et-20250331

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2025

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-32740

ENERGY TRANSFER LP

(Exact name of registrant as specified in its charter)


Delaware						30-0108820
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)

8111 Westchester Drive, Suite 600, Dallas, Texas 75225

(Address of principal executive offices) (zip code)

(214) 981-0700

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Units

New York Stock Exchange

9.250% Series I Fixed Rate Perpetual Preferred Units

ETprI

New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ý No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

Accelerated filer

☐

Non-accelerated filer

Smaller reporting company

☐

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ý

At May 2, 2025, the registrant had 3,431,778,119 Common Units outstanding.

Table of Contents

FORM 10-Q

ENERGY TRANSFER LP AND SUBSIDIARIES

TABLE OF CONTENTS


PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS (Unaudited)
Consolidated Balance Sheets			4
Consolidated Statements of Operations			6
Consolidated Statements of Comprehensive Income			7
Consolidated Statements of Equity			8
Consolidated Statements of Cash Flows			9
Notes to Consolidated Financial Statements			10
1. Organization and Basis of Presentation			10
2. Acquisitions			10
3. Cash and Cash Equivalents			11
4. Inventories			12
5. Fair Value Measures			12
6. Net Income per Common Unit			15
7. Debt Obligations			15
8. Redeemable Noncontrolling Interests			16
9. Equity			16
10. Regulatory Matters, Commitments, Contingencies and Environmental Liabilities			18
11. Revenue			29
12. Derivative Assets and Liabilities			30
13. Reportable Segments			33
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			39
Recent Developments			39
Results of Operations			42
Liquidity and Capital Resources			52
Cash Distributions			56


ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			59
ITEM 4. CONTROLS AND PROCEDURES			60
PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS			61
ITEM 1A. RISK FACTORS			62







ITEM 6. EXHIBITS			66
SIGNATURE			67

Table of Contents

Definitions

References to the “Partnership” or “Energy Transfer” refer to Energy Transfer LP. In addition, the following is a list of certain acronyms and terms used throughout this document:


/d						per day
AOCI						accumulated other comprehensive income
Bakken Pipeline						Refers collectively to Dakota Access and Energy Transfer Crude Oil Pipeline and/or Energy Transfer Crude Oil Company, LLC, a non-wholly owned subsidiary of Energy Transfer
BBtu						billion British thermal units

Citrus						Citrus, LLC, a 50/50 joint venture which owns Florida Gas Transmission Company, LLC, which owns the Florida Gas Transmission Pipeline

Dakota Access						Dakota Access, LLC, a non-wholly owned subsidiary of Energy Transfer and/or Dakota Access Pipeline
Energy Transfer Preferred Units						Collectively, the Series A Preferred Units, Series B Preferred Units, Series C Preferred Units, Series D Preferred Units, Series E Preferred Units, Series F Preferred Units, Series G Preferred Units, Series H Preferred Units and Series I Preferred Units
Energy Transfer R&M						Energy Transfer (R&M), LLC (formerly Sunoco (R&M), LLC)
ETC Sunoco						ETC Sunoco Holdings LLC (formerly Sunoco, Inc.), a wholly owned subsidiary of Energy Transfer
ETO						Energy Transfer Operating, L.P., formerly a non-wholly owned subsidiary of Energy Transfer until its merger into the Partnership in April 2021
ET-S Permian						ET-S Permian Holdings Company LP, a joint venture between Energy Transfer and Sunoco LP, which owns crude oil and water gathering pipelines and storage assets in the Permian Basin
Exchange Act						Securities Exchange Act of 1934, as amended
Explorer						Explorer Pipeline Company
FERC						Federal Energy Regulatory Commission
GAAP						accounting principles generally accepted in the United States of America
General Partner						LE GP, LLC, the general partner of Energy Transfer
IFERC						Inside FERC’s Gas Market Report
J.C. Nolan						collectively, J.C. Nolan Terminal Co., LLC and J.C. Nolan Pipeline Co., LLC, both of which are joint ventures between Energy Transfer and Sunoco LP, which own a diesel fuel storage terminal in Midland, Texas and a 500-mile diesel fuel pipeline
LIFO						last-in, first-out
MBbls						thousand barrels
MEP						Midcontinent Express Pipeline LLC

NGL						natural gas liquid, such as propane, butane and natural gasoline
NuStar						NuStar Energy L.P.
NYMEX						New York Mercantile Exchange
OTC						over-the-counter
Panhandle						Panhandle Eastern Pipe Line and/or Panhandle Eastern Pipe Line Company, LP, a wholly owned subsidiary of Energy Transfer
Partnership Agreement						Energy Transfer’s Fourth Amended and Restated Agreement of Limited Partnership, as amended to date
PHMSA						Pipeline and Hazardous Materials Safety Administration
Rover						Rover Pipeline and/or Rover Pipeline LLC, a non-wholly owned subsidiary of Energy Transfer

SEC						Securities and Exchange Commission
Series A Preferred Units						Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series B Preferred Units						Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series C Preferred Units						Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series D Preferred Units						Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series E Preferred Units						Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series F Preferred Units						Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
Series G Preferred Units						Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
Series H Preferred Units						Series H Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
Series I Preferred Units						Series I Fixed-Rate Perpetual Preferred Units
SESH						Southeast Supply Header, LLC

SPLP						Sunoco Pipeline L.P., a wholly owned subsidiary of Energy Transfer
Transwestern						Transwestern Pipeline and/or Transwestern Pipeline Company, LLC, a wholly owned subsidiary of Energy Transfer
USAC						USA Compression Partners, LP, a publicly traded partnership and consolidated subsidiary of Energy Transfer
White Cliffs						White Cliffs Pipeline, L.L.C.

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PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)


	March 31, 2025		December 31, 2024
ASSETS
Current assets:
Cash and cash equivalents	$	453	$	312
Accounts receivable, net	11,302		10,191
Accounts receivable from related companies	131		87
Inventories	2,787		3,070
Income taxes receivable	91		56
Derivative assets	6		9
Other current assets	467		477

Total current assets	15,237		14,202

Property, plant and equipment	130,496		129,242
Accumulated depreciation and depletion	(35,257)		(34,030)
Property, plant and equipment, net	95,239		95,212

Investments in unconsolidated affiliates	3,260		3,266

Lease right-of-use assets, net	829		809


Other non-current assets, net	2,069		2,017
Intangible assets, net	5,888		5,971
Goodwill	3,903		3,903

Total assets	$	126,425	$	125,380

The accompanying notes are an integral part of these consolidated financial statements.

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ENERGY TRANSFER LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (continued)

(Dollars in million)

(unaudited)


	March 31, 2025		December 31, 2024
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	8,991	$	8,306
Accounts payable to related companies	8		19
Derivative liabilities	20		15

Operating lease current liabilities	66		67
Accrued and other current liabilities	4,479		4,241
Current maturities of long-term debt	7		8

Total current liabilities	13,571		12,656

Long-term debt, less current maturities	59,782		59,752


Non-current operating lease liabilities	752		730
Deferred income taxes	4,179		4,190
Other non-current liabilities	1,561		1,618


Commitments and contingencies
Redeemable noncontrolling interests	418		417

Equity:
Limited Partners:
Preferred Unitholders	3,892		3,852
Common Unitholders	31,364		31,195
General Partner	(2)		(2)
Accumulated other comprehensive income	64		73
Total partners’ capital	35,318		35,118
Noncontrolling interests	10,844		10,899
Total equity	46,162		46,017
Total liabilities and equity	$	126,425	$	125,380

The accompanying notes are an integral part of these consolidated financial statements.

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ENERGY TRANSFER LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in millions, except per unit data)

(unaudited)


	Three Months Ended March 31,
		2025		2024
REVENUES:
Refined product sales		$	4,963	$	5,513
Crude sales		5,449		6,844
NGL sales		5,642		5,251
Gathering, transportation and other fees		3,005		2,901
Natural gas sales		1,581		855
Other		380		265
Total revenues		21,020		21,629
COSTS AND EXPENSES:
Cost of products sold		15,571		16,597
Operating expenses		1,299		1,138
Depreciation, depletion and amortization		1,367		1,254
Selling, general and administrative		288		260
Impairment loss		4		—
Total costs and expenses		18,529		19,249
OPERATING INCOME		2,491		2,380
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized		(809)		(728)
Equity in earnings of unconsolidated affiliates		92		98

Losses on extinguishments of debt		(2)		(5)
Gain on interest rate derivative		—		9


Other, net		(11)		27
INCOME BEFORE INCOME TAX EXPENSE		1,761		1,781
Income tax expense		41		89
NET INCOME		1,720		1,692
Less: Net income attributable to noncontrolling interests		384		436
Less: Net income attributable to redeemable noncontrolling interests		13		16
NET INCOME ATTRIBUTABLE TO PARTNERS		1,323		1,240
General Partner’s interest in net income		1		1
Preferred Unitholders’ interest in net income		67		129
Loss on redemption of preferred units		—		21
Common Unitholders’ interest in net income		$	1,255	$	1,089



NET INCOME PER COMMON UNIT:
Basic		$	0.37	$	0.32
Diluted		$	0.36	$	0.32

The accompanying notes are an integral part of these consolidated financial statements.

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ENERGY TRANSFER LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in millions)

(unaudited)


	Three Months Ended March 31,
		2025		2024
Net income		$	1,720	$	1,692
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities		2		2
Actuarial gain (loss) related to pension and other postretirement benefit plans		(4)		9
Foreign currency translation adjustments		1		—
Change in other comprehensive income from unconsolidated affiliates		(2)		2
		(3)		13
Comprehensive income		1,717		1,705
Less: Comprehensive income attributable to noncontrolling interests		384		436
Less: Comprehensive income attributable to redeemable noncontrolling interests		13		16
Comprehensive income attributable to partners		$	1,320	$	1,253

The accompanying notes are an integral part of these consolidated financial statements.

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ENERGY TRANSFER LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(Dollars in millions)

(unaudited)


	Common Unitholders		Preferred Unitholders		General Partner		AOCI		Noncontrolling Interests		Total
Balance, December 31, 2024	$	31,195	$	3,852	$	(2)	$	73	$	10,899	$	46,017
Distributions to partners	(1,105)		(27)		(1)		—		—		(1,133)
Distributions to noncontrolling interests	—		—		—		—		(455)		(455)

Capital contributions from noncontrolling interests	—		—		—		—		2		2
Other comprehensive loss, net of tax	—		—		—		(3)		—		(3)

Other, net	19		—		—		(6)		14		27
Net income, excluding amounts attributable to redeemable noncontrolling interests	1,255		67		1		—		384		1,707
Balance, March 31, 2025	$	31,364	$	3,892	$	(2)	$	64	$	10,844	$	46,162


	Common Unitholders		Preferred Unitholders		General Partner		AOCI		Noncontrolling Interests		Total
Balance, December 31, 2023	$	30,197	$	6,459	$	(2)	$	28	$	7,257	$	43,939
Distributions to partners	(1,039)		(88)		(1)		—		—		(1,128)
Distributions to noncontrolling interests	—		—		—		—		(421)		(421)

Capital contributions from noncontrolling interests	—		—		—		—		637		637
Other comprehensive income, net of tax	—		—		—		13		—		13
Redemption of Series C and Series D Preferred Units	—		(895)		—		—		—		(895)
Other, net	—		21		—		—		(49)		(28)
Net income, excluding amounts attributable to redeemable noncontrolling interests	1,110		129		1		—		436		1,676
Balance, March 31, 2024	$	30,268	$	5,626	$	(2)	$	41	$	7,860	$	43,793

The accompanying notes are an integral part of these consolidated financial statements.

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ENERGY TRANSFER LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

(unaudited)


	Three Months Ended March 31,
	2025		2024
OPERATING ACTIVITIES:
Net income	$	1,720	$	1,692
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,367		1,254
Deferred income tax expense (benefit)	(16)		67
Inventory valuation adjustments	(61)		(130)
Non-cash compensation expense	37		46
Impairment loss	4		—
Other non-cash	14		(7)
Equity in earnings of unconsolidated affiliates	(92)		(98)

Losses on extinguishments of debt	2		5
Distributions from unconsolidated affiliates	77		84
Distributions on unvested awards	(13)		(14)
Net change in operating assets and liabilities, net of effects of acquisitions	(122)		873
Net cash provided by operating activities	2,917		3,772
INVESTING ACTIVITIES:

Cash paid by Sunoco LP for acquisitions, net of cash received	(12)		(185)
Cash paid for Edwards Lime Gathering, LLC noncontrolling interest	—		(84)

Cash paid for other acquisitions, net of cash received	—		(180)
Capital expenditures, excluding allowance for equity funds used during construction	(1,224)		(795)
Contributions in aid of construction costs	16		25
Contributions to unconsolidated affiliates	(1)		(2)
Distributions from unconsolidated affiliates in excess of cumulative earnings	20		23

Proceeds from sales of other assets	2		2
Other, net	1		—
Net cash used in investing activities	(1,198)		(1,196)
FINANCING ACTIVITIES:
Proceeds from borrowings	10,592		8,141
Repayments of debt	(10,520)		(6,257)
USAC investments in government securities in connection with the legal defeasance of senior notes	—		(749)



Redemption of Series C and Series D Preferred Units	—		(895)

Redemption of Crestwood Niobrara LLC preferred units	—		(37)
Capital contributions from noncontrolling interests	2		637

Distributions to partners	(1,133)		(1,128)
Distributions to noncontrolling interests	(455)		(421)
Distributions to redeemable noncontrolling interests	(13)		(22)
Debt issuance costs	(51)		(60)

Net cash used in financing activities	(1,578)		(791)
Increase in cash and cash equivalents	141		1,785
Cash and cash equivalents, beginning of period	312		161
Cash and cash equivalents, end of period	$	453	$	1,946

The accompanying notes are an integral part of these consolidated financial statements.

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ENERGY TRANSFER LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Tabular dollar and unit amounts, except per unit data, are in millions)

(unaudited)

1.ORGANIZATION AND BASIS OF PRESENTATION

Organization

The consolidated financial statements presented herein contain the results of Energy Transfer LP and its subsidiaries (the “Partnership,” “we,” “us,” “our” or “Energy Transfer”).

Basis of Presentation

The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 14, 2025. In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.

The consolidated financial statements of the Partnership presented herein include the results of operations of our controlled subsidiaries, including Sunoco LP and USAC. The Partnership owns the general partner interest, incentive distribution rights and 28.5 million common units of Sunoco LP, and the general partner interests and 46.1 million common units of USAC.

The operations of certain pipelines and terminals in which we own an undivided interest are proportionately consolidated in the accompanying consolidated financial statements.

Certain prior period amounts have been reclassified to conform to the current period presentation. These reclassifications had no impact on net income or total equity.

Use of Estimates

The unaudited consolidated financial statements have been prepared in conformity with GAAP, which requires the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and the accrual for and disclosure of contingent assets and liabilities that exist at the date of the consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates.

2.ACQUISITIONS

Parkland Acquisition by Sunoco LP

On May 5, 2025, Sunoco LP and Parkland Corporation (“Parkland”) announced that the parties have entered into a definitive agreement whereby Sunoco LP plans to acquire all outstanding shares of Parkland in a cash and equity transaction valued at approximately $9.1 billion, including assumed debt.

As part of the transaction, Sunoco LP intends to form a new publicly-traded Delaware limited liability company named SUNCorp, LLC (“SUNCorp”). SUNCorp is expected to hold limited partnership units of Sunoco LP that are economically equivalent to Sunoco LP’s publicly-traded common units on the basis of one Sunoco LP common unit for each outstanding SUNCorp unit. For a period of two years following closing of the transaction, Sunoco LP would ensure that SUNCorp unitholders receive the same dividend equivalent as the distribution to Sunoco LP unitholders.

Sunoco LP has secured a $2.65 billion 364-day bridge term loan for the proposed cash consideration.

The transaction is currently expected to close in the second half of 2025 upon the satisfaction of closing conditions, including approval by Parkland’s shareholders and customary regulatory and stock exchange listing approvals.

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TanQuid Acquisition by Sunoco LP

In March 2025, Sunoco LP entered into an agreement to acquire TanQuid GmbH & Co. KG (“TanQuid”) for approximately €500 million (approximately $540 million as of March 31, 2025), including approximately €300 million of assumed debt. TanQuid owns and operates 15 fuel terminals in Germany and one fuel terminal in Poland. The transaction is expected to close in the second half of 2025, subject to customary closing conditions, and Sunoco LP will fund it using cash on hand and amounts available under its revolving credit facility.

Other Acquisitions by Sunoco LP

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. These transactions were accounted for as asset acquisitions, and the purchase price was primarily allocated to property, plant and equipment and other non-current assets.

3.CASH AND CASH EQUIVALENTS

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. The Partnership’s consolidated balance sheets did not include any material amounts of restricted cash as of March 31, 2025 or December 31, 2024.

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:


	Three Months Ended March 31,
	2025		2024
Accounts receivable	$	(1,111)	$	(614)
Accounts receivable from related companies	(44)		(246)
Inventories	332		311
Other current assets	(24)		79
Other non-current assets, net	(23)		(76)
Accounts payable	685		883
Accounts payable to related companies	(19)		251
Accrued and other current liabilities	131		274
Other non-current liabilities	(57)		(34)
Derivative assets and liabilities, net	8		45
Net change in operating assets and liabilities, net of effects of acquisitions	$	(122)	$	873

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Non-cash investing and financing activities were as follows:


	Three Months Ended March 31,
	2025		2024
Accrued capital expenditures	$	795	$	421

Lease assets obtained in exchange for new lease liabilities	29		1
Distribution reinvestment	10		22
USAC exercise and conversion of preferred units into common units	—		38
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 common units (noncontrolling interest) issued in connection with acquisitions	5		—

4.INVENTORIES

Inventories consisted of the following:


	March 31, 2025		December 31, 2024
Natural gas, NGLs and refined products	$	1,834	$	1,989
Crude oil	292		400
Spare parts and other	661		681
Total inventories	$	2,787	$	3,070

Sunoco LP’s fuel inventories are stated at the lower of cost or market using the LIFO method. As of March 31, 2025 and December 31, 2024, Sunoco LP’s fuel inventory balance included lower of cost or market reserves of $255 million and $316 million, respectively. For the three months ended March 31, 2025 and 2024, the Partnership’s consolidated income statements did not include any material amounts of income from the liquidation of Sunoco LP’s LIFO fuel inventory. For the three months ended March 31, 2025 and 2024, the Partnership’s cost of products sold included favorable inventory valuation adjustments of $61 million and $130 million, respectively, which increased net income.

5.FAIR VALUE MEASURES

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value.

We have commodity derivatives that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider options transacted through a clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. The valuation methodologies employed for our interest rate derivative do not necessitate material judgment, and the inputs are observed from actively quoted public markets and therefore are categorized in Level 2. Level 3 inputs are unobservable. During the three months ended March 31, 2025, no transfers were made between any levels within the fair value hierarchy.

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The following tables summarize the gross fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of March 31, 2025 and December 31, 2024 based on inputs used to derive their fair values:


	Fair Value Measurements at March 31, 2025
	Fair Value - Level 1
Assets:

Commodity derivatives:

Natural Gas:
Basis Swaps IFERC/NYMEX	$	9
Swing Swaps IFERC	2
Fixed Swaps/Futures	15



Power:
Forwards	37
Futures	16


NGLs – Forwards/Swaps	271
Refined Products – Futures	2
Crude – Forwards/Swaps	17

Total commodity derivatives	369
Other non-current assets	211
Total assets	$	580
Liabilities:

Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	(25)
Swing Swaps IFERC	(2)
Fixed Swaps/Futures	(45)



Power:
Forwards	(34)
Futures	(15)



NGLs – Forwards/Swaps	(245)
Refined Products – Futures	(11)
Crude – Forwards/Swaps	(27)
Total commodity derivatives	(404)
Total liabilities	$	(404)

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	Fair Value Measurements at December 31, 2024
	Fair Value - Level 1
Assets:

Commodity derivatives:

Natural Gas:
Basis Swaps IFERC/NYMEX	$	6
Swing Swaps IFERC	4
Fixed Swaps/Futures	10



Power:
Forwards	39
Futures	10


NGLs – Forwards/Swaps	166
Refined Products – Futures	3
Crude – Forwards/Swaps	25
Total commodity derivatives	263
Other non-current assets	212
Total assets	$	475
Liabilities:

Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	(11)
Swing Swaps IFERC	(11)
Fixed Swaps/Futures	(9)



Power:
Forwards	(38)
Futures	(10)



NGLs – Forwards/Swaps	(170)
Refined Products – Futures	(9)
Crude – Forwards/Swaps	(35)
Total commodity derivatives	(293)
Total liabilities	$	(293)

The aggregate estimated fair value and carrying amount of our consolidated debt obligations as of March 31, 2025 were $59.28 billion and $59.79 billion, respectively. As of December 31, 2024, the aggregate fair value and carrying amount of our consolidated debt obligations were $59.01 billion and $59.76 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the respective debt obligations’ observable inputs for similar liabilities.

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6.NET INCOME PER COMMON UNIT

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


	Three Months Ended March 31,
		2025		2024
Net income		$	1,720	$	1,692
Less: Net income attributable to noncontrolling interests		384		436
Less: Net income attributable to redeemable noncontrolling interests		13		16
Net income, net of noncontrolling interests		1,323		1,240
Less: General Partner’s interest in net income		1		1
Less: Preferred Unitholders’ interest in net income		67		129
Less: Loss on redemption of preferred units		—		21
Common Unitholders’ interest in net income		$	1,255	$	1,089
Basic Income per Common Unit:
Weighted average common units		3,431.4		3,368.6
Basic income per common unit		$	0.37	$	0.32

Diluted Income per Common Unit:
Common Unitholders’ interest in net income		$	1,255	$	1,089
Dilutive effect of equity-based compensation of subsidiaries (1)		—		1
Diluted income attributable to Common Unitholders		$	1,255	$	1,088
Weighted average common units		3,431.4		3,368.6
Dilutive effect of unvested restricted unit awards (1)		21.5		21.5
Weighted average common units, assuming dilutive effect of unvested restricted unit awards		3,452.9		3,390.1
Diluted income per common unit		$	0.36	$	0.32

(1)Dilutive effects are excluded from the calculation for periods where the impact would have been antidilutive.

7.DEBT OBLIGATIONS

Recent Transactions

Energy Transfer Senior Notes Issuance and Redemption

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.

Sunoco LP Senior Notes Issuance and Redemption

In March 2025, Sunoco LP issued $1.00 billion of 6.250% 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 of 5.750% senior notes due 2025 and to repay a portion of the outstanding borrowings under its revolving credit facility.

Credit Facilities and Commercial Paper

Five-Year Credit Facility

The Partnership’s revolving credit facility (the “Five-Year Credit Facility”) allows for unsecured borrowings up to $5.00 billion until April 11, 2027, and 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.

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As of March 31, 2025, the Five-Year Credit Facility had $605 million of outstanding borrowings, all of which consisted of commercial paper. The amount available for future borrowings was $4.37 billion, after accounting for outstanding letters of credit in the amount of $23 million. The weighted average interest rate on the total amount outstanding as of March 31, 2025 was 4.60%.

Sunoco LP Credit Facilities

As of March 31, 2025, Sunoco LP’s credit facility, which matures in May 2029, had no outstanding borrowings and $56 million in standby letters of credit. The unused availability on Sunoco LP’s credit facility as of March 31, 2025 was $1.44 billion. The weighted average interest rate on the total amount outstanding as of March 31, 2025 was 6.53%.

Upon the closing of Sunoco LP’s acquisition of NuStar, 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 March 31, 2025, this facility had no outstanding borrowings.

USAC Credit Facility

As of March 31, 2025, USAC’s credit facility, which matures in December 2026, had $805 million of outstanding borrowings and $1 million outstanding letters of credit. As of March 31, 2025, USAC’s credit facility had $795 million of remaining unused availability of which, due to restrictions related to compliance with the applicable financial covenants, $740 million was available to be drawn. The weighted average interest rate on the total amount outstanding as of March 31, 2025 was 6.96%.

Compliance with our Covenants

We and our subsidiaries were in compliance with all requirements, tests, limitations and covenants related to our debt agreements as of March 31, 2025. For the quarter ended March 31, 2025, the Partnership’s leverage ratio, as calculated pursuant to the covenant related to its Five-Year Credit Facility, was 3.24x.

8.REDEEMABLE NONCONTROLLING INTERESTS

Certain redeemable noncontrolling interests in the Partnership’s subsidiaries were reflected as mezzanine equity on the consolidated balance sheets. Redeemable noncontrolling interests as of March 31, 2025 and December 31, 2024 included a balance of $169 million related to the USAC Series A preferred units and $225 million related to Crestwood Niobrara LLC preferred units. Additionally, as of March 31, 2025 and December 31, 2024, redeemable noncontrolling interests included a balance of $24 million and $23 million, respectively, related to noncontrolling interest holders in one of the Partnership’s consolidated subsidiaries that have the option to sell their interests to the Partnership.

9.EQUITY

Energy Transfer Common Units

Changes in Energy Transfer common units during the three months ended March 31, 2025 were as follows:


			Number of Units
Number of common units at December 31, 2024			3,431.0
Common units issued under the distribution reinvestment plan			0.5
Common units vested under equity incentive plans and other			0.2
Number of common units at March 31, 2025			3,431.7

Energy Transfer Repurchase Program

During the three months ended March 31, 2025, Energy Transfer did not repurchase any of its common units under its current buyback program. As of March 31, 2025, $880 million remained available to repurchase under the current program.

Energy Transfer Distribution Reinvestment Program

During the three months ended March 31, 2025, distributions of $10 million were reinvested under the distribution reinvestment program. As of March 31, 2025, a total of 38.4 million Energy Transfer common units remained available to be issued under currently effective registration statements in connection with the distribution reinvestment program.

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Cash Distributions on Energy Transfer Common Units

Distributions declared and/or paid with respect to Energy Transfer common units subsequent to December 31, 2024 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2024

February 7, 2025

February 19, 2025

0.3250

March 31, 2025

May 9, 2025

May 20, 2025

0.3275

Energy Transfer Preferred Units

As of March 31, 2025 and December 31, 2024, Energy Transfer’s outstanding preferred units included 550,000 Series B Preferred Units, 500,000 Series F Preferred Units, 1,484,780 Series G Preferred Units, 900,000 Series H Preferred Units and 41,464,179 Series I Preferred Units.

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


	Preferred Unitholders
	Series B		Series F		Series G		Series H		Series I		Total
Balance, December 31, 2024	$	556	$	496	$	1,488	$	893	$	419	$	3,852
Distributions to partners	(18)		—		—		—		(9)		(27)



Net income	9		8		26		15		9		67
Balance, March 31, 2025	$	547	$	504	$	1,514	$	908	$	419	$	3,892


	Preferred Unitholders
	Series A		Series B		Series C		Series D		Series E		Series F		Series G		Series H		Series I		Total
Balance, December 31, 2023	$	948	$	556	$	438	$	435	$	786	$	496	$	1,488	$	893	$	419	$	6,459
Distributions to partners	(24)		(18)		(11)		(11)		(15)		—		—		—		(9)		(88)
Redemption of preferred units	—		—		(450)		(445)		—		—		—		—		—		(895)
Other, net	—		—		11		10		—		—		—		—		—		21
Net income	23		9		12		11		15		8		27		15		9		129
Balance, March 31, 2024	$	947	$	547	$	—	$	—	$	786	$	504	$	1,515	$	908	$	419	$	5,626

Cash Distributions on Energy Transfer Preferred Units

Distributions declared on the Energy Transfer Preferred Units were as follows:


Period Ended	Record Date	Payment Date	Series B (1)		Series F (1)		Series G (1)		Series H (1)		Series I (2)
December 31, 2024	February 1, 2025	February 15, 2025	$	33.125	$	—	$	—	$	—	$	0.2111
March 31, 2025	May 1, 2025	May 15, 2025	—		33.750		35.630		32.500		0.2111

(1)Series B, Series F, 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)For the period ended March 31, 2025, the cash distribution for the Series I Preferred Units will be paid on May 15, 2025 to unitholders of record as of the close of business on May 2, 2025.

Noncontrolling Interests

The Partnership’s consolidated financial statements also include noncontrolling interests in Sunoco LP and USAC, both of which are master limited partnerships, as well as other non-wholly owned consolidated joint ventures. The following sections describe cash distributions made by our publicly traded subsidiaries, Sunoco LP and USAC, both of which are required by their respective partnership agreements to distribute all cash on hand (less appropriate reserves determined by the boards of directors of their respective general partners) subsequent to the end of each quarter.

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Sunoco LP Cash Distributions

Distributions on Sunoco LP’s common units declared and/or paid by Sunoco LP subsequent to December 31, 2024 were as follows:

Quarter Ended

Payment Date

Rate

December 31, 2024

February 19, 2025

0.8865

March 31, 2025

May 20, 2025

0.8976

USAC Cash Distributions

Distributions on USAC’s common units declared and/or paid by USAC subsequent to December 31, 2024 were as follows:

Quarter Ended

Payment Date

Rate

December 31, 2024

February 7, 2025

0.525

March 31, 2025

May 9, 2025

0.525

Accumulated Other Comprehensive Income

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


	March 31, 2025		December 31, 2024
Available-for-sale securities	$	22	$	20
Foreign currency translation adjustment	(11)		(6)
Actuarial gains related to pensions and other postretirement benefits	41		45
Investments in unconsolidated affiliates, net	12		14



Total AOCI included in partners’ capital, net of tax	$	64	$	73

10.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 United States 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 District Court case pending the resolution of two cases pending before the United States Supreme Court. Arguments were heard in those cases on November 7, 2022. On April 14, 2023, the United States 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 United States 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 United States Court of Appeals for the Fifth Circuit. On December 11, 2023, FERC filed a motion to withdraw that appeal, which the Fifth Circuit

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granted on December 12, 2023. The FERC and the Federal District Court proceedings were stayed pending resolution of the case pending before the United States Supreme Court. The Supreme Court issued a decision in that case on June 27, 2024. The FERC and District Court proceedings remain stayed at this time. Energy Transfer and Rover intend to vigorously defend 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 Natural Gas Act, 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 Natural Gas Act 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 Natural Gas Act. The Natural Gas Act 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 United States Court of Appeals for the District of Columbia Circuit (“Court of Appeals”), and the Michigan Public Service Commission also subsequently appealed these orders. On April 25, 2023, the Court of Appeals 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 Court of Appeals 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 Court of Appeals 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 Court of Appeals 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.

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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. The request for rehearing will be addressed in a future order. On March 24, 2025, Panhandle petitioned the Court of Appeals for review of the December 5, 2024 and February 3, 2025 orders.

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. During the three months ended March 31, 2025 and 2024, the Partnership recorded $16 million and $13 million, respectively, of ROW expense, which are included in operating expenses in the consolidated statements of operations.

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 March 31, 2025 and December 31, 2024, accruals of approximately $316 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 $42 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

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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 United States 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 District Court remanded the case back to the USACE for preparation of an Environment Impact Statement (“EIS”). On July 6, 2020, the 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 Court of Appeals 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 Court of Appeals (1) granted a stay of the portion of the 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 Court of Appeals as to whether the USACE would be required to prepare an EIS and (3) denied a motion to stay the District Court’s order to vacate the easement during this appeal process. The August 5 order also states that the Court of Appeals expected the USACE to clarify its position with respect to whether USACE intended to allow the continued operation of the pipeline notwithstanding the vacatur of the easement and that the District Court may consider additional relief, if necessary.

On August 10, 2020, the 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 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 Court of Appeals affirmed the 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 Court of Appeals also overturned the 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 Court of Appeals 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 (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 District Court scheduled a status conference for February 10, 2021 to discuss the effects of the Court of Appeals’ January 26, 2021 order on the pending motion for injunctive relief, as well as USACE’s expectations as to how it will proceed regarding its enforcement discretion regarding the easement. On May 3, 2021, USACE advised the 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 District Court denied the plaintiffs’ request for an injunction. On June 22, 2021, the 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. The USACE anticipates that a Final EIS will be issued in December 2025 and a Record of Decision will be issued in early 2026. The pipeline continues to operate pending completion of the EIS. 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.

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Standing Rock Sioux Tribe in Federal Court in District of Columbia

Dakota Access is the subject of litigation in the U.S. District Court for the District of Columbia. The Standing Rock Sioux Tribe (“SRST”) sued the United States Army Corps of Engineers (“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, NEPA, 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 Environmental Impact Statement (“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. Dakota Access intends to vigorously defend against these new claims.

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 District Court has held briefing on the motion for partial summary judgment in abeyance pending the Court’s decision on the motions to dismiss. On March 28, 2025, the Court granted the motions to dismiss. The SRST have until May 27, 2025 to appeal the dismissal.

Williams Antitrust Litigation

On June 28, 2024, Louisiana Energy Gateway LLC, The Williams Companies, Inc., and Williams Fields Services Group, LLC (“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, 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. On October 4, 2024, Williams filed a Motion to Remand, seeking to remand the case back to the 42nd Judicial 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 set for hearing on February 10, 2025 and denied.

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 March 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.

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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 (collectively, the “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 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 State Supreme Court. Energy Transfer and Rover have opposed such permission. On January 28, 2025, the Ohio State Supreme Court declined to hear the State’s appeal. On April 25, 2025, the State of Ohio filed a petition for certiorari with the U.S. Supreme Court. Energy Transfer and Rover intend to vigorously defend this claim.

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 United States 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 United States 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

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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 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 United States 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 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 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 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.

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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 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 attorney’s 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 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. ETMT has been vigorous and diligent in its appeals relating to the finality issues underlying the Order and 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 district court’s plan of allocation (which was part of the final judgment) did not satisfy all finality requirements. The Court held that the 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 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 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 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 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 Plaintiffs is approximately $104 million in actual damages and $75 million in punitive damages. ETMT has appealed the entirety of the judgment to the Tenth Circuit. Oral argument took place on November 20, 2024 and the parties are awaiting a decision.

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, respectively, 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

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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 the Partnership has completed as of January 17, 2024. The matter remains stayed until the DPU sets a new procedural schedule.

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, our consolidated subsidiary, and Crestwood Midstream Partners, LP (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 June 30, 2023. 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 can seek further review of this decision by filing a petition for review in the Texas Supreme Court.

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 attorney’s fees and costs. However, the actual amount sought was not specified.

On June 3, 2024, defendants filed a Motion to Dismiss and, alternatively, 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; (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 ex rel. 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

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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 attorney’s 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 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. A hearing on the motion to dismiss will be held on July 31, 2025.

Defendants cannot predict the ultimate outcome of this litigation but will vigorously defend against these claims.

Tax Contingencies

Internal Revenue Service Audits

The Partnership’s 2020 U.S. Federal income tax return is currently under examination by the Internal Revenue Service (“IRS”). In general, Energy Transfer and its subsidiaries are no longer subject to examination by the IRS, and most state tax authorities, for the 2019 and prior tax years.

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 $29 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 recognized a charge of $1 million, which USAC believes is a reasonable estimate of the potential loss from the aggregate final imputed underpayment for the years 2019 and 2020. This $1 million estimated amount was recognized within income tax expense for the three months ended March 31, 2025. 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 USAC unitholder, and former USAC unitholder, as applicable, with respect to an audited and adjusted return.

New York Motor Fuel Excise Tax Audits

ETMT, Sunoco LLC and Sunoco Retail LLC are currently under motor fuel excise tax audits in the state of New York for the periods of March 2017 through May 2020. These audits are currently ongoing and no assessments have been made. We cannot predict the outcome of these audits; however, to the extent material assessments may be issued, we would expect to use all appropriate administrative and legal measures to defend our positions.

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

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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 polychlorinated biphenyls (“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 March 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.

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.


	March 31, 2025		December 31, 2024
Current	$	54	$	51
Non-current	222		227
Total environmental liabilities	$	276	$	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 three months ended March 31, 2025 and 2024, the Partnership recorded $2 million and $3 million, respectively, of expenditures related to environmental cleanup programs.

Our pipeline operations are subject to regulation by the United States Department of Transportation 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,

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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 the Federal Occupational Safety and Health Act (“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.

11.REVENUE

Disaggregation of Revenue

The Partnership’s consolidated financial statements reflect eight reportable segments, which also represent the level at which the Partnership aggregates revenue for disclosure purposes. Note 13 depicts the disaggregation of revenue by segment.

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 allow 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, 2024	$	759
Additions	298
Revenue recognized	(383)

Balance, March 31, 2025	$	674

Balance, December 31, 2023	$	749
Additions	291
Revenue recognized	(297)

Balance, March 31, 2024	$	743

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The balances of Sunoco LP’s contract assets and contract liabilities were as follows:


	March 31, 2025		December 31, 2024

Contract assets	$	300	$	288
Accounts receivable from contracts with customers	965		1,084
Contract liabilities	37		39

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 contacts, only the fixed components of the contracts are included in the following table.

As of March 31, 2025, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations was $36.78 billion. The Partnership expects to recognize this amount as revenue within the time bands illustrated in the following table:


	Years Ending December 31,
	2025
	(remainder)		2026		2027		Thereafter		Total
Revenue expected to be recognized on contracts with customers existing as of March 31, 2025	$	5,910	$	6,938	$	5,716	$	18,213	$	36,777

12.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 in 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.

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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:


	March 31, 2025		December 31, 2024
	Notional Volume	Maturity	Notional Volume	Maturity
Mark-to-Market Derivatives
Natural Gas (BBtu):
Fixed Swaps/Futures	(15,135)	2025-2027	6,630	2025-2026
Basis Swaps IFERC/NYMEX	880	2025-2028	3,490	2025-2027
Swing Swaps	(138,780)	2025-2027	(156,820)	2025-2027

Options – Calls	600	2025-2026	—

Power (Megawatt):
Forwards	58,600	2025-2029	6,040	2025-2029
Futures	(340,545)	2025-2027	(140,137)	2025-2026
Options – Puts	33,600	2025-2026	(17,600)	2025
Options – Calls	14,400	2025-2026	—

Crude (MBbls):
Forwards/Swaps	(21,363)	2025-2027	(22,512)	2025-2026


NGL/Refined Products (MBbls):
Forward/Swaps	(4,819)	2025-2028	(15,063)	2025-2027
Options – Puts	7	2025-2026	(9)	2025-2026
Options – Calls	(2)	2025-2026	(14)	2025-2026
Futures	(3,064)	2025-2027	(1,763)	2025-2026
Fair Value Hedging Derivatives
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(38,945)	2025	(47,170)	2025
Fixed Swaps/Futures	(38,945)	2025	(47,170)	2025
Hedged Item – Inventory	38,945	2025	44,170	2025

Credit Risk

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.

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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 is 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
	March 31, 2025		December 31, 2024		March 31, 2025		December 31, 2024
Derivatives designated as hedging instruments:
Commodity derivatives – margin deposits	$	18	$	3	$	(46)	$	(7)
	18		3		(46)		(7)
Derivatives not designated as hedging instruments:
Commodity derivatives – margin deposits	308		209		(301)		(229)
Commodity derivatives	43		51		(57)		(57)

	351		260		(358)		(286)
Total derivatives	$	369	$	263	$	(404)	$	(293)

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	March 31, 2025		December 31, 2024		March 31, 2025		December 31, 2024

Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	$	43	$	51	$	(57)	$	(57)
Broker cleared derivative contracts	Other current assets (liabilities)	326		212		(347)		(236)
Total gross derivatives		369		263		(404)		(293)
Offsetting agreements:

Counterparty netting	Derivative assets (liabilities)	(37)		(42)		37		42
Counterparty netting	Other current assets (liabilities)	(282)		(204)		282		204
Total net derivatives		$	50	$	17	$	(85)	$	(47)

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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 date.

The following table summarizes the location and amounts recognized in our consolidated statements of operations with respect to our derivative financial instruments:


	Location of Gain (Loss) Recognized on Income on Derivatives		Amount of Gain (Loss) Recognized in Income on Derivatives
		Three Months Ended March 31,
			2025		2024
Derivatives not designated as hedging instruments:


Commodity derivatives	Cost of products sold		$	(12)	$	16

Interest rate derivative(1)	Gain on interest rate derivative		—		9

Total			$	(12)	$	25

(1)This interest rate derivative was terminated by USAC in August 2024.

13.REPORTABLE SEGMENTS

Our reportable segments, which conduct their business primarily in the United States, 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;

•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 primarily reflected in crude sales. Revenues from our investment in Sunoco LP segment are primarily reflected in refined product sales and, subsequent to Sunoco LP’s acquisition of NuStar in May 2024, also in gathering, transportation and other fees. 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 and gathering, transportation and other fees.

We report Segment Adjusted EBITDA and consolidated Adjusted EBITDA as measures of segment performance. We define Segment Adjusted EBITDA and consolidated 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 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.

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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:


	Three Months Ended March 31,
		2025		2024
Revenues:
Intrastate transportation and storage:
Revenues from external customers		$	1,147	$	810
Intersegment revenues		147		108
		1,294		918
Interstate transportation and storage:
Revenues from external customers		613		595
Intersegment revenues		8		7
		621		602
Midstream:
Revenues from external customers		884		806
Intersegment revenues		2,772		1,968
		3,656		2,774
NGL and refined products transportation and services:
Revenues from external customers		6,034		5,684
Intersegment revenues		875		842
		6,909		6,526
Crude oil transportation and services:
Revenues from external customers		6,205		7,638
Intersegment revenues		3		—
		6,208		7,638
Investment in Sunoco LP:
Revenues from external customers		5,177		5,495
Intersegment revenues		2		4
		5,179		5,499
Investment in USAC:
Revenues from external customers		230		223
Intersegment revenues		15		6
		245		229
All other:
Revenues from external customers		730		378
Intersegment revenues		265		88
		995		466
Eliminations		(4,087)		(3,023)
Total revenues		$	21,020	$	21,629

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	Three Months Ended March 31,
	2025		2024
Cost of products sold:
Intrastate transportation and storage	$	964	$	487
Interstate transportation and storage	2		1
Midstream	2,260		1,719
NGL and refined products transportation and services	5,641		5,319
Crude oil transportation and services	5,214		6,594
Investment in Sunoco LP	4,526		5,015
Investment in USAC	38		36
All other	995		451
Eliminations	(4,069)		(3,025)
Total cost of products sold	$	15,571	$	16,597


	Three Months Ended March 31,
	2025		2024
Operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses:
Intrastate transportation and storage	$	57	$	53
Interstate transportation and storage	189		203
Midstream	421		323
NGL and refined products transportation and services	247		228
Crude oil transportation and services	213		188
Investment in Sunoco LP	158		105
Investment in USAC	43		39
All other	1		6
Eliminations	(45)		(23)
Total operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses	$	1,284	$	1,122


	Three Months Ended March 31,
	2025		2024
Depreciation, depletion and amortization:
Intrastate transportation and storage	$	51	$	54
Interstate transportation and storage	142		142
Midstream	448		429
NGL and refined products transportation and services	248		258
Crude oil transportation and services	237		247
Investment in Sunoco LP	156		43
Investment in USAC	70		63
All other	15		18
Total depreciation, depletion and amortization	$	1,367	$	1,254

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	Three Months Ended March 31,
	2025		2024
Selling, general and administrative expenses, excluding non-cash compensation and accretion expenses:
Intrastate transportation and storage	$	14	$	12
Interstate transportation and storage	37		33
Midstream	56		44
NGL and refined products transportation and services	48		42
Crude oil transportation and services	44		36
Investment in Sunoco LP	36		32
Investment in USAC	14		15
All other	13		12
Total selling, general and administrative expenses, excluding non-cash compensation and accretion expenses	$	262	$	226


	Three Months Ended March 31,
	2025		2024
Equity in earnings of unconsolidated affiliates (1) :
Intrastate transportation and storage	$	5	$	5
Interstate transportation and storage	63		62
Midstream	3		4
NGL and refined products transportation and services	17		19
Crude oil transportation and services	4		7
All other	—		1
Total equity in earnings of unconsolidated affiliates	$	92	$	98

(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.


	Three Months Ended March 31,
	2025		2024
Other income (expense) (1) :
Intrastate transportation and storage	$	85	$	72
Interstate transportation and storage	119		118
Midstream	6		8
NGL and refined products transportation and services	5		52
Crude oil transportation and services	5		28
Investment in Sunoco LP	(1)		(105)

All other	26		26
Eliminations	(50)		(3)
Total other income	$	195	$	196

(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.

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	March 31, 2025		December 31, 2024
Segment assets:
Intrastate transportation and storage	$	6,322	$	6,289
Interstate transportation and storage	17,489		17,656
Midstream	30,341		30,473
NGL and refined products transportation and services	27,173		27,445
Crude oil transportation and services	26,752		25,231
Investment in Sunoco LP	14,342		14,375
Investment in USAC	2,713		2,746
All other and eliminations	1,293		1,165
Total segment assets	$	126,425	$	125,380


	Three Months Ended March 31,
	2025		2024
Additions to property, plant and equipment (1):
Intrastate transportation and storage	$	226	$	14
Interstate transportation and storage	46		49
Midstream	349		178
NGL and refined products transportation and services	363		220
Crude oil transportation and services	107		89
Investment in Sunoco LP	101		41
Investment in USAC	33		111
All other	29		26
Total additions to property, plant and equipment	$	1,254	$	728

(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.


	March 31, 2025		December 31, 2024
Investments in unconsolidated affiliates (1):
Intrastate transportation and storage	$	150	$	150
Interstate transportation and storage	2,352		2,350
Midstream	130		132
NGL and refined products transportation and services	378		383
Crude oil transportation and services	191		193
All other	59		58
Total investments in unconsolidated affiliates	$	3,260	$	3,266

(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.

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	Three Months Ended March 31,
		2025		2024
Segment Adjusted EBITDA:
Intrastate transportation and storage		$	344	$	438
Interstate transportation and storage		512		483
Midstream		925		696
NGL and refined products transportation and services		978		989
Crude oil transportation and services		742		848
Investment in Sunoco LP		458		242
Investment in USAC		150		139
All other		(11)		45
Adjusted EBITDA (consolidated)		$	4,098	$	3,880


	Three Months Ended March 31,
		2025		2024
Reconciliation of net income to Adjusted EBITDA:
Net income		$	1,720	$	1,692
Depreciation, depletion and amortization		1,367		1,254
Interest expense, net of interest capitalized		809		728
Income tax expense		41		89
Impairment loss		4		—
Gain on interest rate derivative		—		(9)
Non-cash compensation expense		37		46
Unrealized losses on commodity risk management activities		69		141
Inventory valuation adjustments (Sunoco LP)		(61)		(130)
Losses on extinguishments of debt		2		5
Adjusted EBITDA related to unconsolidated affiliates		167		171
Equity in earnings of unconsolidated affiliates		(92)		(98)


Other, net		35		(9)
Adjusted EBITDA (consolidated)		$	4,098	$	3,880

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

(Tabular dollar and unit amounts, except per unit data, are in millions)

The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with (i) our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Quarterly Report on Form 10-Q; and (ii) the consolidated financial statements and management’s discussion and analysis of financial condition and results of operations included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2024 filed with the SEC on February 14, 2025. This discussion includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Part I – Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2024 filed with the SEC on February 14, 2025. Additional information on forward-looking statements is discussed in “Forward-Looking Statements.”

Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “Energy Transfer” mean Energy Transfer LP and its consolidated subsidiaries.

RECENT DEVELOPMENTS

Acquisitions

Parkland Acquisition by Sunoco LP

Sunoco LP has secured a $2.65 billion 364-day bridge term loan for the proposed cash consideration.

TanQuid Acquisition by Sunoco LP

Other Acquisitions by Sunoco LP

Quarterly Cash Distribution

In April 2025, Energy Transfer announced a quarterly distribution of $0.3275 per unit ($1.31 annualized) on Energy Transfer common units for the quarter ended March 31, 2025.

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Regulatory Update

Interstate Natural Gas Transportation Regulation

Rate Regulation

Effective January 2018, the 2017 Tax Cuts and Jobs Act (the “Tax Act”) changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. On March 15, 2018, in a set of related proposals, the FERC addressed treatment of federal income tax allowances in regulated entity rates. The FERC issued a Revised Policy Statement on Treatment of Income Taxes (“Revised Policy Statement”) stating that it will no longer permit master limited partnerships to recover an income tax allowance in their cost-of-service rates. The FERC issued the Revised Policy Statement in response to a remand from the United States Court of Appeals for the District of Columbia Circuit in United Airlines v. FERC, in which the court determined that the FERC had not justified its conclusion that a pipeline organized as a master limited partnership would not “double recover” its taxes under the current policy by both including an income-tax allowance in its cost of service and earning a return on equity calculated using the discounted cash flow methodology. On July 18, 2018, the FERC clarified that a pipeline organized as a master limited partnership will not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double-recovery of investors’ income tax costs. On July 31, 2020, the United States Court of Appeals for the District of Columbia Circuit issued an opinion upholding the FERC’s decision denying a separate master limited partnership recovery of an income tax allowance and its decision not to require the master limited partnership to refund accumulated deferred income tax balances. In light of the rehearing order’s clarification regarding an individual entity’s ability to argue in support of recovery of an income tax allowance and the court’s subsequent opinion upholding denial of an income tax allowance to a master limited partnership, the impact of the FERC’s policy on the treatment of income taxes on the rates we can charge for FERC-regulated transportation services is unknown at this time.

Even without application of the FERC’s rate making-related policy statements and rulemakings, the FERC or our shippers may challenge the cost-of-service rates we charge. The FERC’s establishment of a just and reasonable rate is based on many components, including ROE and tax-related components, but also other pipeline costs that will continue to affect FERC’s determination of just and reasonable cost-of-service rates. Moreover, we receive revenues from our pipelines based on a variety of rate structures, including cost-of-service rates, negotiated rates, discounted rates and market-based rates. Many of our interstate pipelines, such as Tiger Pipeline, Midcontinent Express Pipeline and Fayetteville Express Pipeline, have negotiated market rates that were agreed to by customers in connection with long-term contracts entered into to support the construction of the pipelines. Other systems, such as Florida Gas Transmission Pipeline, Transwestern and Panhandle, have a mix of tariff rate, discount rate and negotiated rate agreements. The revenues we receive from natural gas transportation services we provide pursuant to cost-of-service based rates may decrease in the future as a result of changes to FERC policies, combined with the reduced corporate federal income tax rate established in the Tax Act. The extent of any revenue reduction related to our cost-of-service rates, if any, will depend on a detailed review of all of our cost-of-service components and the outcomes of any challenges to our rates by the FERC or our shippers.

On July 18, 2018, the FERC issued a final rule establishing procedures to evaluate rates charged by the FERC-jurisdictional gas pipelines in light of the Tax Act and the FERC’s Revised Policy Statement. 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 Natural Gas Act 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 Natural Gas Act. The Natural Gas Act 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 United States Court of Appeals for the District of Columbia Circuit (“Court of Appeals”), and the Michigan Public Service Commission also subsequently appealed these orders. On April 25, 2023, the Court of Appeals 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 Court of Appeals 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 Court of Appeals regarding the January 5, 2024 order. On May 28, 2024, the FERC

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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 Court of Appeals 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. The request for rehearing will be addressed in a future order. On March 24, 2025, Panhandle petitioned the Court of Appeals for review of the December 5, 2024 and February 3, 2025 orders.

Pipeline Certification

The FERC issued a Notice of Inquiry (“NOI”) on April 19, 2018, thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. On February 18, 2021, the FERC issued another NOI (“2021 NOI”), reopening its review of the 1999 Policy Statement. Comments on the 2021 NOI were due on May 26, 2021; we filed comments in the FERC proceeding. In September 2021, FERC issued a Notice of Technical Conference on Greenhouse Gas Mitigation related to natural gas infrastructure projects authorized under Sections 3 and 7 of the Natural Gas Act of 1938. A technical conference was held on November 19, 2021, and post-technical conference comments were submitted to the FERC on January 7, 2022.

On February 18, 2022, the FERC issued two new policy statements: (1) an Updated Policy Statement on the Certification of New Interstate Natural Gas Facilities (“2022 Certificate Policy Statement”) and (2) a Policy Statement on the Consideration of Greenhouse Gas Emissions in Natural Gas Infrastructure Project Reviews (“GHG Policy Statement”), to be effective that same day. On March 24, 2022, the FERC issued an order designating the 2022 Certificate Policy Statement and the GHG Policy Statement as draft policy statements, and requested further comments. The FERC stated that it will not apply the now draft policy statements to pending applications or applications to be filed at FERC until it issues any final guidance on these topics. Comments on the 2022 Certificate Policy Statement and GHG Policy Statement were due on April 25, 2022, and reply comments were due on May 25, 2022. On January 24, 2025, the FERC issued an order withdrawing the draft GHG Policy Statement and terminating the proceeding. The FERC has taken no further action on the 2022 Certificate Policy Statement. We are unable to predict what, if any, changes may be proposed as a result of the 2022 Certificate Policy Statement that might affect our natural gas pipeline or LNG facility projects, or when such new policy, if any, might become effective. We do not expect that any change in this policy statement would affect us in a materially different manner than any other natural gas pipeline company operating in the United States.

Interstate Common Carrier Regulation

Liquids pipelines transporting in interstate commerce are regulated by FERC as common carriers under the Interstate Commerce Act (“ICA”). Under the ICA, the FERC utilizes an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, or PPI-FG. Many existing pipelines utilize the FERC liquids index to change transportation rates annually. The indexing methodology is applicable to existing rates, with the exclusion of market-based rates. The FERC’s indexing methodology is subject to review every five years.

On December 17, 2020, FERC issued an order establishing a new index of PPI-FG plus 0.78%. The FERC received requests for rehearing of its December 17, 2020 order and on January 20, 2022, granted rehearing and modified the oil index. Specifically, for the five-year period commencing July 1, 2021 and ending June 30, 2026, FERC-regulated liquids pipelines charging indexed rates are permitted to adjust their indexed ceilings annually by PPI-FG minus 0.21%. FERC directed liquids pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022, as well as the ceiling levels for the period July 1, 2022 to June 30, 2023, based on the new index level. Where an oil pipeline’s filed rates exceed its ceiling levels, FERC ordered such oil pipelines to reduce the rate to bring it into compliance with the recomputed ceiling level to be effective March 1, 2022. Some parties sought rehearing of the January 20 order with FERC, which was denied by FERC on May 6, 2022. Certain parties appealed the January 20 and May 6 orders. On July 26, 2024, the D.C. Circuit ruled in LEPA v. FERC that FERC violated the Administrative Procedure Act because the January 20 order modified the index without following notice and comment. As a result, the D.C. Circuit vacated the January 20 order and on September 17, 2024, the Commission reinstated the index level

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established by its original December 17 order, directed pipelines to file an informational filing to show their recomputed ceiling levels reflecting the reinstated index level and stated that pipelines may file to prospectively increase their indexed rates to their recomputed levels. On October 17, 2024, FERC issued a Supplemental Notice of Proposed Rulemaking (“Supplemental NOPR”) that proposes a reduction to the currently effective index by one percent. The Supplemental NOPR, which remains pending before FERC, could result in the reimplementation through a notice-and-comment rulemaking of the same rulings that were vacated by the D.C. Circuit in LEPA v. FERC.

On October 20, 2022, the FERC issued a policy statement on the Standard Applied to Complaints Against Oil Pipeline Index Rate Changes to establish guidelines regarding how the FERC will evaluate shipper complaints against oil pipeline index rate increases. Specifically, the policy statement adopted the proposal in the FERC’s earlier Notice of Inquiry issued on March 25, 2020 to eliminate the “Substantially Exacerbate Test” as the preliminary screen applied to complaints against index rate increases and instead adopt the proposal to apply the “Percentage Comparison Test” as the preliminary screen for both protests and complaints against index rate increases. At this time, we cannot determine the effect of a change in the FERC’s preliminary screen for complaints against index rates changes, however, a revised screen would result in a threshold aligned with the existing threshold for protests against index rate increases. Any complaint or protest raised by a shipper could materially and adversely affect our financial condition, results of operations or cash flows.

Air Quality Standards

In 2023, the United States Environmental Protection Agency (“EPA”) finalized its Good Neighbor Plan (the “Plan”) which seeks to reduce nitrogen oxide pollution from power plants and other industrial facilities from 23 upwind states which the EPA determined is contributing to National Ambient Air Quality Standards (NAAQS) nonattainment and interfering with maintenance of the 2015 ozone NAAQS in downwind states. As part of the Plan, the EPA announced that it would be issuing prescriptive emission standards for several sectors, including certain new and existing internal combustion engines of a certain size used in pipeline transportation of natural gas. The EPA’s final rule was to become effective on August 4, 2023, and the prescribed emission standards were scheduled to be effective in 2026.

Operators and industry groups have challenged the Plan in the D.C. Circuit, as well as the legal predicates to the individual upwind states’ inclusion in the Plan in the regional circuits. The effectiveness of the rule is currently stayed in the nine states within the Partnership’s footprint, by nature of judicial stays of the legal predicate to the Plan, by judicial stay of the Plan itself by the U.S. Supreme Court, or by the administrative stay issued by the EPA in October 2024. Proceedings as to both on the merits are ongoing. In the challenge to the Plan in the D.C. Circuit, oral argument is expected in early 2025 and a decision could take several months, projected late 2025.

The Partnership currently estimates that the final rule would require retrofitting or replacement of approximately 192 engines in its interstate and intrastate natural gas transportation and storage operations. The Partnership is involved in challenging application of the Plan in the nine states impacted within its footprint. Compliance with the Plan (if implementation is not stayed or otherwise delayed) will still require substantial capital expenditures which could adversely affect our business in future periods. However, at this time, we are still assessing the potential costs of this rule and, given uncertainties resulting from the multiple legal challenges filed against the Plan in various states, in the DC Circuit and the U.S. Supreme Court, we cannot predict with any certainty what the final costs of compliance for the Plan for the Partnership ultimately may be.

RESULTS OF OPERATIONS

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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.

Segment Adjusted EBITDA, as reported for each segment in the following table, is analyzed for each segment in the section titled “Segment Operating Results.” Adjusted EBITDA is a non-GAAP measure used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating results of the Partnership’s fundamental business activities and should not be considered in isolation or as a substitution for net income, income from operations, cash flows from operating activities or other GAAP measures.

Consolidated Results


	Three Months Ended March 31,
		2025		2024		Change
Segment Adjusted EBITDA:
Intrastate transportation and storage		$	344	$	438	$	(94)
Interstate transportation and storage		512		483		29
Midstream		925		696		229
NGL and refined products transportation and services		978		989		(11)
Crude oil transportation and services		742		848		(106)
Investment in Sunoco LP		458		242		216
Investment in USAC		150		139		11
All other		(11)		45		(56)
Adjusted EBITDA (consolidated)		$	4,098	$	3,880	$	218


	Three Months Ended March 31,
		2025		2024		Change
Reconciliation of net income to Adjusted EBITDA:
Net income		$	1,720	$	1,692	$	28
Depreciation, depletion and amortization		1,367		1,254		113
Interest expense, net of interest capitalized		809		728		81
Income tax expense		41		89		(48)
Impairment loss		4		—		4
Gain on interest rate derivative		—		(9)		9
Non-cash compensation expense		37		46		(9)
Unrealized losses on commodity risk management activities		69		141		(72)
Inventory valuation adjustments (Sunoco LP)		(61)		(130)		69
Losses on extinguishments of debt		2		5		(3)
Adjusted EBITDA related to unconsolidated affiliates		167		171		(4)
Equity in earnings of unconsolidated affiliates		(92)		(98)		6


Other, net		35		(9)		44
Adjusted EBITDA (consolidated)		$	4,098	$	3,880	$	218

Net Income. For the three months ended March 31, 2025 compared to the same period last year, net income increased by $28 million, or approximately 2%, primarily due to higher segment margin from multiple segments. The most significant increases were in our midstream segment, where segment margin was favorably impacted by recently acquired assets and the non-recurring recognition of $160 million associated with Winter Storm Uri in 2021, which represents the remainder of midstream segment margin from Winter Storm Uri that had not already been recognized. In our intrastate transportation and storage segment, a total of approximately $285 million of previously invoiced amounts that are currently disputed by customers remain unrecognized, of which approximately $263 million is due from CPS Energy. The increase in net income also reflected an increase from our investment in Sunoco LP segment, where results were also favorably impacted by recent acquisitions and strategic transactions. The increase in segment margin was partially offset by increases in operating expenses, selling, general

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and administrative expenses, depreciation, depletion and amortization and interest expense. These changes are discussed in more detail below and in “Segment Operating Results.”

Adjusted EBITDA (consolidated). For the three months ended March 31, 2025 compared to the same period last year, Adjusted EBITDA increased by $218 million, or approximately 6%, primarily due to higher segment margin in our midstream segment and our investment in Sunoco LP segment, as discussed above.

Additional discussion on the changes impacting net income and Adjusted EBITDA is available below and in “Segment Operating Results.”

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased for the three months ended March 31, 2025 compared to the same period last year primarily due to additional depreciation and amortization from assets recently placed in service and recent acquisitions.

Interest Expense, Net of Interest Capitalized. Interest expense, net of interest capitalized, increased for the three months ended March 31, 2025 compared to the same period last year primarily due to an increase in aggregate debt balances following the acquisitions of NuStar and WTG Midstream Holdings LLC and the refinancing of certain preferred units with long-term debt.

Income Tax Expense. For the three months ended March 31, 2025 compared to the same period last year, income tax expense decreased primarily due to a favorable state tax rate change in the current period.

Impairment Loss. For the three months ended March 31, 2025, the impairment loss was related to USAC’s evaluation of the future deployment of its idle fleet under current market conditions.

Gain on Interest Rate Derivative. For the three months ended March 31, 2024, the gain on interest rate derivative resulted from changes in forward interest rates, which caused USAC’s interest rate swap to change in value. This interest rate derivative was terminated by USAC in August 2024.

Unrealized Losses on Commodity Risk Management Activities. The unrealized losses on our commodity risk management activities include changes in fair value of commodity derivatives and the hedged inventory included in designated fair value hedging relationships. Information on the unrealized gain and loss within each segment is included in “Segment Operating Results,” and additional information on the commodity-related derivatives, including notional volumes, maturities and fair values, is available in “Item 3. Quantitative and Qualitative Disclosures About Market Risk” and in Note 12 to our consolidated financial statements included in “Item 1. Financial Statements.”

Inventory Valuation Adjustments. Inventory valuation adjustments represent changes in lower of cost or market reserves using the LIFO method on Sunoco LP’s inventory. These amounts are unrealized valuation adjustments applied to fuel volumes remaining in inventory at the end of the period. For the three months ended March 31, 2025 and 2024, the Partnership’s cost of products sold included Sunoco LP’s favorable inventory valuation adjustments of $61 million and $130 million, respectively, which increased net income.

Losses on Extinguishments of Debt. For the three months ended March 31, 2025, loss on extinguishment of debt was related to Sunoco LP's redemption of senior notes.

Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. See additional information in “Supplemental Information on Unconsolidated Affiliates” and “Segment Operating Results.”

Other, net. Other, net primarily includes the amortization of regulatory assets and other income and expense amounts.

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Supplemental Information on Unconsolidated Affiliates

The following table presents financial information related to unconsolidated affiliates:


	Three Months Ended March 31,
		2025		2024		Change
Equity in earnings of unconsolidated affiliates:
Citrus		$	33	$	37	$	(4)
MEP		17		17		—
White Cliffs		3		6		(3)
Explorer		7		6		1
SESH		14		10		4
Other		18		22		(4)
Total equity in earnings of unconsolidated affiliates		$	92	$	98	$	(6)

Adjusted EBITDA related to unconsolidated affiliates(1):
Citrus		$	79	$	81	$	(2)
MEP		26		26		—
White Cliffs		8		11		(3)
Explorer		11		10		1
SESH		15		13		2
Other		28		30		(2)
Total Adjusted EBITDA related to unconsolidated affiliates		$	167	$	171	$	(4)

Distributions received from unconsolidated affiliates:
Citrus		$	30	$	33	$	(3)
MEP		26		23		3
White Cliffs		9		11		(2)
Explorer		5		8		(3)
SESH		8		18		(10)
Other		19		14		5
Total distributions received from unconsolidated affiliates		$	97	$	107	$	(10)

(1)These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.

Segment Operating Results

We evaluate segment performance based on Segment Adjusted EBITDA, which we believe is an important performance measure of the core profitability of our operations. This measure represents the basis of our internal financial reporting and is one of the performance measures used by senior management in deciding how to allocate capital resources among business segments.

The following tables identify the components of Segment Adjusted EBITDA, which is calculated as follows:

•Segment margin, operating expenses and selling, general and administrative expenses. These amounts represent the amounts included in our consolidated financial statements that are attributable to each segment.

•Unrealized gain or loss on commodity risk management activities and inventory valuation adjustments. These are the unrealized amounts that are included in cost of products sold to calculate segment margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized loss is added back and the unrealized gain is subtracted to calculate the segment measure.

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•Non-cash compensation expense. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate the segment measure.

•Adjusted EBITDA related to 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, 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 following analysis of segment operating results includes a measure of segment margin. Segment margin is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment margin is similar to the GAAP measure of gross margin, except that segment margin excludes charges for depreciation, depletion and amortization. Among the GAAP measures reported by the Partnership, the most directly comparable measure to segment margin is Segment Adjusted EBITDA; a reconciliation of segment margin to Segment Adjusted EBITDA is included in the following tables for each segment where segment margin is presented.

In addition, for certain segments, the following sections include information on the components of segment margin by sales type, which components are included in order to provide additional disaggregated information to facilitate the analysis of segment margin and Segment Adjusted EBITDA. For example, these components include transportation margin, storage margin and other margin. These components of segment margin are calculated consistent with the calculation of segment margin; therefore, these components also exclude charges for depreciation, depletion and amortization.

Intrastate Transportation and Storage


	Three Months Ended March 31,
		2025		2024		Change
Natural gas transported (BBtu/d)		14,220		14,177		43
Withdrawals from storage natural gas inventory (BBtu)		8,225		8,230		(5)
Revenues		$	1,294	$	918	$	376
Cost of products sold		964		487		477
Segment margin		330		431		(101)
Unrealized losses on commodity risk management activities		76		64		12
Operating expenses, excluding non-cash compensation expense		(57)		(53)		(4)
Selling, general and administrative expenses, excluding non-cash compensation expense		(14)		(12)		(2)
Adjusted EBITDA related to unconsolidated affiliates		6		7		(1)
Other		3		1		2
Segment Adjusted EBITDA		$	344	$	438	$	(94)

Volumes. For the three months ended March 31, 2025 compared to the same period last year, transported volumes of gas on our Texas and Oklahoma intrastate pipelines increased primarily due to more third party transportation, partially offset by lower gas production from the Haynesville area. Transported volumes reported above exclude volumes attributable to purchases and sales of gas for our pipelines’ own accounts and the optimization of any unused capacity.

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Segment Margin. The components of our intrastate transportation and storage segment margin were as follows:


	Three Months Ended March 31,
		2025		2024		Change
Transportation fees		$	221	$	222	$	(1)
Natural gas sales and other (excluding unrealized gains and losses)		129		251		(122)
Retained fuel (excluding unrealized gains and losses)		16		8		8
Storage margin (excluding unrealized gains and losses and fair value inventory adjustments)		40		14		26
Unrealized losses on commodity risk management activities and fair value inventory adjustments		(76)		(64)		(12)
Total segment margin		$	330	$	431	$	(101)

Segment Adjusted EBITDA. For the three months ended March 31, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment decreased due to the net impact of the following:

•a decrease of $122 million in realized natural gas sales and other primarily due to lower pipeline optimization as a result of lower volatility in natural gas prices; and

•an increase of $4 million in operating expenses primarily due to increases in project costs, employee costs and ad valorem taxes; partially offset by

•an increase of $26 million in storage margin primarily due to higher storage optimization; and

•an increase of $8 million in retained fuel margin primarily due to higher gas prices.

Interstate Transportation and Storage


	Three Months Ended March 31,
		2025		2024		Change
Natural gas transported (BBtu/d)		18,204		17,665		539
Natural gas sold (BBtu/d)		33		23		10
Revenues		$	621	$	602	$	19
Cost of products sold		2		1		1
Segment margin		619		601		18
Operating expenses, excluding non-cash compensation, amortization and accretion expenses		(189)		(203)		14
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses		(37)		(33)		(4)
Adjusted EBITDA related to unconsolidated affiliates		119		118		1


Segment Adjusted EBITDA		$	512	$	483	$	29

Volumes. For the three months ended March 31, 2025 compared to the same period last year, transported volumes increased primarily due to more capacity sold and higher utilization on our Panhandle, Trunkline and Gulf Run systems due to increased demand.

Segment Adjusted EBITDA. For the three months ended March 31, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net impact of the following:

•an increase of $18 million in segment margin primarily due to a $9 million increase in operational gas sales resulting from higher prices, a $5 million increase in storage and parking revenue and a $4 million increase in transportation revenue from several of our interstate pipeline systems due to higher contracted volumes at higher rates;

•a decrease of $14 million in operating expenses primarily due to lower maintenance costs; and

•an increase of $1 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to an increase from our Southeast Supply Header joint venture; partially offset by

•an increase of $4 million in selling, general and administrative expenses primarily due to an increase in employee costs.

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Midstream


	Three Months Ended March 31,
		2025		2024		Change
Gathered volumes (BBtu/d)		20,411		19,922		489
NGLs produced (MBbls/d)		1,090		890		200
Equity NGLs (MBbls/d)		60		52		8
Revenues		$	3,656	$	2,774	$	882
Cost of products sold		2,260		1,719		541
Segment margin		1,396		1,055		341

Operating expenses, excluding non-cash compensation expense		(421)		(323)		(98)
Selling, general and administrative expenses, excluding non-cash compensation expense		(56)		(44)		(12)
Adjusted EBITDA related to unconsolidated affiliates		5		6		(1)
Other		1		2		(1)
Segment Adjusted EBITDA		$	925	$	696	$	229

Volumes. For the three months ended March 31, 2025 compared to the same period last year, gathered volumes increased primarily due to newly acquired assets and higher volumes in the Permian region, partially offset by declines in other regions. NGL production increased primarily due to recently acquired assets and increased Permian plant utilization.

Segment Adjusted EBITDA. For the three months ended March 31, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net impact of the following:

•an increase of $153 million in segment margin primarily due to recently acquired assets and higher volumes in the Permian region;

•an increase of $160 million in segment margin due to the non-recurring recognition of certain amounts associated with Winter Storm Uri in 2021, which represents the remainder of midstream segment margin from Winter Storm Uri that had not already been recognized; and

•an increase of $28 million in segment margin due to higher natural gas prices of $35 million offset by lower NGL prices of $7 million; partially offset by

•an increase of $98 million in operating expenses primarily due to recent acquisitions and assets placed in service; and

•an increase of $12 million in selling, general and administrative expenses due to higher corporate allocations, as well as the impact of a $5 million decrease in workers’ compensation reserve in the prior period.

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NGL and Refined Products Transportation and Services


	Three Months Ended March 31,
		2025		2024		Change
NGL transportation volumes (MBbls/d)		2,169		2,087		82
Refined products transportation volumes (MBbls/d)		574		573		1
NGL and refined products terminal volumes (MBbls/d)		1,453		1,395		58
NGL fractionation volumes (MBbls/d)		1,089		1,053		36
Revenues		$	6,909	$	6,526	$	383
Cost of products sold		5,641		5,319		322
Segment margin		1,268		1,207		61
Unrealized (gains) losses on commodity risk management activities		(26)		22		(48)
Operating expenses, excluding non-cash compensation expense		(247)		(228)		(19)
Selling, general and administrative expenses, excluding non-cash compensation expense		(48)		(42)		(6)
Adjusted EBITDA related to unconsolidated affiliates		31		30		1


Segment Adjusted EBITDA		$	978	$	989	$	(11)

Volumes. For the three months ended March 31, 2025 compared to the same period last year, NGL transportation volumes increased primarily due to higher volumes from the Permian region and on our Mariner East pipeline system. The increase in transportation volumes also led to higher fractionated volumes at our Mont Belvieu NGL Complex.

Segment Margin. The components of our NGL and refined products transportation and services segment margin were as follows:


	Three Months Ended March 31,
		2025		2024		Change
Transportation margin		$	616	$	615	$	1
Fractionators and refinery services margin		218		233		(15)
Terminal services margin		233		209		24
Storage margin		81		79		2
Marketing margin		94		93		1
Unrealized gains (losses) on commodity risk management activities		26		(22)		48
Total segment margin		$	1,268	$	1,207	$	61

Segment Adjusted EBITDA. For the three months ended March 31, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment decreased due to the net impact of the following:

•an increase of $19 million in operating expenses primarily due to a $10 million increase in gas and power utility costs and a $6 million increase in employee costs;

•a decrease of $15 million in fractionators and refinery services margin primarily due to lower gains from blending activities; and

•an increase of $6 million in selling, general and administrative expenses primarily due to increased costs from recently acquired assets; partially offset by

•an increase of $24 million in terminal services margin primarily due to a $22 million increase in fees from loading NGL volumes for export at our Nederland and Marcus Hook terminals and a $2 million increase from higher throughput and storage at our refined product terminals; and

•an increase of $2 million in storage margin primarily due to the timing of deficiency payments.

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Crude Oil Transportation and Services


	Three Months Ended March 31,
		2025		2024		Change
Crude oil transportation volumes (MBbls/d)		6,719		6,102		617
Crude oil terminal volumes (MBbls/d)		3,325		3,241		84
Revenues		$	6,208	$	7,638	$	(1,430)
Cost of products sold		5,214		6,594		(1,380)
Segment margin		994		1,044		(50)
Unrealized losses on commodity risk management activities		—		19		(19)
Operating expenses, excluding non-cash compensation expense		(213)		(188)		(25)
Selling, general and administrative expenses, excluding non-cash compensation expense		(44)		(36)		(8)
Adjusted EBITDA related to unconsolidated affiliates		6		9		(3)

Other		(1)		—		(1)
Segment Adjusted EBITDA		$	742	$	848	$	(106)

Volumes. For the three months ended March 31, 2025 compared to the same period last year, crude oil transportation volumes were higher due to continued growth on our gathering systems and from assets contributed upon the recent formation of the ET-S Permian joint venture with Sunoco LP, partially offset by lower volumes on our Bakken Pipeline.

Segment Adjusted EBITDA. For the three months ended March 31, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment decreased due to the net impact of the following:

•a decrease of $69 million in segment margin (excluding unrealized losses on commodity risk management activities) due to decreased transportation and the timing of optimization losses realized during the quarter which we expect to partially reverse in future periods, partially offset by increases from assets contributed upon the formation of ET-S Permian;

•an increase of $25 million in operating expenses primarily due to a $9 million increase from assets contributed upon the formation of ET-S Permian, a $7 million increase in volume-driven expenses, and a $5 million increase in employee expenses;

•an increase of $8 million in selling, general and administrative expenses primarily due to costs associated with ET-S Permian; and

•a decrease of $3 million in Adjusted EBITDA related to unconsolidated affiliates due to lower volumes and lower re-contracted rates.

Investment in Sunoco LP


	Three Months Ended March 31,
		2025		2024		Change
Revenues		$	5,179	$	5,499	$	(320)
Cost of products sold		4,526		5,015		(489)
Segment margin		653		484		169
Unrealized (gains) losses on commodity risk management activities		(1)		13		(14)
Operating expenses, excluding non-cash compensation expense		(158)		(105)		(53)
Selling, general and administrative expenses, excluding non-cash compensation expense		(36)		(32)		(4)
Adjusted EBITDA related to unconsolidated affiliates		50		3		47
Inventory valuation adjustments		(61)		(130)		69
Other		11		9		2
Segment Adjusted EBITDA		$	458	$	242	$	216

The investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.

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Segment Adjusted EBITDA. For the three months ended March 31, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP segment increased due to the net impact of the following:

•an increase of $224 million in segment margin (excluding unrealized gains and losses on commodity risk management activities and inventory valuation adjustments) primarily due to the acquisitions of NuStar and Zenith European terminals; and

•an increase of $47 million in Adjusted EBITDA related to unconsolidated affiliates due to the formation of ET-S Permian; partially offset by

•an increase of $53 million in operating expenses and $4 million in selling, general and administrative expenses primarily due to the acquisitions of NuStar and Zenith European terminals.

Investment in USAC


	Three Months Ended March 31,
		2025		2024		Change
Revenues		$	245	$	229	$	16
Cost of products sold		38		36		2
Segment margin		207		193		14

Operating expenses, excluding non-cash compensation expense		(43)		(39)		(4)
Selling, general and administrative expenses, excluding non-cash compensation expense		(14)		(15)		1



Segment Adjusted EBITDA		$	150	$	139	$	11

The investment in USAC segment reflects the consolidated results of USAC.

Segment Adjusted EBITDA. For the three months ended March 31, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC segment increased due to the net impact of the following:

•an increase of $14 million in segment margin primarily due to higher market-based rates on newly deployed and redeployed compression units and higher average rates on existing customer contracts, and higher revenue-generating horsepower as a result of increased demand for compression services; partially offset by

•an increase of $4 million in operating expenses primarily due to an increase in employee costs associated with increased revenue-generating horsepower.

All Other


	Three Months Ended March 31,
		2025		2024		Change
Revenues		$	995	$	466	$	529
Cost of products sold		995		451		544
Segment margin		—		15		(15)
Unrealized losses on commodity risk management activities		20		23		(3)
Operating expenses, excluding non-cash compensation expense		(1)		(6)		5
Selling, general and administrative expenses, excluding non-cash compensation expense		(13)		(12)		(1)
Adjusted EBITDA related to unconsolidated affiliates		—		1		(1)
Other and eliminations		(17)		24		(41)
Segment Adjusted EBITDA		$	(11)	$	45	$	(56)

Amounts reflected in our all other segment primarily include:

•our natural gas marketing operations;

•our wholly owned natural gas compression operations; and

•our natural resources business.

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Segment Adjusted EBITDA. For the three months ended March 31, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment decreased due to the net impact of the following:

•a decrease of $47 million due to intersegment eliminations of Sunoco LP’s 32.5% share of ET-S Permian, which is consolidated in our crude oil transportation and services segment and also reflected as an unconsolidated affiliate in our investment in Sunoco LP segment; and

•a decrease of $13 million in our natural gas marketing business due to the timing of gains on stored natural gas in the prior period; partially offset by

•an increase of $3 million in rental income on recently acquired real estate.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Our ability to satisfy obligations and pay distributions to unitholders will depend on our future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond management’s control.

We currently expect capital expenditures in 2025 to be approximately as follows (including capitalized interest and overhead and only our proportionate share for joint ventures, but excluding capital expenditures related to our investments in Sunoco LP and USAC):


	Growth		Maintenance
Intrastate transportation and storage	$	1,400	$	85
Interstate transportation and storage	170		205
Midstream	1,525		375
NGL and refined products transportation and services	1,375		150
Crude oil transportation and services	295		180
All other (including eliminations)	235		105
Total capital expenditures	$	5,000	$	1,100

The assets used in our natural gas and liquids operations, including pipelines, gathering systems and related facilities, are generally long-lived assets and do not require significant maintenance capital expenditures. Accordingly, we do not have any significant financial commitments for maintenance capital expenditures in our businesses. From time to time we experience increases in pipe costs due to a number of reasons, including but not limited to, delays from steel mills, limited selection of mills capable of producing large diameter pipe timely, higher steel prices, including as a result of the recent governmental action on tariffs, and other factors beyond our control. However, we have included these factors in our anticipated growth capital expenditures for each year.

We generally fund capital expenditures and distributions with cash flows from operating activities.

Sunoco LP currently expects to invest approximately $150 million in maintenance capital expenditures and at least $400 million in growth capital for the full year 2025.

USAC currently plans to invest between $38 million and $42 million in maintenance capital expenditures and between $120 million and $140 million in expansion capital expenditures for the full year 2025.

Cash Flows

Our cash flows may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, the price for our products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of our acquisitions and other factors.

Operating Activities

Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in “Results of Operations”), excluding the impacts of non-cash items and changes in operating assets and liabilities. Non-cash items include recurring non-cash expenses, such as depreciation, depletion and amortization expense and non-cash compensation expense. The increase in depreciation, depletion and amortization expense during the periods presented primarily

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resulted from construction and acquisition of assets, while changes in non-cash compensation expense resulted from changes in the number of units granted and changes in the grant date fair value estimated for such grants. Cash flows from operating activities also differ from earnings as a result of non-cash charges that may not be recurring, such as impairment charges and allowance for equity funds used during construction. The allowance for equity funds used during construction increases in periods when we have a significant amount of interstate pipeline construction in progress. Changes in operating assets and liabilities between periods result from factors such as the changes in the value of price risk management assets and liabilities, the timing of accounts receivable collection, the timing of payments on accounts payable, the timing of purchase and sales of inventories and the timing of advances and deposits received from customers.

Three months ended March 31, 2025 compared to three months ended March 31, 2024. Cash provided by operating activities during 2025 was $2.92 billion compared to $3.77 billion for 2024, and net income was $1.72 billion for 2025 and $1.69 billion for 2024. The difference between net income and net cash provided by operating activities for the three months ended March 31, 2025 primarily consisted of net changes in operating assets and liabilities (net of effects of acquisitions) of $122 million and other items totaling $1.26 billion, which includes non-cash items and items related to investing and financing activities that are included in net income.

The non-cash activity in 2025 and 2024 consisted primarily of depreciation, depletion and amortization of $1.37 billion and $1.25 billion, respectively, deferred income tax benefit of $16 million and deferred income tax expense of $67 million, respectively, favorable inventory valuation adjustments of $61 million and $130 million, respectively, and non-cash compensation expense of $37 million and $46 million, respectively. For 2025 and 2024, net income also included equity in earnings of unconsolidated affiliates of $92 million and $98 million, respectively, and losses on extinguishments of debt of $2 million and $5 million, respectively, as well as an impairment loss of $4 million in 2025.

Cash provided by operating activities includes cash distributions received from unconsolidated affiliates that are deemed to be paid from cumulative earnings, which distributions were $77 million in 2025 and $84 million in 2024.

Cash paid for interest, net of interest capitalized, was $519 million and $444 million for the three months ended March 31, 2025 and 2024, respectively. Interest capitalized was $47 million and $23 million for the three months ended March 31, 2025 and 2024, respectively.

Investing Activities

Cash flows from investing activities primarily consist of cash amounts paid for acquisitions, capital expenditures, cash contributions to our joint ventures and cash proceeds from sales or contributions of assets or businesses. In addition, distributions from equity investees are included in cash flows from investing activities if the distributions are deemed to be a return of the Partnership’s investment. Changes in capital expenditures between periods primarily result from increases or decreases in our growth capital expenditures to fund our construction and expansion projects.

Three months ended March 31, 2025 compared to three months ended March 31, 2024. Cash used in investing activities was $1.20 billion for both 2025 and 2024. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for 2025 were $1.21 billion compared to $770 million for 2024. Additional detail related to our capital expenditures is provided in the table below.

In 2025, Sunoco LP paid $12 million in cash for acquisitions of fuel equipment, motor fuel inventory and supply agreements. In 2024, Sunoco LP paid $185 million in cash for the acquisition of Zenith European terminals. In 2024, we also paid $84 million to acquire the outstanding noncontrolling interest in Edwards Lime Gathering, LLC, which is now a wholly owned subsidiary, and $180 million for other acquisitions.

In 2025 and 2024, we received cash distributions from unconsolidated affiliates in excess of cumulative earnings of $20 million and $23 million, respectively, and we paid cash contributions to unconsolidated affiliates of $1 million and $2 million, respectively.

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The following is a summary of capital expenditures (including only our proportionate share for joint ventures, net of contributions in aid of construction costs) on an accrual basis for the three months ended March 31, 2025:


	Capital Expenditures Recorded During Period
	Growth		Maintenance		Total
Intrastate transportation and storage	$	209	$	17	$	226
Interstate transportation and storage	24		22		46
Midstream	291		58		349
NGL and refined products transportation and services	343		20		363
Crude oil transportation and services	78		29		107
Investment in Sunoco LP	75		26		101
Investment in USAC	22		11		33
All other (including eliminations)	10		19		29
Total capital expenditures	$	1,052	$	202	$	1,254

Financing Activities

Changes in cash flows from financing activities between periods primarily result from changes in the levels of borrowings and equity issuances, which are primarily used to fund our acquisitions and growth capital expenditures. Distributions increase between the periods based on increases in the number of common units outstanding or increases in the distribution rate.

Three months ended March 31, 2025 compared to three months ended March 31, 2024. Cash used in financing activities during 2025 was $1.58 billion compared to $791 million for 2024. During 2025, we had a net increase in our debt level of $72 million compared to a net increase of $1.88 billion for 2024. In 2025 and 2024, we paid debt issuance costs of $51 million and $60 million, respectively. In 2024, we paid $895 million in cash for the redemption of our Series C and Series D Preferred Units and paid $37 million in cash to redeem a portion of the outstanding Crestwood Niobrara LLC preferred units. In 2024, USAC paid $749 million in cash for investments in government securities in connection with the legal defeasance of senior notes.

For both 2025 and 2024, we paid distributions of $1.13 billion to our partners. In 2025 and 2024, we paid distributions of $455 million and $421 million, respectively, to noncontrolling interests. In 2025 and 2024, we paid distributions of $13 million and $22 million, respectively, to our redeemable noncontrolling interests.

In 2025 and 2024, we received capital contributions of $2 million and $637 million, respectively, in cash from noncontrolling interests.

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Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:


	March 31, 2025		December 31, 2024
Energy Transfer indebtedness:
Notes and debentures(1) (2)	$	48,270	$	46,269

Five-Year Credit Facility(2)	605		2,759
Subsidiary indebtedness:
Transwestern senior notes	75		75
Bakken Project senior notes	850		850
Sunoco LP senior notes, bonds and lease-related obligations(1)	7,703		7,304
USAC senior notes	1,750		1,750
Sunoco LP credit facility	—		203
USAC credit facility	805		772

Other long-term debt	10		11
Net unamortized premiums, discounts and fair value adjustments	63		77
Deferred debt issuance costs	(342)		(310)
Total debt	59,789		59,760
Less: current maturities of long-term debt	7		8

Long-term debt, less current maturities	$	59,782	$	59,752

(1)As of March 31, 2025, these balances included approximately $2.48 billion aggregate principal amount due on or before March 31, 2026, which were classified as long-term as management has the intent and ability to refinance the borrowings on a long-term basis.

(2)See additional information below under “Recent Transactions.”

Recent Transactions

Energy Transfer Senior Notes Issuance and Redemption

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.

Sunoco LP Senior Notes Issuance and Redemption

Credit Facilities and Commercial Paper

Five-Year Credit Facility

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Sunoco LP Credit Facilities

USAC Credit Facility

Compliance with our Covenants

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

CASH DISTRIBUTIONS

Cash Distributions Paid by Energy Transfer

Under its Partnership Agreement, Energy Transfer will distribute all of its Available Cash, as defined in the Partnership Agreement, within 50 days following the end of each fiscal quarter. Available Cash generally means, with respect to any quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of our General Partner to provide for future cash requirements.

Cash Distributions on Energy Transfer Common Units

Distributions declared and/or paid with respect to Energy Transfer common units subsequent to December 31, 2024 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2024

February 7, 2025

February 19, 2025

0.3250

March 31, 2025

May 9, 2025

May 20, 2025

0.3275

Cash Distributions on Energy Transfer Preferred Units

Distributions declared on the Energy Transfer Preferred Units were as follows:


Period Ended	Record Date	Payment Date	Series B (1)		Series F (1)		Series G (1)		Series H (1)		Series I (2)
December 31, 2024	February 1, 2025	February 15, 2025	$	33.125	$	—	$	—	$	—	$	0.2111
March 31, 2025	May 1, 2025	May 15, 2025	—		33.750		35.630		32.500		0.2111

(2)For the period ended March 31, 2025, the cash distribution for the Series I Preferred Units will be paid on May 15, 2025 to unitholders of record as of the close of business on May 2, 2025.

Description of Energy Transfer Preferred Units

A summary of the distribution and redemption rights associated with the Energy Transfer Preferred Units is included in Note 9 in “Item 1. Financial Statements.”

Cash Distributions Paid by Subsidiaries

The Partnership’s consolidated financial statements include Sunoco LP and USAC, both of which are master limited partnerships, as well as other non-wholly owned consolidated joint ventures. The following sections describe cash distributions made by our publicly traded subsidiaries, Sunoco LP and USAC, both of which are required by their respective partnership

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agreements to distribute all cash on hand (less appropriate reserves determined by the boards of directors of their respective general partners) subsequent to the end of each quarter.

Cash Distributions Paid by Sunoco LP

Distributions on Sunoco LP’s common units declared and/or paid by Sunoco LP subsequent to December 31, 2024 were as follows:

Quarter Ended

Payment Date

Rate

December 31, 2024

February 19, 2025

0.8865

March 31, 2025

May 20, 2025

0.8976

Cash Distributions Paid by USAC

Distributions on USAC’s common units declared and/or paid by USAC subsequent to December 31, 2024 were as follows:

Quarter Ended

Payment Date

Rate

December 31, 2024

February 7, 2025

0.525

March 31, 2025

May 9, 2025

0.525

CRITICAL ACCOUNTING ESTIMATES

The Partnership’s critical accounting estimates are described in its Annual Report on Form 10-K filed with the SEC on February 14, 2025. We have not made any changes to the accounting policies involving critical accounting estimates subsequent to the Form 10-K filing. Changes to any of the related estimate amounts are discussed in the notes to consolidated financial statements included in “Item 1. Financial Statements” in this quarterly report on Form 10-Q.

FORWARD-LOOKING STATEMENTS

This quarterly report contains various forward-looking statements and information that are based on our beliefs and those of our General Partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. When used in this quarterly report, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “could,” “believe,” “may,” “will” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our General Partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor our General Partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are:

•the ability of our subsidiaries to make cash distributions to us, which is dependent on their results of operations, cash flows and financial condition;

•the actual amount of cash distributions by our subsidiaries to us;

•the volumes transported on our subsidiaries’ pipelines and gathering systems;

•the level of throughput in our subsidiaries’ processing and treating facilities;

•the fees our subsidiaries charge and the margins they realize for their gathering, treating, processing, storage and transportation services;

•the prices and market demand for, and the relationship between, natural gas and NGLs;

•energy prices generally;

•impacts of world health events;

•the possibility of cyber and malware attacks;

•the prices of natural gas and NGLs compared to the price of alternative and competing fuels;

•the general level of petroleum product demand and the availability and price of NGL supplies;

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•the level of domestic oil, natural gas and NGL production;

•the availability of imported oil, natural gas and NGLs;

•actions taken by foreign oil and gas producing nations;

•the political and economic stability of petroleum producing nations;

•the effect of weather conditions on demand for oil, natural gas and NGLs;

•availability of local, intrastate and interstate transportation systems;

•the continued ability to find and contract for new sources of natural gas supply;

•availability and marketing of competitive fuels;

•the impact of energy conservation efforts;

•energy efficiencies and technological trends;

•U.S. and foreign governmental regulation, taxation and tariffs;

•changes to, and the application of, regulation of tariff rates and operational requirements related to our subsidiaries’ interstate and intrastate pipelines;

•hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs;

•competition from other midstream companies and interstate pipeline companies;

•loss of key personnel;

•loss of key natural gas producers or the providers of fractionation services;

•reductions in the capacity or allocations of third-party pipelines that connect with our subsidiaries’ pipelines and facilities;

•the effectiveness of risk-management policies and procedures and the ability of our subsidiaries’ liquids marketing counterparties to satisfy their financial commitments;

•the nonpayment or nonperformance by our subsidiaries’ customers;

•risks related to the development of new infrastructure projects or other growth projects, including failure to make sufficient progress to justify continued development, delays in obtaining customers, increased costs of financing and raw materials and regulatory, environmental, political and legal uncertainties that may affect the timing and cost of these projects;

•risks associated with the construction of new pipelines, treating and processing facilities or other facilities, or additions to our subsidiaries’ existing pipelines and their facilities, including difficulties in obtaining permits and rights-of-way or other regulatory approvals and the performance by third-party contractors;

•the availability and cost of capital and our subsidiaries’ ability to access certain capital sources;

•a deterioration of the credit and capital markets;

•risks associated with the assets and operations of entities in which our subsidiaries own noncontrolling interests, including risks related to management actions at such entities that our subsidiaries may not be able to control or exert influence;

•the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses;

•changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations; and

•the costs and effects of legal and administrative proceedings.

You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risks described under “Part I - Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2024 filed with the SEC on February 14, 2025. Any forward-looking statement made by us in this Quarterly Report on Form 10-Q is based only on information currently available to us and speaks only as of the date on which it is made. We undertake no obligation to publicly update any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of new information, future developments or otherwise.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information contained in Item 3 updates, and should be read in conjunction with, information set forth in Part II - Item 7A included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2024 filed with the SEC on February 14, 2025, in addition to the accompanying notes and management’s discussion and analysis of financial condition and results of operations presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. Our quantitative and qualitative disclosures about market risk are consistent with those discussed in our Annual Report on Form 10-K for the year ended December 31, 2024. Since December 31, 2024, there have been no material changes to our primary market risk exposures or how those exposures are managed.

Commodity Price Risk

The following table summarizes our commodity-related financial derivative instruments and fair values, including derivatives related to our consolidated subsidiaries, as well as the effect of an assumed hypothetical 10% change in the underlying price of the commodity. Dollar amounts are presented in millions.


	March 31, 2025					December 31, 2024
	Notional Volume	Fair Value Asset (Liability)		Effect of Hypothetical 10% Change		Notional Volume	Fair Value Asset (Liability)		Effect of Hypothetical 10% Change
Mark-to-Market Derivatives
Natural Gas (BBtu):
Fixed Swaps/Futures	(15,135)	$	—	$	7	6,630	$	5	$	3
Basis Swaps IFERC/NYMEX	880	(18)		1		3,490	(6)		3
Swing Swaps IFERC	(138,780)	—		—		(156,820)	(7)		1

Options – Calls	600	—		—		—	—		—

Power (Megawatt):
Forwards	58,600	3		—		6,040	1		—
Futures	(340,545)	1		3		(140,137)	1		1
Options – Puts	33,600	—		—		(17,600)	—		—
Options – Calls	14,400	—		—		—	—		—
Crude (MBbls):
Forwards/Swaps	(21,363)	(10)		21		(22,512)	(10)		39



NGL/Refined Products (MBbls):
Forwards/Swaps	(4,819)	26		28		(15,063)	(4)		58
Options – Puts	7	—		—		(9)	—		—
Options – Calls	(2)	—		—		(14)	—		—
Futures	(3,064)	(9)		21		(1,763)	(7)		13
Fair Value Hedging Derivatives
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(38,945)	2		2		(47,170)	1		2
Fixed Swaps/Futures	(38,945)	(30)		16		(47,170)	(4)		15

The fair values of the commodity-related financial positions have been determined using independent third-party prices, readily available market information and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the above tables. Price-risk sensitivities were calculated by assuming a theoretical 10% change (increase or decrease) in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. Results are presented in absolute terms and represent a potential gain or loss in net income or in other comprehensive income. In the event of an actual 10% change in prompt month natural gas prices, the fair value of our total derivative portfolio may not change by 10% due to factors such as when the financial instrument settles and the location to which the financial instrument is tied (i.e., basis swaps) and the relationship between prompt month and forward months.

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Interest Rate Risk

As of March 31, 2025, we and our subsidiaries had $2.00 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $20 million annually.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We have established disclosure controls and procedures to ensure that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Under the supervision and with the participation of senior management, including the Co-Chief Executive Officers (Co-Principal Executive Officers) and the Chief Financial Officer (Principal Financial Officer) of our General Partner, we evaluated our disclosure controls and procedures, as such term is defined under Rule 13a–15(e) promulgated under the Exchange Act. Based on this evaluation, the Co-Principal Executive Officers and the Principal Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective as of March 31, 2025 to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (1) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) is accumulated and communicated to management, including the Co-Principal Executive Officers and Principal Financial Officer of our General Partner, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting (as defined in Rule 13(a)-15(f) or Rule 15d-15(f) of the Exchange Act) during the three months ended March 31, 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For information regarding legal proceedings, see our Annual Report on Form 10-K filed with the SEC on February 14, 2025 and Note 10 in “Item 1. Financial Statements” in this Quarterly Report on Form 10-Q for the quarter ended March 31, 2025.

Additionally, we have received notices of violations and potential fines under various federal, state and local provisions relating to the discharge of materials into the environment or protection of the environment. While we believe that even if any one or more of the following environmental proceedings were decided against us, it would not be material to our financial position, results of operations or cash flows, we are required to report governmental proceedings if we reasonably believe that such proceedings could result in monetary sanctions in excess of $1 million.

In January 2019, we received notice from the U.S. Department of Justice (“USDOJ”) on behalf of the EPA that a civil penalty enforcement action was being pursued under the Clean Water Act for an estimated 450 barrel crude oil release from the Mid Valley Pipeline operated by SPLP and owned by Mid Valley. The release purportedly occurred in October 2014 on a nature preserve located in Hamilton County, Ohio, near Cincinnati, Ohio. After discovery and notification of the release, SPLP conducted substantial emergency response, remedial work and primary restoration in three phases and the primary restoration has been acknowledged to be complete. In December 2019, SPLP reached an agreement in principal with the USEPA regarding payment of a civil penalty. In September 2024, after a public comment period, the United States District Court for the Southern District of Ohio (Western Division) entered a Consent Decree whereby SPLP and Mid Valley fully resolved both the civil penalty and alleged natural resource damages (NRD) which had been brought jointly by the USDOJ, on behalf of trustees of the United States, and the Ohio Attorney General, on behalf of the trustees of the State of Ohio. Total payments of approximately $3 million were made in satisfaction of the civil penalty and natural resource damages plus interest during November 2024 through February 2025. Operation and maintenance activities associated with the restoration are expected to continue for several years.

On October 28, 2022, the EPA issued a Notice of Proposed Debarment (“NPD”) arising from SPLP’s and ETC Northeast Pipeline, LLC’s nolo contendere plea agreements and convictions for violations of Pennsylvania’s Clean Streams Law related to the Revolution and Mariner 2 pipelines. The following entities were proposed for debarment: (1) SPLP (pleading entity); (2) ETC Northeast Pipeline, LLC (pleading entity); (3) Energy Transfer LP; (4) SemGroup LLC; and (5) LE GP, LLC. The NPD prevented the named entities from pursuing or renewing Federal government contracts or Federal financial assistance agreements. We engaged with the EPA to address the EPA’s concerns. On March 10, 2025, the EPA terminated the proposed debarments of the named entities and administratively closed the matter effective immediately.

On June 15, 2023, PHMSA issued a Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order (collectively “NOPV”), CPF 4-2023-011-NOPV, identifying three probable violations with compliance order actions associated with two of them and civil penalties proposed in an amount totaling approximately $2 million. The NOPV related to a PHMSA Accident Investigation Division investigation of a pigging incident which occurred on March 26, 2020 at the Partnership’s Borcher Station in Kansas and resulted in a fatality. The Partnership challenged PHMSA’s alleged violations and related civil penalties and compliance order actions contained in the NOPV. After an administrative hearing, which was held on April 24, 2024 before a PHMSA Presiding Official, the PHMSA Southwest Region recommended to remain relatively firm on the NOPV, with only a slightly reduced civil penalty by approximately $19 thousand. The Partnership challenged the PHMSA administrative process in federal court, alleging among other things that PHMSA’s in-house administrative enforcement process was unconstitutional. In response, PHMSA has withdrawn the NOPV, terminated its in-house administrative action, and elected to file an enforcement action in federal court. The Partnership intends to defend this matter but remains open to a reasonable settlement to resolve the matter.

On October 13, 2023, Mid Valley Pipeline Company LLC, (“Mid Valley”) received a NOPSO from the PHMSA related to various historical accidents and complaints reported to PHMSA on the Mid Valley system. The NOPSO requests that Mid Valley perform several proposed corrective measures within six months of receipt of a Safety Order; however, in response, Mid Valley requested that PHMSA engage in informal consultations prior to issuing a Safety Order in an effort for the parties to potentially enter into a Consent Agreement and Order. Informal consultation is underway. In the event a Consent Agreement and Order is not reached between the parties during this process, Mid Valley may request a Hearing on the NOPSO. The informal consultation process has concluded with PHMSA and Mid Valley reaching agreement on the Corrective Measures. PHMSA issued the Consent Agreement which was signed by Mid Valley on March 21, 2025. The fully executed version of the Consent Agreement was received by Mid Valley on April 24, 2025.

On February 13, 2025, SPLP received a Notice of Proposed Safety Order (“NOPSO”) from PHMSA related to a release of jet fuel on the Twin Oaks Discharge pipeline system in Bucks County, Pennsylvania. The NOPSO made certain preliminary findings and proposes that SPLP take certain measures with respect to the system to ensure safety. SPLP engaged in informal

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settlement discussions with PHMSA and entered into a Consent Agreement that was finalized into a Consent Order on May 2, 2025. We cannot predict the outcome, timeline or costs associated with this administrative action.

On March 3, 2025, SPLP received an Administrative Order from the Pennsylvania Department of Environmental Protection regarding the release of jet fuel from the Twin Oaks Discharge pipeline system in Bucks County, Pennsylvania. SPLP has complied with all of the Interim Remedial Measures and Remediation requirements identified in the administrative order that were required to be completed as of the date of this submission. SPLP will continue to complete and comply all the requirements of the administrative order. We cannot predict the timeline or costs associated with this administrative order.

Pursuant to the instructions to Form 10-Q, matters disclosed in this Part II - Item 1 include any reportable legal proceeding (i) that has been terminated during the period covered by this report, (ii) that became a reportable event during the period covered by this report, or (iii) for which there has been a material development during the period covered by this report.

For additional information required in this Item, see disclosure under the headings “Litigation and Contingencies” and “Environmental Matters” in Note 10 to our consolidated financial statements in “Item 1. Financial Statements,” which information is incorporated by reference into this Item.

ITEM 1A. RISK FACTORS

The following risk factors, which were previously disclosed by the Partnership in its Annual Report on Form 10-K, have been included herein to reflect updates based on recent developments. These risk factors should be read in conjunction with our risk factors described in “Part I – Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2024 filed with the SEC on February 14, 2025.

General economic, financial, and political conditions, including the impact of tariffs to the extent enacted, may materially adversely affect our results of operations and financial condition.

General economic, financial, and political conditions may have a material adverse effect on our results of operations and financial condition. For example, on March 12, 2025, the U.S. government imposed a 25% tariff on steel imports, and on April 2, 2025, the U.S. government announced a 10% tariff on product imports from almost all foreign countries and individualized higher tariffs on certain other countries. Several tariff announcements have been followed by announcements of limited exemptions and temporary pauses. These actions have caused uncertainty and volatility in financial markets and may result in retaliatory measures on U.S. goods. It is possible that our operations may be affected by the resulting volatility in pricing and demand. Similarly, declines in consumer confidence and/or consumer spending, changes in unemployment, significant inflationary or deflationary changes or disruptive regulatory or geopolitical events could contribute to increased volatility and diminished expectations for the economy and our markets, including the market for our goods and services, and lead to demand or cost pressures that could negatively and adversely impact our business. These conditions could affect both of our business segments.

Examples of such conditions could include:

•a general or prolonged decline in, or shocks to, regional or broader macro-economies;

•regulatory changes that could impact the markets in which we operate, such as immigration, tariffs or trade reform laws, which could reduce demand for or supply of our goods and services or lead to pricing, currency, or other pressures; and

•deflationary economic pressures, which could hinder our ability to operate profitably in view of the challenges inherent in making corresponding deflationary adjustments to our cost structure.

In addition, volatility in the capital markets resulting from tariff announcements could also limit our ability to access capital on favorable terms, which could have an adverse impact on our ability to finance new projects and/or acquisitions.

The nature of these types of risks, which are often unpredictable, makes them difficult to plan for, or otherwise mitigate, and they are generally uninsurable—which compounds their potential impact on our business.

Changes in U.S. administrative policy, including the imposition of or increases in tariffs on steel and/or other raw materials, changes to existing trade agreements and any resulting changes in international trade relations, may have an adverse effect on us.

We own and operate pipelines and terminals and, like others in our industry, we use significant amounts of steel in our projects and rely on our ability to obtain that steel in an affordable way to maintain our operating margins. Any imposition of or increase in tariffs on steel and/or other raw materials could increase our growth project costs, which may impact the profitability of new projects and our maintenance capital expenditures, potentially in excess of budgeted amounts.

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On March 12, 2025, the U.S. government imposed a 25% tariff on steel imports, and on April 2, 2025, the U.S. government announced a 10% tariff on product imports from almost all countries and individualized higher tariffs on certain other countries. Several tariff announcements have been followed by announcements of limited exemptions and temporary pauses. These actions have caused uncertainty and volatility in financial markets and may result in retaliatory measures on U.S. goods. The ultimate impact of these or other potential tariffs is unknown at this time. Additionally, ongoing changes in U.S. and foreign government trade policies, including potential modifications to existing trade agreements and further restrictions on free trade, could introduce additional uncertainty. Any escalation of trade tensions, additional tariffs, retaliatory measures by foreign governments or shifts in U.S. or international trade policies could adversely impact our supply chain and increase costs, particularly on our expansion projects. A trade war or other significant changes in trade regulations could have an adverse effect on our business and results of operations.

The construction of the liquefaction project remains subject to further approvals and some approvals may be subject to further conditions, review and/or revocation.

In December 2015, the FERC authorized Lake Charles LNG Export Company, LLC, a wholly owned subsidiary of Energy Transfer (“Lake Charles LNG Export”), to site, construct and operate the liquefaction project subject to various conditions, including a condition requiring all phases of the liquefaction project to be completed and in-service within five years of the date of the FERC authorization order. The order also requires modifications to our Trunkline pipeline facilities that connect to our Lake Charles facility and additionally requires execution of a transportation contract for natural gas supply to the liquefaction facility prior to the initiation of construction of the liquefaction facility. In December 2019, the FERC granted an extension of time until and including December 16, 2025 to complete construction of the liquefaction project and pipeline facilities modifications and place the facilities into service. In May 2022, the FERC granted a second extension of time until and including December 16, 2028 to complete construction of the liquefaction facilities modifications and place the facilities into service. In April 2025, Lake Charles LNG Export requested a third extension of time until and including December 31, 2031 to complete construction of the liquefaction facilities modifications and place the facilities into service. This request remains pending before FERC.

The export of LNG produced by any liquefaction facility in the United States requires export authorization from the United States Department of Energy (the “DOE”). The NGA requires the DOE to approve applications for LNG exports unless such approval would be “inconsistent with the public interest.” In March 2013, Lake Charles LNG Export obtained a DOE authorization to export LNG to countries with which the United States has or will have Free Trade Agreements (“FTA”) for trade in natural gas (the “FTA Authorization”). In July 2016, Lake Charles LNG Export also obtained a conditional DOE authorization to export LNG to countries that do not have an FTA for trade in natural gas (the “Non-FTA Authorization”) subject to commencement of exports no later than December 2020. Lake Charles LNG Export applied for an extension of the deadline to commence exports under the Non-FTA Authorization to December 2025 and the DOE approved such extension request in October 2020. Lake Charles LNG Export applied for a second extension of the deadline to commence exports and in April 2023, the DOE denied this request in connection with a new DOE policy related to extension requests.

In light of this new policy, in August 2023, Lake Charles LNG Export applied for a new Non-FTA Authorization which, if approved, would provide for a new deadline to commence exports to Non-FTA countries, which deadline would be seven years from the date of such approval. In January 2024, the Biden Administration announced a moratorium on the approval of LNG export authorizations by the DOE and instructed the DOE to conduct studies related to the cumulative impact of LNG exports on domestic natural gas prices, climate change and other matters. The Biden Administration stated that these studies were necessary to enable the DOE to make determinations related to the statutory “public interest” standard. The DOE stated that these studies would take several months to complete, after which they would be made available for public comment. This process was not completed prior to the U.S. Presidential election in November 2024. On July 1, 2024, the federal court for the Western District of Louisiana ordered that the DOE was enjoined and restrained from halting or pausing the approval process for pending and future applications for LNG exports to non-FTA countries. On December 17, 2024, the DOE released an updated study of U.S. LNG exports with a 60-day comment period that was later extended to March 20, 2025. On January 20, 2025, President Trump issued the Unleashing American Energy executive order directing the DOE Secretary to restart reviews of applications for approvals of LNG export projects as expeditiously as possible, consistent with applicable law. The executive order stated that in assessing the “public interest” to be advanced by any particular application, the DOE Secretary shall consider the economic and employment impacts to the United States and the impact to the security of allies and partners that would result from granting the application. On January 21, 2025, the DOE announced that it was ending the moratorium imposed by the Biden Administration on the approvals of LNG export authorizations by the DOE and returning to regular order following direction given by President Trump in the Unleashing American Energy executive order. At this time, it is unclear what actions the Trump Administration may take, if any at all, with respect to the DOE study.

Additionally, while President Trump’s executive order resumes permitting applications, there can be no assurance as to whether Lake Charles LNG Export will receive approval of its application for a Non-FTA Authorization.

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Litigation relating to Sunoco LP’s acquisition of Parkland Corporation (“Parkland”) could result in an injunction preventing the completion of the acquisition and/or substantial costs to Sunoco LP and Parkland.

Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into acquisition, merger or other business combination agreements. Even if such a lawsuit is without merit, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on Sunoco LP’s and Parkland’s respective liquidity and financial condition.

Lawsuits that may be brought against Sunoco LP, Parkland or their respective directors could also seek, among other things, injunctive relief or other equitable relief, including a request to rescind parts of the arrangement agreement already implemented and to otherwise enjoin the parties from consummating the acquisition. One of the conditions to the closing of the acquisition is that no injunction by any court or other tribunal of competent jurisdiction has been entered and continues to be in effect and no law has been adopted or is effective, in either case that prohibits or makes illegal the closing of the acquisition. Consequently, if a plaintiff is successful in obtaining an injunction prohibiting completion of the acquisition, that injunction may delay or prevent the acquisition from being completed within the expected timeframe or at all, which may adversely affect Sunoco LP’s and Parkland’s respective business, financial position and results of operations.

There can be no assurance that any of the defendants will be successful in the outcome of any pending or any potential future lawsuits. The defense or settlement of any lawsuit or claim that remains unresolved at the time the acquisition is completed may adversely affect Sunoco LP’s or Parkland’s business, financial condition, results of operations and cash flows.

Failure by Sunoco LP to complete the acquisition of Parkland and successfully integrate the businesses of Sunoco LP and Parkland in the expected time frame could negatively impact the price of Sunoco LP’s common units and have a material adverse effect on its results of operations, cash flows and financial position.

If Sunoco LP’s acquisition of Parkland is not completed for any reason, including as a result of failure to obtain all requisite regulatory approvals or Parkland’s shareholders fail to approve the applicable proposals, the anticipated benefits of the acquisition may not be realized or may take longer to realize than expected. The success of the merger will depend, in part, on the ability of Sunoco LP to realize the anticipated benefits from combining the businesses of Sunoco LP and Parkland. If Sunoco LP and Parkland are unable to successfully combine their businesses, the anticipated benefits of the merger may take longer to realize than expected. In addition, the actual integration may result in additional and unforeseen expenses, which could reduce the anticipated benefits of the merger.

Additionally, Sunoco LP would be subject to a number of risks, including the following:

•negative reactions from the financial markets, including negative impacts on the price of Sunoco LP’s common units;

•negative reactions from Sunoco LP’s respective customers, distributors, suppliers, vendors, landlords, joint venture partners and other business partners;

•Sunoco LP will still be obligated to pay certain significant costs relating to its acquisition of Parkland, such as legal, accounting, financing, financial advisor and printing fees;

•Sunoco LP may be obligated to pay a termination fee as required by the arrangement agreement governing the acquisition;

•the arrangement agreement governing the acquisition places certain restrictions on the conduct of Sunoco LP’s business, which may delay or prevent the undertaking of business opportunities that, absent the arrangement agreement governing the acquisition, may have been pursued;

•matters relating to Sunoco LP’s acquisition of Parkland (including integration planning) require substantial commitments of time and resources by management, which may have resulted in the distraction from ongoing business operations and pursuing other opportunities that could have been beneficial;

•litigation related to any failure to complete Sunoco LP’s acquisition of Parkland or related to any enforcement proceeding commenced against Sunoco LP to perform its respective obligations under the arrangement agreement governing the acquisition; and

•loss of key employees, the disruption of each of Sunoco LP’s and Parkland’s ongoing businesses and relationships with customers, or inconsistencies in their standards, controls, procedures and policies.

If the acquisition is not completed, the risks described above may materialize and they may have a material adverse effect on Sunoco LP’s results of operations, cash flows, financial position and price of Sunoco LP’s common units.

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Sunoco LP’s future debt levels may impair its financial condition and its ability to make distributions to its unitholders.

Sunoco LP had $7.7 billion of debt outstanding as of March 31, 2025. Sunoco LP has the ability to incur additional debt under its revolving credit facility and the indentures governing its senior notes. In connection with Sunoco LP’s merger with Parkland, Sunoco LP expects to assume Parkland’s debt and issue additional debt, aggregating approximately $5 billion. The level of Sunoco LP’s future indebtedness could have important consequences to us, including:

•making it more difficult for Sunoco LP to satisfy its obligations with respect to its senior notes, its GoZone bonds and its credit agreements governing its revolving credit facility;

•limiting Sunoco LP’s ability to borrow additional amounts to fund working capital, capital expenditures, acquisitions, debt service requirements, the execution of its growth strategy and other activities;

•requiring Sunoco LP to dedicate a substantial portion of its cash flow from operations to pay interest on its debt, which would reduce its cash flow available to make distributions to its unitholders and holders of SUNCorp, LLC units and to fund working capital, capital expenditures, acquisitions, execution of its growth strategy and other activities;

•making Sunoco LP more vulnerable to adverse changes in general economic conditions, its industry and government regulations and in its business by limiting its flexibility in planning for, and making it more difficult for us to react quickly to, changing conditions; and

•placing Sunoco LP at a competitive disadvantage compared with its competitors that have less debt.

In addition, Sunoco LP may not be able to generate sufficient cash flow from its operations to repay its indebtedness when it becomes due and to meet other cash needs. Sunoco LP’s ability to service its debt depends upon, among other things, its financial and operating performance as impacted by prevailing economic conditions, and financial, business, regulatory and other factors, some of which are beyond its control. In addition, Sunoco LP’s ability to service its debt will depend on market interest rates, since the rates applicable to a portion of its borrowings fluctuate. If Sunoco LP is not able to pay its debts as they become due, it will be required to pursue one or more alternative strategies, such as selling assets, refinancing or restructuring its indebtedness or selling additional debt or equity securities. Sunoco LP may not be able to refinance its debt or sell additional debt or equity securities or its assets on favorable terms, if at all, and if Sunoco LP must sell its assets, it may negatively affect its ability to generate revenues and to pay distributions to us.

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ITEM 6. EXHIBITS

The exhibits listed on the following exhibit index are filed or furnished, as indicated, as part of this report:

Exhibit Number

Description

3.1

Certificate of Limited Partnership of Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 3.2 of Form S-1 (File No. 333-128097) filed September 2, 2005)

3.2

Certificate of Amendment of Certificate of Limited Partnership of Energy Transfer Equity, L.P., dated as of October 19, 2018 (incorporated by reference to Exhibit 3.1 of Form 8-K (File No. 1-32740) filed October 19, 2018)

3.3

Fourth Amended and Restated Agreement of Limited Partnership of Energy Transfer LP, dated November 3, 2023 (incorporated by reference to Exhibit 3.3 of Form 10-Q (File No. 1-32740) filed August 8, 2024)

4.1

Seventh Supplemental Indenture, dated as of March 4, 2025 between Energy Transfer LP, as issuer, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-32740) filed March 4, 2025)

22.1

Issuers and Guarantors of Registered Securities (incorporated by reference to Exhibit 22.1 of Form 10-Q (File No. 1-32740) filed August 5, 2021)

31.1*

Certification of Co-Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2*

Certification of Co-Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.3*

Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1**

Certification of Co-Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2**

Certification of Co-Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.3**

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101*

Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets; (ii) our Consolidated Statements of Operations; (iii) our Consolidated Statements of Comprehensive Income; (iv) our Consolidated Statements of Equity; (v) our Consolidated Statements of Cash Flows; and (vi) the notes to our Consolidated Financial Statements

104

Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)

Filed herewith

Furnished herewith

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

ENERGY TRANSFER LP

By:

LE GP, LLC, its general partner

Date:

May 8, 2025

By:

/s/ A. Troy Sturrock

A. Troy Sturrock

Group Senior Vice President, Controller and Principal Accounting Officer