Energy Transfer LP - Quarter Report: 2024 September (Form 10-Q)

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 4. CONTROLS AND PROCEDURES

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

ITEM 1A. RISK FACTORS

ITEM 6. EXHIBITS

SIGNATURE

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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
Bcf						billion cubic feet
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
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
MBbls						thousand barrels
MEP						Midcontinent Express Pipeline LLC
MMcf						million cubic feet
NGL						natural gas liquid, such as propane, butane and natural gasoline
NYMEX						New York Mercantile Exchange
OTC						over-the-counter
Panhandle						Panhandle Eastern Pipe Line Company, LP, a wholly owned subsidiary of Energy Transfer and/or Panhandle Eastern Pipe Line
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 LLC, a non-wholly owned subsidiary of Energy Transfer and/or Rover Pipeline
Sea Robin						Sea Robin Pipeline Company, LLC, a 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
SOFR						Secured Overnight Financing Rate
SPLP						Sunoco Pipeline L.P., a wholly owned subsidiary of Energy Transfer
Transwestern						Transwestern Pipeline Company, LLC, a wholly owned subsidiary of Energy Transfer and/or Transwestern Pipeline
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)


	September 30, 2024	December 31, 2023
ASSETS
Current assets:
Cash and cash equivalents	$	$
Accounts receivable, net
Accounts receivable from related companies
Inventories
Income taxes receivable
Derivative assets
Other current assets

Total current assets

Property, plant and equipment
Accumulated depreciation and depletion	()	()
Property, plant and equipment, net

Investments in unconsolidated affiliates

Lease right-of-use assets, net


Other non-current assets, net
Intangible assets, net
Goodwill

Total assets	$	$

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)

September 30,
2024

December 31,
2023

LIABILITIES AND EQUITY

Current liabilities:

Accounts payable

Accounts payable to related companies

Derivative liabilities

Operating lease current liabilities

Accrued and other current liabilities

Current maturities of long-term debt

Total current liabilities

Long-term debt, less current maturities

Non-current derivative liabilities

Non-current operating lease liabilities

Deferred income taxes

Other non-current liabilities

Commitments and contingencies

Equity:

Limited Partners:

Preferred Unitholders

Common Unitholders

General Partner

()

Accumulated other comprehensive income

Total partners’ capital

Noncontrolling interests

Total equity

Total liabilities and equity

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 September 30,		Nine Months Ended September 30,
	2024	2023	2024	2023
REVENUES:
Refined product sales	$	$	$	$
Crude sales
NGL sales
Gathering, transportation and other fees
Natural gas sales
Other
Total revenues
COSTS AND EXPENSES:
Cost of products sold
Operating expenses
Depreciation, depletion and amortization
Selling, general and administrative
Impairment losses
Total costs and expenses
OPERATING INCOME
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	()	()	()	()
Equity in earnings of unconsolidated affiliates

Loss on extinguishment of debt			()
Gain (loss) on interest rate derivatives	()
Non-operating litigation-related loss		()		()
Gain on sale of Sunoco LP West Texas assets
Other, net
INCOME BEFORE INCOME TAX EXPENSE
Income tax expense
NET INCOME
Less: Net income attributable to noncontrolling interests
Less: Net income attributable to redeemable noncontrolling interests
NET INCOME ATTRIBUTABLE TO PARTNERS
General Partner’s interest in net income
Preferred Unitholders’ interest in net income
Loss on redemption of preferred units
Common Unitholders’ interest in net income	$	$	$	$



NET INCOME PER COMMON UNIT:
Basic	$	$	$	$
Diluted	$	$	$	$

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 September 30,		Nine Months Ended September 30,
	2024	2023	2024	2023
Net income	$	$	$	$
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities
Actuarial gain related to pension and other postretirement benefit plans
Foreign currency translation adjustments	()		()	()
Change in other comprehensive income from unconsolidated affiliates	()		()
	()
Comprehensive income
Less: Comprehensive income attributable to noncontrolling interests
Less: Comprehensive income attributable to redeemable noncontrolling interests
Comprehensive income attributable to partners	$	$	$	$

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, 2023

()

Distributions to partners

()

Distributions to noncontrolling interests

()

Capital contributions from noncontrolling interests

Other comprehensive income, net of tax

Redemption of Series C and Series D Preferred Units

()

Conversion of USAC preferred to USAC common units

Other, net

()

Net income, excluding amounts attributable to redeemable noncontrolling interests

Balance, March 31, 2024

()

Distributions to partners

()

Distributions to noncontrolling interests

()

Other comprehensive loss, net of tax

()

Redemption of Series A and Series E Preferred Units

()

Conversion of USAC preferred to USAC common units

NuStar acquisition

Redemption of NuStar preferred units

()

Other, net

()

Net income, excluding amounts attributable to redeemable noncontrolling interests

Balance, June 30, 2024

()

Distributions to partners

()

Distributions to noncontrolling interests

()

Other comprehensive loss, net of tax

()

WTG Midstream acquisition

Other, net

Net income, excluding amounts attributable to redeemable noncontrolling interests

Balance, September 30, 2024

()

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 (continued)

(Dollars in millions)

(unaudited)

Common Unitholders

Preferred Unitholders

General Partner

AOCI

Noncontrolling Interests

Total

Balance, December 31, 2022

()

Distributions to partners

()

Distributions to noncontrolling interests

()

Capital contributions from noncontrolling interests

Other comprehensive loss, net of tax

()

Other, net

Net income, excluding amounts attributable to redeemable noncontrolling interests

Balance, March 31, 2023

()

Distributions to partners

()

Distributions to noncontrolling interests

()

Other comprehensive income, net of tax

Lotus Midstream acquisition

Other, net

Net income, excluding amounts attributable to redeemable noncontrolling interests

Balance, June 30, 2023

()

Distributions to partners

()

Distributions to noncontrolling interests

()

Other comprehensive income, net of tax

Other, net

Net income, excluding amounts attributable to redeemable noncontrolling interests

Balance, September 30, 2023

()

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)


	Nine Months Ended September 30,
	2024	2023
OPERATING ACTIVITIES:
Net income	$	$
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization
Deferred income taxes
Inventory valuation adjustments		()
Non-cash compensation expense
Impairment losses

Loss on extinguishment of debt
Gain on sale of Sunoco LP West Texas assets	()
Distributions on unvested awards	()	()
Equity in earnings of unconsolidated affiliates	()	()
Distributions from unconsolidated affiliates
Other non-cash		()
Net change in operating assets and liabilities, net of effects of acquisitions and divestitures
Net cash provided by operating activities
INVESTING ACTIVITIES:
Cash paid for WTG Midstream acquisition, net of cash received	()
Cash paid by Sunoco LP for acquisitions of terminals, net of cash received	()
Cash paid for Edwards Lime Gathering, LLC noncontrolling interest	()
Cash received by Sunoco LP from NuStar acquisition
Cash paid for Lotus Midstream acquisition		()
Cash paid for other acquisitions, net of cash received	()	()
Capital expenditures, excluding allowance for equity funds used during construction	()	()
Contributions in aid of construction costs
Contributions to unconsolidated affiliates	()	()
Distributions from unconsolidated affiliates in excess of cumulative earnings
Proceeds from sale of Sunoco LP West Texas assets
Proceeds from sales of other assets
Other, net
Net cash used in investing activities	()	()
FINANCING ACTIVITIES:
Proceeds from borrowings
Repayments of debt	()	()
USAC investments in government securities in connection with the legal defeasance of senior notes	()



Redemption of Series A, Series C, Series D and Series E Preferred Units	()
Sunoco LP redemption of NuStar preferred units	()
Redemption of Crestwood Niobrara LLC preferred units	()
Capital contributions from noncontrolling interests
Capital contributions from redeemable noncontrolling interests
Distributions to partners	()	()
Distributions to noncontrolling interests	()	()
Distributions to redeemable noncontrolling interests	()	()
Debt issuance costs	()	()
Other, net
Net cash used in financing activities	()	()
Increase in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period	$	$

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)

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 million common units of Sunoco LP, and the general partner interests and 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.

billion in cash and approximately million newly issued Energy Transfer common units, which had a fair value of approximately $ million.

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

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Property, plant and equipment, net Lease right-of-use assets, net

Intangible assets, net

Total assets Total current liabilities Non-current operating lease liabilities Other non-current liabilities Total liabilities Total consideration Cash received Total consideration, net of cash received$

Sunoco LP’s Acquisitions

NuStar

On May 3, 2024, Sunoco LP completed the previously announced acquisition of all of the common units of NuStar Energy L.P. (“NuStar”). Under the terms of the merger agreement, NuStar common unitholders received Sunoco LP common units for each NuStar common unit. In connection with the acquisition, Sunoco LP issued approximately million common units, which had a fair value of approximately $ billion, assumed debt totaling approximately $ billion including approximately $ million of lease related financing obligations and assumed preferred units with a fair value of approximately $ million. NuStar has approximately miles of pipeline and terminal and storage facilities that store and distribute crude oil, refined products, renewable fuels, ammonia and specialty liquids.

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

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Property, plant and equipment, net Lease right-of-use assets, net

Goodwill (1)

Intangible assets, net (2)

Other non-current assets Total assets Total current liabilities

Long-term debt, less current maturities (3)

Non-current operating lease liabilities Deferred income taxes Other non-current liabilities Total liabilities

Preferred units (3)

Total consideration Cash received Total consideration, net of cash received$

(1)Goodwill primarily represents expected commercial and operational synergies and is subject to change based on final purchase price allocations. None of the goodwill recorded as a result of this transaction is deductible for tax purposes.

(2) million of favorable contracts, with a remaining weighted average life of approximately years, and $ million of customer relationships, with a remaining weighted average life of approximately years.

(3) million, redeemed NuStar’s subordinated notes totaling $ million and repaid the outstanding balance on the NuStar credit facility totaling $ million.

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

Zenith European Terminals

On March 13, 2024, Sunoco LP completed the previously announced acquisition of liquid fuels terminals in Amsterdam, Netherlands and Bantry Bay, Ireland from Zenith Energy for approximately € million ($ million), which was allocated $ million to other current assets, $ million to property, plant and equipment, $ million to other non-current assets and $ million to goodwill. In connection with this transaction, Sunoco LP also assumed $ million in current liabilities, $ million in deferred income taxes and $ million in other non-current liabilities.

Other Acquisition

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

Sunoco LP’s Divestiture

West Texas Sale

On April 16, 2024, Sunoco LP completed the previously announced sale of convenience stores located in West Texas, New Mexico and Oklahoma to 7-Eleven, Inc. for approximately $ billion, including customary adjustments for fuel

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million gain ($ million, net of current tax expense of $ million and deferred tax benefit of $ million).

Joint Venture Transaction

Permian Joint Venture

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

% interest with Sunoco LP holding the remaining % interest in the joint venture.

)$()Accounts receivable from related companies()()Inventories()()Other current assets Other non-current assets, net()()Accounts payable Accounts payable to related companies ()Accrued and other current liabilities Other non-current liabilities() Derivative assets and liabilities, net ()Net change in operating assets and liabilities, net of effects of acquisitions and divestitures$ $

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$ Lease assets obtained in exchange for new lease liabilities Distribution reinvestment USAC exercise and conversion of preferred units into common units USAC government securities transferred in connection with the legal defeasance of USAC senior notes due 2026 Legal defeasance of USAC senior notes due 2026 Sunoco LP common units (noncontrolling interest) issued in connection with the NuStar acquisition

$ Crude oil Spare parts and other Total inventories$ $ million and $ million, respectively. For the three and nine months ended September 30, 2024 and 2023, 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 September 30, 2024 and 2023, the Partnership’s cost of products sold included unfavorable inventory valuation adjustments of $ million and favorable inventory adjustments of $ million, respectively, related to Sunoco LP’s LIFO inventory. For the nine months ended September 30, 2024 and 2023, the Partnership’s cost of products sold included unfavorable inventory adjustments of $ million and favorable inventory adjustments of $ million, respectively, related to Sunoco LP’s LIFO inventory.

transfers were made between any levels within the fair value hierarchy.

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$ $ Swing Swaps IFERC Fixed Swaps/Futures Forward Physical Contracts Power:Forwards Futures NGLs – Forwards/Swaps Refined Products – Futures Crude – Forwards/Swaps Total commodity derivatives Other non-current assets Total assets$ $ $ Liabilities:Commodity derivatives:Natural Gas:Basis Swaps IFERC/NYMEX$()$()$ Swing Swaps IFERC()() Fixed Swaps/Futures()() Forward Physical Contracts() ()Power:Forwards()() Futures()() NGLs – Forwards/Swaps()() Refined Products – Futures()() Crude – Forwards/Swaps()() Total commodity derivatives()()()Total liabilities$()$()$()

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$ $ Commodity derivatives:Natural Gas:Basis Swaps IFERC/NYMEX Swing Swaps IFERC Fixed Swaps/Futures Forward Physical Contracts Power:Forwards Futures NGLs – Forwards/Swaps Refined Products – Futures Crude – Forwards/Swaps Total commodity derivatives Other non-current assets Total assets$ $ $ Liabilities:Interest rate derivatives$()$ $()Commodity derivatives:Natural Gas:Basis Swaps IFERC/NYMEX()() Swing Swaps IFERC()() Fixed Swaps/Futures()() Options – Puts()() Power:Forwards()() Futures()() NGL/Refined Products Option - Puts()() NGL/Refined Products Option - Calls()() NGLs – Forwards/Swaps()() Refined Products – Futures()() Crude – Forwards/Swaps()() Total commodity derivatives()() Total liabilities$()$()$()

The aggregate estimated fair value and carrying amount of our consolidated debt obligations as of September 30, 2024 were $ billion and $ billion, respectively. As of December 31, 2023, the aggregate fair value and carrying amount of our consolidated debt obligations were $ billion and $ 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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$ $ $ Less: Net income attributable to noncontrolling interests Less: Net income attributable to redeemable noncontrolling interests Net income, net of noncontrolling interests Less: General Partner’s interest in net income Less: Preferred Unitholders’ interest in net income Less: Loss on redemption of preferred units Common Unitholders’ interest in net income$ $ $ $ Basic Income per Common Unit:Weighted average common units Basic income per common unit$ $ $ $ Diluted Income per Common Unit:Common Unitholders’ interest in net income$ $ $ $

Dilutive effect of equity-based compensation of subsidiaries (1)

Diluted income attributable to Common Unitholders$ $ $ $ Weighted average common units

Dilutive effect of unvested restricted unit awards (1)

Weighted average common units, assuming dilutive effect of unvested restricted unit awards Diluted income per common unit$ $ $ $

(1)

billion aggregate principal amount of % senior notes due January 2024, $ million aggregate principal amount of % senior notes due February 2024 and $ million aggregate principal amount of % senior notes due February 2024 using proceeds from its January 2024 notes issuance described below.

During the second quarter of 2024, the Partnership redeemed its $ million aggregate principal amount of % senior notes due April 2024, $ million aggregate principal amount of % senior notes due April 2024, $ million aggregate principal amount of % senior notes due April 2029 and $ million aggregate principal amount of % senior notes due May 2024 using cash on hand and proceeds from its Five-Year Credit Facility (defined below).

Bakken Project Debt Redemption

In April 2024, the Bakken Pipeline entities redeemed $ billion aggregate principal amount of % senior notes due April 2024 using proceeds from member contributions, which included $ million reflected as capital contributions from noncontrolling interests recorded in the Partnership’s consolidated financial statements.

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billion aggregate principal amount of % senior notes due 2034, $ billion aggregate principal amount of % senior notes due 2054 and $ million aggregate principal amount of % fixed-to-fixed reset rate junior subordinated notes due 2054. The Partnership used the net proceeds to refinance existing indebtedness, including borrowings under its Five-Year Credit Facility, redeem its outstanding Series C Preferred Units, Series D Preferred Units and Series E Preferred Units and for general partnership purposes.

Energy Transfer June 2024 Notes Issuance

In June 2024, the Partnership issued $ billion aggregate principal amount of % senior notes due 2029, $ billion aggregate principal amount of % senior notes due 2034, $ billion aggregate principal amount of % senior notes due 2054 and $ million aggregate principal amount of % fixed-to-fixed reset rate junior subordinated notes due 2054. The Partnership used part of the net proceeds to redeem its outstanding Series A Preferred Units. It also used the net proceeds to fund a portion of its previously announced acquisition of WTG Midstream, refinance existing indebtedness, including borrowings under its Five-Year Credit Facility, and for general partnership purposes.

Sunoco LP April 2024 Notes Issuance

On April 30, 2024, Sunoco LP issued $ million of % senior notes due 2029 and $ million of % senior notes due 2032 in a private offering. Sunoco LP used the net proceeds from the offering to repay certain outstanding indebtedness of NuStar in connection with the merger between Sunoco LP and NuStar, to fund the redemption of NuStar's preferred units in connection with the merger and to pay offering fees and expenses.

NuStar Subordinated Note Redemption and Credit Facility Termination

During the second quarter of 2024, subsequent to the closing of the NuStar acquisition, Sunoco LP redeemed NuStar's subordinated notes totaling $ million and repaid and terminated NuStar's credit facility totaling $ million.

USAC March 2024 Notes Issuance

In March 2024, USAC issued $ billion aggregate principal amount of % senior notes due 2029. The net proceeds from this issuance were used to repay a portion of existing borrowings under USAC’s revolving credit facility, to redeem its $ million aggregate principal amount of % senior notes due 2026, which constituted a legal defeasance under GAAP (the “Defeasance”), and for general partnership purposes.

The Defeasance required a cash outlay in the net amount of $ million, which was used to purchase U.S. government securities. These securities generated sufficient cash upon maturity to fund interest payments on the senior notes due 2026 occurring between the effective date of the Defeasance through April 4, 2024, when the senior notes due 2026 were redeemed at par, as well as fund the redemption of the senior notes due 2026 in full. As a result of the Defeasance, USAC recognized a loss on early extinguishment of debt of $ million for the three months ended March 31, 2024.

Current Maturities of Long-Term Debt

As of September 30, 2024, current maturities of long-term debt reflected on the Partnership’s consolidated balance sheet included $ million aggregate principal amount of Transwestern’s % senior notes due December 2024 and Sunoco LP’s $ million aggregate principal amount of Series 2011 GoZone Bonds with a mandatory purchase date of June 1, 2025.

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 $ billion and matures in April 2027. The Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $ billion under certain conditions.

As of September 30, 2024, the Five-Year Credit Facility had $ billion of outstanding borrowings, $ billion of which consisted of commercial paper. The amount available for future borrowings was $ billion, after accounting for outstanding letters of credit in the amount of $ million. The weighted average interest rate on the total amount outstanding as of September 30, 2024 was %.

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million of outstanding borrowings and $ million in standby letters of credit and matures in May 2029 (as amended in May 2024). The amount available for future borrowings at September 30, 2024 was $ billion. The weighted average interest rate on the total amount outstanding as of September 30, 2024 was %.

Upon the closing of the NuStar acquisition, the commitments under NuStar’s receivables financing agreement were reduced to zero during a suspension period, for which the period end has not been determined. As of September 30, 2024, this facility had outstanding borrowings.

USAC Credit Facility

As of September 30, 2024, USAC’s credit facility, which matures in December 2026, had $ million of outstanding borrowings and $ million outstanding letters of credit. As of September 30, 2024, USAC’s credit facility had $ million of remaining unused availability of which, due to restrictions related to compliance with the applicable financial covenants, $ million was available to be drawn. The weighted average interest rate on the total amount outstanding as of September 30, 2024 was %.

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 September 30, 2024. For the quarter ended September 30, 2024, our leverage ratio, as calculated pursuant to the covenant related to our Five-Year Credit Facility, was x.

million and $ million, respectively, related to the USAC Series A preferred units; $ million and $ million, respectively, related to Crestwood Niobrara LLC preferred units; and $ million and $ 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.

USAC Preferred Unit Conversions

On January 12, 2024, the holders of USAC preferred units elected to convert preferred units into common units. These preferred units were converted into common units and, for USAC’s fourth-quarter 2023 distribution, the holders received the common unit distribution of $ on the common units in lieu of the preferred unit distribution of $ on the converted preferred units.

On April 1, 2024, the holders of USAC preferred units elected to convert preferred units into common units. These preferred units were converted into common units and, for USAC’s first-quarter 2024 distribution, the holders received the common unit distribution of $ on the common units in lieu of the preferred unit distribution of $ on the converted preferred units.

Niobrara Preferred Unit Redemption

On February 23, 2024, the Partnership paid approximately $ million in cash to redeem a portion of the outstanding Crestwood Niobrara LLC preferred units.

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Common units issued under the distribution reinvestment plan Common units vested under equity incentive plans and other Common units issued in connection with acquisition of WTG Midstream Number of common units at September 30, 2024

Energy Transfer Repurchase Program

During the nine months ended September 30, 2024, Energy Transfer did not repurchase any of its common units under its current buyback program. As of September 30, 2024, $ million remained available to repurchase under the current program.

Energy Transfer Distribution Reinvestment Program

During the nine months ended September 30, 2024, distributions of $ million were reinvested under the distribution reinvestment program. As of September 30, 2024, a total of million Energy Transfer common units remained available to be issued under currently effective registration statements in connection with the distribution reinvestment program.

Cash Distributions on Energy Transfer Common Units

March 31, 2024May 13, 2024May 20, 2024 June 30, 2024August 9, 2024August 19, 2024 September 30, 2024November 8, 2024November 19, 2024

Energy Transfer Preferred Units

As of September 30, 2024, Energy Transfer’s outstanding preferred units included Series B Preferred Units, Series F Preferred Units, Series G Preferred Units, Series H Preferred Units and Series I Preferred Units. In addition, as of December 31, 2023, Energy Transfer’s outstanding preferred units also included the Series A Preferred Units, Series C Preferred Units, Series D Preferred Units and Series E Preferred Units, all of which were redeemed in 2024.

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$ $ $ $ $ $ $ $ $ Distributions to partners()()()()() ()()Redemption of preferred units ()() ()Other, net Net income Balance, March 31, 2024 Distributions to partners() ()()()()()()Redemption of preferred units() () ()Other, net Net income Balance, June 30, 2024 Distributions to partners () ()()Net income Balance, September 30, 2024$ $ $ $ $ $ $ $ $ $

Preferred Unitholders

Series A

Series B

Series C

Series D

Series E

Series F

Series G

Series H

Total

Balance, December 31, 2022

Distributions to partners

()

Net income

Balance, March 31, 2023

Distributions to partners

()

Net income

Balance, June 30, 2023

Distributions to partners

()

(1)

(2)

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March 31, 2024May 13, 2024May 20, 2024 June 30, 2024August 9, 2024August 19, 2024 September 30, 2024November 8, 2024November 19, 2024

USAC Cash Distributions

March 31, 2024April 22, 2024May 3, 2024 June 30, 2024July 22, 2024August 2, 2024 September 30, 2024October 21, 2024November 1, 2024

Accumulated Other Comprehensive Income

$ Foreign currency translation adjustment()()Actuarial gains related to pensions and other postretirement benefits Investments in unconsolidated affiliates, net Total AOCI included in partners’ capital, net of tax$ $

10.

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

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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

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$ $ $

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

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million and $ 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 $ million.

The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts or our estimates of reasonably possible losses prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.

The following sections include descriptions of certain matters that could impact the Partnership’s financial position, results of operations and/or cash flows in future periods. The following sections also include updates to certain matters that have previously been disclosed, even if those matters are not anticipated to have a potentially significant impact on future periods. In addition to the matters disclosed in the following sections, the Partnership is also involved in multiple other matters that could impact future periods, including other lawsuits and arbitration related to the Partnership’s commercial agreements. With respect to such matters, contingencies that met both the probable and reasonably estimable criteria have been included in the accruals disclosed above, and the range of additional losses disclosed above also reflects any relevant amounts for such matters.

Dakota Access Pipeline

On July 27, 2016, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the 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

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cases: one case initiated by the State of Maryland and one by the Commonwealth of Pennsylvania. The actions brought also named as defendants ETO, ETP Holdco Corporation and Sunoco Partners Marketing & Terminals L.P., now known as Energy Transfer Marketing & Terminals L.P. ETP Holdco Corporation and Energy Transfer Marketing & Terminals L.P. are wholly owned subsidiaries of Energy Transfer.

It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.

Rover – State of Ohio

On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and other defendants (collectively, the “Defendants”) seeking to recover approximately $ 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

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million for late payment interest for identified and unidentified royalty owners and interest-on-interest. This amount was later amended to $ million to account for interest accrued from trial (the “Order”). Judge Gibney also awarded punitive damages in the amount of $ 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.

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 $ 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.

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% 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 $ 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 $ million in actual damages and $ million in punitive damages. ETMT has appealed the entirety of the judgment to the Tenth Circuit. Oral argument will take place at the Tenth Circuit on November 20, 2024.

Energy Transfer LP and ETC Texas Pipeline, Ltd. v. Culberson Midstream LLC, et al.

On April 8, 2022, Energy Transfer and ETC Texas Pipeline, Ltd. (“ETC,” and together with Energy Transfer, “Plaintiffs”) filed suit against Culberson Midstream LLC (“Culberson”), Culberson Midstream Equity, LLC (“Culberson Equity”), and Moontower Resources Gathering, LLC (“Moontower”). On October 1, 2018, ETC and Culberson entered into a Gas Gathering and Processing Agreement (the “Bypass GGPA”) under which Culberson was to gather gas from its dedicated acreage and deliver all committed gas exclusively to ETC. In connection with the Bypass GGPA, on October 18, 2018, Energy Transfer and Culberson Equity also entered into an Option Agreement. Under the Option Agreement, Culberson Equity and Moontower had the right (but not the obligation) to require Energy Transfer to purchase their respective interests in Culberson by way of a put option. Notably, the Option Agreement is only enforceable so long as the parties comply with the Bypass GGPA. In late March 2022, Culberson Equity and Moontower submitted a put notice to Energy Transfer seeking to require Energy Transfer to purchase their respective interests in Culberson for approximately $ million. On April 8, 2022, Plaintiffs filed suit against Culberson, Culberson Equity and Moontower asserting claims for declaratory judgment and breach of contract, contending that they materially breached the Bypass GGPA by sending some committed gas to third parties and also by failing to send any gas to Plaintiffs since March 2020, and thus that Culberson Equity’s and Moontower’s put notice is void. Culberson, Culberson Equity, and Moontower have answered the lawsuit. Additionally, Culberson filed a counterclaim against ETC for breach of the Bypass GGPA, seeking the recovery of damages and attorneys’ fees. Culberson Equity and Moontower also filed a counterclaim against Energy Transfer for (1) breach of the Option Agreement, and (2) a declaratory judgment concerning Energy Transfer’s alleged obligation to purchase the Culberson interests. The lawsuit is pending in the 193rd Judicial District Court (“the Court”) in Dallas County, Texas. On April 27, 2022, Culberson filed an application for a temporary restraining order, temporary injunction, and permanent injunction, and Culberson Equity and Moontower joined in that request. The Court held a hearing on the application on April 28 and denied the injunction. In early May, Culberson filed a motion to enforce the appraisal process and confirm the validity of their put price calculation, to which Plaintiffs objected. On July 11, 2022, the Court held a hearing on the motion, and on July 19, 2022, the Court ordered the parties to engage in an appraisal process regarding the put price. An independent appraiser was appointed and issued his decision on October 15, 2022, concluding that the put price totals $ million. Plaintiffs have consistently reiterated their objection to the appraisal process and conclusion.

On October 6, 2022, Culberson, Culberson Equity and Moontower filed a motion for summary judgment, but the Court postponed considering it until after further document discovery and depositions. On December 7, 2022, Plaintiffs amended their petition to add Moontower Resources Operating, LLC and Moontower Resources WI, LLC as Defendants, and to assert a claim against all Defendants for fraudulent inducement.

Defendants refiled updated motions for summary judgment on May 5, 2023, seeking summary judgment on: (1) Plaintiffs’ breach of contract and declaratory judgment claims on a no-evidence basis; (2) Plaintiffs’ fraud and alter ego claims on a no-evidence basis; and (3) Plaintiffs’ fraud claim on a traditional basis. Plaintiffs responded on June 6, 2023. Defendants submitted their replies in support of summary judgment on June 12, 2023.

On June 5, 2023, counsel for Defendants informed the Court via a letter that Defendants were continuing the submission date of the no-evidence motion regarding Plaintiffs’ breach of contract and declaratory judgment claims, noting that such submission would be rescheduled along with a traditional summary judgment motion regarding the same subject matter. To that end, on July 17, 2023, Defendant Culberson Midstream, LLC filed a Traditional Motion for Summary Judgment on Plaintiffs’ Breach of Contract and Declaratory Judgment Claims, while Defendants Culberson Midstream Equity, LLC and Moontower Resources Gathering filed a Motion for Partial Summary Judgment Regarding the Breach of the Option Agreement. Further, on July 25, 2023, Defendants filed a Traditional and No-Evidence Motion for Summary Judgment Regarding Damages and Recission. On July 28, 2023, in turn, Plaintiff ETC Texas Pipeline, Ltd. filed a Traditional Motion for Partial Summary Judgment on Breach of Contract and Declaratory Judgment.

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

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million, a pre-judgment interest award of approximately $ million and attorney fees and other costs of approximately $ 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 $ 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 and an opinion is expected in early 2025. Crestwood is unable to predict the ultimate outcome on the appeal related to this matter.

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, and the parties are currently awaiting the Judge’s ruling on the motions.

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, along with imputed underpayment computations. Based on discussions with the IRS, USAC has estimated a potential range of loss up to $ million, including interest. Once a final partnership imputed underpayment, if any, is determined, USAC’s general partner may either elect to pay the imputed underpayment (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.

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million, including penalties and interest.

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 September 30, 2024, the Partnership had been named as a PRP at approximately 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.

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$ Non-current Total environmental liabilities$ $

During the nine months ended September 30, 2024 and 2023, the Partnership recorded $ million and $ 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, 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.

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Additions Revenue recognized()Balance, September 30, 2024$ Balance, December 31, 2022$ Additions Revenue recognized()Balance, September 30, 2023$ $ Accounts receivable from contracts with customers Contract liabilities

billion. The Partnership expects to recognize this amount as revenue within the time bands illustrated in the following table:

Years Ending December 31,

(remainder)

Thereafter

Total

Revenue expected to be recognized on contracts with customers existing as of September 30, 2024

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12.

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2024-2026 2024-2026Basis Swaps IFERC/NYMEX 2024-2027()2024-2025Swing Swaps 2024-2025()2024-2025Options – Puts 2024 2024Options – Calls 2024 2024Forward Physical Contracts 2024-2026()2024-2026Power (Megawatt):Forwards 2024-2029 2024-2029Futures 2024-2026()2024Options – Puts 2024-2025 2024Options – Calls()2024-2025 —Crude (MBbls):Forwards/Swaps()2024-2026()2024-2025Options – Puts —()2024Options – Calls —()2024NGL/Refined Products (MBbls):Forward/Swaps()2024-2027()2024-2027Options – Puts()2024-2026 2024-2026Options – Calls()2024-2026()2024-2026Futures()2024-2026()2024-2025Fair Value Hedging DerivativesNatural Gas (BBtu):Basis Swaps IFERC/NYMEX()2024-2025()2024Fixed Swaps/Futures()2024-2025()2024Hedged Item – Inventory 2024-2025 2024$ $

(1)

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Derivative Summary

$ $()$() ()()

Derivatives not designated as hedging instruments:

Commodity derivatives – margin deposits ()()

Commodity derivatives

()()

Interest rate derivatives

() ()()

Total derivatives

$ $ $()$()

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$ $ $()

Derivatives in offsetting agreements:

OTC contracts

Derivative assets (liabilities)

()()

Broker cleared derivative contracts

Other current assets (liabilities)

()()

Total gross derivatives

()()

Offsetting agreements:

Counterparty netting

Derivative assets (liabilities)

()()

Counterparty netting

Other current assets (liabilities)

()()

Total net derivatives

$ $ $()$() $()$ $()

Interest rate derivatives

Gain on interest rate derivatives()

Total

$ $()$ $()

13.

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$ $ $ Intersegment revenues Interstate transportation and storage:Revenues from external customers Intersegment revenues Midstream:Revenues from external customers Intersegment revenues NGL and refined products transportation and services:Revenues from external customers Intersegment revenues Crude oil transportation and services:Revenues from external customers Intersegment revenues Investment in Sunoco LP:Revenues from external customers Intersegment revenues Investment in USAC:Revenues from external customers Intersegment revenues All other:Revenues from external customers Intersegment revenues Eliminations()()()()Total revenues$ $ $ $

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$ $ $ Interstate transportation and storage Midstream NGL and refined products transportation and services Crude oil transportation and services Investment in Sunoco LP Investment in USAC All other() Adjusted EBITDA (consolidated)$ $ $ $


	Three Months Ended September 30,		Nine Months Ended September 30,
	2024	2023	2024	2023
Reconciliation of net income to Adjusted EBITDA:
Net income	$	$	$	$
Depreciation, depletion and amortization
Interest expense, net of interest capitalized
Income tax expense
Impairment losses
(Gain) loss on interest rate derivatives		()	()	()
Non-cash compensation expense
Unrealized (gain) loss on commodity risk management activities	()
Inventory valuation adjustments (Sunoco LP)		()		()
Loss on extinguishment of debt
Adjusted EBITDA related to unconsolidated affiliates
Equity in earnings of unconsolidated affiliates	()	()	()	()
Non-operating litigation-related loss
Gain on sale of West Texas assets (Sunoco LP)			()
Other, net
Adjusted EBITDA (consolidated)	$	$	$	$

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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, 2023 filed with the SEC on February 16, 2024. 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, 2023 filed with the SEC on February 16, 2024 and in “Part II – Item 1A. Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2024 filed with the SEC on May 9, 2024. 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

Energy Transfer’s Acquisition

WTG Midstream

On July 15, 2024, Energy Transfer completed the previously announced acquisition of 100% of the membership interest in WTG Midstream Holdings LLC (“WTG Midstream”). Consideration for the transaction was comprised of $2.28 billion in cash and approximately 50.8 million newly issued Energy Transfer common units, which had a fair value of approximately $833 million. Energy Transfer granted customary registration rights to the sellers and certain of their affiliates and designees in connection with the transaction.

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

Sunoco LP’s Acquisitions

NuStar

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

Zenith European Terminals

Other Acquisition

On August 30, 2024, Sunoco LP acquired a terminal in Portland, Maine for approximately $24 million, including working capital.

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Sunoco LP’s Divestiture

West Texas Sale

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

Joint Venture Transaction

Permian Joint Venture

The joint venture operates more than 5,000 miles of crude oil and water gathering pipelines with crude oil storage capacity in excess of 11 million barrels.

Energy Transfer holds a 67.5% interest with Sunoco LP holding the remaining 32.5% interest in the joint venture.

Quarterly Cash Distribution

In October 2024, Energy Transfer announced a quarterly distribution of $0.3225 per unit ($1.29 annualized) on Energy Transfer common units for the quarter ended September 30, 2024.

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

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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 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, 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 United States Court of Appeals for the District of Columbia for review of the September 9, 2024, July 29, 2024, and May 28, 2024 orders.

Pipeline Certification

The FERC issued a Notice of Inquiry on April 19, 2018 (“Pipeline Certification NOI”), 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. 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 and (2) a Policy Statement on the Consideration of Greenhouse Gas Emissions in Natural Gas Infrastructure Project Reviews (“2022 Policy Statements”), to be effective that same day. On March 24, 2022, the FERC issued an order designating the 2022 Policy Statements as draft policy statements, and requested further comments. The FERC will not apply the now draft 2022 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 Policy Statements were due on April 25, 2022, and reply comments were due on May 25, 2022. We are unable to predict what, if any, changes may be proposed as a result of the 2022 Policy Statements that might affect our natural gas pipeline or LNG facility projects, or when such new policies, if any, might become

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effective. We do not expect that any change in these policy statements 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 have appealed the January 20 and May 6 orders. Such appeals remain pending at the D.C. Circuit.

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, either by nature of judicial stays of the legal predicate to the Plan or by judicial stay of the Plan itself by the U.S. Supreme Court. 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

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

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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.

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.

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 September 30,						Nine Months Ended September 30,
	2024		2023		Change		2024		2023		Change
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	329	$	244	$	85	$	1,095	$	869	$	226
Interstate transportation and storage	460		491		(31)		1,335		1,468		(133)
Midstream	816		631		185		2,205		1,851		354
NGL and refined products transportation and services	1,012		1,076		(64)		3,071		2,852		219
Crude oil transportation and services	768		706		62		2,417		1,906		511
Investment in Sunoco LP	456		257		199		1,018		728		290
Investment in USAC	146		130		16		429		373		56
All other	(28)		6		(34)		29		49		(20)
Adjusted EBITDA (consolidated)	$	3,959	$	3,541	$	418	$	11,599	$	10,096	$	1,503

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2024		2023		Change		2024		2023		Change
Reconciliation of net income to Adjusted EBITDA:
Net income	$	1,434	$	1,047	$	387	$	5,118	$	3,727	$	1,391
Depreciation, depletion and amortization	1,324		1,107		217		3,791		3,227		564
Interest expense, net of interest capitalized	828		632		196		2,318		1,892		426
Income tax expense	89		77		12		405		256		149
Impairment losses	—		1		(1)		50		12		38
(Gain) loss on interest rate derivatives	6		(32)		38		(6)		(47)		41
Non-cash compensation expense	37		35		2		113		99		14
Unrealized (gain) loss on commodity risk management activities	(53)		107		(160)		50		182		(132)
Inventory valuation adjustments (Sunoco LP)	197		(141)		338		99		(113)		212
Loss on extinguishment of debt	—		—		—		11		—		11
Adjusted EBITDA related to unconsolidated affiliates	181		182		(1)		522		514		8
Equity in earnings of unconsolidated affiliates	(102)		(103)		1		(285)		(286)		1
Non-operating litigation-related loss	—		625		(625)		—		625		(625)
Gain on sale of West Texas assets (Sunoco LP)	—		—		—		(598)		—		(598)
Other, net	18		4		14		11		8		3
Adjusted EBITDA (consolidated)	$	3,959	$	3,541	$	418	$	11,599	$	10,096	$	1,503

Net Income. For the three months ended September 30, 2024 compared to the same period last year, net income increased $387 million, or approximately 37%, primarily due to the recognition of a $625 million non-operating litigation-related loss in the prior period. This impact was partially offset by an increase in interest expense, as well as changes in Segment Adjusted EBITDA, as discussed below.

For the nine months ended September 30, 2024 compared to the same period last year, net income increased $1.39 billion, or approximately 37%, primarily due to the recognition of a $598 million gain on Sunoco LP’s sale of its West Texas assets in the current period, as well as the recognition of a $625 million non-operating litigation-related loss in the prior period. The change in net income also reflected higher segment margin from multiple segments, partially offset by increases in operating expenses, selling, general and administrative expenses, depreciation, depletion and amortization, impairment losses, interest expense and income tax expense; these changes are discussed in more detail below and in “Segment Operating Results.”

Adjusted EBITDA (consolidated). For the three months ended September 30, 2024 compared to the same period last year, Adjusted EBITDA increased primarily due to the impacts of recently acquired assets, as well as higher volumes in our midstream segment and higher pipeline optimization in our intrastate transportation and storage segment.

For the nine months ended September 30, 2024 compared to the same period last year, the increase in Adjusted EBITDA reflected higher earnings from multiple segments, primarily due to the impacts of recently acquired assets.

Additional discussion on the changes impacting net income and Adjusted EBITDA for the three and nine months ended September 30, 2024 compared to the same periods last year is available below and in “Segment Operating Results.”

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased for the three and nine months ended September 30, 2024 compared to the same periods 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 and nine months ended September 30, 2024 compared to the same periods last year primarily due to higher aggregate debt balances as a result of recent acquisitions and an increase in Sunoco LP’s debt, including the impact of the NuStar acquisition, as well as higher interest rates on floating rate and recently refinanced debt.

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Income Tax Expense. For the three and nine months ended September 30, 2024 compared to the same periods last year, income tax expense increased due to the taxable gain recognized by a corporate subsidiary of Sunoco LP on its sale of West Texas assets.

Impairment Losses. For the nine months ended September 30, 2024, impairment losses were related to Sunoco LP’s termination of a lease in June 2024. For the three months ended September 30, 2023, impairment losses included a total of $1 million recognized by USAC related to its compression equipment. For the nine months ended September 30, 2023, impairment losses included a total of $12 million recognized by USAC related to its compression equipment.

(Gain) loss on Interest Rate Derivatives. Gains and losses on interest rate derivatives resulted from changes in forward interest rates, which caused our forward-starting swaps to change in value.

Unrealized (Gain) Loss on Commodity Risk Management Activities. The unrealized gains and 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 gains and losses within each segment are 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 last-in, first-out 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 September 30, 2024 and 2023, the Partnership’s cost of products sold included unfavorable inventory valuation adjustments of $197 million and favorable inventory adjustments of $141 million, respectively, related to Sunoco LP’s LIFO inventory. For the nine months ended September 30, 2024 and 2023, the Partnership’s cost of products sold included unfavorable inventory adjustments of $99 million and favorable inventory adjustments of $113 million, respectively, related to Sunoco LP’s LIFO inventory.

Loss on Extinguishment of Debt. For the nine months ended September 30, 2024, the loss on extinguishment of debt included a $4 million loss on Energy Transfer’s redemption of its $450 million aggregate principal amount of 8.00% senior notes due April 2029, a $2 million loss recognized by Sunoco LP and a $5 million loss related to USAC’s redemption of its $725 million aggregate principal amount of 6.875% senior notes due 2026.

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.”

Non-Operating Litigation-Related Loss. Non-operating litigation-related loss recognized in the three and nine months ended September 30, 2023 represents the loss associated with The Williams Companies, Inc. litigation.

Gain on sale of West Texas Assets. The gain on sale of West Texas assets was related to the gain recognized by Sunoco LP on its sale of convenience stores to 7-Eleven Inc.

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 September 30,						Nine Months Ended September 30,
	2024		2023		Change		2024		2023		Change
Equity in earnings of unconsolidated affiliates:
Citrus	$	41	$	39	$	2	$	105	$	110	$	(5)
MEP	16		21		(5)		47		68		(21)
White Cliffs	4		2		2		14		5		9
Explorer	11		10		1		26		27		(1)
SESH	12		8		4		32		22		10
Other	18		23		(5)		61		54		7
Total equity in earnings of unconsolidated affiliates	$	102	$	103	$	(1)	$	285	$	286	$	(1)

Adjusted EBITDA related to unconsolidated affiliates(1):
Citrus	$	89	$	86	$	3	$	252	$	250	$	2
MEP	25		30		(5)		73		94		(21)
White Cliffs	9		7		2		28		19		9
Explorer	17		16		1		41		42		(1)
SESH	13		12		1		39		32		7
Other	28		31		(3)		89		77		12
Total Adjusted EBITDA related to unconsolidated affiliates	$	181	$	182	$	(1)	$	522	$	514	$	8

Distributions received from unconsolidated affiliates:
Citrus	$	—	$	53	$	(53)	$	94	$	123	$	(29)
MEP	16		25		(9)		63		89		(26)
White Cliffs	9		7		2		30		18		12
Explorer	11		10		1		29		29		—
SESH	15		8		7		47		25		22
Other	20		19		1		60		47		13
Total distributions received from unconsolidated affiliates	$	71	$	122	$	(51)	$	323	$	331	$	(8)

(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.

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•Unrealized gains or losses 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 losses are added back and the unrealized gains are subtracted to calculate the segment measure.

•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 September 30,						Nine Months Ended September 30,
	2024		2023		Change		2024		2023		Change
Natural gas transported (BBtu/d)	13,214		15,123		(1,909)		13,510		15,011		(1,501)
Withdrawals from storage natural gas inventory (BBtu)	2,325		—		2,325		10,555		8,400		2,155
Revenues	$	678	$	973	$	(295)	$	2,233	$	3,070	$	(837)
Cost of products sold	272		664		(392)		964		2,119		(1,155)
Segment margin	406		309		97		1,269		951		318
Unrealized (gains) losses on commodity risk management activities	(11)		14		(25)		24		144		(120)
Operating expenses, excluding non-cash compensation expense	(61)		(71)		10		(180)		(207)		27
Selling, general and administrative expenses, excluding non-cash compensation expense	(11)		(13)		2		(37)		(38)		1
Adjusted EBITDA related to unconsolidated affiliates	6		6		—		18		19		(1)
Other	—		(1)		1		1		—		1
Segment Adjusted EBITDA	$	329	$	244	$	85	$	1,095	$	869	$	226

Volumes. For the three and nine months ended September 30, 2024 compared to the same periods last year, transported volumes of gas on our Texas intrastate pipelines decreased primarily due to less third-party transportation and decreased 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 September 30,						Nine Months Ended September 30,
	2024		2023		Change		2024		2023		Change
Transportation fees	$	207	$	211	$	(4)	$	651	$	636	$	15
Natural gas sales and other (excluding unrealized gains and losses)	165		65		100		563		311		252
Retained fuel (excluding unrealized gains and losses)	8		19		(11)		25		49		(24)
Storage margin (excluding unrealized gains and losses and fair value inventory adjustments)	15		28		(13)		54		99		(45)
Unrealized gains (losses) on commodity risk management activities and fair value inventory adjustments	11		(14)		25		(24)		(144)		120
Total segment margin	$	406	$	309	$	97	$	1,269	$	951	$	318

Segment Adjusted EBITDA. For the three months ended September 30, 2024 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impact of the following:

•an increase of $100 million in realized natural gas sales and other primarily due to higher pipeline optimization from physical sales; and

•a decrease of $10 million in operating expenses primarily due to a change related to fuel consumption that is offset in cost of products sold in 2024; partially offset by

•a decrease of $13 million in storage margin primarily due to the timing of financial gains;

•a decrease of $11 million in retained fuel margin primarily due to a change related to fuel consumption that is offset in operating expenses in 2024; and

•a decrease of $4 million in transportation fees primarily due to a contract expiration on our Louisiana system.

Segment Adjusted EBITDA. For the nine months ended September 30, 2024 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impact of the following:

•an increase of $252 million in realized natural gas sales and other primarily due to higher pipeline optimization from physical sales and settled derivatives;

•a decrease of $27 million in operating expenses primarily due to a change related to fuel consumption that is offset in cost of products sold in 2024 and lower compressor rental expense; and

•an increase of $15 million in transportation fees primarily due to the recovery of certain fees earned in a prior period on our Texas system; partially offset by

•a decrease of $45 million in storage margin primarily due to lower storage optimization from settled derivatives; and

•a decrease of $24 million in retained fuel margin primarily due to a change related to fuel consumption that is offset in operating expenses in 2024.

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Interstate Transportation and Storage


	Three Months Ended September 30,						Nine Months Ended September 30,
	2024		2023		Change		2024		2023		Change
Natural gas transported (BBtu/d)	16,616		16,237		379		16,826		16,424		402
Natural gas sold (BBtu/d)	39		40		(1)		27		27		—
Revenues	$	575	$	571	$	4	$	1,696	$	1,755	$	(59)
Cost of products sold	3		2		1		6		5		1
Segment margin	572		569		3		1,690		1,750		(60)
Operating expenses, excluding non-cash compensation, amortization and accretion expenses	(203)		(178)		(25)		(616)		(567)		(49)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses	(34)		(30)		(4)		(99)		(89)		(10)
Adjusted EBITDA related to unconsolidated affiliates	125		129		(4)		361		374		(13)

Other	—		1		(1)		(1)		—		(1)
Segment Adjusted EBITDA	$	460	$	491	$	(31)	$	1,335	$	1,468	$	(133)

Volumes. For the three and nine months ended September 30, 2024 compared to the same periods 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 September 30, 2024 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment decreased due to the net impact of the following:

•an increase of $25 million in operating expenses primarily due to a $10 million one-time benefit recorded in the third quarter of 2023 which reduced operating expense, a $6 million increase in maintenance project costs, a $3 million increase from the revaluation of system gas and an aggregate increase of $5 million in employee costs and office expense;

•an increase of $4 million in selling, general and administrative expenses primarily due to higher professional fees and higher overhead costs; and

•a decrease of $4 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to lower revenue on our Midcontinent Express Pipeline joint venture; partially offset by

•an increase of $3 million in segment margin primarily due to a $23 million increase resulting from a rate adjustment in 2023 related to the conclusion of a rate case on our Panhandle system, partially offset by an $11 million decrease due to lower interruptible utilization, a $7 million decrease in transportation revenue from several of our interstate pipeline systems due to lower contracted volumes at lower rates and a $5 million decrease due to lower market prices on the sale of operational gas.

Segment Adjusted EBITDA. For the nine months ended September 30, 2024 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment decreased due to the net impact of the following:

•a decrease of $60 million in segment margin primarily due to a $36 million decrease due to lower market prices on the sale of operational gas, a $16 million decrease in interruptible utilization and a $9 million decrease in parking revenue;

•an increase of $49 million in operating expenses primarily due to a $32 million increase in maintenance project costs, a $12 million increase in employee related costs, a $6 million increase from the revaluation of system gas and an aggregate $8 million increase in transportation expense, outside services and office expense. These increases were partially offset by an aggregate $9 million decrease in ad valorem taxes, electricity and storage expenses;

•an increase of $10 million in selling, general and administrative expenses primarily due to higher professional fees, overhead and employee related costs; and

•a decrease of $13 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to lower revenue on our Midcontinent Express Pipeline joint venture.

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Midstream


	Three Months Ended September 30,						Nine Months Ended September 30,
	2024		2023		Change		2024		2023		Change
Gathered volumes (BBtu/d)	21,027		19,825		1,202		20,132		19,808		324
NGLs produced (MBbls/d)	1,094		869		225		980		848		132
Equity NGLs (MBbls/d)	65		42		23		58		41		17
Revenues	$	2,758	$	2,777	$	(19)	$	8,039	$	7,999	$	40
Cost of products sold	1,551		1,808		(257)		4,727		5,124		(397)
Segment margin	1,207		969		238		3,312		2,875		437

Operating expenses, excluding non-cash compensation expense	(411)		(294)		(117)		(1,055)		(890)		(165)
Selling, general and administrative expenses, excluding non-cash compensation expense	(57)		(50)		(7)		(144)		(152)		8
Adjusted EBITDA related to unconsolidated affiliates	6		5		1		18		14		4
Other	71		1		70		74		4		70
Segment Adjusted EBITDA	$	816	$	631	$	185	$	2,205	$	1,851	$	354

Volumes. For the three and nine months ended September 30, 2024 compared to the same periods last year, gathered volumes increased primarily due to recently acquired assets and higher volumes in the Permian region. NGL production increased primarily due to recently acquired assets and increased Permian plant utilization.

Segment Adjusted EBITDA. For the three months ended September 30, 2024 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 $254 million in segment margin primarily due to recently acquired assets and higher volumes in the Permian region; and

•an increase of $70 million in other income due to the recognition of proceeds from a business interruption claim; partially offset by

•an increase of $117 million in operating expenses primarily due to a $108 million increase related to recent acquisitions and assets placed in service and a $9 million increase in employee costs;

•a decrease of $16 million in segment margin due to lower natural gas prices; and

•an increase of $7 million in selling, general and administrative expenses primarily due to higher insurance expenses.

Segment Adjusted EBITDA. For the nine months ended September 30, 2024 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 $458 million in segment margin primarily due to recently acquired assets and higher volumes in the Permian region;

•an increase of $70 million in other income due to the recognition of proceeds from a business interruption claim;

•a decrease of $8 million in selling, general and administrative expenses primarily due to one-time expenses in the prior period; and

•an increase of $4 million in Adjusted EBITDA related to unconsolidated affiliates due to recently acquired assets; partially offset by

•an increase of $165 million in operating expenses primarily due to a $159 million increase related to recent acquisitions and assets placed in service and a $22 million increase in employee costs, partially offset by an $8 million decrease in environmental reserves and a $6 million decrease in compressor rental expense; and

•a decrease of $21 million in segment margin due to lower natural gas prices of $52 million, partially offset by higher NGL prices of $31 million.

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NGL and Refined Products Transportation and Services


	Three Months Ended September 30,						Nine Months Ended September 30,
	2024		2023		Change		2024		2023		Change
NGL transportation volumes (MBbls/d)	2,237		2,161		76		2,187		2,101		86
Refined products transportation volumes (MBbls/d)	574		551		23		583		535		48
NGL and refined products terminal volumes (MBbls/d)	1,505		1,475		30		1,470		1,425		45
NGL fractionation volumes (MBbls/d)	1,152		1,029		123		1,099		985		114
Revenues	$	5,853	$	5,260	$	593	$	18,174	$	15,864	$	2,310
Cost of products sold	4,527		4,034		493		14,358		12,365		1,993
Segment margin	1,326		1,226		100		3,816		3,499		317
Unrealized (gains) losses on commodity risk management activities	(64)		84		(148)		(22)		34		(56)
Operating expenses, excluding non-cash compensation expense	(243)		(235)		(8)		(703)		(667)		(36)
Selling, general and administrative expenses, excluding non-cash compensation expense	(42)		(33)		(9)		(118)		(106)		(12)
Adjusted EBITDA related to unconsolidated affiliates	35		34		1		98		92		6


Segment Adjusted EBITDA	$	1,012	$	1,076	$	(64)	$	3,071	$	2,852	$	219

Volumes. For the three and nine months ended September 30, 2024 compared to the same periods last year, NGL transportation volumes increased primarily due to higher volumes from the Permian region, on our Mariner East pipeline system and on our Gulf Coast export pipelines.

The increase in transportation volumes and the commissioning of our eighth fractionator in August 2023 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 September 30,						Nine Months Ended September 30,
	2024		2023		Change		2024		2023		Change
Transportation margin	$	647	$	639	$	8	$	1,916	$	1,778	$	138
Fractionators and refinery services margin	239		251		(12)		704		647		57
Terminal services margin	260		235		25		718		664		54
Storage margin	79		78		1		233		232		1
Marketing margin	37		107		(70)		223		212		11
Unrealized gains (losses) on commodity risk management activities	64		(84)		148		22		(34)		56
Total segment margin	$	1,326	$	1,226	$	100	$	3,816	$	3,499	$	317

Segment Adjusted EBITDA. For the three months ended September 30, 2024 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:

•a decrease of $70 million in marketing margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to $100 million in gains recorded in the third quarter of 2023 from the optimization of hedged NGL and refined product inventories compared to $30 million in gains recorded for the third quarter of 2024. This decrease also included a $2 million decrease in intrasegment margin which is fully offset within our transportation margin;

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•a decrease of $12 million in fractionators and refinery services margin resulting from a $27 million increase due to higher volumes and a $2 million increase from our refinery services business, offset by a $41 million decrease in rates, primarily from our midstream segment due to lower gas prices and the restructuring of certain affiliate fractionation agreements;

•an increase of $8 million in operating expenses primarily due to a $6 million increase in employee costs, a $4 million increase in ad valorem taxes, a $4 million increase in outside services expenses and increases totaling $6 million from various other operating expenses. These increases were partially offset by an $11 million decrease in gas and power utility costs; and

•an increase of $9 million in selling, general and administrative expenses primarily due to increased costs from recently acquired assets; partially offset by

•an increase of $25 million in terminal services margin primarily due to a $15 million increase from higher export volumes loaded at our Nederland Terminal, an $8 million increase from our Marcus Hook Terminal due to higher throughput and contractual rate escalations and a $3 million increase due to higher throughput and storage at our refined product terminals; and

•an increase of $8 million in transportation margin primarily due to higher throughput and contractual rate escalations of $19 million on our Mariner East pipeline system and intrasegment charges of $7 million and $2 million which were fully offset within our fractionators and marketing margins, respectively. These increases were partially offset by decreased revenue on our Texas y-grade pipeline system, despite higher volumes, primarily due to the restructuring of certain affiliate transportation agreements.

Segment Adjusted EBITDA. For the nine months ended September 30, 2024 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impact of the following:

•an increase of $138 million in transportation margin primarily due to higher throughput and contractual rate escalations of $61 million on our Mariner East pipeline system, $30 million on our Texas y-grade pipeline system, $22 million on our refined product pipelines and $21 million on our Mariner West pipeline, as well as an $8 million increase from higher exported volumes feeding into our Nederland Terminal and intrasegment charges of $4 million and $10 million which are fully offset within our fractionation and marketing margins, respectively;

•an increase of $57 million in fractionators and refinery services margin primarily due to a $52 million increase resulting from higher throughput as our eighth fractionator was placed in service in August 2023 and an $8 million increase from our refinery services business. These increases were partially offset by a $4 million decrease in intrasegment margin which was fully offset within our transportation margin;

•an increase of $54 million in terminal services margin primarily due to a $24 million increase from higher export volumes loaded at our Nederland Terminal, a $21 million increase from our Marcus Hook Terminal due to higher throughput and contractual rate escalations and a $9 million increase from higher throughput and storage at our refined product terminals;

•an increase of $11 million in marketing margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to an increase to intrasegment margin of $10 million which is fully offset within our transportation margin; and

•an increase of $6 million in Adjusted EBITDA related to unconsolidated affiliates; partially offset by

•an increase of $36 million in operating expenses primarily due to an $18 million increase in employee costs, a $12 million increase resulting from the timing of project related expenses, a $7 million increase in outside services expenses, a $6 million increase in ad valorem taxes and increases totaling $4 million from various other operating expenses. These increases were partially offset by an $11 million decrease in gas and power utility costs; and

•an increase of $12 million in selling, general and administrative expenses primarily due to increased costs from recently acquired assets.

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Crude Oil Transportation and Services


	Three Months Ended September 30,						Nine Months Ended September 30,
	2024		2023		Change		2024		2023		Change
Crude oil transportation volumes (MBbls/d)	7,025		5,640		1,385		6,540		5,056		1,484
Crude oil terminal volumes (MBbls/d)	3,533		3,548		(15)		3,356		3,359		(3)
Revenues	$	7,309	$	7,289	$	20	$	22,319	$	19,322	$	2,997
Cost of products sold	6,297		6,392		(95)		19,200		16,858		2,342
Segment margin	1,012		897		115		3,119		2,464		655
Unrealized losses on commodity risk management activities	20		14		6		20		26		(6)
Operating expenses, excluding non-cash compensation expense	(231)		(183)		(48)		(635)		(508)		(127)
Selling, general and administrative expenses, excluding non-cash compensation expense	(39)		(29)		(10)		(111)		(90)		(21)
Adjusted EBITDA related to unconsolidated affiliates	6		6		—		22		12		10

Other	—		1		(1)		2		2		—
Segment Adjusted EBITDA	$	768	$	706	$	62	$	2,417	$	1,906	$	511

Volumes. For the three and nine months ended September 30, 2024 compared to the same periods last year, crude oil transportation volumes were higher due to continued growth on our gathering systems and contributions from recently acquired assets.

Segment Adjusted EBITDA. For the three months ended September 30, 2024 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impact of the following:

•an increase of $121 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $150 million increase from recently acquired assets and contributions from the recently formed Permian joint venture with Sunoco LP; this increase was partially offset by a $21 million decrease from our crude oil acquisition and marketing business primarily due to lower refined product prices and an $11 million decrease from existing pipeline assets; partially offset by

•an increase of $48 million in operating expenses from recently acquired and contributed assets, as well as increases in ad valorem taxes, employee costs, outside services and various volume-driven expenses; and

•an increase of $10 million in selling, general and administrative expenses primarily due to an increase of $7 million from recently acquired assets and related corporate allocations, and higher employee expenses.

Segment Adjusted EBITDA. For the nine months ended September 30, 2024 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impact of the following:

•an increase of $649 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $442 million increase from recently acquired assets and contributions from the recently formed Permian joint venture with Sunoco LP, a $169 million increase in transportation revenues from existing pipeline assets and a $32 million increase in our crude oil acquisition and marketing business from more favorable market conditions; and

•an increase of $10 million in Adjusted EBITDA related to unconsolidated affiliates due to recently acquired assets and higher volumes on our White Cliffs crude pipeline; partially offset by

•an increase of $127 million in operating expenses primarily due to a $77 million increase from recently acquired and contributed assets, a $14 million increase in outside services, a $12 million increase in employee expenses and a $9 million increase in ad valorem taxes, as well as various increases in volume-driven expenses; and

•an increase of $21 million in selling, general and administrative expenses primarily due to a $16 million increase from recently acquired assets and related corporate allocations, and higher employee expenses.

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Investment in Sunoco LP


	Three Months Ended September 30,						Nine Months Ended September 30,
	2024		2023		Change		2024		2023		Change
Revenues	$	5,751	$	6,320	$	(569)	$	17,424	$	17,427	$	(3)
Cost of products sold	5,327		5,793		(466)		15,951		16,211		(260)
Segment margin	424		527		(103)		1,473		1,216		257
Unrealized (gains) losses on commodity risk management activities	1		(1)		2		8		(11)		19
Operating expenses, excluding non-cash compensation expense	(168)		(110)		(58)		(423)		(310)		(113)
Selling, general and administrative expenses, excluding non-cash compensation expense	(52)		(28)		(24)		(216)		(83)		(133)
Adjusted EBITDA related to unconsolidated affiliates	47		2		45		53		8		45
Inventory valuation adjustments	197		(141)		338		99		(113)		212
Other	7		8		(1)		24		21		3
Segment Adjusted EBITDA	$	456	$	257	$	199	$	1,018	$	728	$	290

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

Segment Adjusted EBITDA. For the three months ended September 30, 2024 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 in segment margin (excluding unrealized gains and losses on commodity risk management activities and inventory valuation adjustments) of $237 million primarily related to the acquisitions of NuStar and Zenith European terminals; and

•a $45 million increase in Adjusted EBITDA related to unconsolidated affiliates due to the formation of the Permian joint venture; partially offset by

•a $58 million increase in operating expenses and a $24 million increase in selling, general and administrative expenses primarily related to the acquisitions of NuStar and Zenith European terminals.

Segment Adjusted EBITDA. For the nine months ended September 30, 2024 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 in segment margin (excluding unrealized gains and losses on commodity risk management activities and inventory valuation adjustments) of $488 million primarily related to the acquisitions of NuStar and Zenith European terminals; and

•a $45 million increase in Adjusted EBITDA related to unconsolidated affiliates due to the formation of the Permian joint venture; partially offset by

•a $113 million increase in operating expenses and a $133 million increase in selling, general and administrative expenses primarily related to the acquisitions of NuStar and Zenith European terminals.

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Investment in USAC


	Three Months Ended September 30,						Nine Months Ended September 30,
	2024		2023		Change		2024		2023		Change
Revenues	$	240	$	217	$	23	$	705	$	621	$	84
Cost of products sold	38		35		3		110		104		6
Segment margin	202		182		20		595		517		78

Operating expenses, excluding non-cash compensation expense	(43)		(39)		(4)		(125)		(107)		(18)
Selling, general and administrative expenses, excluding non-cash compensation expense	(13)		(13)		—		(42)		(37)		(5)


Other	—		—		—		1		—		1
Segment Adjusted EBITDA	$	146	$	130	$	16	$	429	$	373	$	56

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

Segment Adjusted EBITDA. For the three months ended September 30, 2024 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 $20 million in segment margin primarily due to higher revenue-generating horsepower as a result of increased demand for compression services, higher market-based rates on newly deployed and redeployed compression units and higher average rates on existing customer contracts; 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.

Segment Adjusted EBITDA. For the nine months ended September 30, 2024 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 $78 million in segment margin primarily due to higher revenue-generating horsepower as a result of increased demand for compression services, higher market-based rates on newly deployed and redeployed compression units and higher average rates on existing customer contracts; partially offset by

•an increase of $18 million in operating expenses primarily due to an increase in employee costs associated with increased revenue-generating horsepower; and

•an increase of $5 million in selling, general and administrative expenses primarily due to an increase in professional fees.

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All Other


	Three Months Ended September 30,						Nine Months Ended September 30,
	2024		2023		Change		2024		2023		Change
Revenues	$	379	$	444	$	(65)	$	1,140	$	1,387	$	(247)
Cost of products sold	369		457		(88)		1,107		1,354		(247)
Segment margin	10		(13)		23		33		33		—
Unrealized (gains) losses on commodity risk management activities	1		(4)		5		20		(11)		31
Operating expenses, excluding non-cash compensation expense	(20)		(8)		(12)		(28)		(18)		(10)
Selling, general and administrative expenses, excluding non-cash compensation expense	(23)		(13)		(10)		(43)		(33)		(10)
Adjusted EBITDA related to unconsolidated affiliates	2		2		—		4		3		1
Other and eliminations	2		42		(40)		43		75		(32)
Segment Adjusted EBITDA	$	(28)	$	6	$	(34)	$	29	$	49	$	(20)

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.

Segment Adjusted EBITDA. For the three months ended September 30, 2024 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 $49 million related to intersegment eliminations primarily driven by the formation of the Permian joint venture, 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; partially offset by

•an increase of $11 million in our natural gas marketing business due to higher gains from gas trading and storage positions; and

•an increase of $7 million from our compressor packaging business.

Segment Adjusted EBITDA. For the nine months ended September 30, 2024 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 $45 million related to intersegment eliminations primarily driven by the formation of the Permian joint venture, 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; partially offset by

•an increase of $29 million in our natural gas marketing business due to higher gains from gas trading and storage positions.

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.

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We currently expect capital expenditures in 2024 to be within the following ranges (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
	Low		High		Low		High
Intrastate transportation and storage	$	45	$	50	$	55	$	60
Interstate transportation and storage	160		170		190		195
Midstream	870		940		390		395
NGL and refined products transportation and services	1,215		1,290		130		135
Crude oil transportation and services	290		310		140		145
All other (including eliminations)	220		240		65		70
Total capital expenditures	$	2,800	$	3,000	$	970	$	1,000

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 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 spend approximately $120 million in maintenance capital expenditures and at least $300 million in growth capital for the full year 2024.

USAC currently plans to spend between $27 million and $30 million in maintenance capital expenditures and between $240 million and $250 million in expansion capital expenditures for the full year 2024.

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 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.

Nine months ended September 30, 2024 compared to nine months ended September 30, 2023. Cash provided by operating activities during 2024 was $8.92 billion compared to $8.26 billion for 2023, and net income was $5.12 billion for 2024 and $3.73 billion for 2023. The difference between net income and net cash provided by operating activities for the nine months ended September 30, 2024 primarily consisted of net changes in operating assets and liabilities (net of effects of acquisitions and divestitures) of $190 million and other items totaling $3.39 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 2024 and 2023 consisted primarily of depreciation, depletion and amortization of $3.79 billion and $3.23 billion, respectively, non-cash compensation expense of $113 million and $99 million, respectively, unfavorable

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inventory valuation adjustments of $99 million and favorable inventory adjustments of $113 million, respectively, and deferred income taxes of $165 million and $187 million, respectively. Net income also included equity in earnings of unconsolidated affiliates of $285 million and $286 million for 2024 and 2023, respectively, as well as a $598 million gain on Sunoco LP’s sale of its West Texas assets in 2024.

Cash provided by operating activities includes cash distributions received from unconsolidated affiliates that are deemed to be paid from cumulative earnings, which distributions were $263 million in 2024 and $286 million in 2023.

Cash paid for interest, net of interest capitalized, was $1.84 billion and $1.54 billion for the nine months ended September 30, 2024 and 2023, respectively. Interest capitalized was $77 million and $53 million for the nine months ended September 30, 2024 and 2023, 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.

Nine months ended September 30, 2024 compared to nine months ended September 30, 2023. Cash used in investing activities during 2024 was $4.44 billion compared to $3.36 billion for 2023. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for 2024 were $2.64 billion compared to $2.39 billion for 2023. Additional detail related to our capital expenditures is provided in the table below.

In 2024, we paid $2.17 billion, net of cash received, for the WTG Midstream acquisition, we paid $84 million to acquire the outstanding noncontrolling interest in Edwards Lime Gathering, LLC, which is now a wholly owned subsidiary, and we also paid $219 million for other acquisitions. In 2024, Sunoco LP paid $209 million in cash for acquisitions of terminals and received $27 million in cash from the NuStar acquisition. Additionally, in 2024, Sunoco LP received cash proceeds of $990 million from its sale of West Texas assets. In 2023, we paid $930 million in cash for the Lotus Midstream acquisition and Sunoco LP paid $111 million in cash for the acquisition of terminals.

In 2024 and 2023, we received cash distributions from unconsolidated affiliates in excess of cumulative earnings of $60 million and $45 million, respectively, and we paid contributions to unconsolidated affiliates of $205 million and $5 million in cash, respectively.

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 nine months ended September 30, 2024:


	Capital Expenditures Recorded During Period
	Growth		Maintenance		Total
Intrastate transportation and storage	$	9	$	41	$	50
Interstate transportation and storage	103		129		232
Midstream	529		296		825
NGL and refined products transportation and services	846		83		929
Crude oil transportation and services	183		100		283
Investment in Sunoco LP	146		66		212
Investment in USAC	206		24		230
All other (including eliminations)	64		48		112
Total capital expenditures	$	2,086	$	787	$	2,873

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.

Nine months ended September 30, 2024 compared to nine months ended September 30, 2023. Cash used in financing activities during 2024 was $4.34 billion compared to $4.64 billion for 2023. During 2024, we had a net increase in our debt

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level of $4.24 billion compared to a net decrease of $183 million for 2023. In 2024, we paid debt issuance costs of $142 million, paid $2.65 billion in cash for the redemption of our Series A, Series C, Series D and Series E 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 and Sunoco LP paid $784 million in cash for the redemption of NuStar preferred units.

In 2024 and 2023, we paid distributions of $3.43 billion and $3.12 billion, respectively, to our partners. In 2024 and 2023, we paid distributions of $1.38 billion and $1.29 billion, respectively, to noncontrolling interests. In 2024 and 2023, we paid distributions of $51 million and $37 million, respectively, to our redeemable noncontrolling interests.

In 2024 and 2023, we received capital contributions of $637 million and $3 million, respectively, in cash from noncontrolling interests. In 2024, we received capital contributions of $2 million in cash from redeemable noncontrolling interests.

Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:


	September 30, 2024		December 31, 2023
Energy Transfer indebtedness:
Notes and debentures(1) (2)	$	46,834	$	43,016

Five-Year Credit Facility(2)	1,633		1,412
Subsidiary indebtedness:
Transwestern senior notes	250		250
Bakken Project senior notes(2)	850		1,850
Sunoco LP senior notes, bonds and lease-related obligations(2) (3)	7,311		3,194
USAC senior notes(2)	1,750		1,475
Sunoco LP credit facility	50		411
USAC credit facility	803		872

Other long-term debt	17		18
Net unamortized premiums, discounts and fair value adjustments	81		127
Deferred debt issuance costs	(321)		(237)
Total debt	59,258		52,388
Less: current maturities of long-term debt(4)	263		1,008

Long-term debt, less current maturities	$	58,995	$	51,380

(1)As of September 30, 2024, this balance included a total of $2.57 billion aggregate principal amount of senior notes due on or before September 30, 2025, 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.”

(3)Sunoco LP assumed $2.57 billion aggregate principal amount of NuStar senior notes and bonds in connection with the closing of the NuStar acquisition in May 2024.

(4)As of December 31, 2023, current maturities of long-term debt reflected on the Partnership’s consolidated balance sheet included $1.00 billion of senior notes issued by the Bakken Pipeline entities which were repaid in April 2024, as described below under “Recent Transactions.”

Recent Transactions

Energy Transfer Senior Notes Redemptions

During the first quarter of 2024, the Partnership redeemed its $1.15 billion aggregate principal amount of 5.875% senior notes due January 2024, $350 million aggregate principal amount of 4.90% senior notes due February 2024 and $82 million aggregate principal amount of 7.60% senior notes due February 2024 using proceeds from its January 2024 notes issuance described below.

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During the second quarter of 2024, the Partnership redeemed its $500 million aggregate principal amount of 4.25% senior notes due April 2024, $750 million aggregate principal amount of 4.50% senior notes due April 2024, $450 million aggregate principal amount of 8.00% senior notes due April 2029 and $600 million aggregate principal amount of 3.90% senior notes due May 2024 using cash on hand and proceeds from its Five-Year Credit Facility (defined below).

Bakken Project Debt Redemption

In April 2024, the Bakken Pipeline entities redeemed $1.00 billion aggregate principal amount of 3.90% senior notes due April 2024 using proceeds from member contributions, which included $637 million reflected as capital contributions from noncontrolling interests recorded in the Partnership’s consolidated financial statements.

Energy Transfer January 2024 Notes Issuance

In January 2024, the Partnership issued $1.25 billion aggregate principal amount of 5.55% senior notes due 2034, $1.75 billion aggregate principal amount of 5.95% senior notes due 2054 and $800 million aggregate principal amount of 8.00% fixed-to-fixed reset rate junior subordinated notes due 2054. The Partnership used the net proceeds to refinance existing indebtedness, including borrowings under its Five-Year Credit Facility, redeem its outstanding Series C Preferred Units, Series D Preferred Units and Series E Preferred Units and for general partnership purposes.

Energy Transfer June 2024 Notes Issuance

In June 2024, the Partnership issued $1.00 billion aggregate principal amount of 5.25% senior notes due 2029, $1.25 billion aggregate principal amount of 5.60% senior notes due 2034, $1.25 billion aggregate principal amount of 6.05% senior notes due 2054 and $400 million aggregate principal amount of 7.125% fixed-to-fixed reset rate junior subordinated notes due 2054. The Partnership used part of the net proceeds to redeem its outstanding Series A Preferred Units. It also used the net proceeds to fund a portion of its previously announced acquisition of WTG Midstream, refinance existing indebtedness, including borrowings under its Five-Year Credit Facility, and for general partnership purposes.

Sunoco LP April 2024 Notes Issuance

On April 30, 2024, Sunoco LP issued $750 million of 7.000% senior notes due 2029 and $750 million of 7.250% senior notes due 2032 in a private offering. Sunoco LP used the net proceeds from the offering to repay certain outstanding indebtedness of NuStar in connection with the merger between Sunoco LP and NuStar, to fund the redemption of NuStar's preferred units in connection with the merger and to pay offering fees and expenses.

NuStar Subordinated Note Redemption and Credit Facility Termination

During the second quarter of 2024, subsequent to the closing of the NuStar acquisition, Sunoco LP redeemed NuStar's subordinated notes totaling $403 million and repaid and terminated NuStar's credit facility totaling $455 million.

USAC March 2024 Notes Issuance

In March 2024, USAC issued $1.00 billion aggregate principal amount of 7.125% senior notes due 2029. The net proceeds from this issuance were used to repay a portion of existing borrowings under USAC’s revolving credit facility, to redeem its $725 million aggregate principal amount of 6.875% senior notes due 2026, which constituted a legal defeasance under GAAP (the “Defeasance”), and for general partnership purposes.

The Defeasance required a cash outlay in the net amount of $749 million, which was used to purchase U.S. government securities. These securities generated sufficient cash upon maturity to fund interest payments on the senior notes due 2026 occurring between the effective date of the Defeasance through April 4, 2024, when the senior notes due 2026 were redeemed at par, as well as fund the redemption of the senior notes due 2026 in full. As a result of the Defeasance, USAC recognized a loss on early extinguishment of debt of $5 million for the three months ended March 31, 2024.

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 and matures in April 2027. The Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $7.00 billion under certain conditions.

As of September 30, 2024, the Five-Year Credit Facility had $1.63 billion of outstanding borrowings, $1.58 billion of which consisted of commercial paper. The amount available for future borrowings was $3.34 billion, after accounting for outstanding

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letters of credit in the amount of $31 million. The weighted average interest rate on the total amount outstanding as of September 30, 2024 was 5.04%.

Sunoco LP Facilities

As of September 30, 2024, Sunoco LP’s credit facility had $50 million of outstanding borrowings and $28 million in standby letters of credit and matures in May 2029 (as amended in May 2024). The amount available for future borrowings at September 30, 2024 was $1.42 billion. The weighted average interest rate on the total amount outstanding as of September 30, 2024 was 7.30%.

USAC Credit Facility

As of September 30, 2024, USAC’s credit facility, which matures in December 2026, had $803 million of outstanding borrowings and $1 million outstanding letters of credit. As of September 30, 2024, USAC’s credit facility had $796 million of remaining unused availability of which, due to restrictions related to compliance with the applicable financial covenants, $642 million was available to be drawn. The weighted average interest rate on the total amount outstanding as of September 30, 2024 was 7.50%.

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 September 30, 2024.

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, 2023 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2023

February 7, 2024

February 20, 2024

0.3150

March 31, 2024

May 13, 2024

May 20, 2024

0.3175

June 30, 2024

August 9, 2024

August 19, 2024

0.3200

September 30, 2024

November 8, 2024

November 19, 2024

0.3225

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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 A		Series B (1)		Series C		Series D		Series E		Series F (1)		Series G (1)		Series H (1)		Series I (2)
December 31, 2023	February 1, 2024	February 15, 2024	$	24.710	$	33.125	$	0.6075	$	0.6199	$	0.475	$	—	$	—	$	—	$	0.2111
March 31, 2024	May 1, 2024	May 15, 2024	23.992		—		—		—		0.475		33.750		35.630		32.500		0.2111
June 30, 2024	August 1, 2024	August 15, 2024	9.879		33.125		—		—		—		—		—		—		0.2111
September 30, 2024	November 1, 2024	November 15, 2024	—		—		—		—		—		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 September 30, 2024, the cash distribution for the Series I Preferred Units will be paid on November 14, 2024 to unitholders of record as of the close of business on November 4, 2024. For the period ended June 30, 2024, the cash distribution for the Series I Preferred Units was paid on August 14, 2024 to unitholders of record as of the close of business on August 2, 2024.

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 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, 2023 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2023

February 7, 2024

February 20, 2024

0.8420

March 31, 2024

May 13, 2024

May 20, 2024

0.8756

June 30, 2024

August 9, 2024

August 19, 2024

0.8756

September 30, 2024

November 8, 2024

November 19, 2024

0.8756

Cash Distributions Paid by USAC

Distributions on USAC’s common units declared and/or paid by USAC subsequent to December 31, 2023 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2023

January 22, 2024

February 2, 2024

0.525

March 31, 2024

April 22, 2024

May 3, 2024

0.525

June 30, 2024

July 22, 2024

August 2, 2024

0.525

September 30, 2024

October 21, 2024

November 1, 2024

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 16, 2024. We have not made any changes to the accounting policies involving critical accounting estimates

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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;

•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;

•governmental regulation and taxation;

•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;

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•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 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 a 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;

•the costs and effects of legal and administrative proceedings; and

•risks associated with a potential failure to successfully combine Sunoco LP’s business with that of NuStar, as well as the risks associated with a potential failure to successfully integrate our business with that of WTG Midstream.

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, 2023 filed with the SEC on February 16, 2024. 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, 2023 filed with the SEC on February 16, 2024, 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, 2023. Since December 31, 2023, 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.


	September 30, 2024					December 31, 2023
	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	1,820	$	3	$	—	5,247	$	16	$	2
Basis Swaps IFERC/NYMEX	83,845	(3)		1		(46,975)	20		5
Swing Swaps IFERC	36,503	2		1		(97,728)	18		1
Options – Puts	—	—		—		1,900	(2)		—
Options – Calls	500	—		—		250	—		—
Forward Physical Contracts	2,138	3		2		(1,751)	8		1
Power (Megawatt):
Forwards	101,440	1		—		155,600	1		—
Futures	27,323	2		2		(464,897)	—		1
Options – Puts	—	—		—		136,000	—		—
Options – Calls	(33,600)	—		—		—	—		—
Crude (MBbls):
Forward Physical Contracts	(856)	(12)		2		(2,674)	8		5

Options – Puts	—	—		—		(15)	—		—
Options – Calls	—	—		—		(20)	—		—
NGL/Refined Products (MBbls):
Forwards/Swaps	(15,745)	53		47		(13,870)	20		43
Options – Puts	(12)	—		—		121	(1)		—
Options – Calls	(21)	—		—		(43)	(1)		—
Futures	(3,528)	(1)		26		(4,548)	17		38
Fair Value Hedging Derivatives
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(49,858)	(2)		2		(39,013)	1		1
Fixed Swaps/Futures	(49,858)	2		16		(39,013)	45		9

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

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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.

Interest Rate Risk

As of September 30, 2024, we and our subsidiaries had $3.09 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $31 million annually. However, our actual change in interest expense may be less in a given period due to interest rate floors included in our variable rate debt instruments. We manage a portion of our interest rate exposure by utilizing interest rate swaps, including forward-starting interest rate swaps to lock-in the rate on a portion of anticipated debt issuances.

The following table summarizes USAC’s interest rate swap which is no longer outstanding as of September 30, 2024, and which was not designated as a hedge for accounting purposes:

Term

Type

Notional Amount Outstanding

September 30,
2024

December 31,
2023

December 2025 (1)

Pay a fixed rate of 3.9725% and receive a floating rate based on SOFR

—

700

(1)In August 2024, USAC elected to terminate the outstanding interest rate swap.

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 September 30, 2024 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 September 30, 2024 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 16, 2024 and Note 10 in “Item 1. Financial Statements” in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2024.

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 $0.3 million.

In January 2019, we received notice from the United States Department of Justice (“DOJ”) on behalf of the United States Environmental Protection Agency (“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 Pipeline Company LLC (“MVPL”). 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 of 2019, SPLP reached an agreement in principal with the USEPA regarding payment of a civil penalty. In September of 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 MVPL fully resolved both the civil penalty and alleged natural resource damages (NRD) which had been brought jointly by the DOJ, on behalf of trustees of the United States, and the Ohio Attorney General, on behalf of the trustees of the State of Ohio. Payments of approximately $565,000 for the civil penalty plus interest and approximately $1.9 million for natural resource damages, reimbursement and interest will be made within 30 days. Operation and maintenance activities associated with the restoration are expected to continue for several years.

On June 26, 2023, Plaintiffs Michael and Cecilia Weinman ("Plaintiffs") filed suit in Chester County, Tennessee, against MVPL and other Energy Transfer defendants asserting claims for negligence, trespass, and other tort claims and alleging damage to their property stemming from the crude oil release. Plaintiffs alleged actual monetary damages and punitive damages totaling $380 million. The Energy Transfer defendants were served on or around July 5, 2023, and timely filed a notice of removal of the lawsuit to federal court in the Western District of Tennessee Eastern Division on August 2, 2023. On August 8, 2023, plaintiffs filed a notice of voluntary dismissal of their lawsuit without prejudice. On or about August 7, 2024, plaintiffs refiled their suit with slight modifications and removing their negligence per se claim in Chester County, Tennessee. On or about August 27, 2024, the first two Energy Transfer defendants were served. On or about September 13, 2024, plaintiffs filed a notice of voluntary dismissal of their latest lawsuit without prejudice.

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 $2,473,912. 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 of approximately $2.5 million. The Partnership is challenging this recommendation and filed its response on July 31, 2024.

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

There have been no material changes from the risk factors described in “Part I — Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2023 filed with the SEC on February 16, 2024 and in “Part II — Item 1A. Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2024 filed with the SEC on May 9, 2024.

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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)


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:

November 7, 2024

By:

/s/ A. Troy Sturrock

A. Troy Sturrock

Group Senior Vice President, Controller and Principal Accounting Officer

Energy Transfer LP - Quarter Report: 2024 September (Form 10-Q)

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