filed a motion for summary judgment on all of the claims asserted in ACERS’ amended complaint, and ACERS filed a motion for partial summary judgment. The court heard oral argument on the parties’ motions for summary judgment on July 15, 2024. On August 8, 2024, the court ruled on the parties’ cross motions for summary judgment. The court granted defendants’ motion in part, entering judgment for defendants on loss causation for two categories of challenged statements, thereby significantly reducing the class period and potential damages. The court also granted plaintiffs’ motion for partial summary judgment in part, entering judgment for plaintiffs on the elements of falsity and the scienter of certain individuals as to four of the challenged statements. On April 23, 2025, the parties reached an agreement in principle to settle the litigation for $15 million. On July 10, 2025, the court preliminarily approved the settlement, and the final settlement hearing was held on October 7, 2025. On October 8, 2025, the court entered orders approving the class action judgment and the plan of allocation of the net settlement fund.

On June 3, 2022, another purported unitholder of Energy Transfer, Mike Vega, filed suit, purportedly on behalf of a class, against Energy Transfer and Messrs. Warren, Long, McCrea and Whitehurst. See Vega v. Energy Transfer LP et al., Case No. 1:22-cv-4614 (S.D.N.Y.). The action asserts claims for violations of Sections 10(b) and 20(a) of the Exchange Act and Rule 10b-5 promulgated thereunder related primarily to statements made in connection with the construction of Rover. On August 10, 2022, the court appointed the New Mexico State Investment Council and Public Employees Retirement Association of New Mexico (the “New Mexico Funds”) as lead plaintiffs. New Mexico Funds filed an amended complaint on September 30, 2022 and added as additional defendants Energy Transfer directors John W. McReynolds and Matthew S. Ramsey. On November 7, 2022, the court granted the defendants’ motion to transfer and transferred this action to the U.S. District Court for the Northern District of Texas. On January 27, 2023, the defendants filed their motion to dismiss the New Mexico Funds’ amended complaint.

The defendants cannot predict the outcome of these lawsuits or any lawsuits that might be filed subsequent to the date of this filing, nor can the defendants predict the amount of time and expense that will be required to resolve these lawsuits. However, the defendants believe that the claims are without merit and intend to vigorously contest them.

Cline Class Action

On July 7, 2017, Perry Cline filed a class action complaint in the Eastern District of Oklahoma (the “Eastern District Court”) against Sunoco, Inc. (R&M), LLC (now known as Energy Transfer R&M) and Energy Transfer Marketing & Terminals L.P. (collectively, “ETMT”) that alleged ETMT failed to make timely payments of oil and gas proceeds from Oklahoma wells and to pay statutory interest for those untimely payments. On October 3, 2019, the Eastern District Court certified a class to include all persons who received untimely payments from Oklahoma wells on or after July 7, 2012, and who have not already been paid statutory interest on the untimely payments (the “Class”). Excluded from the Class are those entitled to payments of proceeds that qualify as “minimum pay,” prior period adjustments and pass through payments, as well as governmental agencies and publicly traded oil and gas companies.

After a bench trial, on August 17, 2020, Judge John Gibney (sitting from the Eastern District of Virginia) issued an opinion that awarded the Class actual damages of $75 million for late payment interest for identified and unidentified royalty owners and interest-on-interest. This amount was later amended to $81 million to account for interest accrued from trial (the “Order”). Judge Gibney also awarded punitive damages in the amount of $75 million. The Class is also seeking attorneys’ fees.

On August 27, 2020, ETMT filed its Notice of Appeal with the 10th Circuit Court of Appeals (“10th Circuit”) and appealed the entirety of the Order. The matter was fully briefed, and oral argument was set for November 15, 2021. However, on November 1, 2021, the 10th Circuit dismissed the appeal due to jurisdictional concerns with finality of the Order. En banc rehearing of this decision was denied on November 29, 2021. On December 1, 2021, ETMT filed a Petition for Writ of Mandamus to the 10th Circuit to correct the jurisdictional problems and secure final judgment. On February 2, 2022, the 10th Circuit denied the Petition for Writ of Mandamus, citing that there are other avenues for ETMT to obtain adequate relief. On February 10, 2022, ETMT filed a Motion to Modify the Plan of Allocation Order and Issue a Rule 58 Judgment with the trial court, requesting the Eastern District Court to enter a final judgment in compliance with the Rules. ETMT also filed an injunction with the trial court to enjoin all efforts by plaintiffs to execute on any non-final judgment. On March 31, 2022, Judge Gibney denied the Motion to Modify the Plan of Allocation, reiterating his thoughts that the order constitutes a final judgment. Judge Gibney granted the injunction in part (placing a hold on enforcement efforts for 60 days) and denied the injunction in part. The injunction has since been lifted.

Despite the fact that ETMT has taken the position that the judgment is not final and not subject to execution, the Class engaged in asset discovery and actively tried to collect on the judgment through garnishment proceedings from ETMT’s customers. ETMT unsuccessfully tried to deposit the funds into the Eastern District Court’s Registry. Accordingly, to stop the garnishment proceedings, on December 2, 2022, ETMT wired approximately $161 million to the Plaintiff’s approved Plan Administrator, which represented at the time the full amount of the judgment with attorneys’ fees and post-judgment interest. ETMT did so without waiving its ability to pursue its pending appeal or its right to appeal the merits of the judgment. Plaintiff has since dismissed the garnishment actions.

ETMT appealed the denial of the Motion to Modify to the 10th Circuit in an attempt to get a decision on finality. The appeal was fully briefed, and oral argument was held on March 21, 2023. On August 3, 2023, the 10th Circuit ruled in favor of ETMT and found that the Eastern District Court’s plan of allocation (which was part of the final judgment) did not satisfy all finality requirements. The 10th Circuit held that the Eastern District Court abused its discretion in denying ETMT’s Rule 60(b)(6) Motion to Modify and reversed and remanded for further proceedings. The case was sent back to the trial court so that the Eastern District Court could fix the finality requirements with the judgment. Further, ETMT sought and recovered a return of funds deposited with the Plan Administrator; Class Counsel did not oppose this motion.

At a status hearing on September 28, 2023, Class Counsel indicated that it would seek additional interest up until the date that the final judgment is entered. The Eastern District Court asked for briefing on the issue of additional interest and held a hearing on October 17, 2023 to address this issue further and enter a ruling as to whether additional interest should be added to the judgment total. During the hearing, the Eastern District Court ruled that additional interest should be awarded at the 12% statutory rate from the date of the prior improper judgment up until October 17, 2023. However, the Judge tolled the running of interest for the time period during which the Plan Administrator was in possession of ETMT’s funds (between November 2, 2022 and October 10, 2023). Based on this ruling, the Class calculated that approximately $23 million in additional interest should be added to the final judgment. On October 19, 2023, the Eastern District Court entered the new final judgment with a corrected Plan of Allocation. Both parties agree that this newly entered judgment fixes the finality concerns and will allow an appeal to the 10th Circuit on the merits. With the inclusion of additional interest, the total amount awarded to the Class is approximately $104 million in actual damages and $75 million in punitive damages. ETMT appealed the entirety of the judgment to the 10th Circuit. Oral argument took place on November 20, 2024. On November 17, 2025, the Tenth Circuit issued its opinion, reversing on the issue of punitive damages and affirming the remainder of the district court’s findings and rulings. Specifically, the Tenth Circuit affirmed the district court’s orders granting class certification and denying post-trial class decertification, along with the orders determining the actual damages awarded to the Class, including pre-judgment interest. The Tenth Circuit, however, vacated the $75 million punitive damages award and remanded to the district court to amend the judgment consistent with this opinion. ETMT intends to appeal this decision to the United States Supreme Court. ETMT cannot predict the outcome of the case, nor can ETMT predict the amount of time and expense that will be required to resolve the appeal.

Massachusetts Attorney General v. New England Gas Company

On July 7, 2011, the Massachusetts Attorney General (the “MA AG”) filed a regulatory complaint with the Massachusetts Department of Public Utilities (“DPU”) against New England Gas Company (“NEG”) with respect to certain environmental cost recoveries. NEG was an operating division of Southern Union Company (“SUG”), and the NEG assets were acquired in connection with the merger transaction with Energy Transfer in March 2012. Subsequent to the merger, in 2013, SUG sold the NEG assets to Liberty Utilities (“Liberty,” and together with NEG and SUG, “Respondents”) and retained certain potential liabilities, including the environmental cost recoveries with respect to the pending complaint before the DPU. Specifically, the MA AG seeks a refund to NEG’s ratepayers for approximately $18 million in legal fees associated with SUG environmental response activities. The MA AG requests that the DPU initiate an investigation into NEG’s collection and reconciliation of recoverable environmental costs, namely: (1) the legal fees charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005; (2) the legal fees charged by the Bishop, London & Dodds firm and passed through the recovery mechanisms since 2005; and (3) the legal fees passed through the recovery mechanism that the MA AG contends only qualify for a lesser (i.e., 50%) level of recovery. Respondents maintain that, by tariff, these costs are recoverable through rates charged to NEG customers pursuant to the environmental remediation adjustment clause program. After the Respondents answered the complaint and filed a motion to dismiss in 2011, the Hearing Officer deferred decision on the motion to dismiss and issued a stay of discovery pending resolution of a discovery dispute, which it later lifted on June 24, 2013, permitting the case to resume. However, the MA AG failed to take any further steps to prosecute its claims for nearly seven years. The case remained largely dormant until February 2022, when the Hearing Officer denied the motion to dismiss. After receiving input from the parties, the Hearing Officer entered a procedural schedule on March 16, 2022 (which was amended slightly on August 22, 2022). The parties engaged in discovery and the preparation of pre-filed testimony. Respondents submitted their pre-filed testimony on July 11, 2022. The MA AG served three sets of discovery requests on Respondents on September 9, September 12, and September 20, 2022, to which Respondents timely responded. On October 5, 2022, the MA AG requested that the DPU issue a ruling on whether the information that Respondents redacted in their attorneys’ fees invoices is protected by the attorney-client privilege. On the same day, the MA AG also filed a Motion to Stay the Procedural Schedule pending a ruling on the privilege issue. On October 6, 2022, without even affording Respondents the opportunity to respond, the DPU granted the MA AG’s request to stay the procedural schedule. Accordingly, all previous deadlines (including the MA AG’s October 7, 2022 deadline to submit direct pre-filed testimony) are presently stayed. On October 18, 2023, the DPU issued an Order on Attorney General’s Motion to Compel, ruling on issues originally raised in a motion to compel that the MA AG filed in 2013. The October 18, 2023 Order directed NEG to review its redactions again and, to the extent any invoices are completely redacted or heavily redacted, to provide more lightly redacted versions within 30 days. The October 18, 2023 Order also stated that the DPU will set a new procedural schedule in this matter sometime after NEG complies with the directives in the order, which Respondents have completed as of January 17, 2024. On January 6, 2026, the Hearing Officer issued a memo requesting substantial briefing on the merits of the matter. The initial brief by the MA AG is due on March 24, 2026 and the initial brief by the Respondents is due on April 7, 2026. All briefing is to be concluded by April 29, 2026.

Crestwood Midstream Partners, LP – Linde Litigation

On December 23, 2019, Linde Engineering North America Inc. (“Linde”) filed a lawsuit in the District Court of Harris County, Texas alleging that Arrow Field Services, LLC and Crestwood Midstream Partners LP, our consolidated subsidiaries (collectively, “Crestwood”), breached a contract entered into in March 2018 under which Linde was to provide engineering, procurement and construction services to Crestwood related to the completion of the construction of the Bear Den II cryogenic processing plant.

Trial was held in June 2022, and a final judgment was entered on October 24, 2022. The final judgment includes an award of damages of approximately $21 million, a pre-judgment interest award of approximately $18 million and attorney fees and other costs of approximately $5 million. Crestwood has insurance coverage related to certain pre-judgment interest awards but has not recorded a receivable related to any potential insurance recovery. On January 9, 2023, Crestwood paid approximately $21 million to the Court Registry under protest to mitigate the impact of post-judgment interest. Crestwood filed a Notice of Appeal on January 13, 2023, and filed its Appellate Brief on September 29, 2023. Linde’s response was filed on February 8, 2024. Oral argument was held on September 26, 2024.

On December 17, 2024, the First Court of Appeals in Houston issued its opinion, in which it reversed the trial court judgment in part and affirmed it in part. The appellate court reversed the awards to Linde of $18 million in interest and $5 million for fees and other costs. This reversal reduces the judgment amount by approximately $22 million. The appellate court affirmed the damages award to Linde of $21 million. The appellate court remanded the case to the trial court to recompute the prejudgment interest award. Linde filed its petition for review in the Texas Supreme Court on March 17, 2025; Crestwood filed its cross petition on April 30, 2025. In July 2025, the Texas Supreme Court requested responses to the petitions for review from both Linde and Crestwood. On September 26, 2025, the parties resolved and executed a settlement agreement, concluding this matter.

Twin Oaks Pipeline Litigation

On March 27, 2025, Daniel and Katherine La Hart filed a Class Action Complaint against SPLP, Energy Transfer, and Energy Transfer R&M in the Court of Common Pleas of Philadelphia County, captioned Daniel La Hart and Katherine La Hart v. Sunoco Pipeline L.P., Energy Transfer, and Energy Transfer R&M; Case No. 250303655. The action is related to the release of jet fuel (the “Release”) from the 14-inch Twin-Oaks to Newark Pipeline (the “Pipeline”) in Upper Makefield Township, Bucks County, Pennsylvania. Seven individual actions have also been filed in the Court of Common Pleas of Philadelphia County related to the Release. Plaintiffs in these cases assert causes of action for negligence, gross negligence, negligence per se, strict liability/abnormally dangerous/ultrahazardous activity, strict liability failure to warn, public nuisance, private nuisance, trespass, negligent infliction of emotional distress and medical monitoring. Plaintiffs seek compensatory damages, punitive damages, declaratory and injunctive relief, and medical monitoring for their alleged exposure to petroleum constituents at their properties and in groundwater. The putative class is comprised of homeowners in the surrounding area from September 1, 2023 to present.

On June 25, 2025, Defendants filed their preliminary objections to Plaintiffs’ Amended Complaints which included an objection based on improper venue, and on June 27, 2025, Defendants filed a Motion to Transfer the cases to the Court of Common Pleas of Bucks County, Pennsylvania on the grounds of forum non conveniens. On July 9, 2025, Plaintiffs filed a Motion for Preliminary Injunction in the class action, seeking inter alia, to enjoin the operation of the Pipeline; which Defendants opposed on July 21, 2025. In connection with the venue issues raised by these filings, the Court of Common Pleas ordered certain discovery, followed by amended pleadings and/or supplemental briefing. Following this discovery, Plaintiffs filed the current operative complaints on January 15, 2026, which add multiple additional defendants, including Energy Transfer Marketing & Terminals L.P. as well as other defendants who were allegedly shippers of product on the Pipeline and contractors who allegedly worked on the Pipeline. The parties have proposed a schedule which provides for additional venue-related discovery and a determination of venue.

Shortly after the original complaint was filed, SPLP, Energy Transfer, and Energy Transfer R&M removed the class action to the U.S. District Court for the Eastern District of Pennsylvania (the “E.D. Pa.”) on April 24, 2025. On June 13, 2025, the E.D. Pa. granted Plaintiffs’ motion to remand the case to the Court of Common Pleas of Philadelphia County. Defendants have appealed the remand decision.

SPLP, Energy Transfer, Energy Transfer R&M and Energy Transfer Marketing & Terminals intend to vigorously defend these claims.

State of Oklahoma Attorney General – Winter Storm Uri

On April 10, 2024, the State of Oklahoma, through Attorney General Gentner Drummond, filed a petition on behalf of Grand River Dam Authority against defendants ET Gathering & Processing LLC, successor by merger to Enable Midstream Partners, LP, Enable Oklahoma Intrastate Transmission, LLC, Enable Gas Transmission, LLC and Enable Energy Resources, LLC arising out of Winter Storm Uri in February 2021. Specifically, plaintiff alleges that defendants violated the Oklahoma Antitrust Reform Act (79 O.S. §201, et. seq.) by acting individually and in concert with each other to unreasonably restrain trade in the natural gas market in Oklahoma during the storm. Plaintiff also alleges causes of action for breach of contract, unjust enrichment, fraud, bad faith, conspiracy and negligence. Plaintiff’s petition seeks actual damages, punitive damages, treble damages and attorneys’ fees and costs. However, the actual amount sought was not specified.

On June 3, 2024, defendants filed a Motion to Dismiss and a Motion to Transfer Venue, along with a Brief in Support. In its Motion to Dismiss, defendants argued that plaintiff’s petition fails to state a claim upon which relief can be granted and also that such claims should be dismissed because collateral estoppel bars plaintiff from bringing allegations inconsistent with earlier agency and judicial findings that the extreme cold weather—not defendants’ conduct—caused the natural gas shortage and resulting high prices during Winter Storm Uri. Defendants also argued that plaintiff’s suit should be dismissed for filing suit in the wrong forum or, alternatively, should be transferred to the correct county of venue (Oklahoma County). Plaintiff filed its response brief on July 12, 2024. A hearing on both motions was held on October 15, 2024. On January 16, 2025, the Judge denied all motions, noting (1) that venue is proper in Osage County, Oklahoma; (2) collateral estoppel does not bar recovery; (3) the plaintiffs can plead inconsistent theories of recovery; and (4) the recovery is public in nature and not foreclosed by statute of limitations. The case will now proceed into the discovery phase.

In a separate matter filed on January 9, 2025, the State of Oklahoma through Gentner Drummond, Attorney General of Oklahoma (“Plaintiff”), filed a petition against ETC Marketing Ltd. and ETC Marketing Inc. (collectively, “ETCM”) and other natural gas marketers in Case No. CJ-25-06 in the District Court of Osage County, Oklahoma, arising out of Winter Storm Uri in February 2021. The Oklahoma Attorney General brought this action on behalf of its state agencies, political subdivisions and the people of the State of Oklahoma. Specifically, Plaintiff alleges that the defendants violated the Oklahoma Antitrust Reform Act (79 O.S. §201, et. seq.) by acting individually and in concert with each other to unreasonably restrain trade in the natural gas market in Oklahoma during the storm. Plaintiff also alleges causes of action for unjust enrichment and violation of the Oklahoma Consumer Protection Act. Plaintiff’s petition seeks damages in excess of $75,000, including actual damages, punitive damages, treble damages, and attorneys’ fees and costs. However, the actual amount sought was not specified.

On March 17, 2025, all defendants (including ETCM) jointly filed a motion to dismiss and brief in support. In the joint motion to dismiss, defendants asserted that FERC’s exclusive jurisdiction preempts all the Attorney General’s state-law claims and, alternatively, that the petition does not state a claim under Oklahoma antitrust law. Further, the motion argues that the Oklahoma Consumer Protection Act claims are time-barred and inconsistent with the statute, and that the unjust enrichment claims are barred by Oklahoma law. Finally, the motion alleges that the Attorney General’s unjust enrichment claims fail as a matter of law because defendants sold natural gas pursuant to valid contracts and the individual consumers were not direct purchasers of natural gas from defendants. On August 19, 2025, the court denied the motion without holding oral argument. The case will now proceed into the discovery phase.

Defendants cannot predict the ultimate outcome of this litigation but will vigorously defend against these claims.

Tax Contingencies

Rover Ad Valorem Taxes

Rover appealed the Ohio Department of Taxation (the "Department")’s final determination of the 2019 Ohio true value of the Rover pipeline to the Ohio Board of Tax Appeals (the "BTA") on September 11, 2020. On March 7, 2024, the BTA remanded the matter to the Department to redetermine the Ohio true value of the Rover pipeline consistent with the opinion of the appraiser the Department engaged for purposes of the BTA hearing. Rover appealed the BTA’s order to the Ohio Supreme Court on April 5, 2024, and the court affirmed the BTA’s order on August 13, 2025.

Rover timely petitioned the Department's preliminary assessments of its 2020, 2021, 2022, 2023, 2024, and 2025 Ohio true values, and these petitions remain pending. If it becomes probable that the Ohio Tax Commissioner’s preliminary assessments for tax years 2020 through 2025 are ultimately upheld, then Rover would recognize an additional Ohio public utility personal property tax liability for tax years 2020 through 2025 up to approximately $294 million, including interest. Rover intends to pursue all available legal remedies for the 2020 through 2025 tax years, and Rover cannot predict the outcome of these matters at this time.

On November 10, 2025, Rover filed a complaint against the Ohio Tax Commissioner in the Court of Common Pleas, Franklin County, Ohio. Rover is seeking a declaration that the Tax Commissioner’s 2019 valuation approach, if applied to Rover’s subsequent tax years, would violate certain protections afforded to Rover under the U.S. Constitution and the Ohio Constitution. The Tax Commissioner filed a motion to dismiss on December 8, 2025, Rover replied on January 15, 2026, and the Tax Commissioner responded to Rover’s reply on January 22, 2026. This matter remains pending, and Rover cannot predict the outcome of this matter at this time.

Sunoco LP New York Motor Fuel Excise Tax Audit

New York State issued a motor fuel excise tax assessment to Sunoco, LLC, a wholly owned subsidiary of Sunoco LP, in the amount of approximately $20 million, exclusive of penalties and interest, for the periods of March 2017 through May 2020. Sunoco, LLC filed an appeal with the New York State Division of Tax Appeals challenging the assessment. Sunoco, LLC cannot predict the outcome of this matter at this time.

See income tax contingencies in Note 10.

Environmental Matters

Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, natural resource damages, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.

Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on our results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.

Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.

Environmental Remediation

Our subsidiaries are responsible for environmental remediation at certain sites, including the following:

•Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could be contractually responsible for contamination caused by other parties.

•Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.

•Legacy sites related to Sunoco, Inc. that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that the Partnership no longer operates, closed and/or sold refineries and other formerly owned sites.

•The Partnership is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of December 31, 2025, the Partnership had been named as a PRP at approximately 31 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. The Partnership is usually one of a number of companies identified as a PRP at a site. The Partnership has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon the Partnership’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.

To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets.


	December 31,
	2025		2024
Current	$	62	$	51
Non-current	354		227
Total environmental liabilities	$	416	$	278

We have established a wholly owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.

During the years ended December 31, 2025 and 2024, the Partnership recorded $29 million and $11 million, respectively, of expenditures related to environmental cleanup programs.

Our pipeline operations are subject to regulation by the DOT under PHMSA, pursuant to which PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.

Our operations are also subject to the requirements of OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, the Occupational Safety and Health Administration’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our past costs for OSHA required activities, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances have not had a material adverse effect on our results of operations; however, there is no assurance that such costs will not be material in the future.

Estimates (Schedule Of Non-Cash Investing And Financing Activities) (Details) - USD ($)
$ in Millions

12 Months Ended

May 03, 2024

Dec. 31, 2025

Dec. 31, 2024

Dec. 31, 2023

NON-CASH INVESTING ACTIVITIES: [Abstract]

Cash paid for interest, net of interest capitalized

$ 3,136

$ 2,884

$ 2,298

Accrued capital expenditures

1,112

688

442

Lease assets obtained in exchange for new lease liabilities

296

Gain from subsidiary issuances of common units

164

301

Senior notes redeemed and issued in an exchange transaction

749

3,654

Stock Issued During Period, Value, Dividend Reinvestment Plan

Partners' Capital Account, Acquisitions

833

3,940

Convertible Preferred Stock Converted to Other Securities

749

USAC [Member] | legal defeasance of senior notes due 2026

725

Subsidiary unit transactions

^[1]

4,038

2,850

$ 0

Partners' Capital Account, Acquisitions

$ 403

$ 2,547

$ 3,651

[1]	See Note 3 for additional information.

Equity Incentive Plans (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Awards granted	$ 16.85
Unvested awards	35,200,000	36,100,000
Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Term	3 years 2 months 12 days
Awards granted	9,400,000
Liability of subsidiary outstanding cash restricted units	$ 0.1
Sunoco LP [Member]
Awards granted	303,179
USAC [Member]
Awards granted	172,405
SunocoCorp
Awards granted	61,171
ETE Long-Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	33,100,000
ET Unit Based Compensation Plans [Member]
Awards granted		$ 18.95	$ 13.78
Fair Value Of Units As Of The Vesting Date		$ 194.0	$ 106.0
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount	$ 332.0
Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Term	2 years 10 months 24 days
Subsidiary Unit Based Compensation [Member]
Fair Value Of Units As Of The Vesting Date	$ 29.0	$ 29.0	$ 37.0
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount	$ 93.0
ET Cash Restricted Unit Plan [Member]
Unvested awards	5,900,000
Awards granted	3,100,000	2,800,000	3,200,000
Deferred Compensation Share-based Arrangements, Liability, Current and Noncurrent	$ 3.8
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Period	3 years

Equity (Quarterly Distributions Of Available Cash) (Details) - $ / shares

3 Months Ended

12 Months Ended

Dec. 31, 2025

Sep. 30, 2025

Jun. 30, 2025

Mar. 31, 2025

Dec. 31, 2024

Sep. 30, 2024

Jun. 30, 2024

Mar. 31, 2024

Dec. 31, 2023

Sep. 30, 2023

Jun. 30, 2023

Mar. 31, 2023

Dec. 31, 2022

Dec. 31, 2025

Parent Company [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.3350

$ 0.3325

$ 0.3300

$ 0.3275

$ 0.3250

$ 0.3225

$ 0.3200

$ 0.3175

$ 0.3150

$ 0.3125

$ 0.3100

$ 0.3075

$ 0.3050

Distribution Made to Limited Partner, Distributions Paid, Per Unit

0.5250

Sunoco LP [Member] | Common Units

Distribution Made to Limited Partner, Distributions Paid, Per Unit

0.9317

0.9202

0.9088

0.8976

0.8865

0.8756

0.8420

0.8255

Sunoco LP [Member] | Class D Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

0.9317

Minimum Quarterly Distribution [Member]

First Target Distribution [Member]

$0.4375

Second Target Distribution [Member]

$0.4375 to $0.503125

Third Target Distribution [Member]

$0.503125 to $0.546875

$0.546875 to $0.656250

Thereafter [Member]

Common Stock | Minimum Quarterly Distribution [Member]

Above $0.656250

Common Stock | First Target Distribution [Member]

100%

Common Stock | Second Target Distribution [Member]

100%

Common Stock | Third Target Distribution [Member]

85%

Common Stock | Thereafter [Member]

75%

IDRs [Member] | Minimum Quarterly Distribution [Member]

50%

IDRs [Member] | First Target Distribution [Member]

—%

IDRs [Member] | Second Target Distribution [Member]

—%

IDRs [Member] | Third Target Distribution [Member]

15%

IDRs [Member] | Thereafter [Member]

25%

Series A Preferred Units [Member]

50%

Distribution Made to Limited Partner, Distributions Paid, Per Unit

9.88

23.99

24.71

24.67

23.89

21.98

31.25

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[1]

33.125

Series C Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

0.6075

0.6489

0.6294

0.4609

Series D Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

0.6199

0.6622

0.4766

Series E Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

0.4750

Series F Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

33.7500

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[1]

35.63

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[1]

32.50

Series I Preferred Units

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.2111

^[2]

$ 0.2111

^[2]

$ 0.2111

^[2]

$ 0.2111

^[2]

$ 0.2111

^[2]

$ 0.2111

^[2]

$ 0.2111

^[2]

$ 0.2111

^[2]

$ 0.2111

^[2]

$ 0

^[2]

$ 0

^[2]

$ 0

^[2]

$ 0

^[2]

$ 0.2111

[1]

Series B, Series G and Series H distributions are currently paid on a semi-annual basis. Distributions on the Series B Preferred Units will begin to be paid quarterly on February 15, 2028.

[2]

The record date and payment date shown above apply to all Energy Transfer Preferred Units, except for the Series I Preferred Units. For the period ended December 31, 2025, the cash distribution for the Series I Preferred Units was paid on February 17, 2026 to unitholders of record as of the close of business on February 4, 2026. For the period ended September 30, 2025, the cash distribution for the Series I Preferred Units were paid on November 14, 2025 to unitholders of record as of the close of business on November 4, 2025. For the period ended June 30, 2025, the cash distribution for the Series I Preferred Units was paid on August 14, 2025 to unitholders of record as of the close of business on August 4, 2025. For the period ended March 31, 2025, the cash distribution for the Series I Preferred Units was paid on May 15, 2025 to unitholders of record as of the close of business on May 2, 2025. For the period ended December 31, 2024, the cash distribution for the Series I Preferred Units was paid on February 14, 2025 to unitholders of record as of the close of business on February 4, 2025. For the period ended September 30, 2024, the cash distribution for the Series I Preferred Units was paid on November 14, 2024 to unitholders of record as of the close of business on November 4, 2024. For the period ended June 30, 2024, the cash distribution for the Series I Preferred Units was paid on August 14, 2024 to unitholders of record as of the close of business on August 2, 2024.

Debt Obligations Debt Obligations (Tables)

12 Months Ended

Dec. 31, 2025

Debt Obligations [Abstract]

Schedule of debt obligations

Our debt obligations consist of the following:


	December 31,
	2025	2024
Energy Transfer Indebtedness
4.05% senior notes due March 15, 2025(1)	—	1,000
2.90% senior notes due May 15, 2025(1)	—	1,000
5.95% senior notes due December 1, 2025(1)	—	400
4.75% senior notes due January 15, 2026(2)(3)	1,000	1,000
3.90% senior notes due July 15, 2026(2)	550	550
6.05% senior notes due December 1, 2026(2)	1,000	1,000
4.40% senior notes due March 15, 2027	700	700
4.20% senior notes due April 15, 2027	600	600
5.625% senior notes due May 1, 2027(3)	600	600
5.50% senior notes due June 1, 2027	44	44
5.50% senior notes due June 1, 2027	956	956
4.00% senior notes due October 1, 2027	750	750
5.55% senior notes due February 15, 2028	1,000	1,000
4.95% senior notes due May 15, 2028	800	800
4.95% senior notes due June 15, 2028	1,000	1,000
6.10% senior notes due December 1, 2028	500	500
6.00% senior notes due February 1, 2029	700	700
5.25% senior notes due April 15, 2029	1,500	1,500
5.25% senior notes due July 1, 2029	1,000	1,000
7.00% senior notes due July 15, 2029	66	66
4.15% senior notes due September 15, 2029	547	547
8.25% senior notes due November 15, 2029	33	33
8.25% senior notes due November 15, 2029	267	267
5.20% senior notes due April 1, 2030	650	—
3.75% senior note due May 15, 2030	1,500	1,500
6.40% senior notes due December 1, 2030	1,000	1,000
7.375% senior notes due April 1, 2031	600	600
5.75% senior notes due February 15, 2033	1,500	1,500
4.05% tax-exempt bonds due June 1, 2033	225	225
6.55% senior notes due December 1,2033	1,500	1,500
5.55% senior notes due May 15, 2034	1,250	1,250
5.60% senior notes due September 1, 2034	1,250	1,250
4.90% senior notes due March 15, 2035	500	500
5.70% senior notes due April 1, 2035	1,250	—
6.625% senior notes due October 15, 2036	400	400
5.80% senior notes due June 15, 2038	500	500
7.50% senior notes due July 1, 2038	550	550
6.85% senior notes due February 15, 2040	250	250
6.05% senior notes due June 1, 2041	700	700
6.50% senior notes due February 1, 2042	1,000	1,000
6.10% senior notes due February 15, 2042	300	300
4.95% senior notes due January 15, 2043	350	350
5.15% senior notes due February 1, 2043	450	450


5.95% senior notes due October 1, 2043	450	450
5.30% senior notes due April 1, 2044	700	700
5.00% senior notes due May 15, 2044	531	531
5.15% senior notes due March 15, 2045	1,000	1,000
5.35% senior notes due May 15, 2045	800	800
6.125% senior notes due December 15, 2045	1,000	1,000
5.30% senior notes due April 15, 2047	900	900
5.40% senior notes due October 1, 2047	1,500	1,500
6.00% senior notes due June 15, 2048	1,000	1,000
6.25% senior notes due April 15, 2049	1,750	1,750
5.00% senior notes due May 15, 2050	2,000	2,000
5.95% senior notes due May 15, 2054	1,750	1,750
6.05% senior notes due September 1, 2054	1,250	1,250
8.00% fixed-to-fixed reset rate junior subordinated notes due May 15, 2054	800	800
7.125% fixed-to-fixed reset rate junior subordinated notes due October 1, 2054	400	400
6.20% senior notes due April 1, 2055	1,100	—
6.50% Series 2025A junior subordinated notes due February 15, 2056	1,200	—
6.75% Series 2025B junior subordinated notes due February 15, 2056	800	—
Floating rate junior subordinated notes due November 1, 2066	600	600
Five-year credit facility due April 11, 2029	2,856	2,759
Unamortized premiums, discounts and fair value adjustments, net	30	62
Deferred debt issuance costs	(277)	(250)
	51,478	48,840
Subsidiary Indebtedness
Transwestern Debt
6.16% senior notes due May 24, 2037	75	75
	75	75
Bakken Project Debt
4.625% senior notes due April 1, 2029	850	850

Deferred debt issuance costs	(2)	(3)
	848	847
Sunoco LP Debt
5.750% senior notes due 2025 (1)	—	600
6.000% senior notes due 2026 (2)	500	500
3.875% CAD senior notes due 2026 (2) (4)	400	—
Parkland 3.875% CAD senior notes due 2026 (2)(5)	37	—
6.000% senior notes due 2027	600	600
5.625% senior notes due 2027	550	550
5.875% senior notes due 2027 (4)	499	—
Parkland 5.875% senior notes due 2027 (5)	1	—
5.875% senior notes due 2028	400	400
7.000% senior notes due 2028	500	500
6.000% CAD senior notes due 2028 (4)	277	—
Parkland 6.000% CAD senior notes due 2028 (5)	14	—
4.500% senior notes due 2029	800	800
7.000% senior notes due 2029	750	750
4.375% CAD senior notes due 2029 (4)	397	—
Parkland 4.375% CAD senior notes due 2029 (5)	40	—
4.500% senior notes due 2029 (4)	790	—


Parkland 4.500% senior notes due 2029 (5)	10		—
4.500% senior notes due 2030	800		800
6.375% senior notes due 2030	600		600
4.625% senior notes due 2030 (4)	798		—
Parkland 4.625% senior notes due 2030 (5)	2		—
5.625% senior notes due 2031	1,000		—
7.250% senior notes due 2032	750		750
6.625% senior notes due 2032 (4)	493		—
Parkland 6.625% senior notes due 2032 (5)	7		—
6.250% senior notes due 2033	1,000		—
5.875% senior notes due 2034	900		—
GoZone bonds	322		322
Sunoco LP credit facility due June 17, 2030	—		203
Lease-related obligations and other Sunoco LP subsidiary debt	233		132
Unamortized premiums, discounts and fair value adjustments, net	2		15
Deferred debt issuance costs	(83)		(37)
	13,389		7,485
USAC Debt
6.875% senior notes due September 1, 2027(1)	—		750
7.125% senior notes due March 15, 2029	1,000		1,000
6.250% senior notes due October 1, 2033	750		—
USAC credit facility due August 27, 2030	795		772
Deferred debt issuance costs	(21)		(20)
	2,524		2,502

Other long-term debt	19		11

Total debt	68,333		59,760
Less: Current maturities of long-term debt	25		8
Long-term debt, less current maturities	$	68,308	$	59,752

(1)These notes were redeemed in 2025.

(2)As of December 31, 2025, these obligations were classified as long-term as management had the intent and ability to refinance the borrowings on a long-term basis.

(3)These notes were redeemed in 2026.

Future maturities of long-term debt


2026	$	3,512
2027	5,314
2028	4,505
2029	11,619
2030	6,154
Thereafter	37,581
Total	$	68,685

Schedule of Debt Conversions

The following table summarizes the GoZone Bonds outstanding as of December 31, 2025:

Series

Date Issued

Amount Outstanding

Interest Rate

Mandatory Purchase Date

Original Redemption Date

Maturity Date

Series 2008

June 26, 2008

6.10

June 1, 2030

n/a

June 1, 2038

Series 2010

July 15, 2010

100

6.35

n/a

June 1, 2030

July 1, 2040

Series 2010A

October 7, 2010

6.35

n/a

June 1, 2030

October 1, 2040

Series 2010B

December 29, 2010

6.10

June 1, 2030

n/a

December 1, 2040

Series 2011

October 1, 2025

3.70

June 1, 2030

n/a

August 1, 2041

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(22))
-SubTopic 10
-Topic 210
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480566/210-10-S99-1

Reference 2: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 942
-SubTopic 235
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477314/942-235-S99-2

Reference 3: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S50
-Paragraph 4
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-4

Reference 4: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 3
-Subparagraph (SX 210.12-04(a))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-3

Reference 5: http://www.xbrl.org/2003/role/exampleRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 69B
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481568/470-20-55-69B

Reference 6: http://www.xbrl.org/2003/role/exampleRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 69E
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481568/470-20-55-69E

Reference 7: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 835
-SubTopic 30
-Name Accounting Standards Codification
-Section 45
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482925/835-30-45-2

Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-3

Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477734/942-470-50-3

Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-8

Reference 11: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 6
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-6

Reference 12: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 7
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-7

General Discussion of Derivative Instruments and Hedging Activities [Abstract]

Equity Incentive Plans (Subsidiary Equity Incentive Plans) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards	35,200,000	36,100,000
Unvested awards	$ 14,980,000	$ 13.18
Awards granted	9,400,000
Awards granted	$ 16.85
Awards vested	(9,500,000)
Awards vested	$ 10.20
Awards forfeited	800,000
Awards forfeited	$ 13.70
Sunoco LP Unit Based Compensation Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards	1,771,372	1,542,700
Unvested awards	$ 52.49	$ 46.83
Awards granted	730,078
Awards granted	$ 54.79
Awards vested	(442,386)
Awards vested	$ 36.60
Awards forfeited	59,020
Awards forfeited	$ 48.22
SunocoCorp Unit Based Compensation Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards	183,813	0
Unvested awards	$ 51.24	$ 0
Awards granted	183,813
Awards granted	$ 51.24
Awards vested	0
Awards vested	$ 0
Awards forfeited	0
Awards forfeited	$ 0
USAC Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards	302,334	1,320,316
Unvested awards	$ 20.16	$ 18.59
Awards granted	0
Awards granted	$ 0
Awards vested	(797,412)
Awards vested	$ 17.03
Awards forfeited	220,570
Awards forfeited	$ 18.82
USAC Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards	646,382	323,390
Unvested awards	$ 23.84	$ 22.25
Awards granted	392,422
Awards granted	$ 24.26
Awards vested	0
Awards vested	$ 0
Awards forfeited	69,430
Awards forfeited	$ 22.25

Derivative Assets And Liabilities (Tables)

12 Months Ended

Dec. 31, 2025

Outstanding Commodity-Related Derivatives

The following table details our outstanding commodity-related derivatives:


	December 31, 2025		December 31, 2024
	Notional Volume	Maturity	Notional Volume	Maturity
Mark-to-Market Derivatives







Natural Gas (BBtu)	(233,645)	2026-2028	(146,700)	2025-2027





Power (Megawatt):	(461,896)	2026-2029	(151,697)	2025-2029









Crude, NGL and refined products (MBbls)	(59,247)	2026-2029	(39,361)	2025-2027




Other	*	2026-2042	—	—
Fair Value Hedging Derivatives



Natural Gas (BBtu)	(100,346)	2026	(94,340)	2025

*Forward contracts consisting of 54 million RINs maturing in 2026 and emission credits of 747,038 metric tons maturing through 2042.

Fair Value Of Derivative Instruments

The following table provides a summary of our derivative assets and liabilities:


	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	December 31, 2025		December 31, 2024		December 31, 2025		December 31, 2024
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	31	$	3	$	(2)	$	(7)
	31		3		(2)		(7)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	485		209		(392)		(229)
Commodity derivatives	102		51		(60)		(57)




	587		260		(452)		(286)
Total derivatives	$	618	$	263	$	(454)	$	(293)

Offsetting Assets [Table Text Block]

The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:


		Asset Derivatives				Liability Derivatives
	Balance Sheet Location	December 31, 2025		December 31, 2024		December 31, 2025		December 31, 2024

Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	102		51		(60)		(57)
Broker cleared derivative contracts	Other current assets (liabilities)	516		212		(394)		(236)
		618		263		(454)		(293)
Offsetting agreements:

Counterparty netting	Derivative assets (liabilities)	(50)		(42)		50		42
Counterparty netting	Other current assets (liabilities)	(384)		(204)		384		204
Total net derivatives		$	184	$	17	$	(20)	$	(47)

Derivatives Not Designated as Hedging Instruments [Table Text Block]

The following tables summarize the amounts recognized with respect to our derivative financial instruments:


	Location of Gain (Loss) Recognized in Income on Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives
		Years Ended December 31,
		2025		2024		2023
Derivatives not designated as hedging instruments:



Commodity derivatives	Cost of products sold	$	241	$	57	$	47

Interest rate derivatives	Other, net	—		6		36

Total		$	241	$	63	$	83

Consolidated Statements Of Cash Flows - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2025

Dec. 31, 2024

Dec. 31, 2023

CASH FLOWS FROM OPERATING ACTIVITIES:

NET INCOME

$ 5,708

$ 6,565

$ 5,294

Reconciliation of net income to net cash provided by operating activities:

Deferred Income Tax Expense (Benefit)

5,682

5,165

4,385

178

276

203

Inventory valuation adjustments

156

114

Non-cash compensation expense

148

151

130

(Gains) losses on extinguishments of debt

285

(2)

Distributions on unvested awards

Proceeds from Equity Method Investment, Distribution

382

356

353

^[1]

(419)

(379)

(383)

Other Noncash Income (Expense)

(586)

(23)

(63)

Net change in operating assets and liabilities, net of effects of acquisitions and divestitures

(1,976)

(196)

(451)

Net cash provided by operating activities

10,149

11,506

9,555

Cash Acquired from Acquisition

Capital expenditures, excluding allowance for equity funds used during construction

(6,303)

(4,164)

(3,134)

Contributions in aid of construction costs

100

Contributions to unconsolidated affiliates

(10)

(206)

(6)

Distributions from unconsolidated affiliates in excess of cumulative earnings

Net cash used in investing activities

(8,373)

(5,904)

(4,325)

Proceeds from borrowings

32,870

34,150

32,130

Repayments of debt

(28,052)

(29,409)

(31,416)

Preferred units issued for cash

(749)

1,473

Distributions to noncontrolling interests

(4,725)

(4,623)

(4,248)

(1,734)

(1,780)

(1,691)

Distributions to redeemable noncontrolling interests

Debt issuance costs

(119)

(147)

(45)

Capital contributions from noncontrolling interests

Net cash used in financing activities

(816)

(5,451)

(5,326)

Increase (decrease) in cash and cash equivalents

960

151

(96)

Cash and cash equivalents, beginning of period

312

161

257

Cash and cash equivalents, end of period

1,272

312

161

Proceeds from Contributions from Affiliates

638

Nustar

Payments for Repurchase of Preferred Stock and Preference Stock

(784)

Other Assets

Proceeds from sales of other assets

Sunoco LP West Texas Assets

Proceeds from sales of other assets

987

Crestwood Niobrara LLC

Payments for Repurchase of Preferred Stock and Preference Stock

(37)

Series A, Series C, Series D and Series E preferred units

Payments for Repurchase of Preferred Stock and Preference Stock

(500)

(2,645)

(288)

(930)

Sunoco LP acquisitions of terminals

(2,174)

Edwards Lime Gathering, LLC

(253)

(224)

(84)

Other acquisitions [Member]

(2,004)

Estimates, Significant Accounting Policies and Balance Sheet Detail

$ (4)

$ (250)

$ (111)

[1]	Amounts reflected above exclude Sunoco LP’s earnings from the ET-S Permian and J.C. Nolan joint ventures, which are eliminated in consolidation.

Estimates, Significant Accounting Policies and Balance Sheet Detail

12 Months Ended

Dec. 31, 2025

Accounting Policies [Abstract]

ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The oil and gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for much of our business are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.

Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.

Regulatory Accounting – Regulatory Assets and Liabilities

Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that segment have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities, in accordance with Accounting Standards Codification (“ASC”) Topic 980. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment under ASC Topic 980 for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.

Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of the FERC in accordance with the NGA and NGPA, Panhandle does not currently apply ASC Topic 980 in its GAAP-basis consolidated financial statements, primarily due to the level of discounting from tariff rates and its inability to recover specific costs.

Cash, Cash Equivalents and Supplemental Cash Flow Information

Cash and cash equivalents include all cash on hand, demand deposits and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value.

We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.

The net change in operating assets and liabilities, net of effects of acquisitions and divestitures, included in cash flows from operating activities is comprised as follows:


	Years Ended December 31,
	2025		2024		2023
Accounts receivable	$	(77)	$	(775)	$	(171)
Accounts receivable from related companies	31		15		(5)
Inventories	(717)		(735)		35
Other current assets	(80)		82		221
Other non-current assets, net	(120)		(166)		(125)
Accounts payable	(322)		1,315		(501)
Accounts payable to related companies	(24)		(35)		(38)
Accrued and other current liabilities	(96)		166		209
Other non-current liabilities	(523)		(123)		(33)
Derivative assets and liabilities, net	(48)		60		(43)
Net change in operating assets and liabilities, net of effects of acquisitions and divestitures	$	(1,976)	$	(196)	$	(451)

Non-cash investing and financing activities and supplemental cash flow information are as follows:


	Years Ended December 31,
	2025		2024		2023
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Accrued capital expenditures	$	1,112	$	688	$	442
Lease assets obtained in exchange for new lease liabilities	296		7		23
Distribution reinvestment	45		89		90
Energy Transfer common units issued in connection with acquisitions (1)	—		833		3,940
USAC exercise and conversion of preferred units into common units	164		301		—
USAC government securities transferred in connection with the legal defeasance of USAC senior notes due 2026	—		749		—
Legal defeasance of USAC senior notes due 2026	—		725		—
Sunoco LP senior notes redeemed and issued in exchange transaction	3,654		—		—
Sunoco LP common units (noncontrolling interest) issued in connection with acquisitions (1)	4,038		2,850		—
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	$	3,136	$	2,884	$	2,298

(1)See Note 3 for additional information.

Accounts Receivable, net

Our operations deal with a variety of counterparties across the energy sector. Internal credit ratings and credit limits are assigned to all counterparties and limits are monitored against credit exposure. Letters of credit or prepayments may be required from those counterparties that are not investment grade depending on the internal credit rating and level of commercial activity with the counterparty.

We have a diverse portfolio of customers; however, because of the midstream and transportation services we provide, many of our customers are engaged in the exploration and production sector. We manage trade credit risk to mitigate credit losses and exposure to uncollectible trade receivables. Prospective and existing customers are reviewed regularly for creditworthiness to manage credit risk within approved tolerances. Customers that do not meet minimum credit standards are required to provide additional credit support in the form of a letter of credit, prepayment, or other forms of security. We establish an allowance for credit losses on trade receivables based on the expected ultimate recovery of these receivables and consider many factors including historical customer collection experience, general and specific economic trends, and known specific issues related to individual customers, sectors, and transactions that might impact collectability. Changes in the allowance are recorded as a component of operating expenses; reductions in the allowance are recorded when

receivables are subsequently collected or written-off. Past due receivable balances are written-off when our efforts have been unsuccessful in collecting the amount due.

Inventories

Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method.

Sunoco LP’s fuel inventories, other than in the Caribbean, are stated at the lower of cost or market using the last-in-first-out (“LIFO”) method. As of December 31, 2025 and 2024, Sunoco LP’s fuel inventory balance included lower of cost or market reserves of $472 million and $316 million, respectively. For the years ended December 31, 2025, 2024 and 2023, the Partnership’s consolidated statements of operations and comprehensive income did not include any material amounts of income from the liquidation of Sunoco LP’s LIFO fuel inventory. For the years ended December 31, 2025, 2024 and 2023, the Partnership’s cost of products sold included unfavorable inventory adjustments of $156 million, $86 million and $114 million, respectively, which decreased net income.

Sunoco LP’s fuel inventories in the Caribbean, which totaled $88 million at December 31, 2025, are stated at the lower of cost or market using the FIFO method. Under this methodology, the cost of fuel sold consists of older acquisition costs, which includes transportation and storage costs.

The Partnership’s inventories consisted of the following:


	December 31,
	2025		2024
Natural gas, NGLs and refined products	$	3,506	$	1,989
Crude oil	286		400
Spare parts and other	978		681
Total inventories	$	4,770	$	3,070

We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.

Other Current Assets

Other current assets consisted of the following:


	December 31,
	2025		2024
Deposits paid to vendors	$	216	$	150
Prepaid expenses and other	472		327
Total other current assets	$	688	$	477

Property, Plant and Equipment, net

Property, plant and equipment is stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC-mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment is retired or sold, any gain or loss is included in our consolidated statements of operations.

Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value.

For the years ended December 31 2025, 2024 and 2023, USAC recognized fixed asset impairments of $8 million, $1 million and $12 million, respectively, primarily related to its compression equipment as a result of its evaluation of the future deployment of idle fleet.

In 2025, the Partnership recorded a $256 million fixed asset impairment related to the suspension of the Lake Charles LNG export project.

Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the then current weighted average interest rate of our outstanding debt when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.

Components and useful lives of property, plant and equipment were as follows:


	December 31,
	2025		2024
Land and improvements	$	3,051	$	1,675
Buildings and improvements (1 to 40 years)	8,448		4,688
Pipelines and equipment (5 to 65 years)	101,506		97,078
Product storage and related facilities (2 to 40 years)	8,399		7,869
Right of way (20 to 65 years)	9,344		9,239
Other (1 to 48 years)	4,694		4,060
Construction work-in-process	5,841		4,633
	141,283		129,242
Less – Accumulated depreciation and depletion	(39,141)		(34,030)
Property, plant and equipment, net	$	102,142	$	95,212

We recognized the following amounts for the periods presented:


	Years Ended December 31,
	2025		2024		2023
Depreciation, depletion and amortization expense	$	5,203	$	4,701	$	3,986
Capitalized interest	150		120		77

Investments in Unconsolidated Affiliates

We own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary.

Other Non-Current Assets, net

Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following:


	December 31,
	2025		2024
Crude pipeline linefill and tank bottoms	$	787	$	743
Regulatory assets	40		39
Pension assets	209		188
Deferred charges	146		151
Restricted funds	210		216
Other	1,199		680
Total other non-current assets, net	$	2,591	$	2,017

Restricted funds primarily consist of investments held in our wholly owned captive insurance companies, including an immaterial amount of restricted cash.

Intangible Assets, net

Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized.

Components and useful lives of intangible assets were as follows:


	December 31, 2025				December 31, 2024
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Amortizable intangible assets:
Customer relationships, contracts and agreements (3 to 46 years)	$	10,859	$	(4,128)	$	9,304	$	(3,654)
Patents (10 years)	48		(48)		48		(48)

Trade names (20 years)	66		(51)		66		(48)
Other (5 to 20 years)	95		(9)		12		(11)
Total amortizable intangible assets	11,068		(4,236)		9,430		(3,761)
Non-amortizable intangible assets:
Trademarks	606		—		302		—

Total non-amortizable intangible assets	606		—		302		—
Total intangible assets	$	11,674	$	(4,236)	$	9,732	$	(3,761)

Aggregate amortization expense of intangible assets was as follows:


	Years Ended December 31,
	2025		2024		2023
Reported in depreciation, depletion and amortization expense	$	479	$	464	$	399

Estimated aggregate amortization of intangible assets for the next five years is as follows:


Years Ending December 31:
2026	$	558
2027	542
2028	539
2029	533
2030	516

We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate.

Goodwill

Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test was performed during the fourth quarter.

Changes in the carrying amount of goodwill were as follows:


	Midstream		NGL and Refined Products Transportation and Services		Crude Oil Transportation and Services		Investment in Sunoco LP		All Other		Total










Balance, December 31, 2023	$	601	$	884	$	853	$	1,599	$	82	$	4,019
Acquired	—		—		—		16		—		16
Disposed	—		—		—		(138)		—		(138)

Other	16		2		(12)		—		—		6
Balance, December 31, 2024	617		886		841		1,477		82		3,903
Acquired	—		—		—		1,528		—		1,528


Other	—		—		—		21		—		21
Balance, December 31, 2025	$	617	$	886	$	841	$	3,026	$	82	$	5,452

Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized. During 2025, $1.53 billion of goodwill was recorded in connection with Sunoco LP’s acquisition of Parkland. During 2024, $16 million of goodwill was recorded in connection with Sunoco LP’s acquisition of NuStar and $138 million of goodwill was removed in connection with Sunoco LP’s sale of 204 convenience stores to 7-Eleven, Inc.

The Partnership determines the fair value of our reporting units using the discounted cash flow method, the guideline company method, or a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determines fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determines the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimates a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business. The fair

value estimates used in the long-lived asset and goodwill tests were primarily based on Level 3 inputs of the fair value hierarchy.

Asset Retirement Obligations

We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.

An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an ARO in the periods in which management can reasonably estimate the settlement dates.

As of December 31, 2025 and 2024, other non-current liabilities in the Partnership’s consolidated balance sheets included AROs of $589 million and $418 million, respectively. For the years ended December 31, 2025, 2024 and 2023 aggregate accretion expense related to AROs was $13 million, $11 million and $10 million, respectively.

Except for the AROs discussed above, management was not able to reasonably measure the fair value of AROs as of December 31, 2025 and 2024, in most cases because the settlement dates were indeterminable. Although a number of onshore assets in our systems are subject to agreements or regulations that give rise to an ARO upon discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Our subsidiaries also have legal obligations for several other assets at previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, our subsidiaries are legally or contractually required to abandon in place or remove the asset. We believe we may have additional AROs related to pipeline assets and storage tanks, for which it is not possible to estimate whether or when the AROs will be settled. Consequently, these AROs cannot be measured at this time. Sunoco LP also has AROs related to the estimated future cost to remove underground storage tanks.

Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future. We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.

As of December 31, 2025 and 2024, other non-current assets on the Partnership’s consolidated balance sheets included $35 million and $31 million, respectively, of funds that were legally restricted for the purpose of settling AROs.

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:


	December 31,
	2025		2024
Interest payable	$	878	$	685
Customer advances and deposits	343		360
Accrued capital expenditures	1,112		688
Accrued wages and benefits	494		422
Taxes payable other than income taxes	844		737


Exchanges payable	86		90
Deferred revenue	366		322
Other	1,042		937
Total accrued and other current liabilities	$	5,165	$	4,241

In certain circumstances, customer advances and deposits are received from our customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may be required when customers exceed their credit limits or do not qualify for open credit.

Redeemable Noncontrolling Interests

Our redeemable noncontrolling interests relate to certain preferred unitholders of our consolidated subsidiaries that have the option to convert their preferred units to such subsidiary’s common units at the election of the holders and the noncontrolling interest holders in our consolidated subsidiaries that have the option to sell their interests to us. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable noncontrolling interests on our consolidated balance sheets. See Note 7 for further information.

Environmental Remediation

We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued.

Fair Value of Financial Instruments

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value.

Commodity derivatives, excluding those designated as normal purchases or normal sales, are recognized as assets or liabilities at fair value on our consolidated balance sheets. Fair value is determined using the highest level of observable inputs available, in accordance with the fair value hierarchy.

Exchange-traded contracts, such as futures, swaps and options, are valued using quoted market prices from exchanges including the New York Mercantile Exchange, Intercontinental Exchange or similar platforms. These are classified as Level 1.

Over-the-counter (OTC) swaps, options and physical forward contracts that are comparable to actively traded instruments are valued using third-party broker quotes, pricing services or relevant exchange data. This category also includes OTC options valued using an option pricing model based on observable market inputs. These instruments are classified as Level 2.

Less liquid instruments, including non-standard term OTC swaps and options, as well as long-dated contracts, are valued using internally developed models based on historical industry practices. These models incorporate forward price curves, volatility assumptions, time value and other relevant economic factors. These are classified as Level 3.

The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2025 and 2024 based on inputs used to derive their fair values:


	Fair Value Total		Fair Value Measurements at December 31, 2025
			Level 1		Level 2
Assets:





















Total commodity derivatives	$	618	$	531	$	87
Other non-current assets	209		209		—
Total assets	$	827	$	740	$	87
Liabilities:





















Total commodity derivatives	$	(454)	$	(404)	$	(50)
Total liabilities	$	(454)	$	(404)	$	(50)


	Fair Value Total		Fair Value Measurements at December 31, 2024
			Level 1		Level 2
Assets:


















Total commodity derivatives	$	263	$	263	$	—
Other non-current assets	212		212		—
Total assets	$	475	$	475	$	—
Liabilities:




















Total commodity derivatives	$	(293)	$	(293)	$	—
Total liabilities	$	(293)	$	(293)	$	—

Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our debt obligations as of December 31, 2025 was $68.55 billion and $68.33 billion, respectively. As of December 31, 2024, the aggregate fair value and carrying amount of our debt obligations was $59.01 billion and $59.76 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

Contributions in Aid of Construction Costs

On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. For our regulated businesses, contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received. For our non-regulated businesses, contributions in aid of construction costs are included in the transaction price of the underlying contract.

Shipping and Handling Costs

Shipping and handling costs are included in cost of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are included in operating expenses.

Costs and Expenses

Cost of products sold include actual cost of fuel sold, adjusted for the effects of our hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership and administrative personnel.

We record the collection of taxes to be remitted to government authorities on a net basis, except for consumer excise taxes collected by Sunoco LP on sales of refined products and merchandise which are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income. For the years ended December 31, 2025, 2024 and 2023, excise taxes collected by Sunoco LP were $261 million, $164 million and $274 million, respectively.

Issuances of Subsidiary Units

We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon our subsidiary’s issuance of common units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interests are adjusted as a change in partners’ capital.

Related Party Transactions

The Partnership regularly enters into related party transactions with several of its unconsolidated affiliates. In addition to commercial transactions, these transactions include the provision of certain management services and leases of certain assets. While the Partnership believes that such related party transactions generally reflect market rates, the pricing under such agreements may not be comparable to similar transactions with unaffiliated third parties. For the years ended December 31, 2025, 2024 and 2023, the Partnership’s consolidated income statements reflect revenues from related parties of $568 million, $603 million and $626 million, respectively.

Foreign Currency Translation

The functional currencies of our foreign subsidiaries are the local currencies of the countries in which the subsidiaries are located. Transactions in foreign currencies are translated to the respective functional currencies at the exchange rates applicable on the dates of the transactions. Monetary assets and liabilities denominated in foreign currencies are translated to the appropriate functional currency at the exchange rate at the consolidated balance sheet date. Foreign exchange gains and losses are recorded in the consolidated statements of operations. Non-monetary assets and liabilities denominated in foreign currencies are measured at cost using the exchange rates on the dates of initial recognition.

On consolidation, the financial statements of foreign operations are translated to U.S. dollars. The assets and liabilities of foreign operations are translated to U.S. dollars at the exchange rate prevailing at the consolidated balance sheet date. Income and expenses of foreign operations are translated to U.S. dollars at the exchange rates that approximate those on the dates of the transactions. Foreign exchange differences arising on translation for consolidation are recognized in other comprehensive income (loss). The results and financial position of subsidiaries with the functional currencies of hyperinflationary economies, after being restated for the effects of inflation in line with the Partnership’s policy over hyperinflation accounting, are translated to U.S. dollars at the exchange rate prevailing at the consolidated balance sheet date.

In connection with certain internal restructuring transactions subsequent to the Parkland acquisition, Sunoco LP and Parkland established an intercompany loan that is denominated in Canadian dollars. Foreign currency translation gains and losses related to this intercompany loan are recorded in “Other, net” within net income on the Partnership’s consolidated statement of operations.

Income Taxes

Energy Transfer is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and most state purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities, in addition to the allocation requirements related to taxable income under our Partnership Agreement. We do not have access to information regarding each partner’s individual tax basis in our limited partner interests.

As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and IRS pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, Energy Transfer would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2025, 2024 and 2023, our qualifying income met the statutory requirement.

The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local, and foreign income taxes. These corporate subsidiaries include ETP Holdco, Sunoco Retail LLC and Aloha, among others. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method.

Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.

The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our consolidated financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes.

The acquisition of Parkland by Sunoco LP brought the Partnership into scope for Pillar Two global minimum tax regime, a legislative framework established by Organization for Economic Co-operation and Development, as several jurisdictions in which the Partnership now operates have enacted Pillar Two global minimum tax legislation.

Consistent with ASC 740 and current industry guidance, the Partnership has applied a temporary exception and has not recognized deferred tax assets or liabilities related to Pillar Two tax liability.

The Partnership has elected to account for the tax on global intangible low-taxed income (“GILTI”) under IRC §951A as a period cost in the year the tax is incurred, rather than recognizing deferred taxes on basis differences in its controlled foreign corporations that may give rise to future GILTI inclusions.

Accounting for Derivative Instruments and Hedging Activities

For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third-party prices, readily available market information, broker quotes and appropriate valuation techniques.

At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period.

If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in our consolidated statements of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statements of operations.

Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged.

If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, the change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.

We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in other expenses in the consolidated statements of operations.

Equity Incentive Compensation

For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of the underlying common units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of the underlying common units as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets.

Pensions and Other Postretirement Benefit Plans

The Partnership recognizes the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans). Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Changes in the funded status of the plan are recorded in the year in which the change occurs within AOCI in equity or, for entities applying regulatory accounting, as a regulatory asset or regulatory liability.

Allocation of Income

For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests.

Recent Accounting Pronouncements

In November 2024, Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2024-03, Income Statement–Reporting Comprehensive Income–Expense Disaggregation Disclosures (Subtopic 220-40). ASU 2024-03 requires disclosure of specified information about certain costs and expenses in the notes to the consolidated financial statements. ASU 2024-03 is effective for annual periods beginning after December 15, 2026, and interim periods within annual periods beginning after December 15, 2027, with early adoption permitted. ASU 2024-03 is to be applied on a prospective basis, with retrospective application permitted. We are currently evaluating the impact, if any, of ASU 2024-03 on our consolidated financial statements and related disclosures.

In December 2023, FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. ASU 2023-09 improves and enhances income tax disclosure requirements, including new disclosures related to tax rate reconciliation and income taxes paid. The Partnership retrospectively adopted ASU 2023-09 during the year ended December 31, 2025 and has revised its disclosures accordingly, as reflected above in “Cash, Cash Equivalents and Supplemental Cash Flow Information” within Note 2 and below in Note 10.

Lease Accounting - Components of Lease Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	$ 137	$ 91
Interest on lease liabilities	3	2
Lease, Cost	227	138
Lease costs, gross	262	183
Finance Leases [Member]
Lessee, Lease, Description [Line Items]
Lease, Cost	8	4
Cost of goods sold
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	0	1
Operating expenses
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	116	71
Short-term lease cost	105	69
Variable lease cost	12	19
Selling, general and administrative
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	21	19
Depreciation, depletion and amortization
Lessee, Lease, Description [Line Items]
Amortization of lease assets	5	2
Other Revenue [Member]
Lessee, Lease, Description [Line Items]
Sublease Income	$ 35	$ 45

Consolidated Balance Sheets Balance Sheet (Paranthetical) - shares	Dec. 31, 2025	Dec. 31, 2024
Class of Stock [Line Items]
Authorized	3,439,986,779	3,431,088,022
Issued	3,439,986,779	3,431,088,022
Outstanding	3,439,986,779	3,431,088,022
Preferred Units, Authorized	44,398,959	44,898,959
Preferred Units, Issued	44,398,959	44,898,959
Preferred Units, Outstanding	44,398,959	44,898,959

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 8A
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-8A

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-2

Reference 3: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 480
-SubTopic 10
-Name Accounting Standards Codification
-Section S50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479857/480-10-S50-1

Reference 5: http://www.xbrl.org/2003/role/exampleRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-13

Reference 6: http://www.xbrl.org/2003/role/recommendedDisclosureRef
-Topic 272
-SubTopic 10
-Name Accounting Standards Codification
-Section 45
-Paragraph 3
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483014/272-10-45-3

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 272
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482987/272-10-50-1

Reference 8: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(d))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-13

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-13

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-13

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (h)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-13

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 14
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-14

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 18
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-18

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
-Topic 210
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(27)(b))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480566/210-10-S99-1

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Topic 210
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(28))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480566/210-10-S99-1

Reference 17: http://www.xbrl.org/2003/role/disclosureRef
-Topic 210
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(29))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480566/210-10-S99-1

Reference 18: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 3
-Subparagraph (SX 210.6-03(i)(2))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479886/946-10-S99-3

Reference 19: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 3
-Subparagraph (SX 210.6-03(i)(1))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479886/946-10-S99-3

Reference 20: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 3
-Subparagraph (SX 210.6-03(i)(2)(i))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479886/946-10-S99-3

Reference 21: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 3
-Subparagraph (SX 210.6-03(i)(2)(ii))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479886/946-10-S99-3

General Discussion of Derivative Instruments and Hedging Activities [Abstract]

Lease Accounting - Remaining term and rate (Details)	Dec. 31, 2025 Rate	Dec. 31, 2024 Rate
Leases [Abstract]
Operating leases	20 years	18 years
Finance leases	14 years	15 years
Operating leases	6.00%	6.00%
Finance leases	5.00%	6.00%

Investments in Unconsolidated Affiliates (Narrative) (Details)	Dec. 31, 2025
Citrus [Member]
Interest ownership	50.00%
FGT [Member]
Interest ownership	100.00%
Midcontinent Express Pipeline, LLC [Member]
Interest ownership	50.00%
White Cliffs
Interest ownership	54.30%
Explorer
Interest ownership	15.00%
SESH
Interest ownership	50.00%

Retirement Benefits (Net Periodic Benefit Costs Schedule) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Defined Benefit Plan Disclosure [Line Items]
Settlements	$ 0	$ 0
Defined Benefit Plan, Benefit Obligation, Business Combination	0	12
Nustar Acquisition
Defined Benefit Plan Disclosure [Line Items]
Return on plan assets and other	0	0
Unfunded Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Settlements	0	0
Defined Benefit Plan, Benefit Obligation, Business Combination	0	0
Unfunded Plans [Member] \| Nustar Acquisition
Defined Benefit Plan Disclosure [Line Items]
Return on plan assets and other	0	0
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	0	1
Interest cost	1	6
Expected return on plan assets	0	(8)
Prior service cost amortization	(2)	(2)
Defined Benefit Plan, Actuarial Gain (Loss), Immediate Recognition as Component in Net Periodic Benefit (Cost) Credit	0	0
Settlements	0	2
Net periodic benefit cost	(1)	(1)
Fair value of plan assets		182
Accumulated benefit obligation		158	$ 23
Pension Benefits \| Funded Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	4	6
Settlements	(21)	0
Fair value of plan assets	28	182	22
Return on plan assets and other	3	13
Employer contributions	1	5
Benefits paid, net	(137)	(36)
Accumulated benefit obligation	0	158
Defined Benefit Plan, Accumulated Benefit Obligation, Increase (Decrease) for Plan Amendment	0	0
Benefits paid, net	(137)	(37)
Actuarial gain and other	(4)	13
Defined Benefit Plan, Benefit Obligation, Business Combination	0	152
Pension Benefits \| Funded Plans [Member] \| Nustar Acquisition
Defined Benefit Plan Disclosure [Line Items]
Return on plan assets and other	0	178
Pension Benefits \| Unfunded Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	0	0
Interest cost	1	1
Fair value of plan assets	0	0	0
Return on plan assets and other	0	0
Employer contributions	0	0
Benefits paid, net	0	0
Accumulated benefit obligation	15	16	17
Defined Benefit Plan, Accumulated Benefit Obligation, Increase (Decrease) for Plan Amendment	0	0
Benefits paid, net	(3)	(3)
Actuarial gain and other	1	1
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	2	0
Interest cost	7	7
Expected return on plan assets	(14)	(13)
Prior service cost amortization	3	2
Defined Benefit Plan, Actuarial Gain (Loss), Immediate Recognition as Component in Net Periodic Benefit (Cost) Credit	(3)	(1)
Settlements	0	0
Net periodic benefit cost	(5)	(5)
Fair value of plan assets	321	295	277
Return on plan assets and other	34	29
Employer contributions	3	2
Benefits paid, net	(11)	(13)
Accumulated benefit obligation	131	127	$ 138
Defined Benefit Plan, Accumulated Benefit Obligation, Increase (Decrease) for Plan Amendment	7	(11)
Benefits paid, net	(11)	(13)
Actuarial gain and other	$ (1)	$ (6)

Derivative Assets And Liabilities

12 Months Ended

Dec. 31, 2025

Derivative Assets And Liabilities

DERIVATIVE ASSETS AND LIABILITIES:

Commodity Price Risk

We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets.

We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off-peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized.

We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales on our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes.

We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes.

We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of natural gas, refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.

We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales. These contracts are not designated as hedges for accounting purposes.

We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our intrastate transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our intrastate transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.

The following table details our outstanding commodity-related derivatives:


	December 31, 2025		December 31, 2024
	Notional Volume	Maturity	Notional Volume	Maturity
Mark-to-Market Derivatives







Natural Gas (BBtu)	(233,645)	2026-2028	(146,700)	2025-2027





Power (Megawatt):	(461,896)	2026-2029	(151,697)	2025-2029









Crude, NGL and refined products (MBbls)	(59,247)	2026-2029	(39,361)	2025-2027




Other	*	2026-2042	—	—
Fair Value Hedging Derivatives



Natural Gas (BBtu)	(100,346)	2026	(94,340)	2025

*Forward contracts consisting of 54 million RINs maturing in 2026 and emission credits of 747,038 metric tons maturing through 2042.

Credit Risk and Customers

Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.

Our natural gas transportation and midstream revenues are derived significantly from companies that engage in exploration and production activities. In addition to oil and gas producers, the Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrial end-users, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.

The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily with independent system operators and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative

instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.

For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.

Derivative Summary

The following table provides a summary of our derivative assets and liabilities:


	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	December 31, 2025		December 31, 2024		December 31, 2025		December 31, 2024
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	31	$	3	$	(2)	$	(7)
	31		3		(2)		(7)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	485		209		(392)		(229)
Commodity derivatives	102		51		(60)		(57)




	587		260		(452)		(286)
Total derivatives	$	618	$	263	$	(454)	$	(293)


		Asset Derivatives				Liability Derivatives
	Balance Sheet Location	December 31, 2025		December 31, 2024		December 31, 2025		December 31, 2024

Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	102		51		(60)		(57)
Broker cleared derivative contracts	Other current assets (liabilities)	516		212		(394)		(236)
		618		263		(454)		(293)
Offsetting agreements:

Counterparty netting	Derivative assets (liabilities)	(50)		(42)		50		42
Counterparty netting	Other current assets (liabilities)	(384)		(204)		384		204
Total net derivatives		$	184	$	17	$	(20)	$	(47)

We disclose the non-exchange traded financial derivative instruments as derivative assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement.

The following tables summarize the amounts recognized with respect to our derivative financial instruments:


	Location of Gain (Loss) Recognized in Income on Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives
		Years Ended December 31,
		2025		2024		2023
Derivatives not designated as hedging instruments:



Commodity derivatives	Cost of products sold	$	241	$	57	$	47

Interest rate derivatives	Other, net	—		6		36

Total		$	241	$	63	$	83

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

Reference 1: http://www.xbrl.org/2003/role/exampleRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 182
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480401/815-10-55-182

Reference 2: http://www.xbrl.org/2003/role/exampleRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 185
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480401/815-10-55-185

Reference 3: http://www.xbrl.org/2003/role/exampleRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 184
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480401/815-10-55-184

Reference 4: http://www.xbrl.org/2003/role/exampleRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 181
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480401/815-10-55-181

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4K
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4K

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4K
-Subparagraph (a)(5)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4K

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4K
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4K

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4K
-Subparagraph (a)(3)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4K

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4K
-Subparagraph (b)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4K

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4H
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4H

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4H
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4H

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 15
-Name Accounting Standards Codification
-Section 50
-Paragraph 3
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480960/815-15-50-3

Reference 13: http://www.xbrl.org/2003/role/exampleRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 183
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480401/815-10-55-183

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4K
-Subparagraph (a)(4)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4K

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4K
-Subparagraph (a)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4K

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4K
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4K

Reference 17: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4I
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4I

Reference 18: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4F
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4F

Reference 19: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-2

Reference 20: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (a)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-2

Reference 21: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (a)(1)(iii)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-2

Reference 22: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (a)(1)(ii)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-2

Reference 23: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (a)(1)(i)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-2

Reference 24: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-1B

Reference 25: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1A
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-1A

Reference 26: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1A
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-1A

Reference 27: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1A
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-1A

Reference 28: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1A
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-1A

Reference 29: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org/815/tableOfContent

Reference 30: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 40
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (f)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480237/815-40-50-5

Reference 31: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 5C
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-5C

Estimates (Other Current Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Other Information [Abstract]
Deposits paid to vendors	$ 216	$ 150
Prepaid expenses and other	472	327
Total other current assets	$ 688	$ 477

Debt Obligations Debt Obligations (Schedule Of Debt Obligations) (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2025

Dec. 31, 2024

Other Long-term Debt

$ 19

$ 11

Current maturities of long-term debt

68,333

59,760

Long-term debt, less current maturities

68,308

59,752

Five Year Credit Facility

6.625% senior notes due 2032

$ 2,860

Parkland 6.625% senior notes due 2032

^[1]

6.625% senior notes due 2032 (4)

6.250% Senior Notes due 2033

^[2]

Parkland 6.625% senior notes due 2032 (5)

5.875% Senior Notes due 2034

6.250% senior notes due 2033

5.875% senior notes due 2034

Bakken Project [Member]

$ (2)

(3)

Bakken Project [Member] | 4.625% Senior Notes due 2029 [Member]

848

847

$ 850

850

4.625% senior notes due April 1, 2029

Capital Lease Obligations

$ 0

203

233

132

Debt Instrument, Unamortized Discount (Premium), Net

(2)

(15)

(83)

(37)

$ 13,389

7,485

Sunoco LP [Member] | 5.875% senior notes due 2028 [Member]

Sunoco LP credit facility due June 17, 2030

$ 400

400

Sunoco LP [Member] | 5.75% Senior Notes due October 1, 2025

5.875% senior notes due 2028

^[3]

$ 0

600

Sunoco LP [Member] | 6.00% Senior Notes due June 1, 2026

^[3]

5.750% senior notes due 2025 (1)

^[4]

$ 500

500

Sunoco LP [Member] | GoZone Bonds

^[4]

6.000% senior notes due 2026 (2)

$ 322

322

Sunoco LP [Member] | 3.875% CAD senior notes due June 16, 2026

^[4]

GoZone bonds

^[1],[4]

$ 400

Sunoco LP [Member] | 4.375% CAD senior notes due March 26, 2029

^[1],[4]

3.875% CAD senior notes due 2026 (2) (4)

^[2]

$ 40

Sunoco LP [Member] | 3.875% CAD senior notes due 2026

^[2]

Parkland 4.375% CAD senior notes due 2029 (5)

^[2],[4]

$ 37

Sunoco LP [Member] | 6.000% Senior notes due 2027

^[2],[4]

Parkland 3.875% CAD senior notes due 2026 (2)(5)

$ 600

600

Sunoco LP [Member] | 5.625% senior notes due 2027

6.000% senior notes due 2027

$ 550

550

Sunoco LP [Member] | 5.875% Senior notes due 2027

5.625% senior notes due 2027

^[1]

$ 499

Sunoco LP [Member] | 7.000% senior notes due 2028

^[1]

5.875% senior notes due 2027 (4)

$ 500

500

Sunoco LP [Member] | 6.000% senior notes due 2028

7.000% senior notes due 2028

^[1]

$ 277

Sunoco LP [Member] | 4.500% senior notes due 2029

^[1]

6.000% CAD senior notes due 2028 (4)

$ 800

800

Sunoco LP [Member] | 7.000% senior notes due 2029

4.500% senior notes due 2029

$ 750

750

Sunoco LP [Member] | 4.375% senior notes due 2029

7.000% senior notes due 2029

^[1]

$ 397

Sunoco LP [Member] | Parkland 5.875% Senior notes due 2027

^[1]

4.375% CAD senior notes due 2029 (4)

^[2]

$ 1

Sunoco LP [Member] | Parkland 6.000% senior notes due 2028

Parkland 5.875% senior notes due 2027 (5)

^[2]

$ 14

Sunoco LP [Member] | 4.50% senior notes due 2029

^[2]

Parkland 6.000% CAD senior notes due 2028 (5)

^[1]

$ 790

Sunoco LP [Member] | Parkland 4.500% senior notes due 2029

^[1]

4.500% senior notes due 2029 (4)

^[2]

$ 10

Sunoco LP [Member] | 4.500% senior notes due 2030

^[2]

Parkland 4.500% senior notes due 2029 (5)

$ 800

800

Sunoco LP [Member] | 6.375% senior notes due 2030

4.500% senior notes due 2030

$ 600

600

Sunoco LP [Member] | 4.625% senior notes due 2030

6.375% senior notes due 2030

^[1]

$ 798

Sunoco LP [Member] | Parkland 4.625% Senior notes due 2030

^[1]

4.625% senior notes due 2030 (4)

^[2]

$ 2

Sunoco LP [Member] | 5.625% Senior Notes due 2031

^[2]

Parkland 4.625% senior notes due 2030 (5)

$ 1,000

Sunoco LP [Member] | 7.250% senior notes due 2032

5.625% senior notes due 2031

$ 750

750

Sunoco LP [Member] | 6.625% senior notes due 2032

7.250% senior notes due 2032

Sunoco LP [Member] | Parkland 6.625% senior notes due 2032

^[1]

$ 493

Sunoco LP [Member] | 6.250% Senior Notes due 2033

^[2]

Sunoco LP [Member] | 5.875% Senior Notes due 2034

1,000

900

Transwestern [Member]

Transwestern [Member] | 6.16% Senior Unsecured Notes, due May 24, 2037 [Member]

$ 75

USA Compression Partners, LP [Member]

6.16% senior notes due May 24, 2037

$ 795

772

(21)

(20)

$ 2,524

2,502

USA Compression Partners, LP [Member] | 6.875% Senior Notes due September 2027 [Member]

USAC credit facility due August 27, 2030

^[3]

$ 0

750

USA Compression Partners, LP [Member] | 7.125% Senior Notes due March 2029

^[3]

6.875% senior notes due September 1, 2027(1)

$ 1,000

1,000

USA Compression Partners, LP [Member] | 6.250% senior notes due October 1, 2033

7.125% senior notes due March 15, 2029

$ 750

6.250% senior notes due October 1, 2033

ET [Member]

Debt Instrument, Unamortized Discount (Premium), Net

$ 30

(277)

(250)

ET [Member] | 5.5% Senior Notes due June 1, 2027 [Member]

51,478

48,840

$ 956

956

ET [Member] | 4.05% Senior Notes due March 2025 [Member]

5.50% senior notes due June 1, 2027

^[5]

$ 0

1,000

ET [Member] | 4.75% Senior Notes due January 2026 [Member]

4.05% senior notes due March 15, 2025(1)

^[4],[6]

$ 1,000

1,000

ET [Member] | 8.25% Senior Notes, due November 14, 2029 [Member]

^[4],[6]

4.75% senior notes due January 15, 2026(2)(3)

$ 267

267

ET [Member] | 4.90% Senior Notes due March 2035 [Member]

8.25% senior notes due November 15, 2029

$ 500

500

ET [Member] | 6.625% Senior Notes, due October 15, 2036 [Member]

4.90% senior notes due March 15, 2035

$ 400

400

ET [Member] | 5.80% Senior Notes due 2038 [Member]

6.625% senior notes due October 15, 2036

$ 500

500

ET [Member] | 7.5% Senior Notes, due July 1, 2038 [Member]

5.80% senior notes due June 15, 2038

$ 550

550

ET [Member] | Senior Notes 6.05% Due June 1, 2041 [Member]

7.50% senior notes due July 1, 2038

$ 700

700

ET [Member] | Senior Notes 6.50% Due February 1, 2042 [Member]

6.05% senior notes due June 1, 2041

$ 1,000

1,000

ET [Member] | 5.15% Senior Notes due February 1, 2043 [Member]

6.50% senior notes due February 1, 2042

$ 450

450

ET [Member] | 5.95% Senior Notes due October 1, 2043 [Member]

5.15% senior notes due February 1, 2043

$ 450

450

ET [Member] | 5.15% Senior Notes due March 2045 [Member]

5.95% senior notes due October 1, 2043

$ 1,000

1,000

ET [Member] | 6.125% Senior Notes due December 2045 [Member]

5.15% senior notes due March 15, 2045

$ 1,000

1,000

ET [Member] | 5.30% Senior Notes due April 2047 [Member]

6.125% senior notes due December 15, 2045

$ 900

900

ET [Member] | 5.40% Senior Notes due October 1, 2047 [Member]

5.30% senior notes due April 15, 2047

$ 1,500

1,500

ET [Member] | 6.0% Senior Notes due 2048 [Member]

5.40% senior notes due October 1, 2047

$ 1,000

1,000

ET [Member] | 6.25% Senior Notes due 2049 [Member]

6.00% senior notes due June 15, 2048

$ 1,750

1,750

ET [Member] | 6.85% Senior Notes, due February 15, 2040 [Member]

6.25% senior notes due April 15, 2049

$ 250

250

ET [Member] | 5.95% Senior Notes due December 2025 [Member]

6.85% senior notes due February 15, 2040

^[3]

$ 0

400

ET [Member] | 3.90% Senior Notes due July 15, 2026 [Member]

^[4]

5.95% senior notes due December 1, 2025(1)

^[4]

$ 550

550

ET [Member] | 4.20% Senior Notes due April 2027 [Member]

^[4]

3.90% senior notes due July 15, 2026(2)

$ 600

600

ET [Member] | 4.00% Senior Notes due October 1, 2027 [Member]

4.20% senior notes due April 15, 2027

$ 750

750

ET [Member] | 4.95% Senior Notes due 2028 [Member]

4.00% senior notes due October 1, 2027

$ 1,000

1,000

ET [Member] | Senior Note 6.10%, due February 15, 2042 [Member]

4.95% senior notes due June 15, 2028

$ 300

300

ET [Member] | 5.30% Senior Notes due April 1, 2044 [Member]

6.10% senior notes due February 15, 2042

$ 700

700

ET [Member] | 5.35% Senior Notes due May 15, 2045 [Member]

5.30% senior notes due April 1, 2044

$ 800

800

ET [Member] | 2.9% Senior Notes due May 15, 2025

5.35% senior notes due May 15, 2045

^[3]

$ 0

1,000

ET [Member] | 3.75 Senior Notes due May 15, 2030

^[4]

2.90% senior notes due May 15, 2025(1)

$ 1,500

1,500

ET [Member] | 5.00% Senior Notes due May 15, 2050

3.75% senior note due May 15, 2030

$ 2,000

2,000

ET [Member] | Five Year Credit Facility

5.00% senior notes due May 15, 2050

$ 2,856

2,759

ET [Member] | 5.00% Senior Notes due May 15, 2044

Five-year credit facility due April 11, 2029

$ 531

531

ET [Member] | 4.40% Senior Notes due March 15, 2027

5.00% senior notes due May 15, 2044

$ 700

700

ET [Member] | 4.95% Senior Notes due May 15, 2028

4.40% senior notes due March 15, 2027

$ 800

800

ET [Member] | 4.15% Senior Notes due September 15, 2029

4.95% senior notes due May 15, 2028

$ 547

547

ET [Member] | 5.5% Senior Notes due June 1, 2027

4.15% senior notes due September 15, 2029

$ 44

ET [Member] | 5.55% Senior Notes due February 15, 2028

5.50% senior notes due June 1, 2027

$ 1,000

1,000

ET [Member] | 5.75% Senior Notes due February 15, 2023

5.55% senior notes due February 15, 2028

$ 1,500

1,500

ET [Member] | 8.25% Senior Notes due to November 15, 2029 - Previously held by Panhandle

5.75% senior notes due February 15, 2033

$ 33

ET [Member] | 4.95% Senior Notes due January 2043 [Member]

8.25% senior notes due November 15, 2029

$ 350

350

ET [Member] | 6.05% Senior Notes due December 1, 2026

4.95% senior notes due January 15, 2043

^[4]

$ 1,000

1,000

ET [Member] | 6.10% Senior Notes due December 1, 2028

^[4]

6.05% senior notes due December 1, 2026(2)

$ 500

500

ET [Member] | 6.0% Senior Notes due February 1, 2029

6.10% senior notes due December 1, 2028

$ 700

700

ET [Member] | 6.40% Senior Notes due December 1, 2030

6.00% senior notes due February 1, 2029

$ 1,000

1,000

ET [Member] | 7.38 % Senior Notes due April 1, 2031

6.40% senior notes due December 1, 2030

$ 600

600

ET [Member] | 4.05% Senior Notes due June 1, 2033

7.375% senior notes due April 1, 2031

$ 225

225

ET [Member] | 6.55% Senior Notes due December 1, 2033

4.05% tax-exempt bonds due June 1, 2033

$ 1,500

1,500

ET [Member] | 5.25% Senior Notes due July 2029

6.55% senior notes due December 1,2033

$ 1,000

1,000

ET [Member] | 5.25% Senior Notes due April 2029

5.25% senior notes due July 1, 2029

$ 1,500

1,500

ET [Member] | 5.55% Senior Notes due May 15, 2034

5.25% senior notes due April 15, 2029

$ 1,250

1,250

ET [Member] | 5.60% Senior Notes due September 1, 2034

5.55% senior notes due May 15, 2034

$ 1,250

1,250

ET [Member] | 5.95% Senior Notes due May 15, 2054

5.60% senior notes due September 1, 2034

$ 1,750

1,750

ET [Member] | 6.05% Senior Notes due September 1, 2054

5.95% senior notes due May 15, 2054

$ 1,250

1,250

ET [Member] | Floating Rate Junior Subordinated Notes due November 1, 2066

6.05% senior notes due September 1, 2054

$ 600

600

ET [Member] | Floating Rate Junior Subordinated Notes Due May 15, 2054

Floating rate junior subordinated notes due November 1, 2066

$ 800

800

ET [Member] | Floating Rate Subordinated Notes due October 1, 2054

8.00% fixed-to-fixed reset rate junior subordinated notes due May 15, 2054

$ 400

400

ET [Member] | 5.625% Senior Notes due April 28, 2027

7.125% fixed-to-fixed reset rate junior subordinated notes due October 1, 2054

^[6]

$ 600

600

ET [Member] | 5.20% senior notes due April 1, 2030

^[6]

5.625% senior notes due May 1, 2027(3)

$ 650

ET [Member] | 5.70% Senior Notes due April 1, 2030

5.20% senior notes due April 1, 2030

$ 1,250

ET [Member] | 7.00% Senior Notes, due July 15, 2029 [Member]

5.70% senior notes due April 1, 2035

$ 66

ET [Member] | 6.20% senior notes due April 1, 2055

7.00% senior notes due July 15, 2029

$ 1,100

ET [Member] | 6.50% Series 2025A junior subordinated notes due February 15, 2056

6.20% senior notes due April 1, 2055

$ 1,200

ET [Member] | 6.75% Series 2025B junior subordinated notes due February 15,2056

6.50% Series 2025A junior subordinated notes due February 15, 2056

$ 800

$ 0

Unamortized Discounts, Premiums, Fair Value Adjustments and Deferred Debt Issuance Costs

6.75% Series 2025B junior subordinated notes due February 15, 2056

[1]	These senior notes, totaling $3.65 billion as of December 31, 2025, were assumed by Sunoco LP in connection with the closing of the Parkland acquisition. For additional information, see “Sunoco LP Parkland Senior Note Exchange” below.
[2]	These senior notes, totaling $111 million as of December 31, 2025, represent the aggregate principal amounts not tendered in the private exchange offers and remain outstanding obligations of Parkland. For additional information, see “Sunoco LP Parkland Senior Note Exchange” below.
[3]	These notes were redeemed in 2025.
[4]	As of December 31, 2025, these obligations were classified as long-term as management had the intent and ability to refinance the borrowings on a long-term basis.
[5]	(1)Intangible assets, net comprised of $1.49 billion of customer relationships, with a remaining weighted average life of approximately 20 years, $297 million of indefinite-lived tradenames and $85 million of other intangibles with a remaining weighted average life of approximately 10 years.
[6]	These notes were redeemed in 2026.

Insider Trading Arrangements	12 Months Ended
Insider Trading Arrangements	Dec. 31, 2025
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

Estimates, Significant Accounting Policies and Balance Sheet Detail (Policy)	12 Months Ended
	Dec. 31, 2025
Accounting Policies [Abstract]
Basis of Presentation	The consolidated financial statements of Energy Transfer LP presented herein have been prepared in accordance with GAAP and pursuant to the rules and regulations of the SEC. We consolidate all subsidiaries in which we have a controlling financial interest and limited partnerships in which we control the general partner. All significant intercompany transactions and accounts are eliminated in consolidation.
Consolidation	The consolidated financial statements of Energy Transfer presented herein include the results of operations of our controlled subsidiaries, including SunocoCorp, Sunoco LP and USAC. We also consolidate SunocoCorp as its primary beneficiary under the variable interest model, based on the Partnership’s interests in its subsidiary, Sunoco LP.
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The oil and gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for much of our business are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects. Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.
Regulatory Accounting - Regulatory Assets and Liabilities	Regulatory Accounting – Regulatory Assets and Liabilities Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that segment have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities, in accordance with Accounting Standards Codification (“ASC”) Topic 980. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment under ASC Topic 980 for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs. Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of the FERC in accordance with the NGA and NGPA, Panhandle does not currently apply ASC Topic 980 in its GAAP-basis consolidated financial statements, primarily due to the level of discounting from tariff rates and its inability to recover specific costs.
Cash, Cash Equivalents and Supplemental Cash Flow Information	Cash, Cash Equivalents and Supplemental Cash Flow Information Cash and cash equivalents include all cash on hand, demand deposits and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value. We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.
Accounts Receivable, net	Accounts Receivable, net Our operations deal with a variety of counterparties across the energy sector. Internal credit ratings and credit limits are assigned to all counterparties and limits are monitored against credit exposure. Letters of credit or prepayments may be required from those counterparties that are not investment grade depending on the internal credit rating and level of commercial activity with the counterparty. We have a diverse portfolio of customers; however, because of the midstream and transportation services we provide, many of our customers are engaged in the exploration and production sector. We manage trade credit risk to mitigate credit losses and exposure to uncollectible trade receivables. Prospective and existing customers are reviewed regularly for creditworthiness to manage credit risk within approved tolerances. Customers that do not meet minimum credit standards are required to provide additional credit support in the form of a letter of credit, prepayment, or other forms of security. We establish an allowance for credit losses on trade receivables based on the expected ultimate recovery of these receivables and consider many factors including historical customer collection experience, general and specific economic trends, and known specific issues related to individual customers, sectors, and transactions that might impact collectability. Changes in the allowance are recorded as a component of operating expenses; reductions in the allowance are recorded when receivables are subsequently collected or written-off. Past due receivable balances are written-off when our efforts have been unsuccessful in collecting the amount due.
Inventories	Inventories Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method. Sunoco LP’s fuel inventories, other than in the Caribbean, are stated at the lower of cost or market using the last-in-first-out (“LIFO”) method. As of December 31, 2025 and 2024, Sunoco LP’s fuel inventory balance included lower of cost or market reserves of $472 million and $316 million, respectively. For the years ended December 31, 2025, 2024 and 2023, the Partnership’s consolidated statements of operations and comprehensive income did not include any material amounts of income from the liquidation of Sunoco LP’s LIFO fuel inventory. For the years ended December 31, 2025, 2024 and 2023, the Partnership’s cost of products sold included unfavorable inventory adjustments of $156 million, $86 million and $114 million, respectively, which decreased net income. Sunoco LP’s fuel inventories in the Caribbean, which totaled $88 million at December 31, 2025, are stated at the lower of cost or market using the FIFO method. Under this methodology, the cost of fuel sold consists of older acquisition costs, which includes transportation and storage costs.We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.
Property, Plant and Equipment, net	Property, Plant and Equipment, net Property, plant and equipment is stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC-mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment is retired or sold, any gain or loss is included in our consolidated statements of operations. Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value. For the years ended December 31 2025, 2024 and 2023, USAC recognized fixed asset impairments of $8 million, $1 million and $12 million, respectively, primarily related to its compression equipment as a result of its evaluation of the future deployment of idle fleet. In 2025, the Partnership recorded a $256 million fixed asset impairment related to the suspension of the Lake Charles LNG export project. Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the then current weighted average interest rate of our outstanding debt when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.
Investments in Unconsolidated Affiliates	Investments in Unconsolidated Affiliates We own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary.
Other Non-Current Assets, net	Other non-current assets, net are stated at cost less accumulated amortization. Restricted funds primarily consist of investments held in our wholly owned captive insurance companies, including an immaterial amount of restricted cash.
Intangible Assets, net	Intangible Assets, net Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized. We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate.
Goodwill	Goodwill Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test was performed during the fourth quarter. Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized. During 2025, $1.53 billion of goodwill was recorded in connection with Sunoco LP’s acquisition of Parkland. During 2024, $16 million of goodwill was recorded in connection with Sunoco LP’s acquisition of NuStar and $138 million of goodwill was removed in connection with Sunoco LP’s sale of 204 convenience stores to 7-Eleven, Inc. The Partnership determines the fair value of our reporting units using the discounted cash flow method, the guideline company method, or a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determines fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determines the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimates a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business. The fair value estimates used in the long-lived asset and goodwill tests were primarily based on Level 3 inputs of the fair value hierarchy.
Asset Retirement Obligations	Asset Retirement Obligations We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO. An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an ARO in the periods in which management can reasonably estimate the settlement dates. As of December 31, 2025 and 2024, other non-current liabilities in the Partnership’s consolidated balance sheets included AROs of $589 million and $418 million, respectively. For the years ended December 31, 2025, 2024 and 2023 aggregate accretion expense related to AROs was $13 million, $11 million and $10 million, respectively. Except for the AROs discussed above, management was not able to reasonably measure the fair value of AROs as of December 31, 2025 and 2024, in most cases because the settlement dates were indeterminable. Although a number of onshore assets in our systems are subject to agreements or regulations that give rise to an ARO upon discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Our subsidiaries also have legal obligations for several other assets at previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, our subsidiaries are legally or contractually required to abandon in place or remove the asset. We believe we may have additional AROs related to pipeline assets and storage tanks, for which it is not possible to estimate whether or when the AROs will be settled. Consequently, these AROs cannot be measured at this time. Sunoco LP also has AROs related to the estimated future cost to remove underground storage tanks. Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future. We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely. As of December 31, 2025 and 2024, other non-current assets on the Partnership’s consolidated balance sheets included $35 million and $31 million, respectively, of funds that were legally restricted for the purpose of settling AROs.
Customer Advances and Deposits and Shipping and Handling Costs	In certain circumstances, customer advances and deposits are received from our customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may be required when customers exceed their credit limits or do not qualify for open credit. Shipping and Handling Costs Shipping and handling costs are included in cost of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are included in operating expenses.
Redeemable Noncontrolling Interests	Redeemable Noncontrolling Interests Our redeemable noncontrolling interests relate to certain preferred unitholders of our consolidated subsidiaries that have the option to convert their preferred units to such subsidiary’s common units at the election of the holders and the noncontrolling interest holders in our consolidated subsidiaries that have the option to sell their interests to us. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable noncontrolling interests on our consolidated balance sheets. See Note 7 for further information.
Environmental Remediation	Environmental Remediation We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued.
Fair Value of Financial Instruments	Fair Value of Financial Instruments The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Commodity derivatives, excluding those designated as normal purchases or normal sales, are recognized as assets or liabilities at fair value on our consolidated balance sheets. Fair value is determined using the highest level of observable inputs available, in accordance with the fair value hierarchy. Exchange-traded contracts, such as futures, swaps and options, are valued using quoted market prices from exchanges including the New York Mercantile Exchange, Intercontinental Exchange or similar platforms. These are classified as Level 1. Over-the-counter (OTC) swaps, options and physical forward contracts that are comparable to actively traded instruments are valued using third-party broker quotes, pricing services or relevant exchange data. This category also includes OTC options valued using an option pricing model based on observable market inputs. These instruments are classified as Level 2. Less liquid instruments, including non-standard term OTC swaps and options, as well as long-dated contracts, are valued using internally developed models based on historical industry practices. These models incorporate forward price curves, volatility assumptions, time value and other relevant economic factors. These are classified as Level 3.
Contributions In Aid Of Construction Costs	Contributions in Aid of Construction Costs On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. For our regulated businesses, contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received. For our non-regulated businesses, contributions in aid of construction costs are included in the transaction price of the underlying contract.
Costs and Expenses	Costs and Expenses Cost of products sold include actual cost of fuel sold, adjusted for the effects of our hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership and administrative personnel. We record the collection of taxes to be remitted to government authorities on a net basis, except for consumer excise taxes collected by Sunoco LP on sales of refined products and merchandise which are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income. For the years ended December 31, 2025, 2024 and 2023, excise taxes collected by Sunoco LP were $261 million, $164 million and $274 million, respectively.
Issuances of Subsidiary Units	Issuances of Subsidiary Units We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon our subsidiary’s issuance of common units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interests are adjusted as a change in partners’ capital.
Related Party Transactions	Related Party Transactions The Partnership regularly enters into related party transactions with several of its unconsolidated affiliates. In addition to commercial transactions, these transactions include the provision of certain management services and leases of certain assets. While the Partnership believes that such related party transactions generally reflect market rates, the pricing under such agreements may not be comparable to similar transactions with unaffiliated third parties. For the years ended December 31, 2025, 2024 and 2023, the Partnership’s consolidated income statements reflect revenues from related parties of $568 million, $603 million and $626 million, respectively.
Foreign Currency Translation	Foreign Currency Translation The functional currencies of our foreign subsidiaries are the local currencies of the countries in which the subsidiaries are located. Transactions in foreign currencies are translated to the respective functional currencies at the exchange rates applicable on the dates of the transactions. Monetary assets and liabilities denominated in foreign currencies are translated to the appropriate functional currency at the exchange rate at the consolidated balance sheet date. Foreign exchange gains and losses are recorded in the consolidated statements of operations. Non-monetary assets and liabilities denominated in foreign currencies are measured at cost using the exchange rates on the dates of initial recognition. On consolidation, the financial statements of foreign operations are translated to U.S. dollars. The assets and liabilities of foreign operations are translated to U.S. dollars at the exchange rate prevailing at the consolidated balance sheet date. Income and expenses of foreign operations are translated to U.S. dollars at the exchange rates that approximate those on the dates of the transactions. Foreign exchange differences arising on translation for consolidation are recognized in other comprehensive income (loss). The results and financial position of subsidiaries with the functional currencies of hyperinflationary economies, after being restated for the effects of inflation in line with the Partnership’s policy over hyperinflation accounting, are translated to U.S. dollars at the exchange rate prevailing at the consolidated balance sheet date. In connection with certain internal restructuring transactions subsequent to the Parkland acquisition, Sunoco LP and Parkland established an intercompany loan that is denominated in Canadian dollars. Foreign currency translation gains and losses related to this intercompany loan are recorded in “Other, net” within net income on the Partnership’s consolidated statement of operations.
Income Taxes	Income Taxes Energy Transfer is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and most state purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities, in addition to the allocation requirements related to taxable income under our Partnership Agreement. We do not have access to information regarding each partner’s individual tax basis in our limited partner interests. As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and IRS pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, Energy Transfer would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2025, 2024 and 2023, our qualifying income met the statutory requirement. The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local, and foreign income taxes. These corporate subsidiaries include ETP Holdco, Sunoco Retail LLC and Aloha, among others. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized. The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our consolidated financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes. The acquisition of Parkland by Sunoco LP brought the Partnership into scope for Pillar Two global minimum tax regime, a legislative framework established by Organization for Economic Co-operation and Development, as several jurisdictions in which the Partnership now operates have enacted Pillar Two global minimum tax legislation. Consistent with ASC 740 and current industry guidance, the Partnership has applied a temporary exception and has not recognized deferred tax assets or liabilities related to Pillar Two tax liability. The Partnership has elected to account for the tax on global intangible low-taxed income (“GILTI”) under IRC §951A as a period cost in the year the tax is incurred, rather than recognizing deferred taxes on basis differences in its controlled foreign corporations that may give rise to future GILTI inclusions.
Accounting for Derivative Instruments and Hedging Activities	Accounting for Derivative Instruments and Hedging Activities For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third-party prices, readily available market information, broker quotes and appropriate valuation techniques. At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period. If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in our consolidated statements of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statements of operations. Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged. If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, the change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations. We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in other expenses in the consolidated statements of operations.
Equity Incentive Compensation	Equity Incentive Compensation For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of the underlying common units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of the underlying common units as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets.
Pensions and Other Postretirement Benefit Plans	Pensions and Other Postretirement Benefit Plans The Partnership recognizes the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans). Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Changes in the funded status of the plan are recorded in the year in which the change occurs within AOCI in equity or, for entities applying regulatory accounting, as a regulatory asset or regulatory liability.
Allocation of Income	Allocation of Income For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests.
Recent Accounting Pronouncements	Recent Accounting Pronouncements In November 2024, Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2024-03, Income Statement–Reporting Comprehensive Income–Expense Disaggregation Disclosures (Subtopic 220-40). ASU 2024-03 requires disclosure of specified information about certain costs and expenses in the notes to the consolidated financial statements. ASU 2024-03 is effective for annual periods beginning after December 15, 2026, and interim periods within annual periods beginning after December 15, 2027, with early adoption permitted. ASU 2024-03 is to be applied on a prospective basis, with retrospective application permitted. We are currently evaluating the impact, if any, of ASU 2024-03 on our consolidated financial statements and related disclosures. In December 2023, FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. ASU 2023-09 improves and enhances income tax disclosure requirements, including new disclosures related to tax rate reconciliation and income taxes paid. The Partnership retrospectively adopted ASU 2023-09 during the year ended December 31, 2025 and has revised its disclosures accordingly, as reflected above in “Cash, Cash Equivalents and Supplemental Cash Flow Information” within Note 2 and below in Note 10.
Revenue Recognition	Disaggregation of revenue The major types of revenue within our reportable segments are as follows: •intrastate transportation and storage; •interstate transportation and storage; •midstream; •NGL and refined products transportation and services; •crude oil transportation and services; •investment in Sunoco LP; ◦fuel distribution; ◦pipeline systems; and ◦terminals •investment in USAC; ◦contract operations; and ◦retail parts and services; and •all other. Note 16 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606. Intrastate transportation and storage revenue Our intrastate transportation and storage segment’s revenues are determined primarily by the volume of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected or withdrawn into or out of our storage facilities. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity they transport or store. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected/withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject/withdraw into or out of our storage facilities. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead. Interstate transportation and storage revenue Our interstate transportation and storage segment’s revenues are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected into or withdrawn out of our storage facilities. Our interstate transportation and storage segment’s contracts can be firm or interruptible. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity transported or stored. In exchange for such fees, we must stand ready to perform a contractually agreed-upon minimum volume of services whenever the customer requests such services. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected or withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject into or withdraw out of our storage facilities. Consequently, we are not required to stand ready to provide any contractually agreed-upon volume of service, but instead provides the services based on existing capacity at the time the customer requests the services. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Lake Charles LNG’s revenues are primarily derived from terminalling services for shippers by receiving LNG at the facility for storage and delivering such LNG to shippers, either in liquid state or gaseous state after regasification. Lake Charles LNG derives all of its revenue from a series of long-term contracts with a wholly owned subsidiary of Royal Dutch Shell plc (“Shell”). Terminalling revenue is generated from fees paid by Shell for storage and other associated services at the terminal. Payment for services under these contracts are typically due the month after the services have been performed. The terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volumes transported by Shell or services provided at the terminal. The performance obligation with respect to firm contracts is a promise to provide a single type of service (terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. Midstream revenue Our midstream segment’s revenues are derived primarily from margins we earn for natural gas volumes that are gathered, processed and/or transported. The various types of revenue contracts our midstream segment enters into include: Fixed fee gathering and processing: Contracts under which we provide gathering and processing services in exchange for a fixed cash fee per unit of volume. Revenue for cash fees is recognized when the service is performed. Keepwhole: Contracts under which we gather raw natural gas from a third-party producer, process the gas to convert it to pipeline quality natural gas, and redeliver to the producer a thermal-equivalent volume of pipeline quality natural gas. In exchange for these services, we retain the NGLs extracted from the raw natural gas received from the producer as well as cash fees paid by the producer. The value of NGLs retained as well as cash fees is recognized as revenue when the services are performed. Percent of Proceeds (“POP”): Contracts under which we provide gathering and processing services in exchange for a specified percentage of the producer’s commodity (“POP percentage”) and also in some cases additional cash fees. The two types of POP revenue contracts are described below: •In-Kind POP: We retain our POP percentage (non-cash consideration) and also any additional cash fees in exchange for providing the services. We recognize revenue for the non-cash consideration and cash fees at the time the services are performed. •Mixed POP: We purchase NGLs from the producer and retain a portion of the residue gas as non-cash consideration for services provided. We may also receive cash fees for such services. Under Topic 606, these agreements were determined to be hybrid agreements which were partially supply agreements (for the NGLs we purchased) and customer agreements (for the services provided related to the product that was returned to the customer). Given that these are hybrid agreements, we split the cash and non-cash consideration between revenue and a reduction of costs based on the value of the service provided vs. the value of the supply received. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligations with respect to our midstream segment’s contracts are to provide gathering, transportation and processing services, each of which would be completed on or about the same time, and each of which would be recognized on the same line item on the income statement, therefore identification of separate performance obligations would not impact the timing or geography of revenue recognition. Certain contracts of our midstream segment include throughput commitments under which customers commit to purchasing a certain minimum volume of service over a specified time period. If such volume of service is not purchased by the customer, deficiency fees are billed to the customer. In some cases, the customer is allowed to apply any deficiency fees paid to future purchases of services. In such cases, we defer revenue recognition until the customer uses the deficiency fees for services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. Our midstream segment also generates revenues from the sale of residue gas and NGLs at the tailgate of our processing facilities primarily to affiliates and some third-party customers. NGL and refined products transportation and services revenue Our NGL and refined products transportation and services segment’s revenues are primarily derived from transportation, fractionation, blending and storage of NGL and refined products as well as acquisition and marketing activities. Revenues are generated utilizing a complementary network of pipelines, storage and blending facilities, and strategic offtake locations that provide access to multiple NGL markets. Transportation, fractionation and storage revenue is generated from fees charged to customers under a combination of firm and interruptible contracts. Firm contracts are in the form of take-or-pay arrangements where certain fees will be charged to customers regardless of the volume of service they request for any given period. Under interruptible contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of service provided for any given period. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation, fractionation, blending, or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Crude oil transportation and services revenue Our crude oil transportation and services segment’s revenues are primarily derived from providing transportation, terminalling and acquisition and marketing services to crude oil markets throughout the Southwest, Midwest and Northeast United States. Crude oil transportation revenue is generated from tariffs paid by shippers utilizing our transportation services and is generally recognized as the related transportation services are provided. Crude oil terminalling revenue is generated from fees paid by customers for storage and other associated services at the terminal. Crude oil acquisition and marketing revenue is generated from sale of crude oil acquired from a variety of suppliers to third parties. Payment for services under these contracts are typically due the month after the services have been performed. Certain transportation and terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volume of crude oil transported by the customer or services provided at the terminal. For these agreements, any fixed fees billed in excess of services provided are not recognized as revenue until the earlier of (i) the time at which the customer applies the fees against cost of service provided in a later period, or (ii) the customer becomes unable to apply the fees against cost of future service due to capacity constraints or contractual terms. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and/or product and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Sunoco LP’s fuel distribution revenue Revenues from Sunoco LP’s fuel distribution segment are derived from the sale of fuel, non-fuel and lease income. Fuel sales consist primarily of the sale of motor fuel under supply agreements with third-party customers and affiliates. Fuel supply contracts with Sunoco LP’s customers generally provide that it distributes motor fuel at a price based on a formula which includes published rates, volume-based profit margin and other terms specific to the agreement. The customer is invoiced the agreed-upon price with most payment terms ranging less than 30 days. If the consideration promised in a contract includes a variable amount, Sunoco LP estimates the variable consideration amount and factors in such estimate to determine the transaction price under the expected value method. Revenue is recognized under the motor fuel contracts at the point in time the customer takes control of the fuel. At the time control is transferred to the customer the sale is considered final, because the agreements do not grant customers the right to return motor fuel. To determine when control transfers to the customer, the shipping terms of the contract are assessed as a primary indicator of the transfer of control. For free on board ("FOB") shipping point terms, revenue is recognized at the time of shipment. The performance obligation with respect to the sale of goods is satisfied at the time of shipment since the customer gains control at this time under the terms. Shipping and/or handling costs that occur before the customer obtains control of the goods are deemed to be fulfillment activities and are accounted for as fulfillment costs. Once the goods are shipped, Sunoco LP is precluded from redirecting the shipment to another customer and revenue is recognized. Non-fuel revenue includes merchandise revenue that comprises the in-store merchandise and food service sales at company-operated retail stores and other revenue such as credit card processing, car washes, lottery and other services. Lease revenue is derived from the leasing or subleasing of real estate used in the retail distribution of motor fuels. Sunoco LP’s pipeline systems revenue Revenues from Sunoco LP’s pipeline systems segment are derived from interstate and intrastate pipeline transportation of refined products, crude oil and anhydrous ammonia and the applicable pipeline tariff on a per barrel basis for crude oil or refined products and on a per ton basis for ammonia. Sunoco LP’s terminals revenue Revenues from Sunoco LP’s terminals segment include fees for tank storage agreements, under which a customer agrees to pay for a certain amount of storage in a tank over a period of time (storage terminal revenues) and throughput agreements, under which a customer pays a fee per barrel for volumes moving through Sunoco LP’s terminals (throughput terminal revenues). Sunoco LP’s terminals also provide blending, additive injections, handling and filtering services for which Sunoco LP charges additional fees. Additionally, Sunoco LP leases certain of its storage tanks in exchange for a fixed fee, subject to an annual consumer price index adjustment. Sunoco LP’s refinery revenue Revenues from Sunoco LP’s refinery segment are derived from refined products, generated environmental compliance credits and excess crude oil sales are recognized when delivered and the customer obtains control of such inventory, which is typically when title passes and the customer is billed. All revenues are reported inclusive of shipping and handling costs billed and exclusive of any sales taxes billed to customers where applicable. Shipping and handling costs incurred are reported in cost of sales. USAC’s contract operations revenue USAC’s revenue from contracted compression, natural gas treating and maintenance services is recognized ratably under its fixed-fee contracts over the term of the contract as services are provided to its customers. Initial contract terms typically range from six months to five years; however, USAC usually continues to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. USAC primarily enters into fixed-fee contracts whereby its customers are required to pay the monthly fee even during periods of limited or disrupted throughput. Services are generally billed monthly, one month in advance of the commencement of the service month, except for certain customers who are billed at the beginning of the service month, and payment is generally due 30 days after receipt of the invoice. Amounts invoiced in advance are recorded as deferred revenue until earned, at which time they are recognized as revenue. The amount of consideration USAC receives and revenue it recognizes is based upon the fixed fee rate stated in each service contract. Variable consideration exists in select contracts when billing rates vary based on actual equipment availability or volume of total installed horsepower. USAC’s contracts with customers may include multiple performance obligations. For such arrangements, USAC allocates revenues to each performance obligation based on its relative standalone service fee. USAC generally determines standalone service fees based on the service fees charged to customers or using expected cost plus margin. The majority of USAC’s service performance obligations are satisfied over time as services are rendered at selected customer locations on a monthly basis and based upon specific performance criteria identified in the applicable contract. The monthly service for each location is substantially the same service month to month and is promised consecutively over the service contract term. USAC measures progress and performance of the service consistently using a straight-line, time-based method as each month passes, because its performance obligations are satisfied evenly over the contract term as the customer simultaneously receives and consumes the benefits provided by its service. If variable consideration exists, it is allocated to the distinct monthly service within the series to which such variable consideration relates. USAC has elected to apply the invoicing practical expedient to recognize revenue for such variable consideration, as the invoice corresponds directly to the value transferred to the customer based on its performance completed to date. There are typically no material obligations for returns or refunds. USAC’s standard contracts do not usually include material non-cash consideration. USAC’s retail parts and services revenue USAC’s retail parts and services revenue is primarily earned on directly reimbursable freight and crane charges that are the financial responsibility of USAC’s customers and maintenance work on units at its customers’ locations that are outside the scope of its core maintenance activities. Revenue from retail parts and services is recognized at the point in time the part is transferred or service is provided and control is transferred to the customer. At such time, the customer has the ability to direct the use of the benefits of such part or service after USAC has performed its services. USAC bills upon completion of the service or transfer of the parts, and payment is generally due 30 days after receipt of the invoice. The amount of consideration USAC receives and revenue it recognizes is based on the invoice amount. There are typically no material obligations for returns, refunds, or warranties. USAC’s standard contracts do not usually include material variable or non-cash consideration. All other revenue Our all other segment primarily includes our compression equipment business which provides full-service compression design and manufacturing services for the oil and gas industry. It also includes the management of coal and natural resources properties and the related collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities and collecting oil and gas royalties. These operations also include end-user coal handling facilities. Contract Balances with Customers The Partnership satisfies its obligations by transferring goods or services in exchange for consideration from customers. The timing of performance may differ from the timing the associated consideration is paid to or received from the customer, thus resulting in the recognition of a contract asset or a contract liability. The Partnership recognizes a contract asset when making upfront consideration payments to certain customers or when providing services to customers prior to the time at which the Partnership is contractually allowed to bill for such services. The Partnership recognizes a contract liability if the customer’s payment of consideration precedes the Partnership’s fulfillment of the performance obligations. Certain contracts contain provisions requiring customers to pay a fixed minimum fee, but allows customers to apply such fees against services to be provided at a future point in time. These amounts are reflected as deferred revenue until the customer applies the deficiency fees to services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. Additionally, Sunoco LP maintains some franchise agreements requiring dealers to make one-time upfront payments for long-term license agreements. Sunoco LP recognizes a contract liability when the upfront payment is received and recognizes revenue over the term of the license.
Lessee, Leases [Policy Text Block]	Lessee Accounting The Partnership leases terminal facilities, tank cars, office space, land and equipment under non-cancelable operating leases whose initial terms are typically five to 15 years, with some real estate leases having terms of 40 years or more, along with options that permit renewals for additional periods. At the inception of each, we determine if the arrangement is a lease or contains an embedded lease and review the facts and circumstances of the arrangement to classify lease assets as operating or finance leases under Topic 842. The Partnership has elected not to record any leases with terms of 12 months or less on our consolidated balance sheets. At present, the majority of the Partnership’s active leases are classified as operating in accordance with Topic 842. Balances related to operating leases are included in operating lease ROU assets, accrued and other current liabilities, operating lease current liabilities and non-current operating lease liabilities in our consolidated balance sheets. Finance leases represent a small portion of the active lease agreements and are included in finance lease ROU assets, current maturities of long-term debt and long-term debt, less current maturities in our consolidated balance sheets. The ROU assets represent the Partnership’s right to use an underlying asset for the lease term and lease liabilities represent the obligation of the Partnership to make minimum lease payments arising from the lease for the duration of the lease term. Most leases include one or more options to renew, with renewal terms that can extend the lease term from one to 20 years or greater. The exercise of lease renewal options is typically at the sole discretion of the Partnership and lease extensions are evaluated on a lease-by-lease basis. Leases containing early termination clauses typically require the agreement of both parties to the lease. At the inception of a lease, all renewal options reasonably certain to be exercised are considered when determining the lease term. Presently, the Partnership does not have leases that include options to purchase or automatic transfer of ownership of the leased property to the Partnership. The depreciable life of lease assets and leasehold improvements are limited by the expected lease term. To determine the present value of future minimum lease payments, we use the implicit rate when readily determinable. Presently, because many of our leases do not provide an implicit rate, the Partnership applies its incremental borrowing rate based on the information available at the lease commencement date to determine the present value of minimum lease payments. The operating and finance lease ROU assets include any lease payments made and exclude lease incentives. Minimum rent payments are expensed on a straight-line basis over the term of the lease. In addition, some leases require additional contingent or variable lease payments, which are based on the factors specific to the individual agreement. Variable lease payments the Partnership is typically responsible for include payment of real estate taxes, maintenance expenses and insurance. For short-term leases (leases that have term of twelve months or less upon commencement), lease payments are recognized on a straight-line basis and no ROU assets are recorded.
Lessor, Leases [Policy Text Block]	Lessor Accounting Sunoco LP leases or subleases a portion of its real estate portfolio to third-party companies as a stable source of long-term revenue. Sunoco LP’s lessor and sublease portfolio consists mainly of operating leases with convenience store operators. At this time, most lessor agreements contain five-year terms with renewal options to extend and early termination options based on established terms specific to the individual agreement. Additionally, Sunoco LP leases certain of its storage tanks in exchange for a fixed fee, subject to an annual consumer price index adjustment.

Estimates (Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis) (Details) - Fair Value, Recurring [Member] - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Commodity derivatives:	$ 618	$ 263
Other Assets, Fair Value Disclosure	209	212
Total assets	827	475
Commodity derivatives:	(454)	(293)
Financial and Nonfinancial Liabilities, Fair Value Disclosure	(454)	(293)
Level 1 [Member]
Commodity derivatives:	531	263
Other Assets, Fair Value Disclosure	209	212
Total assets	740	475
Commodity derivatives:	(404)	(293)
Financial and Nonfinancial Liabilities, Fair Value Disclosure	(404)	(293)
Level 2 [Member]
Commodity derivatives:	87	0
Other Assets, Fair Value Disclosure	0	0
Total assets	87	0
Commodity derivatives:	(50)	0
Financial and Nonfinancial Liabilities, Fair Value Disclosure	$ (50)	$ 0

Net Income Per Common Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Earnings Per Share [Abstract]
NET INCOME	$ 5,708	$ 6,565	$ 5,294
Less: Net income attributable to redeemable noncontrolling interests	67	59	60
Less: Net income attributable to noncontrolling interests	1,208	1,692	1,299
NET INCOME ATTRIBUTABLE TO PARTNERS	4,433	4,814	3,935
Less: General Partner’s interest in net income	(4)	(4)	(3)
Less: Preferred Unitholders’ interest in net income	248	362	463
Preferred Stock Redemption Premium	8	54	0
Limited Partners’ interest in net income	4,173	4,394	3,469
Dilutive effect of equity-based compensation of subsidiaries and distributions to convertible units	(1)	(1)	(1)
Diluted income available to Common Unitholders	$ 4,172	$ 4,393	$ 3,468
Weighted average common units	3,432.9	3,395.1	3,161.7
Basic	$ 1.22	$ 1.29	$ 1.10
Dilutive effect of unconverted unit awards and ET Series A Convertible Preferred Units	16.6	25.4	15.5
Weighted average common units, assuming dilutive effect of unvested unit awards	3,449.5	3,420.5	3,177.2
Diluted	$ 1.21	$ 1.28	$ 1.09

Debt Obligations (Debt Narrative) (Details)
$ in Millions, $ in Millions

Feb. 28, 2026

USD ($)

Jan. 31, 2026

USD ($)

Dec. 31, 2025

USD ($)

Dec. 31, 2025

CAD ($)

Oct. 31, 2025

USD ($)

Oct. 21, 2025

USD ($)

Oct. 21, 2025

CAD ($)

Dec. 31, 2024

USD ($)

May 03, 2024

USD ($)

$ (351)

108

Long-term Debt, Gross

68,685

Financing Receivable, Revolving

Business Combination, Recognized Liability Assumed, Long-Term Debt, Noncurrent

^[1]

$ 3,500

Business Combination, Recognized Liability Assumed, Long-Term Debt, Noncurrent

3,650

$ 3,797

Parkland Acquisition [Member] | not tendered in private exchange offers

Business Combination, Recognized Liability Assumed, Long-Term Debt, Noncurrent

111

Five Year Credit Facility

Line of Credit Facility, Current Borrowing Capacity

5,000

Letters of Credit Outstanding, Amount

Line of Credit Facility, Remaining Borrowing Capacity

$ 2,120

Line of Credit Facility, Interest Rate at Period End

4.00%

Five Year Credit Facility | April 2029

$ 2,860

Commercial Paper

2,570

Line of Credit Facility, Current Borrowing Capacity

$ 4,840

5.20% Senior Notes due April 2030

5.20%

5.70% Senior Notes due April 2035

$ 650

5.70%

6.20% Senior Notes due April 2055

$ 1,250

6.20%

4.05% Senior Notes due March 2025 [Member]

$ 1,100

4.05%

2.90% Senior Notes due 2025

$ 1,000

2.90%

Series 205A Junior Subordinated Notes due 2056

$ 1,000

Series 205B Junior Subordinated Notes due 2056

1,200

5.95% Senior Notes due December 2025 [Member]

$ 800

5.95%

4.55% senior notes due 2031 | Subsequent Event [Member]

$ 400

4.55%

5.35% senior notes due 2036 | Subsequent Event [Member]

$ 1,000

5.35%

6.30% senior notes due 2056 | Subsequent Event [Member]

$ 1,000

6.30%

4.75% Senior Notes due January 2026 [Member] | Subsequent Event [Member]

$ 1,000

4.75%

5.625% senior notes due 2027 | Subsequent Event [Member]

$ 1,000

5.625%

USAC [Member] | USAC Credit Facility

$ 600

Line of Credit Facility, Current Borrowing Capacity

954

Letters of Credit Outstanding, Amount

$ 1

Line of Credit Facility, Interest Rate at Period End

5.74%

Line of Credit Facility, Maximum Borrowing Capacity

$ 795

$ 1,750

USAC [Member] | 6.250% Senior Notes due 2033

6.25%

USAC [Member] | 6.875% Senior Notes due 2027

$ 750

6.875%

USAC [Member] | 7.125% Senior Notes due 2029

$ 750

Line of Credit Facility, Interest Rate at Period End

7.125%

$ 50

Sunoco LP [Member] | Nustar Acquisition

$ 203

Business Combination, Recognized Liability Assumed, Long-Term Debt, Noncurrent

3,500

Sunoco LP [Member] | Sunoco LP Credit Facility

$ 56

Letters of Credit Outstanding, Amount

Line of Credit Facility, Remaining Borrowing Capacity

$ 2,470

Line of Credit Facility, Interest Rate at Period End

6.38%

Line of Credit Facility, Maximum Borrowing Capacity

$ 0

2,500

Sunoco LP [Member] | Sunoco LP Credit Facility | Parkland

Line of Credit Facility, Maximum Borrowing Capacity

3,500

Sunoco LP [Member] | 6.250% Senior Notes due 2033

$ 1,000

6.25%

Sunoco LP [Member] | 5.750% Senior Notes due 2025

$ 1,000

5.75%

Sunoco LP [Member] | 5.625% Senior Notes due 2031

$ 600

$ 1,000

5.625%

Sunoco LP [Member] | 5.875% Senior Notes due 2034

$ 1,000

$ 900

5.875%

Sunoco LP [Member] | PKI CAD Notes | Parkland Acquisition [Member]

$ 900

Sunoco LP [Member] | 5.625% senior notes due 2027

2,600

$ 1,600

$ 2,580

$ 1,470

Sunoco LP [Member] | Series 2011 GoZone Bonds

550

$ 75

USA Compression Partners, LP [Member]

3.70%

$ 795

772

Southside Oil, LLC

11.865%