0001276187-23-000093 | 10-Q | XBRL Viewer

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Reportable Segments Table - Segment Adjusted EBITDA (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	$ 3,541	$ 3,088	$ 10,096	$ 9,656
Depreciation, depletion and amortization	1,107	1,030	3,227	3,104
Interest Expense	632	577	1,892	1,714
Impairment losses and other	1	86	12	386
Gains on interest rate derivatives	(32)	(60)	(47)	(303)
Non-cash compensation expense	35	27	99	88
Unrealized (gains) losses on commodity risk management activities	107	(76)	182	(130)
Equity in earnings of unconsolidated affiliates	(103)	(68)	(286)	(186)
Gain (Loss) Related to Litigation Settlement	625	0	625	0
Income tax expense	77	82	256	159
Net income	1,047	1,322	3,727	4,431
Inventory valuation adjustments	(141)	40	(113)	(81)
Adjusted EBITDA attributable to unconsolidated affiliates	182	147	514	409
Other, net	4	(19)	8	65
Intrastate Transportation And Storage [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	244	301	869	963
Investment In Sunoco LP [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	257	276	728	681
Investment In USAC [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	130	109	373	313
Interstate Transportation and Storage [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	491	409	1,468	1,259
Midstream [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	631	868	1,851	2,578
NGL and refined products transportation and services [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	1,076	634	2,852	2,097
Crude oil transportation and services [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	706	461	1,906	1,616
All Other Segment
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	$ 6	$ 30	$ 49	$ 149

Acquisitions and Related Transactions (Tables)

9 Months Ended

Sep. 30, 2023

Lotus Midstream LLC

Business Acquisition [Line Items]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

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


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

Total assets	1,551

Total current liabilities	27

Other non-current liabilities	16
Total liabilities	43



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

Fair Value Measurements

9 Months Ended

Sep. 30, 2023

Fair Value Measurements [Abstract]

Fair Value Measurements

FAIR VALUE MEASURESWe have commodity derivatives and interest rate derivatives that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing

broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider options transacted through a clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. The valuation methodologies employed for our interest rate derivatives do not necessitate material judgment, and the inputs are observed from actively quoted public markets and therefore are categorized in Level 2. Level 3 inputs are unobservable. During the nine months ended September 30, 2023, no transfers were made between any levels within the fair value hierarchy.

The following tables summarize the gross fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of September 30, 2023 and December 31, 2022 based on inputs used to derive their fair values:


			Fair Value Measurements at September 30, 2023
	Fair Value Total		Level 1		Level 2
Assets:
Interest rate derivatives	$	14	$	—	$	14
Commodity derivatives:

Natural Gas:
Basis Swaps IFERC/NYMEX	$	3	$	3	$	—
Swing Swaps IFERC	4		4		—
Fixed Swaps/Futures	28		28		—


Forward Physical Contracts	3		—		3
Power:
Forwards	46		—		46
Futures	6		6		—


NGLs – Forwards/Swaps	256		256		—
Refined Products – Futures	27		27		—
Crude – Forwards/Swaps	32		32		—

Total commodity derivatives	405		356		49
Other non-current assets	28		18		10
Total assets	$	447	$	374	$	73
Liabilities:

Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	(10)	$	(10)	$	—
Swing Swaps IFERC	(5)		(5)		—
Fixed Swaps/Futures	(2)		(2)		—



Power:
Forwards	(45)		—		(45)
Futures	(5)		(5)		—


NGLs – Forwards/Swaps	(306)		(306)		—
Refined Products – Futures	(35)		(35)		—
Crude – Forwards/Swaps	(41)		(41)		—
Total commodity derivatives	(449)		(404)		(45)
Total liabilities	$	(449)	$	(404)	$	(45)


			Fair Value Measurements at December 31, 2022
	Fair Value Total		Level 1		Level 2
Assets:

Commodity derivatives:

Natural Gas:
Basis Swaps IFERC/NYMEX	$	60	$	60	$	—
Swing Swaps IFERC	75		75		—
Fixed Swaps/Futures	113		113		—


Forward Physical Contracts	10		—		10
Power:
Forwards	52		—		52
Futures	3		3		—


NGLs – Forwards/Swaps	317		317		—
Refined Products – Futures	20		20		—

Crude – Forwards/Swaps	38		38		—

Total commodity derivatives	688		626		62
Other non-current assets	27		18		9
Total assets	$	715	$	644	$	71
Liabilities:
Interest rate derivatives	$	(23)	$	—	$	(23)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(25)		(25)		—
Swing Swaps IFERC	(12)		(12)		—
Fixed Swaps/Futures	(4)		(4)		—


Forward Physical Contracts	(2)		—		(2)
Power:
Forwards	(51)		—		(51)
Futures	(3)		(3)		—

NGLs – Forwards/Swaps	(358)		(358)		—
Refined Products – Futures	(59)		(59)		—

Crude – Forwards/Swaps	(12)		(12)		—

Total commodity derivatives	(526)		(473)		(53)
Total liabilities	$	(549)	$	(473)	$	(76)

The aggregate estimated fair value and carrying amount of our consolidated debt obligations as of September 30, 2023 were $44.60 billion and $48.08 billion, respectively. As of December 31, 2022, the aggregate fair value and carrying amount of our consolidated debt obligations were $45.42 billion and $48.26 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.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Derivative Assets And Liabilities Table - Interest Rate Swaps Outstanding (Details) - USD ($)
$ in Millions

9 Months Ended

Sep. 30, 2023

Dec. 31, 2022

Discussion of Interest Rate Derivative Risk Management Policy

Interest Rate RiskWe are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.

July 2024

Description of Interest Rate Derivative Activities

^[1],[2]

Forward-starting to pay an average fixed rate of 3.388% and receive a floating rate

Derivative, Notional Amount

^[2]

$ 0

$ 400

April 2025

Derivative, Fixed Interest Rate

3.9725%

April 2025 | USAC [Member]

Description of Interest Rate Derivative Activities

^[1],[3]

Pay a fixed rate of 3.785% and receive a floating rate (effective April 2023)

Derivative, Notional Amount

^[3]

$ 700

$ 0

[1]	Floating rates are based on SOFR.
[2]	The July 2024 interest rate swaps were terminated and settled in August 2023.
[3]	In October 2023, USAC modified its April 2025 interest rate swap. The termination date was extended from April 1, 2025 to December 31, 2025. Under the modified interest rate swap, USAC pays a fixed interest rate of 3.9725% and continues to receive floating interest rate payments that are indexed to the one-month SOFR.

DEI Document - shares	9 Months Ended
DEI Document - shares	Sep. 30, 2023	Oct. 27, 2023
Document Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2023
Document Transition Report	false
Entity File Number	1-32740
Entity Registrant Name	ENERGY TRANSFER LP
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Shell Company	false
Entity Central Index Key	0001276187
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		3,145,065,881
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Tax Identification Number	30-0108820
Entity Incorporation, State or Country Code	DE
Entity Address, Address Line One	8111 Westchester Drive
Entity Address, Address Line Two	Suite 600
Entity Address, City or Town	Dallas
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	75225
City Area Code	214
Local Phone Number	981-0700
Document Quarterly Report	true
Common Units
Document Information [Line Items]
Trading Symbol	ET
Security Exchange Name	NYSE
Title of 12(b) Security	Common Units
ETprC
Document Information [Line Items]
Trading Symbol	ETprC
Security Exchange Name	NYSE
Title of 12(b) Security	7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
ETprD
Document Information [Line Items]
Trading Symbol	ETprD
Security Exchange Name	NYSE
Title of 12(b) Security	7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
ETprE
Document Information [Line Items]
Trading Symbol	ETprE
Security Exchange Name	NYSE
Title of 12(b) Security	7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

Inventories Table - Inventory Balances (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Inventory [Line Items]
Natural gas, NGLs and refined products	$ 1,951	$ 1,802
Crude oil	169	246
Spare parts and other	470	413
Total inventories	$ 2,590	$ 2,461

Derivative Assets And Liabilities Table - Outstanding Commodity-Related Derivatives (Details)

Sep. 30, 2023

MMbtu

Megawatt

bbl

barrels

Dec. 31, 2022

MMbtu

Megawatt

bbl

barrels

Natural Gas Liquids [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forwards Swaps [Member] | Short [Member]

Derivative, Nonmonetary Notional Amount | bbl

(14,238)

Natural Gas Liquids [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forwards Swaps [Member] | Long [Member]

Derivative, Nonmonetary Notional Amount | bbl

(6,934)

Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Long [Member]

Derivative, Nonmonetary Notional Amount

(48,393)

(42,440)

Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Swing Swaps IFERC [Member] | Short [Member]

Derivative, Nonmonetary Notional Amount

(72,220)

(202,815)

Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | Short [Member]

Derivative, Nonmonetary Notional Amount

(4,803)

(15,758)

Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Physical Contracts [Member] | Short [Member]

Derivative, Nonmonetary Notional Amount

(2,145)

Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Physical Contracts [Member] | Long [Member]

Derivative, Nonmonetary Notional Amount

(2,423)

Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Short [Member]

Derivative, Nonmonetary Notional Amount

^[1]

(44,800)

(39,563)

Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Fixed Swaps/Futures [Member] | Long [Member]

Derivative, Nonmonetary Notional Amount

(330)

(145)

Natural Gas [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Short [Member]

Derivative, Nonmonetary Notional Amount

(43,745)

(37,448)

Natural Gas [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | Short [Member]

Derivative, Nonmonetary Notional Amount

(43,745)

(37,448)

Natural Gas [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Hedged Item - Inventory (MMBtu) [Member] | Long [Member]

Derivative, Nonmonetary Notional Amount

(43,745)

(37,448)

Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Puts [Member] | Long [Member]

Derivative, Nonmonetary Notional Amount | Megawatt

(68,800)

Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Call Option [Member] | Short [Member]

Derivative, Nonmonetary Notional Amount | Megawatt

Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Forwards Swaps [Member] | Long [Member]

Derivative, Nonmonetary Notional Amount | Megawatt

(171,600)

Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member] | Short [Member]

Derivative, Nonmonetary Notional Amount | Megawatt

(74,391)

(21,384)

Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Put Option [Member] | Long [Member]

Derivative, Nonmonetary Notional Amount | Megawatt

(119,200)

Crude Oil [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forwards Swaps [Member] | Short [Member]

Derivative, Nonmonetary Notional Amount | bbl

(7,660)

Crude Oil [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forwards Swaps [Member] | Long [Member]

Derivative, Nonmonetary Notional Amount | bbl

(795)

Refined product sales | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member] | Short [Member]

Derivative, Nonmonetary Notional Amount | barrels

(5,751)

(3,547)

[1]	Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.

Cash And Cash Equivalents Non-Cash Activities (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Accrued capital expenditures	$ 354	$ 454
Right-of-Use Assets Obtained in Exchange for Liabilities	26	37
Stock Issued During Period, Value, Dividend Reinvestment Plan	$ 70	$ 42

Debt Obligations	9 Months Ended
Debt Obligations	Sep. 30, 2023
Debt Obligations [Abstract]
Debt Obligations	DEBT OBLIGATIONS Recent Transactions Senior Notes On November 1, 2023, the Partnership redeemed $600 million aggregate principal amount of its 4.50% Senior Notes due November 1, 2023 using proceeds from the senior notes offering discussed in the following paragraph. In October 2023, the Partnership issued $1.00 billion aggregate principal amount of 6.05% Senior Notes due 2026, $500 million aggregate principal amount of 6.10% Senior Notes due 2028, $1.00 billion aggregate principal amount of 6.40% Senior Notes due 2030 and $1.50 billion aggregate principal amount of 6.55% Senior Notes due 2033. The Partnership intends to use the net proceeds to refinance existing indebtedness, including borrowings under its Five-Year Credit Facility (defined below) and for general partnership purposes. In the third quarter of 2023, the Partnership redeemed $500 million aggregate principal amount of its 4.20% Senior Notes due September 2023 using proceeds from its Five-Year Credit Facility. In the first quarter of 2023, the Partnership redeemed $350 million aggregate principal amount of its 3.45% Senior Notes due January 2023, $800 million aggregate principal amount of its 3.60% Senior Notes due February 2023 and $1.00 billion aggregate principal amount of its 4.25% Senior Notes due March 2023 using proceeds from its Five-Year Credit Facility. HFOTCO Debt In May 2023, the Partnership refinanced all of the $225 million outstanding principal amount of HFOTCO tax-exempt bonds with new 10-year tax-exempt bonds. The new bonds, which were issued through the Harris County Industrial Development Corporation and are obligations of Energy Transfer, accrue interest at a fixed rate of 4.05% and are mandatorily redeemable in 2033. Upon redemption, these tax-exempt bonds may be remarketed on different terms through final maturity of November 1, 2050. Sunoco LP Senior Notes Offering In September 2023, Sunoco LP issued $500 million aggregate principal amount of 7.00% senior notes due 2028 in a private placement to eligible purchasers. The net proceeds from this offering were used to repay a portion of Sunoco LP’s existing borrowings under its credit facility. Current Maturities of Long-Term Debt As of September 30, 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 mature in April 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, 2023, the Five-Year Credit Facility had $2.85 billion of outstanding borrowings, of which $1.55 billion consisted of commercial paper. The amount available for future borrowings was $2.12 billion, after accounting for outstanding letters of credit in the amount of $32 million. The weighted average interest rate on the total amount outstanding as of September 30, 2023 was 6.29%. Sunoco LP Credit Facility As of September 30, 2023, Sunoco LP’s credit facility had $647 million of outstanding borrowings and $6 million in standby letters of credit and matures in April 2027. The amount available for future borrowings at September 30, 2023 was $847 million. The weighted average interest rate on the total amount outstanding as of September 30, 2023 was 7.34%. USAC Credit Facility As of September 30, 2023, USAC’s credit facility, which matures in December 2026, had $813 million of outstanding borrowings and no outstanding letters of credit. As of September 30, 2023, USAC had $787 million of availability under its credit facility, and subject to compliance with applicable financial covenants, available borrowing capacity of $434 million. The weighted average interest rate on the total amount outstanding as of September 30, 2023 was 7.99%. 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, 2023. For the quarter ended September 30, 2023, our leverage ratio, as calculated pursuant to the covenant related to our Five-Year Credit Facility, was 3.11x.

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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Reference 6: http://www.xbrl.org/2003/role/disclosureRef
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-Topic 470
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+ Details

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

9 Months Ended

Sep. 30, 2023

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

FERC Proceedings

Rover – FERC - Stoneman House

In late 2016, FERC Enforcement Staff began a non-public investigation related to Rover’s purchase and removal of a potentially historic home (known as the Stoneman House) while Rover’s application for permission to construct the new 711-mile interstate natural gas pipeline and related facilities was pending. On March 18, 2021, FERC issued an Order to Show Cause and Notice of Proposed Penalty (Docket No. IN19-4-000), ordering Rover to explain why it should not pay a $20 million civil penalty for alleged violations of FERC regulations requiring certificate holders to be forthright in their submissions of information to the FERC. Rover filed its answer and denial to the order on June 21, 2021 and a surreply on September 15, 2021. FERC issued an order on January 20, 2022 setting the matter for hearing before an administrative law judge. The hearing was set to commence on March 6, 2023; as explained below, this FERC proceeding has been stayed.

On February 1, 2022, Energy Transfer and Rover filed a Complaint for Declaratory Relief in the United States District Court for the Northern District of Texas (“Federal District Court”) seeking an order declaring that FERC must bring its enforcement action in federal district court (instead of before an administrative law judge). Also on February 1, 2022, Energy Transfer and Rover filed an expedited request to stay the proceedings before the FERC administrative law judge pending the outcome of the Federal District Court case. On May 24, 2022, the Federal District Court ordered a stay of the FERC’s enforcement case and the District Court case pending the resolution of two cases pending before the United States Supreme Court. Arguments were heard in those cases on November 7, 2022. On April 14, 2023, the United States Supreme Court held against the government in both cases, finding that the federal district courts had jurisdiction to hear those suits and to resolve the parties’ constitutional challenges. The cases were remanded to the federal district courts for further proceedings.

On September 13, 2023 the District Court ordered that the District Court case would be stayed pending the resolution of another case pending before the United States Supreme Court and that the FERC enforcement case would remain stayed. Energy Transfer and Rover intend to vigorously defend this claim.

Rover – FERC - Tuscarawas

In mid-2017, FERC Enforcement Staff began a non-public investigation regarding allegations that diesel fuel may have been included in the drilling mud at the Tuscarawas River horizontal directional drilling (“HDD”) operations. Rover and the Partnership are cooperating with the investigation. In 2019, Enforcement Staff provided Rover with a notice pursuant to Section 1b.19 of the FERC regulations that Enforcement Staff intended to recommend that the FERC pursue an enforcement action against Rover and the Partnership. On December 16, 2021, FERC issued an Order to Show Cause and Notice of Proposed Penalty (Docket No. IN17-4-000), ordering Rover and Energy Transfer to show cause why they should not be found to have violated Section 7(e) of the Natural Gas Act, Section 157.20 of FERC’s regulations, and the Rover Pipeline Certificate Order, and assessed civil penalties of $40 million.

Rover and Energy Transfer filed their answer to this order on March 21, 2022, and Enforcement Staff filed a reply on April 20, 2022. Rover and Energy Transfer filed their surreply to this order on May 13, 2022. 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 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 FERC further considered the requests for rehearing of its December 16, 2022 order. On September 25, 2023, FERC issued its order addressing arguments raised on rehearing and compliance, which denied our requests for rehearing. Panhandle is evaluating the September 25 order and has sixty days from that date to appeal the order to the Court of Appeals.

On December 1, 2022, Sea Robin filed a rate case pursuant to Section 4 of the Natural Gas Act. By order dated June 29, 2023, a revised procedural schedule was adopted in this proceeding setting the commencement of the hearing for January 9, 2024, with an initial decision anticipated by May 21, 2024. Subsequently, by Order of the Acting Chief Administrative Law Judge, deadlines in the procedural schedule were extended, including revised hearing commencement and initial decisions deadlines to March 26, 2024 and August 8, 2024, respectively.

In May 2021, the FERC commenced an audit of SPLP for the period from January 1, 2018 to present to evaluate SPLP’s compliance with its FERC oil tariffs, the accounting requirements of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s Form No. 6 reporting requirements. An audit report was received in September 2023 noting no issues that would have a material impact on the Partnership's financial position or results of operations.

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 jurisdictions for 2017 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 $25 million. 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, with respect to an audited and adjusted return.

Commitments

In the normal course of business, Energy Transfer purchases, processes and sells natural gas pursuant to long-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. Energy Transfer believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on the Partnership’s financial position or results of operations.

Our joint venture agreements require that we fund our proportionate share of capital contributions to our unconsolidated affiliates. Such contributions will depend upon the unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.

We have certain non-cancelable rights-of-way (“ROW”) commitments which require fixed payments and either expire upon our chosen abandonment or at various dates in the future. The following table reflects ROW expense included in operating expenses in the accompanying consolidated statements of operations:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
ROW expense	$	20	$	16	$	46	$	44

Litigation and Contingencies

We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Due to the flammable and combustible nature of natural gas and crude oil, the potential exists for personal injury and/or property damage to occur in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.

We or our subsidiaries are parties to various legal proceedings, arbitrations and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.

As of September 30, 2023 and December 31, 2022, accruals of approximately $947 million and $200 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 $200 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 (December 16, 2021). Dakota Access filed their reply on January 4, 2022. On February 22, 2022, the U.S. Supreme Court declined to hear the case.

The District Court scheduled a status conference for February 10, 2021 to discuss the effects of the Court of Appeals’ January 26, 2021 order on the pending motion for injunctive relief, as well as USACE’s expectations as to how it will proceed regarding its enforcement discretion regarding the easement. On May 3, 2021, USACE advised the District Court that it had not changed its position with respect to its opposition to the Tribes’ motion for injunction. On May 21, 2021, the District Court denied the plaintiffs’ request for an injunction. On June 22, 2021, the District Court terminated the consolidated lawsuits and dismissed all remaining outstanding counts without prejudice.

On September 8, 2023, the USACE published the Draft EIS. The USACE anticipates that a Final EIS and Record of Decision would be issued in 2024. The pipeline continues to operate pending completion of the EIS. Energy Transfer cannot determine when or how future lawsuits will be resolved or the impact they may have on the Bakken Pipeline, which consists of both Dakota Access and the Energy Transfer Crude Oil Pipeline; however, Energy Transfer expects that after the law and complete record are fully considered, any such proceeding will be resolved in a manner that will allow the pipeline to continue to operate.

In addition, lawsuits and/or regulatory proceedings or actions of this or a similar nature could result in interruptions to construction or operations of current or future projects, delays in completing those projects and/or increased project costs, all of which could have an adverse effect on our business and results of operations.

Mont Belvieu Incident

On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL Mont Belvieu LP’s (“Lone Star”), now known as Energy Transfer Mont Belvieu NGLs LP, facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations resumed at the facilities in the fall of 2016, with the exception of one of Lone Star’s storage wells at the North Terminal that has not been returned to service. Lone Star has obtained payment for most of the losses it has submitted to the adjacent operator. Lone Star continues to quantify and seek reimbursement for outstanding losses.

MTBE Litigation

ETC Sunoco and Energy Transfer R&M (collectively, “Sunoco Defendants”) are defendants in lawsuits alleging methyl tertiary butyl ether (“MTBE”) contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability, nuisance, trespass, negligence, violation of environmental laws and/or deceptive business practices

claims. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages and attorneys’ fees.

As of September 30, 2023, Sunoco Defendants are defendants in two cases: one case initiated by the State of Maryland and one by the Commonwealth of Pennsylvania. The actions brought also named as defendants ETO, ETP Holdco Corporation and Sunoco Partners Marketing & Terminals L.P., now known as Energy Transfer Marketing & Terminals L.P. ETP Holdco Corporation and Energy Transfer Marketing & Terminals L.P. are wholly-owned subsidiaries of Energy Transfer.

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

Litigation Filed By or Against Williams

In April and May 2016, The Williams Companies, Inc. (“Williams”) filed two lawsuits (the “Williams Litigation”) against Energy Transfer, LE GP, LLC, and, in one of the lawsuits, Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC (collectively, “Energy Transfer Defendants”) in the Delaware Court of Chancery (“the Court”), alleging that the Energy Transfer Defendants breached their obligations under the Energy Transfer-Williams merger agreement (the “Merger Agreement”). In general, Williams alleges that the Energy Transfer Defendants breached the Merger Agreement by (a) failing to use commercially reasonable efforts to obtain from Latham & Watkins LLP (“Latham”) the delivery of a tax opinion concerning Section 721 of the Internal Revenue Code (“721 Opinion”), (b) issuing the Partnership’s Series A convertible preferred units (the “Issuance”) and (c) making allegedly untrue representations and warranties in the Merger Agreement. Williams asked the Court to compel the Energy Transfer Defendants to close the merger or take various other affirmative actions.

After a two-day trial on June 20 and 21, 2016, the Court ruled in favor of the Energy Transfer Defendants and issued a declaratory judgment that Energy Transfer could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court did not reach a decision regarding Williams’ claims related to the Issuance or certain of the alleged untrue representations and warranties. On March 23, 2017, the Delaware Supreme Court affirmed this ruling on the June 2016 trial. In September 2016, the parties filed amended pleadings. Williams filed an amended complaint seeking a $410 million termination fee (the “Termination Fee”) based on the alleged breaches of the Merger Agreement listed above. The Energy Transfer Defendants filed amended counterclaims and affirmative defenses, asserting that Williams materially breached the Merger Agreement by, among other things, (a) modifying and qualifying its board recommendation in a manner adverse to the merger, (b) failing to use its reasonable best efforts to consummate the merger, (c) failing to provide material information to Energy Transfer for inclusion in the Form S-4 related to the merger, (d) failing to facilitate the financing of the merger and (e) breaching the Merger Agreement’s forum-selection clause. The Energy Transfer Defendants sought a $1.48 billion termination fee under the Merger Agreement and additional damages caused by Williams’ misconduct.

On September 29, 2016, Williams filed a motion to dismiss the Energy Transfer Defendants’ amended counterclaims and to strike certain of the Energy Transfer Defendants’ affirmative defenses. On December 1, 2017, the Court issued a Memorandum Opinion granting in part and denying in part Williams’ motion to dismiss. The Court dismissed, among other things, the Energy Transfer Defendants’ claim for a $1.48 billion termination fee.

Trial was held on all remaining claims on May 10-17, 2021, and on December 29, 2021, the Court ruled in favor of Williams and awarded it the Termination Fee plus certain fees and expenses, holding that the Issuance breached the Merger Agreement and that Williams had not materially breached the Merger Agreement, though the Court awarded sanctions against Williams due to its CEO’s intentional spoliation of evidence. The Court subsequently awarded Williams approximately $190 million in attorneys’ fees, expenses and pre-judgment interest.

On September 21, 2022, the Court entered a final judgment against the Energy Transfer Defendants in the amount of approximately $601 million plus post-judgment interest at a rate of 3.5% per year, compounded quarterly. The Energy Transfer Defendants filed a notice of appeal on October 21, 2022 and filed their opening brief in support of their appeal on December 30, 2022. Williams filed their answering brief on January 20, 2023, and the Energy Transfer Defendants filed their reply brief on February 6, 2023. The Delaware Supreme Court heard oral argument on July 12, 2023.

On October 10, 2023, the Delaware Supreme Court affirmed. On October 25, 2023, Energy Transfer Defendants filed a motion for reargument. Therefore, the mandate will not issue until the Delaware Supreme Court disposes of that motion.

Once the mandate issues, the previously-stayed judgment in the amount of approximately $617 million will become effective, plus additional post-judgment interest.

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 $2.6 million in civil penalties allegedly owed and certain injunctive relief related to permit compliance. The Defendants filed several motions to dismiss, which were granted on all counts. The Ohio EPA appealed, and on December 9, 2019, the Fifth District Court of Appeals entered a unanimous judgment affirming the trial court. The Ohio EPA sought review from the Ohio Supreme Court. On April 22, 2020, the Ohio Supreme Court granted the review. On March 17, 2022, the Ohio Supreme Court reversed in part and remanded to the Ohio trial court. The Ohio Supreme Court agreed with Rover that the State of Ohio had waived its rights under Section 401 of the Clean Water Act but remanded to the trial court to determine whether any of the allegations fell outside the scope of the waiver.

On remand, the Ohio EPA voluntarily dismissed four of the other five defendants and dismissed one of its counts against Rover. In its Fourth Amended Complaint, the Ohio EPA removed all paragraphs that alleged violations by the four dismissed defendants, including those where the dismissed defendants were alleged to have acted jointly with Rover or others. At a June 2, 2022, status conference, the trial judge set a schedule for Rover and the other remaining defendant to file motions to dismiss the Fourth Amended Complaint. On August 1, 2022, Rover and the other remaining defendant each filed their respective motions. Briefing on those motions was completed on November 4, 2022. By order issued on October 20, 2023, the trial judge dismissed the Ohio EPA’s Fourth Amended Complaint.

Unitholder Litigation Regarding Pipeline Construction

Various purported unitholders of Energy Transfer have filed derivative actions against various past and current members of Energy Transfer’s Board of Directors, LE GP, LLC, and Energy Transfer, as a nominal defendant that assert claims for breach of fiduciary duties, unjust enrichment, waste of corporate assets, breach of Energy Transfer’s Partnership Agreement, tortious interference, abuse of control and gross mismanagement related primarily to matters involving the construction of pipelines in Pennsylvania and Ohio. They also seek damages and changes to Energy Transfer’s corporate governance structure. See Bettiol v. LE GP, Case No. 3:19-cv-02890-X (N.D. Tex.); Davidson v. Kelcy L. Warren, Cause No. DC-20-02322 (44th Judicial District of Dallas County, Texas); Harris v. Kelcy L. Warren, Case No. 2:20-cv-00364-GAM (E.D. Pa.); Barry King v. LE GP, Case No. 3:20-cv-00719-X (N.D. Tex.); Inter-Marketing Group USA, Inc. v. LE GP, et at., Case No. 2022-0139-SG (Del. Ch.); Elliot v. LE GP LLC, Case No. 3:22-cv-01527-B (N.D. Tex.); Chapa v. Kelcy L. Warren, et al., Index No. 611307/2022 (N.Y. Sup. Ct.); Elliott v. LE GP et al, Cause No. DC-22-14194 (Dallas County, Tex.); and Charles King v. LE GP, LLC et al, Cause No. DC-22-14159 (Dallas County, Texas). The Barry King action that was filed in the United States District Court for the Northern District of Texas (Case No. 3:20-cv-00719-X) has been consolidated with the Bettiol action. On August 9, 2022, the Elliot action that was filed in the United States District Court for the Northern District of Texas (Case No. 3:22-cv-01527-B) was voluntarily dismissed.

Another purported unitholder of Energy Transfer, Allegheny County Employees’ Retirement System (“ACERS”), individually and on behalf of all others similarly situated, filed a suit under the federal securities laws purportedly on behalf of a class, against Energy Transfer and three of Energy Transfer’s directors: Kelcy L. Warren, John W. McReynolds and Thomas E. Long. See Allegheny County Emps.’ Ret. Sys. v. Energy Transfer LP, Case No. 2:20-00200-GAM (E.D. Pa.). On June 15, 2020, ACERS filed an amended complaint and added as additional defendants Energy Transfer directors Marshall McCrea and Matthew S. Ramsey, as well as Michael J. Hennigan and Joseph McGinn. The amended complaint asserts claims for violations of Sections 10(b) and 20(a) of the Exchange Act and Rule 10b-5 promulgated thereunder related primarily to matters involving the construction of pipelines in Pennsylvania. On August 14, 2020, the defendants filed a motion to dismiss ACERS’ amended complaint. On April 6, 2021, the court granted in part and denied in part the defendants’ motion to dismiss. The court held that ACERS could proceed with its claims regarding certain statements put at issue by the amended complaint while also dismissing claims based on other statements. The court also dismissed without prejudice the claims against defendants McReynolds, McGinn and Hennigan. Discovery is ongoing. On August 23, 2022, the court granted in part and denied in part ACERS’ motion for class certification. The court certified a class consisting of those who purchased or otherwise acquired common units of Energy Transfer between February 25, 2017 and November 11, 2019.

On June 3, 2022, another purported unitholder of Energy Transfer, Mike Vega, filed suit, purportedly on behalf of a class, against Energy Transfer and Messrs. Warren, Long, McCrea and Whitehurst. See Vega v. Energy Transfer LP et al., Case No. 1:22-cv-4614 (S.D.N.Y.). The action asserts claims for violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder related primarily to statements made in connection with the

construction of Rover. On August 10, 2022, the court appointed the New Mexico State Investment Council and Public Employees Retirement Association of New Mexico (the “New Mexico Funds”) as lead plaintiffs. New Mexico Funds filed an amended complaint on September 30, 2022 and added as additional defendants Energy Transfer directors John W. McReynolds and Matthew S. Ramsey. On November 7, 2022, the court granted the defendants’ motion to transfer and transferred this action to the United States District Court for the Northern District of Texas. On January 27, 2023, the defendants filed their motion to dismiss the New Mexico Funds’ amended complaint.

The defendants cannot predict the outcome of these lawsuits or any lawsuits that might be filed subsequent to the date of this filing, nor can the defendants predict the amount of time and expense that will be required to resolve these lawsuits. However, the defendants believe that the claims are without merit and intend to vigorously contest them.

Cline Class Action

On July 7, 2017, Perry Cline filed a class action complaint in the Eastern District of Oklahoma against Sunoco, Inc. (R&M), LLC (now known as Energy Transfer R&M) and Energy Transfer Marketing & Terminals L.P. (collectively, “ETMT”) that alleged ETMT failed to make timely payments of oil and gas proceeds from Oklahoma wells and to pay statutory interest for those untimely payments. On October 3, 2019, the District Court certified a class to include all persons who received untimely payments from Oklahoma wells on or after July 7, 2012, and who have not already been paid statutory interest on the untimely payments (the “Class”). Excluded from the Class are those entitled to payments of proceeds that qualify as “minimum pay,” prior period adjustments and pass through payments, as well as governmental agencies and publicly traded oil and gas companies.

After a bench trial, on August 17, 2020, Judge John Gibney (sitting from the Eastern District of Virginia) issued an opinion that awarded the Class actual damages of $74.8 million for late payment interest for identified and unidentified royalty owners and interest-on-interest. This amount was later amended to $80.7 million to account for interest accrued from trial (the “Order”). Judge Gibney also awarded punitive damages in the amount of $75 million. The Class is also seeking attorneys’ fees.

On August 27, 2020, ETMT filed its Notice of Appeal with the 10th Circuit Court of Appeals (“10th Circuit”) and appealed the entirety of the Order. The matter was fully briefed, and oral argument was set for November 15, 2021. However, on November 1, 2021, the 10th Circuit dismissed the appeal due to jurisdictional concerns with finality of the Order. En banc rehearing of this decision was denied on November 29, 2021. On December 1, 2021, ETMT filed a Petition for Writ of Mandamus to the 10th Circuit to correct the jurisdictional problems and secure final judgment. On February 2, 2022, the 10th Circuit denied the Petition for Writ of Mandamus, citing that there are other avenues for ETMT to obtain adequate relief. On February 10, 2022, ETMT filed a Motion to Modify the Plan of Allocation Order and Issue a Rule 58 Judgment with the trial court, requesting the District Court to enter a final judgment in compliance with the Rules. ETMT also filed an injunction with the trial court to enjoin all efforts by plaintiffs to execute on any non-final judgment. On March 31, 2022, Judge Gibney denied the Motion to Modify the Plan of Allocation, reiterating his thoughts that the order constitutes a final judgment. Judge Gibney granted the injunction in part (placing a hold on enforcement efforts for 60 days) and denied the injunction in part. The injunction has since been lifted.

Despite the fact that ETMT has taken the position that the judgment is not final and not subject to execution, the Class engaged in asset discovery and actively tried to collect on the judgment through garnishment proceedings from ETMT’s customers. ETMT unsuccessfully tried to deposit the funds into the District Court’s Registry. Accordingly, to stop the garnishment proceedings, on December 2, 2022, ETMT wired approximately $161 million to the Plaintiff’s approved Plan Administrator, which represents 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 is now back at the trial court so that the district court can fix the finality requirements with the judgment. Further, ETMT sought and recovered a return of funds deposited with the Plan Administrator; Class Counsel did not oppose this motion.

At a status hearing on September 28, 2023, Class Counsel indicated that it would seek additional interest up until the date that the final judgment is entered. The District Court asked for briefing on the issue of additional interest and held a hearing

on October 17, 2023 to address this issue further and enter a ruling as to whether additional interest should be added to the judgment total. During the hearing, the District Court ruled that additional interest should be awarded at the 12% statutory rate from the date of the prior improper judgment up until October 17, 2023. However, the Judge tolled the running of interest for the time period during which the Plan Administrator was in possession of Sunoco’s funds (between November 2, 2022 and October 10, 2023). Based on this ruling, the Class calculated that approximately $23 million in additional interest should be added to the final judgment. On October 19, 2023, the District Court entered the new final judgment with a corrected Plan of Allocation. Both Parties agree that this newly entered judgment fixes the finality concerns and will allow an appeal to the 10th Circuit on the merits. With the inclusion of additional interest, the total amount awarded to the Plaintiffs is approximately $104 million in actual damages and $75 million in punitive damages. Sunoco intends on appealing the entirety of the judgment.

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 $93 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 $93 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.

On September 20, 2023, the Court held oral argument on the various Motions for Summary Judgment. Following oral argument, on September 26, 2023, the Court ruled on each of the Motions. The Court denied Defendants’ Traditional Motion for Partial Summary Judgment Regarding Fraud, Defendants’ No Evidence Motion for Summary Judgment Regarding Plaintiffs’ Fraud and Alter Ego Claims, Defendants’ Traditional and No Evidence Motion for Partial Summary Judgment Regarding Damages and Rescission, and Plaintiff ETC Texas Pipeline, Ltd.’s Traditional Motion for Partial Summary Judgment on Breach of Contract and Declaratory Judgment. The Court granted Culberson Midstream, LLC’s Traditional Motion for Partial Summary Judgment Seeking Dismissal of Plaintiffs’ Breach of Contract and Declaratory Judgment Claims and Culberson Midstream Equity, LLC and Moontower Resources Gathering, LLC’s Motion for Partial Summary Judgment Regarding Breach of the Option Agreement.

Discovery has closed in this matter. Trial on the remaining issues is currently set for June 18, 2024. Plaintiffs cannot predict the ultimate outcome of this litigation or the amount of time and expense that will be required to resolve it.

Massachusetts Attorney General v. New England Gas Company

On July 7, 2011, the Massachusetts Attorney General (the “MA AG”) filed a regulatory complaint with the Massachusetts Department of Public Utilities (“DPU”) against New England Gas Company (“NEG”) with respect to certain environmental cost recoveries. NEG was an operating division of Southern Union Company (“SUG”), and the NEG assets were acquired in connection with the merger transaction with Energy Transfer in March 2012. Subsequent to the merger, in 2013, SUG sold the NEG assets to Liberty Utilities (“Liberty,” and together with NEG and SUG, “Respondents”) and retained certain potential liabilities, including the environmental cost recoveries with respect to the pending complaint before the DPU. Specifically, the MA AG seeks a refund to NEG’s ratepayers for approximately $18 million in legal fees associated with SUG environmental response activities. The MA AG requests that the DPU initiate an investigation into NEG’s collection and reconciliation of recoverable environmental costs, namely: (1) the legal fees charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005; (2) the legal fees charged by the Bishop, London & Dodds firm and passed through the recovery mechanisms since 2005; and (3) the legal fees passed through the recovery mechanism that the MA AG contends only qualify for a lesser (i.e., 50 percent) 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 directs 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 states that the MDPU will set a new procedural schedule in this matter sometime after NEG complies with the directives in the order. Respondents cannot predict the ultimate outcome of this regulatory proceeding, nor can they predict the amount of time and expense that will be required to resolve these claims; however, Respondents will vigorously defend themselves against the MA AG’s claims.

Environmental Matters

Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and

criminal penalties, the imposition of investigatory, remedial and corrective action obligations, natural resource damages, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.

Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on our results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.

Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.

Environmental Remediation

Our subsidiaries are responsible for environmental remediation at certain sites, including the following:

•Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of 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, 2023, the Partnership had been named as a PRP at approximately 31 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. The Partnership is usually one of a number of companies identified as a PRP at a site. The Partnership has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon the Partnership’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.

To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets.

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


	September 30, 2023		December 31, 2022
Current	$	44	$	54
Non-current	240		228
Total environmental liabilities	$	284	$	282

We have established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.

During the nine months ended September 30, 2023 and 2022, the Partnership recorded $23 million and $8 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.

Inventories (Notes)

9 Months Ended

Sep. 30, 2023

Inventory, Net [Abstract]

Inventories

INVENTORIES

Inventories consisted of the following:


	September 30, 2023		December 31, 2022
Natural gas, NGLs and refined products	$	1,951	$	1,802
Crude oil	169		246
Spare parts and other	470		413
Total inventories	$	2,590	$	2,461

Sunoco LP’s fuel inventories are stated at the lower of cost or market using the last-in, first-out (“LIFO”) method. As of September 30, 2023 and December 31, 2022, the carrying value of Sunoco LP’s fuel inventory included lower of cost or market reserves of $3 million and $116 million, respectively. For the three and nine months ended September 30, 2023 and 2022, 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, 2023 and 2022, the Partnership’s cost of products sold included favorable inventory adjustments of $141 million and unfavorable inventory adjustments of $40 million, respectively, related to Sunoco LP’s LIFO inventory. For the nine months ended September 30, 2023 and 2022, the Partnership’s cost of products sold included favorable inventory adjustments of $113 million and favorable inventory adjustments of $81 million, respectively, related to Sunoco LP’s LIFO inventory.

Cash And Cash Equivalents Cash and Cash Equivalents (Policies)	9 Months Ended
	Sep. 30, 2023
Supplemental Cash Flow Information [Abstract]
Cash and Cash Equivalents, Unrestricted Cash and Cash Equivalents, Policy [Policy Text Block]	Cash and cash equivalents include all cash on hand, demand deposits and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value. The Partnership’s consolidated balance sheets did not include any material amounts of restricted cash as of September 30, 2023 or December 31, 2022. We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Schedule of Right of Way Expense (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Commitments and Contingencies Disclosure [Abstract]
ROW Expense	$ 20	$ 16	$ 46	$ 44

Acquisitions and Related Transactions (Details) $ in Millions			9 Months Ended
	May 02, 2023 USD ($) shares	May 01, 2023 USD ($) sites	Sep. 30, 2023 USD ($) shares
Business Acquisition [Line Items]
Equity Issued in Business Combination, Fair Value Disclosure	$ 574
Lotus Midstream LLC
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	1,504		$ 1,500
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets	61
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment [Abstract]	1,263
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets	4
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill	75
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets	1,551
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities	27
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other	16
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities	43
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	1,508
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents	$ 4
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable Fair Value Method \| shares	44,500,000		44,500,000
Lotus Midstream LLC \| Investments in Unconsolidated Affiliates
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Assets	$ 138
Lotus Midstream LLC \| Lease right-of-use assets, net
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Assets	$ 10
Lotus Midstream LLC \| Cash and Cash Equivalents
Business Acquisition [Line Items]
Business Combination, Consideration Transferred			$ 930
Zenith Energy
Business Acquisition [Line Items]
Business Combination, Price of Acquisition, Expected		$ 111
Zenith Energy \| Refineries
Business Acquisition [Line Items]
Number of Units in Real Estate Property \| sites		16
Crestwood
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares \| shares			2.07

Reportable Segments Table - Revenues (External and Intersegment) by Investments (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Revenues	$ (20,739)	$ (22,939)	$ (58,054)	$ (69,375)
Intersegment Eliminations [Member]
Revenues	3,112	5,212	(9,391)	(14,971)
Intrastate Transportation And Storage [Member]
Revenues	(973)	(2,383)	(3,070)	(6,218)
Investment In Sunoco LP [Member]
Revenues	(6,320)	(6,594)	(17,427)	(19,811)
Investment In USAC [Member]
Revenues	(217)	(179)	(621)	(514)
Interstate Transportation and Storage [Member]
Revenues	(571)	(549)	(1,755)	(1,645)
Midstream [Member]
Revenues	(2,777)	(4,871)	(7,999)	(13,846)
NGL and refined products transportation and services [Member]
Revenues	(5,260)	(6,075)	(15,864)	(19,909)
Crude oil transportation and services [Member]
Revenues	(7,289)	(6,416)	(19,322)	(19,642)
Other Segments [Member]
Revenues	(444)	(1,084)	(1,387)	(2,761)
Intersegment [Member] \| Intrastate Transportation And Storage [Member]
Revenues	(93)	(302)	(646)	(668)
Intersegment [Member] \| Investment In Sunoco LP [Member]
Revenues	(3)	(17)	(32)	(44)
Intersegment [Member] \| Investment In USAC [Member]
Revenues	(5)	(3)	(16)	(11)
Intersegment [Member] \| Interstate Transportation and Storage [Member]
Revenues	(9)	(16)	(35)	(54)
Intersegment [Member] \| Midstream [Member]
Revenues	(2,002)	(3,756)	(5,629)	(10,447)
Intersegment [Member] \| NGL and refined products transportation and services [Member]
Revenues	(891)	(906)	(2,654)	(3,265)
Intersegment [Member] \| Crude oil transportation and services [Member]
Revenues	0	(1)	(1)	(2)
Intersegment [Member] \| Other Segments [Member]
Revenues	(109)	(211)	(378)	(480)
External Customers [Member] \| Intrastate Transportation And Storage [Member]
Revenues	(880)	(2,081)	(2,424)	(5,550)
External Customers [Member] \| Investment In Sunoco LP [Member]
Revenues	(6,317)	(6,577)	(17,395)	(19,767)
External Customers [Member] \| Investment In USAC [Member]
Revenues	(212)	(176)	(605)	(503)
External Customers [Member] \| Interstate Transportation and Storage [Member]
Revenues	(562)	(533)	(1,720)	(1,591)
External Customers [Member] \| Midstream [Member]
Revenues	(775)	(1,115)	(2,370)	(3,399)
External Customers [Member] \| NGL and refined products transportation and services [Member]
Revenues	(4,369)	(5,169)	(13,210)	(16,644)
External Customers [Member] \| Crude oil transportation and services [Member]
Revenues	(7,289)	(6,415)	(19,321)	(19,640)
External Customers [Member] \| Other Segments [Member]
Revenues	$ (335)	$ (873)	$ (1,009)	$ (2,281)

Consolidated Statement Of Equity - USD ($) $ in Millions	Total	Common Unitholders	Preferred Unitholders	General Partner	AOCI	Noncontrolling Interests
Balance, Beginning of Period at Dec. 31, 2021	$ 39,345	$ 25,230	$ 6,051	$ (4)	$ 23	$ 8,045
Partners' Capital Account, Distributions	(608)	(528)	(80)	0	0	0
Distributions to noncontrolling interests	307	0	0	0	0	307
Capital contributions from noncontrolling interests	(373)	0	0	0	0	(373)
Other comprehensive loss, net of tax	25	0	0	0	20	5
Other, net	27	17	0	0	0	10
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest	1,474	1,162	106	1	0	205
Balance, End of Period at Mar. 31, 2022	40,329	25,881	6,077	(3)	43	8,331
Balance, Beginning of Period at Dec. 31, 2021	39,345	25,230	6,051	(4)	23	8,045
Other comprehensive loss, net of tax	12
Net income	4,431
Balance, End of Period at Sep. 30, 2022	40,568	26,725	6,077	(3)	32	7,737
Balance, Beginning of Period at Mar. 31, 2022	40,329	25,881	6,077	(3)	43	8,331
Partners' Capital Account, Distributions	(735)	(603)	(131)	(1)	0	0
Distributions to noncontrolling interests	446	0	0	0	0	446
Capital contributions from noncontrolling interests	(24)	0	0	0	0	(24)
Other comprehensive loss, net of tax	(28)	0	0	0	(14)	(14)
Other, net	11	9	0	0	0	2
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest	1,610	1,220	105	1	0	284
Balance, End of Period at Jun. 30, 2022	40,765	26,507	6,051	(3)	29	8,181
Partners' Capital Account, Distributions	(775)	(694)	(80)	(1)	0	0
Distributions to noncontrolling interests	424	0	0	0	0	424
Capital contributions from noncontrolling interests	(7)	0	0	0	0	(7)
Other comprehensive loss, net of tax	15	0	0	0	12	3
Noncontrolling Interest, Decrease from Deconsolidation	346	0	0	0	9	337
Other, net	16	13	0	0	0	3
Net income	1,322
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest	1,310	899	106	1	0	304
Balance, End of Period at Sep. 30, 2022	40,568	26,725	6,077	(3)	32	7,737
Balance, Beginning of Period at Dec. 31, 2022	40,659	26,960	6,051	(2)	16	7,634
Partners' Capital Account, Distributions	(1,001)	(920)	(80)	(1)	0	0
Distributions to noncontrolling interests	441	0	0	0	0	441
Capital contributions from noncontrolling interests	(3)	0	0	0	0	(3)
Other comprehensive loss, net of tax	(3)	0	0	0	(3)	0
Other, net	18	14	0	0	0	4
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest	1,434	1,003	109	1	0	321
Balance, End of Period at Mar. 31, 2023	40,669	27,057	6,080	(2)	13	7,521
Balance, Beginning of Period at Dec. 31, 2022	40,659	26,960	6,051	(2)	16	7,634
Other comprehensive loss, net of tax	3
Net income	3,727
Balance, End of Period at Sep. 30, 2023	40,561	27,014	6,083	(2)	29	7,437
Balance, Beginning of Period at Mar. 31, 2023	40,669	27,057	6,080	(2)	13	7,521
Partners' Capital Account, Distributions	(1,094)	(942)	(151)	(1)	0	0
Distributions to noncontrolling interests	421	0	0	0	0	421
Other comprehensive loss, net of tax	1	0	0	0	1	0
Partners' Capital Account, Acquisitions	574	574	0	0	0	0
Other, net	14	1	0	0	10	3
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest	1,219	797	113	1	0	308
Balance, End of Period at Jun. 30, 2023	40,962	27,487	6,042	(2)	24	7,411
Partners' Capital Account, Distributions	(1,029)	(952)	(77)	0	0	0
Distributions to noncontrolling interests	428	0	0	0	0	428
Other comprehensive loss, net of tax	5	0	0	0	5	0
Other, net	16	13	0	0	0	3
Net income	1,047
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest	1,035	466	118	0	0	451
Balance, End of Period at Sep. 30, 2023	$ 40,561	$ 27,014	$ 6,083	$ (2)	$ 29	$ 7,437

Net Income per Limited Partner Unit (Tables)

9 Months Ended

Sep. 30, 2023

Earnings Per Share [Abstract]

Reconciliation Of Net Income And Weighted Average Units

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Net income	$	1,047	$	1,322	$	3,727	$	4,431
Less: Net income attributable to noncontrolling interests	451		304		1,080		793
Less: Net income attributable to redeemable noncontrolling interests	12		12		39		37
Net income, net of noncontrolling interests	584		1,006		2,608		3,601
Less: General Partner’s interest in net income	—		1		2		3
Less: Preferred Unitholders’ interest in net income	118		106		340		317
Common Unitholders’ interest in net income	$	466	$	899	$	2,266	$	3,281
Basic Income per Common Unit:
Weighted average common units	3,144.0		3,087.6		3,122.3		3,085.6
Basic income per common unit	$	0.15	$	0.29	$	0.73	$	1.06

Diluted Income per Common Unit:
Common Unitholders’ interest in net income	$	466	$	899	$	2,266	$	3,281
Dilutive effect of equity-based compensation of subsidiaries (1)	1		—		2		2
Diluted income attributable to Common Unitholders	$	465	$	899	$	2,264	$	3,279
Weighted average common units	3,144.0		3,087.6		3,122.3		3,085.6
Dilutive effect of unvested restricted unit awards (1)	23.7		21.0		23.6		20.8
Weighted average common units, assuming dilutive effect of unvested restricted unit awards	3,167.7		3,108.6		3,145.9		3,106.4
Diluted income per common unit	$	0.15	$	0.29	$	0.72	$	1.06

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

Cash And Cash Equivalents Net Change in Operating Assets and Liabilities (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Accounts receivable	$ (1,125)	$ (999)
Accounts receivable from related companies	(8)	17
Inventories	(3)	(287)
Other current assets	208	(176)
Other non-current assets, net	(135)	106
Accounts payable	1,076	599
Accounts payable to related companies	(12)	1
Accrued and other current liabilities	562	585
Other non-current liabilities	669	254
Derivative assets and liabilities, net	(50)	(312)
Net change in operating assets and liabilities, net of effects of acquisitions and divestitures	$ (1,182)	$ 212

Redeemable Noncontrolling Interest (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Redeemable noncontrolling interests	$ 498	$ 493
USAC Preferred Units
Redeemable noncontrolling interests	477
Noncontrolling Interests
Redeemable noncontrolling interests	$ 21	$ 16

Acquisitions and Related Transactions

9 Months Ended

Sep. 30, 2023

Business Combination and Asset Acquisition [Abstract]

Business Combination Disclosure

ACQUISITIONS

Pending Crestwood Acquisition

On August 16, 2023, the Partnership announced its entry into a definitive merger agreement to acquire Crestwood Equity Partners LP (“Crestwood”). Under the terms of the merger agreement, Crestwood’s common unitholders will receive 2.07 Energy Transfer common units for each Crestwood common unit. Crestwood owns gathering and processing assets located in the Williston, Delaware and Powder River basins. On October 30, 2023, a majority of Crestwood’s unitholders voted to approve the merger. The transaction is expected to close on November 3, 2023, subject to customary closing conditions.

Lotus Midstream Acquisition

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

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


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

Total assets	1,551

Total current liabilities	27

Other non-current liabilities	16
Total liabilities	43



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

Sunoco LP’s Acquisition

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

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Table - Accrued Environmental Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Environmental Exit Cost [Line Items]
Current	$ 44	$ 54
Non-current	240	228
Total environmental liabilities	$ 284	$ 282

Derivative Assets And Liabilities

9 Months Ended

Sep. 30, 2023

General Discussion of Derivative Instruments and Hedging Activities [Abstract]

Derivative Assets And Liabilities

DERIVATIVE ASSETS AND LIABILITIES

Commodity Price Risk

We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets.

We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off-peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated

derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized.

We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales in our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes.

We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes.

We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of natural gas, refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.

We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales. These contracts are not designated as hedges for accounting purposes.

We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our intrastate transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our intrastate transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.

The following table details our outstanding commodity-related derivatives:


	September 30, 2023		December 31, 2022
	Notional Volume	Maturity	Notional Volume	Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Fixed Swaps/Futures	330	2023-2024	145	2023
Basis Swaps IFERC/NYMEX (1)	(44,800)	2023-2024	(39,563)	2023



Power (Megawatt):
Forwards	171,600	2023-2029	—	2023-2029
Futures	(74,391)	2023-2024	(21,384)	2023
Options – Puts	68,800	2023-2024	119,200	2023
Options – Calls	—	2023-2024	—	—



(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	48,393	2023-2025	42,440	2023-2024
Swing Swaps IFERC	(72,220)	2023-2025	(202,815)	2023-2024
Fixed Swaps/Futures	(4,803)	2023-2025	(15,758)	2023-2025
Forward Physical Contracts	(2,145)	2023-2025	2,423	2023-2024

NGLs (MBbls) – Forwards/Swaps	(14,238)	2023-2026	6,934	2023-2025
Crude (MBbls) – Forwards/Swaps	(7,660)	2023-2025	795	2023-2024
Refined Products (MBbls) – Futures	(5,751)	2023-2025	(3,547)	2023-2024

Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(43,745)	2023-2024	(37,448)	2023
Fixed Swaps/Futures	(43,745)	2023-2024	(37,448)	2023
Hedged Item – Inventory	43,745	2023-2024	37,448	2023

(1)Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.

Interest Rate Risk

We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.

The following table summarizes our interest rate swaps outstanding (including USAC’s), none of which were designated as hedges for accounting purposes:

Term

Type(1)

Notional Amount Outstanding

September 30,
2023

December 31,
2022

Energy Transfer:

July 2024(2)

Forward-starting to pay an average fixed rate of 3.388% and receive a floating rate

—

400

USAC:

April 2025(3)

Pay a fixed rate of 3.785% and receive a floating rate (effective April 2023)

700

—

(1)Floating rates are based on SOFR.

(2)The July 2024 interest rate swaps were terminated and settled in August 2023.

(3)In October 2023, USAC modified its April 2025 interest rate swap. The termination date was extended from April 1, 2025 to December 31, 2025. Under the modified interest rate swap, USAC pays a fixed interest rate of 3.9725% and continues to receive floating interest rate payments that are indexed to the one-month SOFR.

Credit Risk

Credit risk refers to the risk that a counterparty may default on its contractual obligations, resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.

Our natural gas transportation and midstream revenues are derived significantly from companies that engage in exploration and production activities. In addition to oil and gas producers, the Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrial end-users, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect on our financial position or results of operations as a consequence of counterparty non-performance.

The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily with independent system operators and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.

For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.

Derivative Summary

The following table provides a summary of our derivative assets and liabilities:


	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	September 30, 2023		December 31, 2022		September 30, 2023		December 31, 2022
Derivatives designated as hedging instruments:
Commodity derivatives – margin deposits	$	23	$	87	$	(7)	$	(7)
	23		87		(7)		(7)
Derivatives not designated as hedging instruments:
Commodity derivatives – margin deposits	311		506		(371)		(411)
Commodity derivatives	71		95		(71)		(108)
Interest rate derivatives	14		—		—		(23)
	396		601		(442)		(542)
Total derivatives	$	419	$	688	$	(449)	$	(549)

The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:


		Asset Derivatives				Liability Derivatives
	Balance Sheet Location	September 30, 2023		December 31, 2022		September 30, 2023		December 31, 2022
Derivatives without offsetting agreements	Derivative assets (liabilities)	$	14	$	—	$	—	$	(23)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	71		95		(71)		(108)
Broker cleared derivative contracts	Other current assets (liabilities)	334		593		(378)		(418)
Total gross derivatives		419		688		(449)		(549)
Offsetting agreements:

Counterparty netting	Derivative assets (liabilities)	(67)		(85)		67		85
Counterparty netting	Other current assets (liabilities)	(303)		(359)		303		359
Total net derivatives		$	49	$	244	$	(79)	$	(105)

We disclose the non-exchange traded financial derivative instruments as derivative assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.

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


	Location	Amount of Gain (Loss) Recognized in Income on Derivatives
		Three Months Ended September 30,				Nine Months Ended September 30,
		2023		2022		2023		2022
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	4	$	22	$	(6)	$	50
Commodity derivatives – Non-trading	Cost of products sold	(166)		186		(106)		(6)

Interest rate derivatives	Gains on interest rate derivatives	32		60		47		303

Total		$	(130)	$	268	$	(65)	$	347

Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Net income	$ 1,047	$ 1,322	$ 3,727	$ 4,431
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities	2	(4)	2	(13)
Actuarial gain related to pension and other postretirement benefit plans	0	0	0	7
Foreign currency translation adjustments	0	13	(5)	(6)
Change in other comprehensive income from unconsolidated affiliates	3	6	6	24
Other comprehensive income (loss), net of tax	5	15	3	12
Comprehensive income	1,052	1,337	3,730	4,443
Less: Comprehensive income attributable to noncontrolling interests	451	307	1,080	787
Less: Net income attributable to redeemable noncontrolling interests	12	12	39	37
Comprehensive income attributable to partners	$ 589	$ 1,018	$ 2,611	$ 3,619

Revenue (Tables)

9 Months Ended

Sep. 30, 2023

Revenue [Abstract]

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

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


	Contract Liabilities
Balance, December 31, 2022	$	615
Additions	794
Revenue recognized	(836)

Balance, September 30, 2023	$	573

Balance, December 31, 2021	$	459
Additions	815
Revenue recognized	(688)
Other	(13)
Balance, September 30, 2022	$	573

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


	September 30, 2023		December 31, 2022

Contract assets	$	239	$	200
Accounts receivable from contracts with customers	1,079		834

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction

As of September 30, 2023, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations was $39.83 billion. The Partnership expects to recognize this amount as revenue within the time bands illustrated in the following table:


	Years Ending December 31,
	2023
	(remainder)		2024		2025		Thereafter		Total
Revenue expected to be recognized on contracts with customers existing as of September 30, 2023	$	2,176	$	7,345	$	6,247	$	24,062	$	39,830

Redeemable Noncontrolling Interest (Notes)	9 Months Ended
Redeemable Noncontrolling Interest (Notes)	Sep. 30, 2023
Temporary Equity Disclosure [Abstract]
Redeemable Noncontrolling Interest [Text Block]	REDEEMABLE NONCONTROLLING INTERESTSCertain redeemable noncontrolling interests in the Partnership’s subsidiaries were reflected as mezzanine equity on the consolidated balance sheets. Redeemable noncontrolling interests as of September 30, 2023 and December 31, 2022 included a balance of $477 million related to the USAC Series A preferred units. Redeemable noncontrolling interests also included a balance of $21 million as of September 30, 2023 and $16 million as of December 31, 2022 related to noncontrolling interest holders in one of the Partnership’s consolidated subsidiaries that have the option to sell their interests to the Partnership.

Revenue (Notes)

9 Months Ended

Sep. 30, 2023

Revenue [Abstract]

Revenue from Contract with Customer [Text Block]

REVENUE

Disaggregation of Revenue

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

Contract Balances with Customers

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

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

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

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


	Contract Liabilities
Balance, December 31, 2022	$	615
Additions	794
Revenue recognized	(836)

Balance, September 30, 2023	$	573

Balance, December 31, 2021	$	459
Additions	815
Revenue recognized	(688)
Other	(13)
Balance, September 30, 2022	$	573

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


	September 30, 2023		December 31, 2022

Contract assets	$	239	$	200
Accounts receivable from contracts with customers	1,079		834

Performance Obligations

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


	Years Ending December 31,
	2023
	(remainder)		2024		2025		Thereafter		Total
Revenue expected to be recognized on contracts with customers existing as of September 30, 2023	$	2,176	$	7,345	$	6,247	$	24,062	$	39,830

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 9
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-9

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

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 15
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-15

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-12

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

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

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

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

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (b)(2)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-13

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Name Accounting Standards Codification
-Topic 606
-Publisher FASB
-URI https://asc.fasb.org//606/tableOfContent

+ Details

Inventories (Tables)

9 Months Ended

Sep. 30, 2023

Inventory, Net [Abstract]

Schedule Of Inventory

Inventories consisted of the following:


	September 30, 2023		December 31, 2022
Natural gas, NGLs and refined products	$	1,951	$	1,802
Crude oil	169		246
Spare parts and other	470		413
Total inventories	$	2,590	$	2,461

Fair Value Measurements Fair Value Measurements (Policies)	9 Months Ended
	Sep. 30, 2023
Fair Value Disclosures [Abstract]
Fair Value Measurement, Policy [Policy Text Block]	We have commodity derivatives and interest rate derivatives that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider options transacted through a clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. The valuation methodologies employed for our interest rate derivatives do not necessitate material judgment, and the inputs are observed from actively quoted public markets and therefore are categorized in Level 2. Level 3 inputs are unobservable. During the nine months ended September 30, 2023, no transfers were made between any levels within the fair value hierarchy.

Equity - Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	6 Months Ended	9 Months Ended
	Jun. 30, 2023	Sep. 30, 2023	Dec. 31, 2022
Equity [Abstract]
Available-for-sale securities		$ 11	$ 9
Foreign currency translation adjustment	$ 1	6
Actuarial gain related to pensions and other postretirement benefits	$ (7)	(7)
AOCI attributable to equity method investments		19	13
Accumulated other comprehensive income		$ 29	$ 16

- Definition

Amount, after tax, of accumulated increase (decrease) in equity from transaction and other event and circumstance from nonowner source.

+ References + Details

Inventories Inventory Narrative (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022
Inventory [Line Items]
Inventory valuation adjustments	$ (141)	$ 40	$ (113)	$ (81)
Sunoco LP [Member]
Inventory [Line Items]
Inventory, LIFO Reserve	$ 3		$ 3		$ 116

Reportable Segments (Tables)

9 Months Ended

Sep. 30, 2023

Financial Information By Segment

The following tables present financial information by segment:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	880	$	2,081	$	2,424	$	5,550
Intersegment revenues	93		302		646		668
	973		2,383		3,070		6,218
Interstate transportation and storage:
Revenues from external customers	562		533		1,720		1,591
Intersegment revenues	9		16		35		54
	571		549		1,755		1,645
Midstream:
Revenues from external customers	775		1,115		2,370		3,399
Intersegment revenues	2,002		3,756		5,629		10,447
	2,777		4,871		7,999		13,846
NGL and refined products transportation and services:
Revenues from external customers	4,369		5,169		13,210		16,644
Intersegment revenues	891		906		2,654		3,265
	5,260		6,075		15,864		19,909
Crude oil transportation and services:
Revenues from external customers	7,289		6,415		19,321		19,640
Intersegment revenues	—		1		1		2
	7,289		6,416		19,322		19,642
Investment in Sunoco LP:
Revenues from external customers	6,317		6,577		17,395		19,767
Intersegment revenues	3		17		32		44
	6,320		6,594		17,427		19,811
Investment in USAC:
Revenues from external customers	212		176		605		503
Intersegment revenues	5		3		16		11
	217		179		621		514
All other:
Revenues from external customers	335		873		1,009		2,281
Intersegment revenues	109		211		378		480
	444		1,084		1,387		2,761
Eliminations	(3,112)		(5,212)		(9,391)		(14,971)
Total revenues	$	20,739	$	22,939	$	58,054	$	69,375


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	244	$	301	$	869	$	963
Interstate transportation and storage	491		409		1,468		1,259
Midstream	631		868		1,851		2,578
NGL and refined products transportation and services	1,076		634		2,852		2,097
Crude oil transportation and services	706		461		1,906		1,616
Investment in Sunoco LP	257		276		728		681
Investment in USAC	130		109		373		313
All other	6		30		49		149
Adjusted EBITDA (consolidated)	$	3,541	$	3,088	$	10,096	$	9,656


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Reconciliation of net income to Adjusted EBITDA:
Net income	$	1,047	$	1,322	$	3,727	$	4,431
Depreciation, depletion and amortization	1,107		1,030		3,227		3,104
Interest expense, net of interest capitalized	632		577		1,892		1,714
Income tax expense	77		82		256		159
Impairment losses and other	1		86		12		386
Gains on interest rate derivatives	(32)		(60)		(47)		(303)
Non-cash compensation expense	35		27		99		88
Unrealized (gains) losses on commodity risk management activities	107		(76)		182		(130)
Inventory valuation adjustments (Sunoco LP)	(141)		40		(113)		(81)

Adjusted EBITDA related to unconsolidated affiliates	182		147		514		409
Equity in earnings of unconsolidated affiliates	(103)		(68)		(286)		(186)
Non-operating litigation-related loss	625		—		625		—
Other, net	4		(19)		8		65
Adjusted EBITDA (consolidated)	$	3,541	$	3,088	$	10,096	$	9,656

Equity - Quarterly Distributions of Available Cash (Details) - $ / shares

3 Months Ended

9 Months Ended

Sep. 30, 2023

Jun. 30, 2023

Mar. 31, 2023

Dec. 31, 2022

Sep. 30, 2023

Feb. 15, 2028

May 15, 2024

Aug. 15, 2023

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.3125

$ 0.3100

$ 0.3075

$ 0.3050

Series A Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

24.672

^[1]

23.891

^[2]

21.982

^[2]

31.250

^[2]

Preferred Stock, Dividend Rate, Percentage

6.25%

Shares Issued, Price Per Share

$ 1,000

Preferred Units, Liquidation Spread, Percent

4.028%

Series A Preferred Units [Member] | Tenor spread adjustment

Preferred Units, Liquidation Spread, Percent

0.26161%

Series B Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[1]

$ 0

33.125

Series B Preferred Units [Member] | Subsequent Event

Preferred Units, Liquidation Spread, Percent

4.155%

Series B Preferred Units [Member] | Subsequent Event | Tenor spread adjustment

Preferred Units, Liquidation Spread, Percent

0.26161%

Series C Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

0.6489

0.6294

^[2]

0.4609

^[2]

0.4609

^[2]

Preferred Stock, Dividend Rate, Percentage

7.375%

Shares Issued, Price Per Share

$ 25

Preferred Units, Liquidation Spread, Percent

4.53%

Series C Preferred Units [Member] | Tenor spread adjustment

Preferred Units, Liquidation Spread, Percent

0.26161%

Series D Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.6622

0.4766

Preferred Stock, Dividend Rate, Percentage

7.625%

Shares Issued, Price Per Share

$ 25

Preferred Units, Liquidation Spread, Percent

4.738%

Series D Preferred Units [Member] | Tenor spread adjustment

Preferred Units, Liquidation Spread, Percent

0.26161%

Series E Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

0.475

Series E Preferred Units [Member] | Subsequent Event

Preferred Units, Liquidation Spread, Percent

5.161%

Series E Preferred Units [Member] | Subsequent Event | Tenor spread adjustment

Preferred Units, Liquidation Spread, Percent

0.26161%

Series F Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[1]

33.750

Series G Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[1]

35.625

Series H Preferred Units

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[1]

32.500

USAC [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

0.525

Sunoco LP [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.8420

$ 0.8255

[1]	Series B, Series F, Series G and Series H distributions are paid on a semi-annual basis.
[2]	See additional information on Series A, Series C and Series D distributions below.

Revenue Revenue (Policies)

9 Months Ended

Sep. 30, 2023

Revenue from Contract with Customer [Abstract]

Revenue [Policy Text Block]

Disaggregation of Revenue

Revenue Recognition, Deferred Revenue [Policy Text Block]

Contract Balances with Customers

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


	Contract Liabilities
Balance, December 31, 2022	$	615
Additions	794
Revenue recognized	(836)

Balance, September 30, 2023	$	573

Balance, December 31, 2021	$	459
Additions	815
Revenue recognized	(688)
Other	(13)
Balance, September 30, 2022	$	573

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

- Definition

Disclosure of accounting policy for revenue from contract with customer.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 17
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-17

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 19
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-19

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 18
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-18

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 18
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-18

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 20
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-20

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 20
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-20

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 20
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-20

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 20
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-20

Reference 9: http://www.xbrl.org/2003/role/exampleRef
-Name Accounting Standards Codification
-Section 50
-Paragraph 4
-Subparagraph (e)
-SubTopic 10
-Topic 235
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147483426/235-10-50-4

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Name Accounting Standards Codification
-Topic 606
-Publisher FASB
-URI https://asc.fasb.org//606/tableOfContent

+ Details

Equity Narrative (Details) - USD ($) $ / shares in Units, $ in Millions	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Feb. 15, 2028	May 15, 2024	Oct. 27, 2023	Aug. 15, 2023	Dec. 31, 2022
Stock Repurchase Program, Remaining Authorized Repurchase Amount	$ 880
Stock Issued During Period, Value, Dividend Reinvestment Plan	$ 70	$ 42
Stock Issued During Period, Shares, Dividend Reinvestment Plan	5,500,000
Common Units Remaining Available to be Issued Under Distribution Reinvestment Plan	6,000,000
USAC Issue Tranche 2
Class of Warrant or Right, Exercise Price of Warrants or Rights							$ 19.59
USAC [Member]
Warrants and Rights Outstanding	$ 10
USAC [Member] \| Subsequent Event
Class of Warrant or Right, Number of Securities Called by Warrants or Rights					2,360,000
Series F Preferred Units [Member]
Preferred Stock, Shares Outstanding	500,000
Series G Preferred Units [Member]
Preferred Stock, Shares Outstanding	1,484,780
Series E Preferred Units [Member]
Preferred Stock, Shares Outstanding	32,000,000
Series E Preferred Units [Member] \| Subsequent Event
Preferred Units, Liquidation Spread, Percent				5.161%
Series E Preferred Units [Member] \| Subsequent Event \| Tenor spread adjustment
Preferred Units, Liquidation Spread, Percent				0.26161%
Series D Preferred Units [Member]
Preferred Stock, Shares Outstanding	17,800,000
Preferred Stock, Dividend Rate, Percentage	7.625%
Shares Issued, Price Per Share	$ 25
Preferred Units, Liquidation Spread, Percent						4.738%
Series D Preferred Units [Member] \| Tenor spread adjustment
Preferred Units, Liquidation Spread, Percent						0.26161%
Series C Preferred Units [Member]
Preferred Stock, Shares Outstanding	18,000,000
Preferred Stock, Dividend Rate, Percentage	7.375%
Shares Issued, Price Per Share	$ 25
Preferred Units, Liquidation Spread, Percent	4.53%					4.53%
Series C Preferred Units [Member] \| Tenor spread adjustment
Preferred Units, Liquidation Spread, Percent						0.26161%
Series B Preferred Units [Member]
Preferred Stock, Shares Outstanding	550,000
Series B Preferred Units [Member] \| Subsequent Event
Preferred Units, Liquidation Spread, Percent			4.155%
Series B Preferred Units [Member] \| Subsequent Event \| Tenor spread adjustment
Preferred Units, Liquidation Spread, Percent			0.26161%
Series A Preferred Units [Member]
Preferred Stock, Shares Outstanding	950,000
Preferred Stock, Dividend Rate, Percentage	6.25%
Shares Issued, Price Per Share	$ 1,000
Preferred Units, Liquidation Spread, Percent	4.028%					4.028%
Series A Preferred Units [Member] \| Tenor spread adjustment
Preferred Units, Liquidation Spread, Percent						0.26161%
Series H Preferred Units
Preferred Stock, Shares Outstanding	900,000

Cash And Cash Equivalents (Tables)

9 Months Ended

Sep. 30, 2023

Supplemental Cash Flow Information [Abstract]

Cash Flow, Operating Capital [Table Text Block]

The net change in operating assets and liabilities, net of effects of acquisitions, included in cash flows from operating activities is comprised as follows:


	Nine Months Ended September 30,
	2023		2022
Accounts receivable	$	(1,125)	$	(999)
Accounts receivable from related companies	(8)		17
Inventories	(3)		(287)
Other current assets	208		(176)
Other non-current assets, net	(135)		106
Accounts payable	1,076		599
Accounts payable to related companies	(12)		1
Accrued and other current liabilities	562		585
Other non-current liabilities	669		254
Derivative assets and liabilities, net	(50)		(312)
Net change in operating assets and liabilities, net of effects of acquisitions and divestitures	$	1,182	$	(212)

Schedule Of Non-Cash Investing and Non-Cash Financing Activities

Non-cash investing and financing activities were as follows:


	Nine Months Ended September 30,
	2023		2022

Accrued capital expenditures	$	354	$	454

Lease assets obtained in exchange for new lease liabilities	26		37
Distribution reinvestment	70		42

Derivative Assets And Liabilities Table - Partnership's Derivative Assets and Liabilities Amount of Gain (Loss) Recognized (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ (130)	$ 268	$ (65)	$ 347
Gains on interest rate derivatives	32	60	47	303
Commodity Derivatives [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	(166)	186	(106)	(6)
Commodity Derivatives - Trading [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ 4	$ 22	$ (6)	$ 50

Equity (Tables)

9 Months Ended

Sep. 30, 2023

Schedule of Capital Units [Table Text Block]

Changes in Energy Transfer common units during the nine months ended September 30, 2023 were as follows:


			Number of Units
Number of common units at December 31, 2022			3,094.4
Common units issued under the distribution reinvestment plan			5.5
Common units issued for Lotus Midstream acquisition			44.5
Common units vested under equity incentive plans and other			0.7
Number of common units at September 30, 2023			3,145.1

Accumulated Other Comprehensive Income

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


	September 30, 2023		December 31, 2022
Unrealized gains on available-for-sale securities	$	11	$	9
Foreign currency translation adjustment	6		1
Actuarial loss related to pensions and other postretirement benefits	(7)		(7)
Investments in unconsolidated affiliates, net	19		13



Total AOCI included in partners’ capital, net of tax	$	29	$	16

Distributions Made to Limited Partner, by Distribution [Table Text Block]

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(1)		Series B(2)		Series C(1)		Series D(1)		Series E		Series F(2)		Series G(2)		Series H(2)
December 31, 2022	February 1, 2023	February 15, 2023	$	31.250	$	33.125	$	0.4609	$	0.4766	$	0.475	$	—	$	—	$	—
March 31, 2023	May 1, 2023	May 15, 2023	21.982		—		0.4609		0.4766		0.475		33.750		35.625		32.500
June 30, 2023	August 1, 2023	August 15, 2023	23.891		33.125		0.6294		0.4766		0.475		—		—		—
September 30, 2023	November 1, 2023	November 15, 2023	24.672		—		0.6489		0.6622		0.475		33.750		35.625		32.500

(1)See additional information on Series A, Series C and Series D distributions below.

(2)Series B, Series F, Series G and Series H distributions are paid on a semi-annual basis.

Schedule of Preferred Units [Table Text Block]

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


	Preferred Unitholders
	Series A		Series B		Series C		Series D		Series E		Series F		Series G		Series H		Total
Balance, December 31, 2022	$	958	$	556	$	440	$	434	$	786	$	496	$	1,488	$	893	$	6,051
Distributions to partners	(30)		(18)		(8)		(9)		(15)		—		—		—		(80)


Net income	18		9		8		9		15		8		27		15		109
Balance, March 31, 2023	946		547		440		434		786		504		1,515		908		6,080

Distributions to partners	(21)		—		(8)		(9)		(15)		(16)		(53)		(29)		(151)

Net income	22		9		9		9		15		8		26		15		113
Balance, June 30, 2023	947		556		441		434		786		496		1,488		894		6,042
Distributions to partners	(22)		(20)		(12)		(8)		(15)		—		—		—		(77)

Net income	23		10		11		10		15		8		27		14		118
Balance, September 30, 2023	$	948	$	546	$	440	$	436	$	786	$	504	$	1,515	$	908	$	6,083


	Preferred Unitholders
	Series A		Series B		Series C		Series D		Series E		Series F		Series G		Series H		Total
Balance, December 31, 2021	$	958	$	556	$	440	$	434	$	786	$	496	$	1,488	$	893	$	6,051
Distributions to partners	(30)		(18)		(8)		(9)		(15)		—		—		—		(80)
Net income	15		9		8		9		15		8		27		15		106
Balance, March 31, 2022	943		547		440		434		786		504		1,515		908		6,077

Distributions to partners	—		—		(8)		(9)		(15)		(16)		(53)		(30)		(131)

Net income	15		9		8		9		15		8		26		15		105
Balance, June 30, 2022	958		556		440		434		786		496		1,488		893		6,051
Distributions to partners	(30)		(18)		(8)		(9)		(15)		—		—		—		(80)

Net income	15		9		8		9		15		8		27		15		106
Balance, September 30, 2022	$	943	$	547	$	440	$	434	$	786	$	504	$	1,515	$	908	$	6,077

Variable Rate Terms [Member]

Schedule of Preferred Units [Table Text Block]

Distributions on the Series B Preferred Units and Series E Preferred Units are scheduled to begin accruing at a floating rate as follows:


	Beginning of floating rate period	Applicable Spread		Tenor spread adjustment		Floating rate
Series B Preferred Units	February 15, 2028	4.155	%	0.26161	%	Three-month SOFR

Series E Preferred Units	May 15, 2024	5.161	%	0.26161	%	Three-month SOFR

Parent Company [Member]

Distributions Made to Limited Partner, by Distribution [Table Text Block]

Distributions declared and/or paid with respect to Energy Transfer common units subsequent to December 31, 2022 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2022

February 7, 2023

February 21, 2023

0.3050

March 31, 2023

May 8, 2023

May 22, 2023

0.3075

June 30, 2023

August 14, 2023

August 21, 2023

0.3100

September 30, 2023

October 30, 2023

November 20, 2023

0.3125

Sunoco LP [Member]

Distributions Made to Limited Partner, by Distribution [Table Text Block]

Distributions on Sunoco LP’s common units declared and/or paid by Sunoco LP subsequent to December 31, 2022 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2022

February 7, 2023

February 21, 2023

0.8255

March 31, 2023

May 8, 2023

May 22, 2023

0.8420

June 30, 2023

August 14, 2023

August 21, 2023

0.8420

September 30, 2023

October 30, 2023

November 20, 2023

0.8420

USA Compression Partners, LP [Member]

Distributions Made to Limited Partner, by Distribution [Table Text Block]

Distributions on USAC’s common units declared and/or paid by USAC subsequent to December 31, 2022 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2022

January 23, 2023

February 3, 2023

0.525

March 31, 2023

April 24, 2023

May 5, 2023

0.525

June 30, 2023

July 24, 2023

August 4, 2023

0.525

September 30, 2023

October 23, 2023

November 3, 2023

0.525

Derivative Assets And Liabilities Derivative Assets and Liabilities (Policies)	9 Months Ended
	Sep. 30, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Concentration Risk, Credit Risk, Policy [Policy Text Block]	Credit Risk Credit risk refers to the risk that a counterparty may default on its contractual obligations, resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties. Our natural gas transportation and midstream revenues are derived significantly from companies that engage in exploration and production activities. In addition to oil and gas producers, the Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrial end-users, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect on our financial position or results of operations as a consequence of counterparty non-performance. The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily with independent system operators and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets. For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.
Derivatives, Policy [Policy Text Block]	Commodity Price Risk We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets. We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off-peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales in our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes. We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes. We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of natural gas, refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes. We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales. These contracts are not designated as hedges for accounting purposes. We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our intrastate transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our intrastate transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy. We disclose the non-exchange traded financial derivative instruments as derivative assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.

Operations And Organization Accounting policy (Policies)	9 Months Ended
	Sep. 30, 2023
Accounting Policies [Abstract]
Basis of Accounting, Policy [Policy Text Block]	Basis of Presentation The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 17, 2023. In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.
Use of Estimates, Policy [Policy Text Block]	Use of Estimates The unaudited consolidated financial statements have been prepared in conformity with GAAP, which requires the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and the accrual for and disclosure of contingent assets and liabilities that exist at the date of the consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates.

Inventories Inventories (Policies)	9 Months Ended
Inventories Inventories (Policies)	Sep. 30, 2023
Inventory Disclosure [Abstract]
Inventory, Policy [Policy Text Block]	Sunoco LP’s fuel inventories are stated at the lower of cost or market using the last-in, first-out (“LIFO”) method. As of September 30, 2023 and December 31, 2022, the carrying value of Sunoco LP’s fuel inventory included lower of cost or market reserves of $3 million and $116 million, respectively. For the three and nine months ended September 30, 2023 and 2022, 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, 2023 and 2022, the Partnership’s cost of products sold included favorable inventory adjustments of $141 million and unfavorable inventory adjustments of $40 million, respectively, related to Sunoco LP’s LIFO inventory. For the nine months ended September 30, 2023 and 2022, the Partnership’s cost of products sold included favorable inventory adjustments of $113 million and favorable inventory adjustments of $81 million, respectively, related to Sunoco LP’s LIFO inventory.

- Definition

Disclosure of inventory accounting policy for inventory classes, including, but not limited to, basis for determining inventory amounts, methods by which amounts are added and removed from inventory classes, loss recognition on impairment of inventories, and situations in which inventories are stated above cost.

+ References + Details

Consolidated Statements Of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
OPERATING ACTIVITIES:
Net income	$ 3,727	$ 4,431
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	3,227	3,104
Deferred income taxes	187	158
Inventory valuation adjustments	(113)	(81)
Non-cash compensation expense	99	88
Impairment losses and other	12	386
Distributions on unvested awards	(47)	(37)
Equity in earnings of unconsolidated affiliates	(286)	(186)
Distributions from unconsolidated affiliates	286	182
Other non-cash	(15)	(120)
Net change in operating assets and liabilities, net of effects of acquisitions and divestitures	1,182	(212)
Net Cash Provided by (Used in) Operating Activities, Continuing Operations	8,259	7,713
INVESTING ACTIVITIES:
Cash paid for acquisitions	(111)	(1,062)
Capital expenditures, excluding allowance for equity funds used during construction	(2,430)	(2,493)
Contributions in aid of construction costs	38	50
Payments for Advance to Affiliate	(5)	0
Distributions from unconsolidated affiliates in excess of cumulative earnings	45	66
Proceeds from Sale of Equity Method Investments	0	302
Proceeds from Sale of Other Assets, Investing Activities	31	60
Payments for (Proceeds from) Other Investing Activities	1	0
Net Cash Provided by (Used in) Investing Activities, Continuing Operations	(3,361)	(3,077)
FINANCING ACTIVITIES:
Proceeds from borrowings	22,912	19,400
Repayments of debt	(23,095)	(21,110)
Capital contributions from noncontrolling interest	3	404
Distributions to partners	(3,124)	(2,118)
Distributions to noncontrolling interests	(1,290)	(1,177)
Preferred Units, Cumulative Cash Distributions	(37)	(37)
Payments of Debt Issuance Costs	(12)	(9)
Other, net	2	1
Net cash used in financing activities	(4,641)	(4,646)
Increase (decrease) in cash and cash equivalents	257	(10)
Cash and cash equivalents, beginning of period	257	336
Cash and cash equivalents, end of period	514	326
Lotus Midstream LLC
INVESTING ACTIVITIES:
Cash paid for acquisitions	$ (930)	$ 0

Consolidated Statements Of Operations - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
REVENUES:
Total revenues	$ 20,739	$ 22,939	$ 58,054	$ 69,375
COSTS AND EXPENSES:
Cost of products sold	16,059	18,516	44,761	56,169
Operating expenses	1,105	973	3,224	2,982
Depreciation, depletion and amortization	1,107	1,030	3,227	3,104
Selling, general and administrative	234	361	700	802
Impairment losses and other	1	86	12	386
Total costs and expenses	18,506	20,966	51,924	63,443
OPERATING INCOME	2,233	1,973	6,130	5,932
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(632)	(577)	(1,892)	(1,714)
Equity in earnings of unconsolidated affiliates	103	68	286	186
Gains on interest rate derivatives	32	60	47	303
Gain (Loss) Related to Litigation Settlement	(625)	0	(625)	0
INCOME BEFORE INCOME TAX EXPENSE	1,124	1,404	3,983	4,590
Income tax expense	77	82	256	159
Net income	1,047	1,322	3,727	4,431
Less: Net income attributable to noncontrolling interests	451	304	1,080	793
Less: Net income attributable to redeemable noncontrolling interests	12	12	39	37
NET INCOME ATTRIBUTABLE TO PARTNERS	584	1,006	2,608	3,601
Less: General Partner’s interest in net income	0	1	2	3
Preferred Unitholders’ interest in net income	118	106	340	317
Common Unitholders’ interest in net income	$ 466	$ 899	$ 2,266	$ 3,281
NET INCOME PER COMMON UNIT:
Basic	$ 0.15	$ 0.29	$ 0.73	$ 1.06
Diluted	$ 0.15	$ 0.29	$ 0.72	$ 1.06
Other, net	$ 13	$ (120)	$ 37	$ (117)
Refined product sales
NET INCOME PER COMMON UNIT:
Revenue	6,403	6,647	17,691	20,043
NGL sales
NET INCOME PER COMMON UNIT:
Revenue	3,760	4,823	11,409	15,828
Natural gas sales
NET INCOME PER COMMON UNIT:
Revenue	878	2,648	2,462	6,830
Other
NET INCOME PER COMMON UNIT:
Revenue	287	218	782	628
Crude sales
NET INCOME PER COMMON UNIT:
Revenue	6,587	5,773	17,298	17,758
Gathering, transportation and other fees
NET INCOME PER COMMON UNIT:
Revenue	$ 2,824	$ 2,830	$ 8,412	$ 8,288

Reportable Segments

9 Months Ended

Sep. 30, 2023

Segment Reporting [Abstract]

Reportable Segments

REPORTABLE SEGMENTS

Our reportable segments, which conduct their business primarily in the United States, are as follows:

•intrastate transportation and storage;

•interstate transportation and storage;

•midstream;

•NGL and refined products transportation and services;

•crude oil transportation and services;

•investment in Sunoco LP;

•investment in USAC; and

•all other.

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

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

We report Segment Adjusted EBITDA and consolidated Adjusted EBITDA as measures of segment performance. We define Segment Adjusted EBITDA and consolidated Adjusted EBITDA as total partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items, as well as certain non-recurring gains and losses. Inventory adjustments that are excluded from the calculation of Adjusted EBITDA represent only the changes in lower of cost or market reserves on inventory that is carried at LIFO. These amounts are unrealized valuation adjustments applied to Sunoco LP’s fuel volumes remaining in inventory at the end of the period.

Segment Adjusted EBITDA and consolidated Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted

EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.

The following tables present financial information by segment:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	880	$	2,081	$	2,424	$	5,550
Intersegment revenues	93		302		646		668
	973		2,383		3,070		6,218
Interstate transportation and storage:
Revenues from external customers	562		533		1,720		1,591
Intersegment revenues	9		16		35		54
	571		549		1,755		1,645
Midstream:
Revenues from external customers	775		1,115		2,370		3,399
Intersegment revenues	2,002		3,756		5,629		10,447
	2,777		4,871		7,999		13,846
NGL and refined products transportation and services:
Revenues from external customers	4,369		5,169		13,210		16,644
Intersegment revenues	891		906		2,654		3,265
	5,260		6,075		15,864		19,909
Crude oil transportation and services:
Revenues from external customers	7,289		6,415		19,321		19,640
Intersegment revenues	—		1		1		2
	7,289		6,416		19,322		19,642
Investment in Sunoco LP:
Revenues from external customers	6,317		6,577		17,395		19,767
Intersegment revenues	3		17		32		44
	6,320		6,594		17,427		19,811
Investment in USAC:
Revenues from external customers	212		176		605		503
Intersegment revenues	5		3		16		11
	217		179		621		514
All other:
Revenues from external customers	335		873		1,009		2,281
Intersegment revenues	109		211		378		480
	444		1,084		1,387		2,761
Eliminations	(3,112)		(5,212)		(9,391)		(14,971)
Total revenues	$	20,739	$	22,939	$	58,054	$	69,375


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	244	$	301	$	869	$	963
Interstate transportation and storage	491		409		1,468		1,259
Midstream	631		868		1,851		2,578
NGL and refined products transportation and services	1,076		634		2,852		2,097
Crude oil transportation and services	706		461		1,906		1,616
Investment in Sunoco LP	257		276		728		681
Investment in USAC	130		109		373		313
All other	6		30		49		149
Adjusted EBITDA (consolidated)	$	3,541	$	3,088	$	10,096	$	9,656


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Reconciliation of net income to Adjusted EBITDA:
Net income	$	1,047	$	1,322	$	3,727	$	4,431
Depreciation, depletion and amortization	1,107		1,030		3,227		3,104
Interest expense, net of interest capitalized	632		577		1,892		1,714
Income tax expense	77		82		256		159
Impairment losses and other	1		86		12		386
Gains on interest rate derivatives	(32)		(60)		(47)		(303)
Non-cash compensation expense	35		27		99		88
Unrealized (gains) losses on commodity risk management activities	107		(76)		182		(130)
Inventory valuation adjustments (Sunoco LP)	(141)		40		(113)		(81)

Adjusted EBITDA related to unconsolidated affiliates	182		147		514		409
Equity in earnings of unconsolidated affiliates	(103)		(68)		(286)		(186)
Non-operating litigation-related loss	625		—		625		—
Other, net	4		(19)		8		65
Adjusted EBITDA (consolidated)	$	3,541	$	3,088	$	10,096	$	9,656

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 22
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-22

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 15
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-15

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 31
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-31

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-32

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

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (f)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-32

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 40
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-40

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org//280/tableOfContent

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 26
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-26

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

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 41
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-41

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 21
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-21

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 21
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-21

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-32

+ Details

Equity

9 Months Ended

Sep. 30, 2023

Equity [Abstract]

Equity

EQUITY

Energy Transfer Common Units

Changes in Energy Transfer common units during the nine months ended September 30, 2023 were as follows:


			Number of Units
Number of common units at December 31, 2022			3,094.4
Common units issued under the distribution reinvestment plan			5.5
Common units issued for Lotus Midstream acquisition			44.5
Common units vested under equity incentive plans and other			0.7
Number of common units at September 30, 2023			3,145.1

Energy Transfer Repurchase Program

During the nine months ended September 30, 2023, Energy Transfer did not repurchase any of its common units under its current buyback program. As of September 30, 2023, $880 million remained available to repurchase under the current program.

Energy Transfer Distribution Reinvestment Program

During the nine months ended September 30, 2023, distributions of $70 million were reinvested under the distribution reinvestment program. As of September 30, 2023, a total of 6 million Energy Transfer common units remained available to be issued under the existing registration statement in connection with the distribution reinvestment program.

Cash Distributions on Energy Transfer Common Units

Distributions declared and/or paid with respect to Energy Transfer common units subsequent to December 31, 2022 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2022

February 7, 2023

February 21, 2023

0.3050

March 31, 2023

May 8, 2023

May 22, 2023

0.3075

June 30, 2023

August 14, 2023

August 21, 2023

0.3100

September 30, 2023

October 30, 2023

November 20, 2023

0.3125

Energy Transfer Preferred Units

As of September 30, 2023 and December 31, 2022, Energy Transfer’s outstanding preferred units included 950,000 Series A Preferred Units, 550,000 Series B Preferred Units, 18,000,000 Series C Preferred Units, 17,800,000 Series D Preferred Units, 32,000,000 Series E Preferred Units, 500,000 Series F Preferred Units, 1,484,780 Series G Preferred Units and 900,000 Series H Preferred Units.

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


	Preferred Unitholders
	Series A		Series B		Series C		Series D		Series E		Series F		Series G		Series H		Total
Balance, December 31, 2022	$	958	$	556	$	440	$	434	$	786	$	496	$	1,488	$	893	$	6,051
Distributions to partners	(30)		(18)		(8)		(9)		(15)		—		—		—		(80)


Net income	18		9		8		9		15		8		27		15		109
Balance, March 31, 2023	946		547		440		434		786		504		1,515		908		6,080

Distributions to partners	(21)		—		(8)		(9)		(15)		(16)		(53)		(29)		(151)

Net income	22		9		9		9		15		8		26		15		113
Balance, June 30, 2023	947		556		441		434		786		496		1,488		894		6,042
Distributions to partners	(22)		(20)		(12)		(8)		(15)		—		—		—		(77)

Net income	23		10		11		10		15		8		27		14		118
Balance, September 30, 2023	$	948	$	546	$	440	$	436	$	786	$	504	$	1,515	$	908	$	6,083


	Preferred Unitholders
	Series A		Series B		Series C		Series D		Series E		Series F		Series G		Series H		Total
Balance, December 31, 2021	$	958	$	556	$	440	$	434	$	786	$	496	$	1,488	$	893	$	6,051
Distributions to partners	(30)		(18)		(8)		(9)		(15)		—		—		—		(80)
Net income	15		9		8		9		15		8		27		15		106
Balance, March 31, 2022	943		547		440		434		786		504		1,515		908		6,077

Distributions to partners	—		—		(8)		(9)		(15)		(16)		(53)		(30)		(131)

Net income	15		9		8		9		15		8		26		15		105
Balance, June 30, 2022	958		556		440		434		786		496		1,488		893		6,051
Distributions to partners	(30)		(18)		(8)		(9)		(15)		—		—		—		(80)

Net income	15		9		8		9		15		8		27		15		106
Balance, September 30, 2022	$	943	$	547	$	440	$	434	$	786	$	504	$	1,515	$	908	$	6,077

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(1)		Series B(2)		Series C(1)		Series D(1)		Series E		Series F(2)		Series G(2)		Series H(2)
December 31, 2022	February 1, 2023	February 15, 2023	$	31.250	$	33.125	$	0.4609	$	0.4766	$	0.475	$	—	$	—	$	—
March 31, 2023	May 1, 2023	May 15, 2023	21.982		—		0.4609		0.4766		0.475		33.750		35.625		32.500
June 30, 2023	August 1, 2023	August 15, 2023	23.891		33.125		0.6294		0.4766		0.475		—		—		—
September 30, 2023	November 1, 2023	November 15, 2023	24.672		—		0.6489		0.6622		0.475		33.750		35.625		32.500

(1)See additional information on Series A, Series C and Series D distributions below.

(2)Series B, Series F, Series G and Series H distributions are paid on a semi-annual basis.

Prior to February 15, 2023, distributions on the Series A Preferred Units accrued at a fixed rate of 6.250% per annum of the liquidation preference of $1,000. Beginning February 15, 2023 to, but excluding, August 15, 2023, the Series A Preferred Units accrued a floating distribution rate set each quarterly distribution period at a percentage of the $1,000 liquidation preference equal to the then-current three-month LIBOR plus a spread of 4.028% per annum. On and after August 15, 2023, the floating distribution rate on the Series A Preferred Units is based on the three-month SOFR, plus a tenor spread adjustment of 0.26161%, plus 4.028% per annum. Distributions on Series A Preferred Units were previously payable semiannually in arrears until February 15, 2023, and, after February 15, 2023, quarterly in arrears, when, as, and if declared by our General Partner out of legally available funds for such purpose.

Prior to May 15, 2023, distributions on the Series C Preferred Units accrued at a fixed rate of 7.375% per annum of the liquidation preference of $25. Beginning May 15, 2023 to, but excluding, August 15, 2023, the Series C Preferred Units accrued a floating distribution rate set each quarterly distribution period at a percentage of the $25 liquidation preference equal to the then-current three-month LIBOR plus a spread of 4.530% per annum. On and after August 15, 2023, the floating distribution rate on the Series C Preferred Units is based on the three-month SOFR, plus a tenor spread adjustment of 0.26161%, plus 4.530% per annum.

Prior to August 15, 2023, distributions on the Series D Preferred Units accrued at a fixed rate of 7.625% per annum of the liquidation preference of $25. On and after August 15, 2023, the Series D Preferred Units accrue a floating distribution rate set each quarterly distribution period at a percentage of the $25 liquidation preference equal to the three-month SOFR, plus a tenor spread adjustment of 0.26161%, plus 4.738% per annum.

Distributions on the Series B Preferred Units and Series E Preferred Units are scheduled to begin accruing at a floating rate as follows:


	Beginning of floating rate period	Applicable Spread		Tenor spread adjustment		Floating rate
Series B Preferred Units	February 15, 2028	4.155	%	0.26161	%	Three-month SOFR

Series E Preferred Units	May 15, 2024	5.161	%	0.26161	%	Three-month SOFR

Noncontrolling Interests

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

Sunoco LP Cash Distributions

Distributions on Sunoco LP’s common units declared and/or paid by Sunoco LP subsequent to December 31, 2022 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2022

February 7, 2023

February 21, 2023

0.8255

March 31, 2023

May 8, 2023

May 22, 2023

0.8420

June 30, 2023

August 14, 2023

August 21, 2023

0.8420

September 30, 2023

October 30, 2023

November 20, 2023

0.8420

USAC Cash Distributions

Distributions on USAC’s common units declared and/or paid by USAC subsequent to December 31, 2022 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2022

January 23, 2023

February 3, 2023

0.525

March 31, 2023

April 24, 2023

May 5, 2023

0.525

June 30, 2023

July 24, 2023

August 4, 2023

0.525

September 30, 2023

October 23, 2023

November 3, 2023

0.525

USAC’s Warrants

As of September 30, 2023 and December 31, 2022, USAC warrants with the right to purchase 10,000,000 USAC common units at a strike price of $19.59 per unit were outstanding. On October 27, 2023, such warrants were exercised in full by the holders. The exercise of the warrants will be net settled for approximately 2,360,000 USAC common units.

Accumulated Other Comprehensive Income

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


	September 30, 2023		December 31, 2022
Unrealized gains on available-for-sale securities	$	11	$	9
Foreign currency translation adjustment	6		1
Actuarial loss related to pensions and other postretirement benefits	(7)		(7)
Investments in unconsolidated affiliates, net	19		13



Total AOCI included in partners’ capital, net of tax	$	29	$	16

Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
ASSETS
Cash and cash equivalents	$ 514	$ 257
Accounts receivable, net	9,612	8,466
Inventories	2,590	2,461
Income taxes receivable	84	68
Derivative assets	14	10
Other current assets	508	726
Total current assets	13,423	12,081
Property, plant and equipment	109,411	105,996
Accumulated depreciation and depletion	(28,538)	(25,685)
Property, Plant and Equipment, Net	80,873	80,311
Investments in unconsolidated affiliates	2,993	2,893
Non-current derivative assets	4	0
Lease right-of-use assets, net	820	819
Other non-current assets, net	1,690	1,558
Intangible assets, net	5,204	5,415
Goodwill	2,564	2,566
Total assets	107,571	105,643
LIABILITIES AND EQUITY
Accounts payable	7,997	6,952
Derivative liabilities	4	23
Operating lease current liabilities	45	45
Accrued and other current liabilities	3,696	3,329
Current maturities of long-term debt	1,006	2
Total current liabilities	12,755	10,368
Long-term debt, less current maturities	47,075	48,260
Non-current derivative liabilities	0	23
Non-current operating lease liabilities	775	798
Deferred income taxes	3,891	3,701
Other non-current liabilities	2,016	1,341
Commitments and contingencies
Redeemable noncontrolling interests	498	493
Preferred Unitholders	6,083	6,051
Limited Partners:
Common Unitholders	27,014	26,960
General Partner	(2)	(2)
Accumulated other comprehensive income	29	16
Total partners’ capital	33,124	33,025
Noncontrolling interests	7,437	7,634
Total equity	40,561	40,659
Total liabilities and equity	107,571	105,643
Related Party
ASSETS
Accounts receivable from related companies	101	93
LIABILITIES AND EQUITY
Accounts payable	$ 7	$ 17

Equity - Change In Common Units (Details) - USD ($) $ in Millions		3 Months Ended						9 Months Ended
	May 02, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Sep. 30, 2023	Dec. 31, 2022	Dec. 31, 2021
Class of Stock [Line Items]
Limited Partners' Capital Account, Units Outstanding		3,145,100,000						3,145,100,000	3,094,400,000
Stock Issued During Period, Shares, Dividend Reinvestment Plan								5,500,000
Partners' Capital Account, Unit-based Payment Arrangement, Number of Units								700,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		$ 40,561	$ 40,962	$ 40,669	$ 40,568	$ 40,765	$ 40,329	$ 40,561	$ 40,659	$ 39,345
Distributions to partners		(1,029)	(1,094)	(1,001)	(775)	(735)	(608)
Lotus Midstream LLC
Class of Stock [Line Items]
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable Fair Value Method	44,500,000							44,500,000
Series H Preferred Units
Class of Stock [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		908	894	908	908	893	908	$ 908	893	893
Distributions to partners		0	(29)	0	0	(30)	0
Net Income (Loss), Including Portion Attributable to Nonredeemable Noncontrolling Interest		$ 14	15	15	15	15	15
Preferred Stock, Shares Outstanding		900,000						900,000
Series A Preferred Units [Member]
Class of Stock [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		$ 948	947	946	943	958	943	$ 948	958	958
Distributions to partners		(22)	(21)	(30)	(30)	0	(30)
Net Income (Loss), Including Portion Attributable to Nonredeemable Noncontrolling Interest		$ 23	22	18	15	15	15
Preferred Stock, Shares Outstanding		950,000						950,000
Series C Preferred Units [Member]
Class of Stock [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		$ 440	441	440	440	440	440	$ 440	440	440
Distributions to partners		(12)	(8)	(8)	(8)	(8)	(8)
Net Income (Loss), Including Portion Attributable to Nonredeemable Noncontrolling Interest		$ 11	9	8	8	8	8
Preferred Stock, Shares Outstanding		18,000,000						18,000,000
Series B Preferred Units [Member]
Class of Stock [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		$ 546	556	547	547	556	547	$ 546	556	556
Distributions to partners		(20)	0	(18)	(18)	0	(18)
Net Income (Loss), Including Portion Attributable to Nonredeemable Noncontrolling Interest		$ 10	9	9	9	9	9
Preferred Stock, Shares Outstanding		550,000						550,000
Series D Preferred Units [Member]
Class of Stock [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		$ 436	434	434	434	434	434	$ 436	434	434
Distributions to partners		(8)	(9)	(9)	(9)	(9)	(9)
Net Income (Loss), Including Portion Attributable to Nonredeemable Noncontrolling Interest		$ 10	9	9	9	9	9
Preferred Stock, Shares Outstanding		17,800,000						17,800,000
Series E Preferred Units [Member]
Class of Stock [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		$ 786	786	786	786	786	786	$ 786	786	786
Distributions to partners		(15)	(15)	(15)	(15)	(15)	(15)
Net Income (Loss), Including Portion Attributable to Nonredeemable Noncontrolling Interest		$ 15	15	15	15	15	15
Preferred Stock, Shares Outstanding		32,000,000						32,000,000
Series F Preferred Units [Member]
Class of Stock [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		$ 504	496	504	504	496	504	$ 504	496	496
Distributions to partners		0	(16)	0	0	(16)	0
Net Income (Loss), Including Portion Attributable to Nonredeemable Noncontrolling Interest		$ 8	8	8	8	8	8
Preferred Stock, Shares Outstanding		500,000						500,000
Series G Preferred Units [Member]
Class of Stock [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		$ 1,515	1,488	1,515	1,515	1,488	1,515	$ 1,515	1,488	1,488
Distributions to partners		0	(53)	0	0	(53)	0
Net Income (Loss), Including Portion Attributable to Nonredeemable Noncontrolling Interest		$ 27	26	27	27	26	27
Preferred Stock, Shares Outstanding		1,484,780						1,484,780
Preferred Unitholders
Class of Stock [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		$ 6,083	6,042	6,080	6,077	6,051	6,077	$ 6,083	$ 6,051	$ 6,051
Distributions to partners		(77)	(151)	(80)	(80)	(131)	(80)
Net Income (Loss), Including Portion Attributable to Nonredeemable Noncontrolling Interest		$ 118	$ 113	$ 109	$ 106	$ 105	$ 106

Revenue (Details) $ in Millions	Sep. 30, 2023 USD ($)
Revenue, Remaining Performance Obligation, Amount	$ 39,830

Net Income per Limited Partner Unit Table - Income Reconciliation (Details) - USD ($)
$ / shares in Units, shares in Millions, $ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2023

Sep. 30, 2022

Sep. 30, 2023

Sep. 30, 2022

Earnings Per Share [Abstract]

Net income

$ 1,047

$ 1,322

$ 3,727

$ 4,431

Less: Net income attributable to noncontrolling interests

451

304

1,080

793

Less: Net income attributable to redeemable noncontrolling interests

NET INCOME ATTRIBUTABLE TO PARTNERS

584

1,006

2,608

3,601

General Partner’s interest in net income

Common Unitholders’ interest in net income

$ 466

$ 899

$ 2,266

$ 3,281

Basic Income per Limited Partner Unit

Weighted average common units

3,144.0

3,087.6

3,122.3

3,085.6

Basic

$ 0.15

$ 0.29

$ 0.73

$ 1.06

Diluted Income per Limited Partner Unit:

Net Income (Loss) Available to Common Stockholders, Diluted

$ 465

$ 899

$ 2,264

$ 3,279

Weighted average common units, assuming dilutive effect of unvested restricted unit awards

3,167.7

3,108.6

3,145.9

3,106.4

Diluted

$ 0.15

$ 0.29

$ 0.72

$ 1.06

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

^[1]

$ 1

$ 0

$ 2

Dilutive effect of unvested restricted unit awards (1)

^[1]

23.7

21.0

23.6

20.8

Preferred Unitholders’ interest in net income

$ 118

$ 106

$ 340

$ 317

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

Net Income per Limited Partner Unit

9 Months Ended

Sep. 30, 2023

Earnings Per Share [Abstract]

Net Income Per Limited Partner Unit

NET INCOME PER COMMON UNIT

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Net income	$	1,047	$	1,322	$	3,727	$	4,431
Less: Net income attributable to noncontrolling interests	451		304		1,080		793
Less: Net income attributable to redeemable noncontrolling interests	12		12		39		37
Net income, net of noncontrolling interests	584		1,006		2,608		3,601
Less: General Partner’s interest in net income	—		1		2		3
Less: Preferred Unitholders’ interest in net income	118		106		340		317
Common Unitholders’ interest in net income	$	466	$	899	$	2,266	$	3,281
Basic Income per Common Unit:
Weighted average common units	3,144.0		3,087.6		3,122.3		3,085.6
Basic income per common unit	$	0.15	$	0.29	$	0.73	$	1.06

Diluted Income per Common Unit:
Common Unitholders’ interest in net income	$	466	$	899	$	2,266	$	3,281
Dilutive effect of equity-based compensation of subsidiaries (1)	1		—		2		2
Diluted income attributable to Common Unitholders	$	465	$	899	$	2,264	$	3,279
Weighted average common units	3,144.0		3,087.6		3,122.3		3,085.6
Dilutive effect of unvested restricted unit awards (1)	23.7		21.0		23.6		20.8
Weighted average common units, assuming dilutive effect of unvested restricted unit awards	3,167.7		3,108.6		3,145.9		3,106.4
Diluted income per common unit	$	0.15	$	0.29	$	0.72	$	1.06

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

Cash And Cash Equivalents

9 Months Ended

Sep. 30, 2023

Supplemental Cash Flow Information [Abstract]

Cash and Cash Equivalents Disclosure

CASH AND CASH EQUIVALENTS

Cash and cash equivalents include all cash on hand, demand deposits and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value. The Partnership’s consolidated balance sheets did not include any material amounts of restricted cash as of September 30, 2023 or December 31, 2022.

We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.

The net change in operating assets and liabilities, net of effects of acquisitions, included in cash flows from operating activities is comprised as follows:


	Nine Months Ended September 30,
	2023		2022
Accounts receivable	$	(1,125)	$	(999)
Accounts receivable from related companies	(8)		17
Inventories	(3)		(287)
Other current assets	208		(176)
Other non-current assets, net	(135)		106
Accounts payable	1,076		599
Accounts payable to related companies	(12)		1
Accrued and other current liabilities	562		585
Other non-current liabilities	669		254
Derivative assets and liabilities, net	(50)		(312)
Net change in operating assets and liabilities, net of effects of acquisitions and divestitures	$	1,182	$	(212)

Non-cash investing and financing activities were as follows:


	Nine Months Ended September 30,
	2023		2022

Accrued capital expenditures	$	354	$	454

Lease assets obtained in exchange for new lease liabilities	26		37
Distribution reinvestment	70		42

Insider Trading Arrangements	9 Months Ended
Insider Trading Arrangements	Sep. 30, 2023
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

Fair Value Measurements Narrative (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Dec. 31, 2022
Fair Value Measurements [Abstract]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net	$ 0
Debt obligations, fair value	44,600	$ 45,420
Long-term Debt	$ 48,080	$ 48,260

- Definition

Amount, after deduction of unamortized premium (discount) and debt issuance cost, of long-term debt. Excludes lease obligation.

+ References + Details

Debt Obligations Narrative (Details) - USD ($) $ in Millions		9 Months Ended
	Nov. 01, 2023	Sep. 30, 2023	Oct. 31, 2023
Debt Instrument [Line Items]
Long-term Line of Credit		$ 813.0
Banking Regulation, Supplementary Leverage Ratio, Actual		3.11
Credit Facility due December 2027 [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity		$ 2,120.0
Long-term Line of Credit		2,850.0
Letters of Credit Outstanding, Amount		$ 32.0
Line of Credit Facility, Interest Rate at Period End		6.29%
Line of Credit Facility, Maximum Borrowing Capacity		$ 5,000.0
Commercial Paper		1,550.0
Credit Facility due December 2027 [Member] \| Accordion feature [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		7,000.0
Sunoco LP Revolving Credit Facility due April 2027 [Member] \| Sunoco LP [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		$ 6.0
Line of Credit Facility, Interest Rate at Period End		7.34%
Line of Credit Facility, Remaining Borrowing Capacity		$ 847.0
Line of Credit Facility, Fair Value, Basis for Measurement		647 million
USAC Credit Facility, due 2026 [Member] \| USA Compression Partners, LP [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		$ 787.0
Line of Credit Facility, Interest Rate at Period End		7.99%
Line of Credit Facility, Remaining Borrowing Capacity		$ 434.0
3.45% Senior Notes due January 2023
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		3.45%
Repayments of Senior Debt		$ 350.0
3.60% Senior Notes due February 2023
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		3.60%
Repayments of Senior Debt		$ 800.0
4.25% Senior Notes due March 2023
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.25%
Repayments of Senior Debt		$ 1,000.0
4.05% HFOTCO tax-exempt senior notes due November 1, 2050
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.05%
Senior Notes		$ 225.0
Bakken Pipeline Senior Notes, Maturing April 2024
Debt Instrument [Line Items]
Senior Notes, Current		$ 1,000.0
6.05% Senior Notes due 2026 \| Subsequent Event
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			6.05%
Senior Notes			$ 1,000.0
6.10% Senior Notes due 2030 \| Subsequent Event
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			6.10%
Senior Notes			$ 500.0
6.40% Senior Notes due 2030 \| Subsequent Event
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			6.40%
Senior Notes			$ 1,000.0
6.55% Senior Notes due 2033 \| Subsequent Event
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			6.55%
Senior Notes			$ 1,500.0
4.20% Senior Notes due 2023
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.20%
Repayments of Senior Debt		$ 500.0
7.00% Senior Notes due 2028 \| Sunoco LP [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		7.00%
Senior Notes		$ 500.0
4.50% Senior Notes due November 1, 2023 \| Subsequent Event
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.50%
Repayments of Senior Debt	$ 600.0

Operations And Organization	9 Months Ended
Operations And Organization	Sep. 30, 2023
Operations And Organization [Abstract]
Operations And Organization	ORGANIZATION AND BASIS OF PRESENTATION Organization The consolidated financial statements presented herein contain the results of Energy Transfer LP and its subsidiaries (the “Partnership,” “we,” “us,” “our” or “Energy Transfer”). Basis of Presentation The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 17, 2023. In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC. The consolidated financial statements of the Partnership presented herein include the results of operations of our controlled subsidiaries, including Sunoco LP and USAC. The Partnership owns the general partner interest, incentive distribution rights and 28.5 million common units of Sunoco LP, and the general partner interests and 46.1 million common units of USAC. Certain prior period amounts have been reclassified to conform to the current period presentation. These reclassifications had no impact on net income or total equity. Use of Estimates The unaudited consolidated financial statements have been prepared in conformity with GAAP, which requires the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and the accrual for and disclosure of contingent assets and liabilities that exist at the date of the consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates.

Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2023

Fair Value Measurements [Abstract]

Fair Value, by Balance Sheet Grouping [Table Text Block]


			Fair Value Measurements at September 30, 2023
	Fair Value Total		Level 1		Level 2
Assets:
Interest rate derivatives	$	14	$	—	$	14
Commodity derivatives:

Natural Gas:
Basis Swaps IFERC/NYMEX	$	3	$	3	$	—
Swing Swaps IFERC	4		4		—
Fixed Swaps/Futures	28		28		—


Forward Physical Contracts	3		—		3
Power:
Forwards	46		—		46
Futures	6		6		—


NGLs – Forwards/Swaps	256		256		—
Refined Products – Futures	27		27		—
Crude – Forwards/Swaps	32		32		—

Total commodity derivatives	405		356		49
Other non-current assets	28		18		10
Total assets	$	447	$	374	$	73
Liabilities:

Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	(10)	$	(10)	$	—
Swing Swaps IFERC	(5)		(5)		—
Fixed Swaps/Futures	(2)		(2)		—



Power:
Forwards	(45)		—		(45)
Futures	(5)		(5)		—


NGLs – Forwards/Swaps	(306)		(306)		—
Refined Products – Futures	(35)		(35)		—
Crude – Forwards/Swaps	(41)		(41)		—
Total commodity derivatives	(449)		(404)		(45)
Total liabilities	$	(449)	$	(404)	$	(45)


			Fair Value Measurements at December 31, 2022
	Fair Value Total		Level 1		Level 2
Assets:

Commodity derivatives:

Natural Gas:
Basis Swaps IFERC/NYMEX	$	60	$	60	$	—
Swing Swaps IFERC	75		75		—
Fixed Swaps/Futures	113		113		—


Forward Physical Contracts	10		—		10
Power:
Forwards	52		—		52
Futures	3		3		—


NGLs – Forwards/Swaps	317		317		—
Refined Products – Futures	20		20		—

Crude – Forwards/Swaps	38		38		—

Total commodity derivatives	688		626		62
Other non-current assets	27		18		9
Total assets	$	715	$	644	$	71
Liabilities:
Interest rate derivatives	$	(23)	$	—	$	(23)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(25)		(25)		—
Swing Swaps IFERC	(12)		(12)		—
Fixed Swaps/Futures	(4)		(4)		—


Forward Physical Contracts	(2)		—		(2)
Power:
Forwards	(51)		—		(51)
Futures	(3)		(3)		—

NGLs – Forwards/Swaps	(358)		(358)		—
Refined Products – Futures	(59)		(59)		—

Crude – Forwards/Swaps	(12)		(12)		—

Total commodity derivatives	(526)		(473)		(53)
Total liabilities	$	(549)	$	(473)	$	(76)

Derivative Assets And Liabilities Table - Fair Value of Derivative Instruments (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Total derivatives assets	$ 419	$ 688
Total derivatives liabilities	(449)	(549)
Designated as Hedging Instrument [Member]
Total derivatives assets	23	87
Total derivatives liabilities	(7)	(7)
Not Designated as Hedging Instrument [Member]
Total derivatives assets	396	601
Total derivatives liabilities	(442)	(542)
Commodity Derivatives [Member] \| Not Designated as Hedging Instrument [Member]
Total derivatives assets	71	95
Total derivatives liabilities	(71)	(108)
Commodity Derivatives (Margin Deposits) [Member] \| Designated as Hedging Instrument [Member]
Total derivatives assets	23	87
Total derivatives liabilities	(7)	(7)
Commodity Derivatives (Margin Deposits) [Member] \| Not Designated as Hedging Instrument [Member]
Total derivatives assets	311	506
Total derivatives liabilities	(371)	(411)
Interest Rate Derivatives [Member] \| Not Designated as Hedging Instrument [Member]
Total derivatives assets	14	0
Total derivatives liabilities	$ 0	$ (23)

Revenue, Remaining performance obligations (Details) $ in Millions	Sep. 30, 2023 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 39,830
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 2,176
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2023
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	3 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 7,345
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2024
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year 3 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 6,247
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2025
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	2 years 3 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 24,062
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	3 years 3 months

Pay vs Performance Disclosure - USD ($) $ in Millions	3 Months Ended		9 Months Ended
Pay vs Performance Disclosure - USD ($) $ in Millions	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Pay vs Performance Disclosure
NET INCOME ATTRIBUTABLE TO PARTNERS	$ 584	$ 1,006	$ 2,608	$ 3,601

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References

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

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 323
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 3
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481687/323-10-50-3

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
-Section 50
-Paragraph 28
-Subparagraph (f)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482907/825-10-50-28

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
-Section 50
-Paragraph 6
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482765/220-10-50-6

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 250
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 3
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-URI https://asc.fasb.org//1943274/2147483443/250-10-50-3

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
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-Section 50
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-Subparagraph (b)(2)
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Reference 7: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
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-Paragraph 1
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org//1943274/2147483443/250-10-50-9

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
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-Publisher FASB
-URI https://asc.fasb.org//1943274/2147483443/250-10-50-11

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
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Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 250
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-Name Accounting Standards Codification
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-URI https://asc.fasb.org//1943274/2147483443/250-10-50-4

Reference 13: http://www.xbrl.org/2003/role/exampleRef
-Topic 946
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-Name Accounting Standards Codification
-Section 55
-Paragraph 10
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-URI https://asc.fasb.org//1943274/2147480167/946-830-55-10

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
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-Name Accounting Standards Codification
-Section 45
-Paragraph 7
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-URI https://asc.fasb.org//1943274/2147483581/946-220-45-7

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
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Reference 16: http://www.xbrl.org/2003/role/disclosureRef
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Reference 18: http://www.xbrl.org/2003/role/disclosureRef
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Reference 25: http://www.xbrl.org/2003/role/disclosureRef
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Reference 27: http://www.xbrl.org/2003/role/disclosureRef
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Reference 28: http://www.xbrl.org/2003/role/disclosureRef
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Reference 29: http://www.xbrl.org/2003/role/disclosureRef
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Reference 30: http://www.xbrl.org/2003/role/disclosureRef
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Reference 36: http://www.xbrl.org/2003/role/disclosureRef
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Reference 37: http://www.xbrl.org/2003/role/disclosureRef
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Reference 38: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 39: http://fasb.org/us-gaap/role/ref/legacyRef
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-Paragraph 1
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-Publisher FASB
-URI https://asc.fasb.org//1943274/2147483589/942-220-S99-1

+ Details

Revenue Revenue Contract Liabilities (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022	Dec. 31, 2021
Contract with Customer, Liability	$ 573	$ 573	$ 615	$ 459
Additions	794	815
Revenue Recognized	(836)	(688)
Deferred Revenue, Period Increase (Decrease)		$ (13)
Sunoco LP [Member]
Contract assets	239		200
Accounts receivable from contracts with customers	$ 1,079		$ 834

Operations And Organization Narrative (Details) shares in Millions	Sep. 30, 2023 shares
USAC [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.	46.1
Sunoco LP [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.	28.5

Derivative Assets And Liabilities Table - Gross FV and Netting Offset (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 419	$ 688
Derivative Liability, Fair Value, Gross Liability	(449)	(549)
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	49	244
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	79	105
Derivative assets (liabilities)
Derivatives, Fair Value [Line Items]
Counterparty netting	(67)	(85)
Counterparty netting	67	85
Other current assets (liabilities)
Derivatives, Fair Value [Line Items]
Counterparty netting	(303)	(359)
Counterparty netting	303	359
Without offsetting agreements [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	14	0
Derivative Liability, Fair Value, Gross Liability	0	(23)
OTC Contracts [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	71	95
Derivative Liability, Fair Value, Gross Liability	(71)	(108)
Broker cleared derivative contracts [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	334	593
Derivative Liability, Fair Value, Gross Liability	$ (378)	$ (418)

Derivative Assets And Liabilities (Tables)

9 Months Ended

Sep. 30, 2023

Outstanding Commodity-Related Derivatives

The following table details our outstanding commodity-related derivatives:


	September 30, 2023		December 31, 2022
	Notional Volume	Maturity	Notional Volume	Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Fixed Swaps/Futures	330	2023-2024	145	2023
Basis Swaps IFERC/NYMEX (1)	(44,800)	2023-2024	(39,563)	2023



Power (Megawatt):
Forwards	171,600	2023-2029	—	2023-2029
Futures	(74,391)	2023-2024	(21,384)	2023
Options – Puts	68,800	2023-2024	119,200	2023
Options – Calls	—	2023-2024	—	—



(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	48,393	2023-2025	42,440	2023-2024
Swing Swaps IFERC	(72,220)	2023-2025	(202,815)	2023-2024
Fixed Swaps/Futures	(4,803)	2023-2025	(15,758)	2023-2025
Forward Physical Contracts	(2,145)	2023-2025	2,423	2023-2024

NGLs (MBbls) – Forwards/Swaps	(14,238)	2023-2026	6,934	2023-2025
Crude (MBbls) – Forwards/Swaps	(7,660)	2023-2025	795	2023-2024
Refined Products (MBbls) – Futures	(5,751)	2023-2025	(3,547)	2023-2024

Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(43,745)	2023-2024	(37,448)	2023
Fixed Swaps/Futures	(43,745)	2023-2024	(37,448)	2023
Hedged Item – Inventory	43,745	2023-2024	37,448	2023

(1)Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.

Interest Rate Swaps Outstanding

The following table summarizes our interest rate swaps outstanding (including USAC’s), none of which were designated as hedges for accounting purposes:

Term

Type(1)

Notional Amount Outstanding

September 30,
2023

December 31,
2022

Energy Transfer:

July 2024(2)

Forward-starting to pay an average fixed rate of 3.388% and receive a floating rate

—

400

USAC:

April 2025(3)

Pay a fixed rate of 3.785% and receive a floating rate (effective April 2023)

700

—

(1)Floating rates are based on SOFR.

(2)The July 2024 interest rate swaps were terminated and settled in August 2023.

Fair Value Of Derivative Instruments

The following table provides a summary of our derivative assets and liabilities:


	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	September 30, 2023		December 31, 2022		September 30, 2023		December 31, 2022
Derivatives designated as hedging instruments:
Commodity derivatives – margin deposits	$	23	$	87	$	(7)	$	(7)
	23		87		(7)		(7)
Derivatives not designated as hedging instruments:
Commodity derivatives – margin deposits	311		506		(371)		(411)
Commodity derivatives	71		95		(71)		(108)
Interest rate derivatives	14		—		—		(23)
	396		601		(442)		(542)
Total derivatives	$	419	$	688	$	(449)	$	(549)

Derivatives, Offsetting Fair Value Amounts [Table Text Block]


		Asset Derivatives				Liability Derivatives
	Balance Sheet Location	September 30, 2023		December 31, 2022		September 30, 2023		December 31, 2022
Derivatives without offsetting agreements	Derivative assets (liabilities)	$	14	$	—	$	—	$	(23)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	71		95		(71)		(108)
Broker cleared derivative contracts	Other current assets (liabilities)	334		593		(378)		(418)
Total gross derivatives		419		688		(449)		(549)
Offsetting agreements:

Counterparty netting	Derivative assets (liabilities)	(67)		(85)		67		85
Counterparty netting	Other current assets (liabilities)	(303)		(359)		303		359
Total net derivatives		$	49	$	244	$	(79)	$	(105)

Derivatives Not Designated as Hedging Instruments [Table Text Block]

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


	Location	Amount of Gain (Loss) Recognized in Income on Derivatives
		Three Months Ended September 30,				Nine Months Ended September 30,
		2023		2022		2023		2022
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	4	$	22	$	(6)	$	50
Commodity derivatives – Non-trading	Cost of products sold	(166)		186		(106)		(6)

Interest rate derivatives	Gains on interest rate derivatives	32		60		47		303

Total		$	(130)	$	268	$	(65)	$	347

- Definition

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References + Details

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Narrative (Details)			6 Months Ended		9 Months Ended
	Sep. 21, 2022 USD ($)	Aug. 01, 2020 USD ($)	Jun. 30, 2023 USD ($)	Jun. 30, 2018 USD ($)	Sep. 30, 2023 USD ($) Rate	Sep. 30, 2022 USD ($)	Dec. 31, 2022 USD ($)
Accrual for Environmental Loss Contingencies					$ 284,000,000		$ 282,000,000
Loss Contingency, Estimate of Possible Loss					200,000,000
Litigation Settlement, Expense					161,000,000
Payments for Environmental Liabilities					$ 23,000,000	$ 8,000,000
Interest Statutory Rate \| Rate					12.00%
Proposed Civil Penalty
Payments for Legal Settlements					$ 20,000,000
Litigation Settlement, Expense					40,000,000
Settled Williams Littigation, without post-judgement interest
Litigation Settlement, Expense					617,000,000
Related To Deductibles
Loss Contingency Accrual, at Carrying Value					$ 947,000,000		$ 200,000,000
Sunoco, Inc. [Member]
Loss Contingency, Pending Claims, Number					2
Sunoco [Member]
Site Contingency, Number of Sites Needing Remediation					31
Culberson
Loss Contingency, Damages Sought, Value					$ 93,000,000
USAC [Member]
Loss Contingency, Estimate of Possible Loss					25,000,000
Williams Litigation [Member]
Loss Contingency, Damages Sought, Value				$ 1,480,000,000	410,000,000
Litigation Settlement, Expense	$ 601,000,000
Debt Instrument, Interest Rate, Stated Percentage	3.50%
Legal Fees					190,000,000
Cline Class Action \| Additional Interest
Litigation Settlement Interest					23,000,000
Cline Class Action \| Actual Damages
Litigation Settlement Interest					104,000,000
Cline Class Action \| punitive damages
Litigation Settlement Interest					75,000,000
Cline Class Action \| Actual Damages
Payments for Legal Settlements		$ 74,800,000	$ 80,700,000
Cline Class Action \| punitive damages
Payments for Legal Settlements			$ 75,000,000
Massachusetts Attorney General
Legal Fees					$ 18,000,000

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

9 Months Ended

Sep. 30, 2023

Environmental Exit Costs by Cost


	September 30, 2023		December 31, 2022
Current	$	44	$	54
Non-current	240		228
Total environmental liabilities	$	284	$	282

Right Of Way [Member]

Lease, Cost


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
ROW expense	$	20	$	16	$	46	$	44

Fair Value Measurements Table - Fair Value of Financial Assets and Liabilities (Details) - Fair Value, Recurring [Member] - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Price Risk Derivative Assets, at Fair Value	$ 405	$ 688
Other Assets, Fair Value Disclosure	28	27
Assets, Fair Value Disclosure	447	715
Interest Rate Derivative Liabilities, at Fair Value		(23)
Price Risk Derivative Liabilities, at Fair Value	(449)	(526)
Financial and Nonfinancial Liabilities, Fair Value Disclosure	(449)	(549)
Interest Rate Derivative Assets, at Fair Value	14
Level 1
Price Risk Derivative Assets, at Fair Value	356	626
Other Assets, Fair Value Disclosure	18	18
Assets, Fair Value Disclosure	374	644
Interest Rate Derivative Liabilities, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value	(404)	(473)
Financial and Nonfinancial Liabilities, Fair Value Disclosure	(404)	(473)
Interest Rate Derivative Assets, at Fair Value	0
Level 2
Price Risk Derivative Assets, at Fair Value	49	62
Other Assets, Fair Value Disclosure	10	9
Assets, Fair Value Disclosure	73	71
Interest Rate Derivative Liabilities, at Fair Value		(23)
Price Risk Derivative Liabilities, at Fair Value	(45)	(53)
Financial and Nonfinancial Liabilities, Fair Value Disclosure	(45)	(76)
Interest Rate Derivative Assets, at Fair Value	14
Commodity Derivatives - Natural Gas [Member] \| Basis Swaps IFERC/NYMEX [Member]
Price Risk Derivative Assets, at Fair Value	3	60
Price Risk Derivative Liabilities, at Fair Value	(10)	(25)
Commodity Derivatives - Natural Gas [Member] \| Swing Swaps IFERC [Member]
Price Risk Derivative Assets, at Fair Value	4	75
Price Risk Derivative Liabilities, at Fair Value	(5)	(12)
Commodity Derivatives - Natural Gas [Member] \| Fixed Swaps/Futures [Member]
Price Risk Derivative Assets, at Fair Value	28	113
Price Risk Derivative Liabilities, at Fair Value	(2)	(4)
Commodity Derivatives - Natural Gas [Member] \| Forward Physical Contracts [Member]
Price Risk Derivative Assets, at Fair Value	3	10
Price Risk Derivative Liabilities, at Fair Value		(2)
Commodity Derivatives - Natural Gas [Member] \| Level 1 \| Basis Swaps IFERC/NYMEX [Member]
Price Risk Derivative Assets, at Fair Value	3	60
Price Risk Derivative Liabilities, at Fair Value	(10)	(25)
Commodity Derivatives - Natural Gas [Member] \| Level 1 \| Swing Swaps IFERC [Member]
Price Risk Derivative Assets, at Fair Value	4	75
Price Risk Derivative Liabilities, at Fair Value	(5)	(12)
Commodity Derivatives - Natural Gas [Member] \| Level 1 \| Fixed Swaps/Futures [Member]
Price Risk Derivative Assets, at Fair Value	28	113
Price Risk Derivative Liabilities, at Fair Value	(2)	(4)
Commodity Derivatives - Natural Gas [Member] \| Level 1 \| Forward Physical Contracts [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value		0
Commodity Derivatives - Natural Gas [Member] \| Level 2 \| Basis Swaps IFERC/NYMEX [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] \| Level 2 \| Swing Swaps IFERC [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] \| Level 2 \| Fixed Swaps/Futures [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] \| Level 2 \| Forward Physical Contracts [Member]
Price Risk Derivative Assets, at Fair Value	3	10
Price Risk Derivative Liabilities, at Fair Value		(2)
Commodity Derivatives - Refined Products [Member] \| Future [Member]
Price Risk Derivative Assets, at Fair Value	27	20
Price Risk Derivative Liabilities, at Fair Value	(35)	(59)
Commodity Derivatives - Refined Products [Member] \| Level 1 \| Future [Member]
Price Risk Derivative Assets, at Fair Value	27	20
Price Risk Derivative Liabilities, at Fair Value	(35)	(59)
Commodity Derivatives - Refined Products [Member] \| Level 2 \| Future [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Crude [Member] \| Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	32	38
Price Risk Derivative Liabilities, at Fair Value	(41)	(12)
Commodity Derivatives - Crude [Member] \| Level 1 \| Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	32	38
Price Risk Derivative Liabilities, at Fair Value	(41)	(12)
Commodity Derivatives - Crude [Member] \| Level 2 \| Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Power [Member] \| Future [Member]
Price Risk Derivative Assets, at Fair Value	6	3
Price Risk Derivative Liabilities, at Fair Value	(5)	(3)
Commodity Derivatives - Power [Member] \| Forward Contracts
Price Risk Derivative Assets, at Fair Value	46	52
Price Risk Derivative Liabilities, at Fair Value	(45)	(51)
Commodity Derivatives - Power [Member] \| Level 1 \| Future [Member]
Price Risk Derivative Assets, at Fair Value	6	3
Price Risk Derivative Liabilities, at Fair Value	(5)	(3)
Commodity Derivatives - Power [Member] \| Level 1 \| Forward Contracts
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Power [Member] \| Level 2 \| Future [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Power [Member] \| Level 2 \| Forward Contracts
Price Risk Derivative Assets, at Fair Value	46	52
Price Risk Derivative Liabilities, at Fair Value	(45)	(51)
Commodity Derivatives - NGLs [Member] \| Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	256	317
Price Risk Derivative Liabilities, at Fair Value	(306)	(358)
Commodity Derivatives - NGLs [Member] \| Level 1 \| Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	256	317
Price Risk Derivative Liabilities, at Fair Value	(306)	(358)
Commodity Derivatives - NGLs [Member] \| Level 2 \| Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	$ 0	$ 0