Energy Transfer Reports Second Quarter 2026 Results and Updates 2026 Financial Guidance

DALLAS--(BUSINESS WIRE)--Energy Transfer LP (NYSE:ET) (“Energy Transfer” or the “Partnership”) today reported financial results for the quarter ended June 30, 2026.

Energy Transfer reported net income attributable to partners for the three months ended June 30, 2026 of $2.09 billion compared to $1.16 billion for the three months ended June 30, 2025. For the three months ended June 30, 2026, net income per common unit (basic) was $0.59.

Adjusted EBITDA for the three months ended June 30, 2026 was $5.07 billion compared to $3.87 billion for the three months ended June 30, 2025, an increase of 31%.

Distributable Cash Flow attributable to partners, as adjusted, for the three months ended June 30, 2026 was $2.59 billion compared to $1.96 billion for the three months ended June 30, 2025, an increase of 32%.

The Partnership now expects its Adjusted EBITDA guidance for the full year of 2026 to range between $18.8 billion and $19.1 billion, compared to the previous range of between $18.2 billion and $18.6 billion. The Partnership expects to invest $5.6 billion to $5.9 billion in growth capital for 2026.

Growth capital expenditures in the second quarter of 2026 were $1.10 billion; maintenance capital expenditures were $307 million.

Operational Highlights

• Energy Transfer’s volumes continued to grow during the second quarter of 2026 compared to the second quarter of 2025.
  • NGL transportation volumes were up 13%, setting a new Partnership record.
  • NGL exports were up 25%, setting a new Partnership record.
  • NGL fractionation volumes were up 3%.
  • Crude oil transportation volumes were up 4%, setting a new Partnership record.
  • Midstream gathered volumes were up 4%, setting a new Partnership record.

Strategic Highlights

• Energy Transfer is well positioned to benefit from multiple visible growth drivers across the business.
  • Increasing demand for natural gas infrastructure expansion to support the growing needs for power generation and LNG exports:
    • The Hugh Brinson Pipeline is now in commercial service and is expected to be capable of flowing the full Phase I capacity of 1.5 Bcf/d by September 1, 2026.
    • During the second quarter of 2026, Energy Transfer completed another 14-mile lateral off the Hugh Brinson Pipeline in Abilene, Texas, and it is now ready for service.
    • During the second quarter of 2026, Energy Transfer continued the development of its Desert Southwest expansion project and FERC recently completed scoping meetings in communities along the route.
    • In May 2026, Energy Transfer announced the Springerville Lateral on Transwestern Pipeline to support the conversion of two coal-fired plants to natural gas.
    • Energy Transfer recently had two customers add a combined 100 MMcf/d to their existing contracts for natural gas services to their power plant or data center sites in Texas.
    • Energy Transfer expects to announce additional natural gas pipeline projects later this year to fuel growing power demand.
  • Growing demand for Natural Gas Liquids (NGLs) exports:
    • In June 2026, Energy Transfer announced a fully subscribed export expansion at Nederland facility. The project will increase ethane export capacity at the terminal by 240,000 barrels per day (bpd) along with 55,000 bpd of additional LPG capacity. As part of the expansion, Energy Transfer will also expand its Mont Belvieu to Nederland NGL export pipeline capacity to service the increased refrigeration capacity and will construct two additional NGL ship docks.
    • In the second quarter of 2026, Energy Transfer completed upgrades to its Lone Star Express pipeline, which provides more than 90,000 Bbls/d of incremental Permian NGL takeaway capacity on the pipeline system.
    • In the second quarter of 2026, Energy Transfer signed long-term transportation and/or fractionation agreements for approximately 300,000 Bbls/d on its y-grade assets that extend into the 2030s.
    • In June 2026, Energy Transfer placed the 275 MMcf/d Mustang Draw I processing plant into service in the Midland Basin.
    • In June and July 2026, Energy Transfer placed its third and fourth of eight planned 10-megawatt natural-gas fired electric generation facilities into service in West Texas to support the Partnership’s operations.

Financial Highlights

• In July 2026, Energy Transfer announced a quarterly cash distribution of $0.3400 per common unit ($1.36 annualized) for the quarter ended June 30, 2026, which is an increase of more than 3% compared to the second quarter of 2025. This is the Partnership’s nineteenth consecutive increase to its quarterly cash distribution.
• In July 2026, the Partnership issued $650 million aggregate principal amount of its Series 2026A junior subordinated notes due 2057 (the “Series 2026A notes”) and $1.10 billion aggregate principal amount of its Series 2026B junior subordinated notes due 2057 (the “Series 2026B notes”). Initially, the Series 2026A notes will bear interest at an annual rate of 6.550% and the Series 2026B notes will bear interest at an annual rate of 6.700%.
• As of June 30, 2026, the Partnership’s revolving credit facility had an aggregate $3.76 billion of available borrowing capacity.

Energy Transfer benefits from a portfolio of assets with exceptional product and geographic diversity. The Partnership’s multiple segments generate high-quality, balanced earnings with no single business segment contributing more than one-third of the Partnership’s consolidated Adjusted EBITDA for the three months ended June 30, 2026.

Conference call information:

The Partnership has scheduled a conference call for 8:00 a.m. Central Time/9:00 a.m. Eastern Time on Tuesday, August 4, 2026 to discuss its second quarter 2026 results and provide an update on the Partnership. The conference call will be broadcast live via an internet webcast, which can be accessed through www.energytransfer.com and will also be available for replay on the Partnership’s website for a limited time.

Energy Transfer LP (NYSE: ET) owns and operates one of the largest and most diversified portfolios of energy assets in the United States, with approximately 140,000 miles of pipeline and associated energy infrastructure. Energy Transfer’s strategic network spans 44 states with assets in all of the major U.S. production basins. Energy Transfer is a publicly traded limited partnership with core operations that include complementary natural gas midstream, intrastate and interstate transportation and storage assets; crude oil, natural gas liquids (“NGL”) and refined product transportation and terminalling assets; and NGL fractionation. Energy Transfer also owns the general partner interests, the incentive distribution rights and approximately 28 million common units (representing 15% of the aggregate outstanding common units and Class D units) of Sunoco LP (NYSE: SUN), the managing member interests in SunocoCorp LLC (NYSE: SUNC), and the general partner interests and approximately 46 million common units (representing 32% of the outstanding common units) of USA Compression Partners, LP (NYSE: USAC). For more information, visit the Energy Transfer LP website at www.energytransfer.com.

Sunoco LP (NYSE: SUN) is a leading energy infrastructure and fuel distribution master limited partnership operating across 33 countries and territories in North America, the Greater Caribbean, and Europe. SUN's midstream operations include an extensive network of approximately 14,000 miles of pipeline and over 170 terminals. This critical infrastructure complements SUN's fuel distribution operations, which distribute over 15 billion gallons annually to approximately 11,000 Sunoco and partner-branded retail locations, as well as independent dealers and commercial customers. SUN's general partner is owned by Energy Transfer LP. For more information, visit the Sunoco LP website at www.sunocolp.com.

SunocoCorp LLC (NYSE: SUNC) is a publicly traded limited liability company that owns a direct limited partner interest in Sunoco LP. For more information, visit the Sunoco LP website at www.sunocolp.com.

USA Compression Partners, LP (NYSE: USAC) is one of the nation’s largest independent providers of natural gas compression services in terms of total compression fleet horsepower. USAC partners with a broad customer base composed of producers, processors, gatherers, and transporters of natural gas and crude oil. USAC focuses on providing midstream natural gas compression services to infrastructure applications primarily in high-volume gathering systems, processing facilities, and transportation applications. For more information, visit the USAC website at www.usacompression.com.

Forward-Looking Statements

This news release may include certain statements concerning expectations for the future that are forward-looking statements as defined by federal law. Such forward-looking statements are subject to a variety of known and unknown risks, uncertainties, and other factors that are difficult to predict and many of which are beyond management’s control. An extensive list of factors that can affect future results, including Adjusted EBITDA, and impact current projections, including capital expenditures, are discussed in the Partnership’s Annual Report on Form 10-K and other documents filed from time to time with the Securities and Exchange Commission. The Partnership undertakes no obligation to update or revise any forward-looking statement to reflect new information or events.

The information contained in this press release is available on our website at www.energytransfer.com.

ENERGY TRANSFER LP AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS (In millions) (unaudited)
	June 30, 2026			December 31, 2025
ASSETS
Current assets	$	23,113		$	18,233
Property, plant and equipment, net		104,096			102,142
Investments in unconsolidated affiliates		3,637			3,589
Lease right-of-use assets, net		1,939			1,841
Other non-current assets, net		2,615			2,591
Intangible assets, net		7,160			7,438
Goodwill		5,608			5,452
Total assets	$	148,168		$	141,286
LIABILITIES AND EQUITY
Current liabilities	$	19,858		$	14,955
Long-term debt, less current maturities		68,393			68,308
Non-current operating lease liabilities		1,621			1,515
Deferred income taxes		5,572			5,307
Other non-current liabilities		1,946			1,941
Commitments and contingencies
Redeemable noncontrolling interests		256			250
Equity:
Limited Partners:
Preferred Unitholders		3,356			3,356
Common Unitholders		31,927			30,930
General Partner		(1	)		(2	)
Accumulated other comprehensive income		49			82
Total partners’ capital		35,331			34,366
Noncontrolling interests		15,191			14,644
Total equity		50,522			49,010
Total liabilities and equity	$	148,168		$	141,286

ENERGY TRANSFER LP AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (In millions, except per unit data) (unaudited)
	Three Months Ended June 30,						Six Months Ended June 30,
		2026			2025			2026			2025
REVENUES	$	34,334		$	19,242		$	62,105		$	40,262
COSTS AND EXPENSES:
Cost of products sold		26,936			13,946			48,085			29,517
Operating expenses		1,828			1,343			3,523			2,642
Depreciation, depletion and amortization		1,575			1,384			3,158			2,751
Selling, general and administrative		421			257			782			545
Impairment loss		—			3			—			7
Total costs and expenses		30,760			16,933			55,548			35,462
OPERATING INCOME		3,574			2,309			6,557			4,800
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized		(934	)		(865	)		(1,881	)		(1,674	)
Equity in earnings of unconsolidated affiliates		108			105			218			197
Losses on extinguishments of debt		—			(17	)		(7	)		(19	)
Other, net		(24	)		5			(52	)		(6	)
INCOME BEFORE INCOME TAX EXPENSE		2,724			1,537			4,835			3,298
Income tax expense		194			79			329			120
NET INCOME		2,530			1,458			4,506			3,178
Less: Net income attributable to noncontrolling interests		432			275			1,147			659
Less: Net income attributable to redeemable noncontrolling interests		10			20			17			33
NET INCOME ATTRIBUTABLE TO PARTNERS		2,088			1,163			3,342			2,486
General Partner’s interest in net income		2			1			3			2
Preferred Unitholders’ interest in net income		59			63			118			130
Loss on redemption of preferred units		—			8			—			8
Common Unitholders’ interest in net income	$	2,027		$	1,091		$	3,221		$	2,346
NET INCOME PER COMMON UNIT:
Basic	$	0.59		$	0.32		$	0.94		$	0.68
Diluted	$	0.59		$	0.32		$	0.93		$	0.68
WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING:
Basic		3,442.2			3,432.2			3,441.4			3,431.8
Diluted		3,463.1			3,453.5			3,462.5			3,454.1

ENERGY TRANSFER LP AND SUBSIDIARIES SUPPLEMENTAL INFORMATION (Dollars and units in millions) (unaudited)
	Three Months Ended June 30,						Six Months Ended June 30,
		2026			2025			2026			2025
Reconciliation of net income to Adjusted EBITDA and Distributable Cash Flow^(a):
Net income	$	2,530		$	1,458		$	4,506		$	3,178
Depreciation, depletion and amortization		1,575			1,384			3,158			2,751
Interest expense, net of interest capitalized		934			865			1,881			1,674
Income tax expense		194			79			329			120
Impairment losses		—			3			—			7
Non-cash compensation expense		46			33			88			70
Unrealized (gains) losses on commodity risk management activities		(396	)		(100	)		140			(31	)
Inventory valuation adjustments (Sunoco LP)		18			40			(426	)		(21	)
Losses on extinguishments of debt		—			17			7			19
Adjusted EBITDA related to unconsolidated affiliates		196			182			392			349
Equity in earnings of unconsolidated affiliates		(108	)		(105	)		(218	)		(197	)
Other, net		77			10			146			45
Adjusted EBITDA (consolidated)		5,066			3,866			10,003			7,964
Adjusted EBITDA related to unconsolidated affiliates^(b)		(196	)		(182	)		(392	)		(349	)
Distributable cash flow from unconsolidated affiliates^(b)		134			129			269			240
Interest expense, net of interest capitalized		(934	)		(865	)		(1,881	)		(1,674	)
Preferred unitholders’ distributions ^(c)		(89	)		(65	)		(177	)		(137	)
Current income tax expense		(119	)		(55	)		(162	)		(112	)
Maintenance capital expenditures		(401	)		(305	)		(678	)		(507	)
Other, net		12			13			38			35
Distributable Cash Flow (consolidated)		3,473			2,536			7,020			5,460
Distributable Cash Flow attributable to Sunoco LP and SunocoCorp ^(d)		(594	)		(290	)		(1,120	)		(600	)
Distributions from Sunoco LP		102			67			201			131
Distributable Cash Flow attributable to USAC (100%)		(125	)		(90	)		(256	)		(179	)
Distributions from USAC		24			24			48			48
Distributable Cash Flow attributable to noncontrolling interests in other non-wholly owned consolidated subsidiaries		(293	)		(289	)		(602	)		(597	)
Distributable Cash Flow attributable to the partners of Energy Transfer		2,587			1,958			5,291			4,263
Transaction-related adjustments		—			1			—			3
Distributable Cash Flow attributable to the partners of Energy Transfer, as adjusted	$	2,587		$	1,959		$	5,291		$	4,266
Distributions to partners:
Limited Partners	$	1,171		$	1,133		$	2,332		$	2,257
General Partner		1			1			2			2
Total distributions to be paid to partners	$	1,172		$	1,134		$	2,334		$	2,259
Common Units outstanding – end of period		3,443.3			3,432.6			3,443.3			3,432.6

(a)	Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating results of Energy Transfer’s fundamental business activities and should not be considered in isolation or as a substitute for net income, income from operations, cash flows from operating activities or other GAAP measures.
	There are material limitations to using measures such as Adjusted EBITDA and Distributable Cash Flow, including the difficulty associated with using either as the sole measure to compare the results of one company to another, and the inability to analyze certain significant items that directly affect a company’s net income or loss or cash flows. In addition, our calculations of Adjusted EBITDA and Distributable Cash Flow may not be consistent with similarly titled measures of other companies and should be viewed in conjunction with measures that are computed in accordance with GAAP, such as operating income, net income and cash flows from operating activities.
	Definition of Adjusted EBITDA
	We define Adjusted EBITDA as total partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt, certain foreign currency transaction gains and losses and other non-operating income or expense items. Inventory valuation adjustments that are excluded from the calculation of Adjusted EBITDA represent only the changes in lower of cost or market reserves on inventory that is carried at last-in, first-out (“LIFO”). These amounts are unrealized valuation adjustments applied to Sunoco LP’s fuel volumes remaining in inventory at the end of the period.
	Adjusted EBITDA reflects 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 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 Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.
	Adjusted EBITDA is used by management to determine our operating performance and, along with other financial and volumetric data, as internal measures for setting annual operating budgets, assessing financial performance of our numerous business locations, as a measure for evaluating targeted businesses for acquisition and as a measurement component of incentive compensation.
	Definition of Distributable Cash Flow
	We define Distributable Cash Flow as net income, adjusted for certain non-cash items, less distributions to preferred unitholders and maintenance capital expenditures. Non-cash items include depreciation, depletion and amortization, non-cash compensation expense, amortization included in interest 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 deferred income taxes. For unconsolidated affiliates, Distributable Cash Flow reflects the Partnership’s proportionate share of the investees’ distributable cash flow.
	Distributable Cash Flow is used by management to evaluate our overall performance. Our partnership agreement requires us to distribute all available cash, and Distributable Cash Flow is calculated to evaluate our ability to fund distributions through cash generated by our operations.
	On a consolidated basis, Distributable Cash Flow includes 100% of the Distributable Cash Flow of Energy Transfer’s consolidated subsidiaries. However, to the extent that noncontrolling interests exist among our subsidiaries, the Distributable Cash Flow generated by our subsidiaries may not be available to be distributed to our partners. In order to reflect the cash flows available for distributions to our partners, we have reported Distributable Cash Flow attributable to partners, which is calculated by adjusting Distributable Cash Flow (consolidated), as follows:
	For subsidiaries with publicly traded equity interests, Distributable Cash Flow (consolidated) includes 100% of Distributable Cash Flow attributable to such subsidiary, and Distributable Cash Flow attributable to our partners includes distributions to be received by the parent company with respect to the periods presented. For consolidated joint ventures or similar entities, where the noncontrolling interest is not publicly traded, Distributable Cash Flow (consolidated) includes 100% of Distributable Cash Flow attributable to such subsidiaries, but Distributable Cash Flow attributable to partners reflects only the amount of Distributable Cash Flow of such subsidiaries that is attributable to our ownership interest.
	For Distributable Cash Flow attributable to partners, as adjusted, certain transaction-related adjustments and non-recurring expenses that are included in net income are excluded.
(b)	These amounts exclude Sunoco LP’s Adjusted EBITDA and distributable cash flow related to its investment in the ET-S Permian and J.C. Nolan joint ventures, which amounts are eliminated in the Energy Transfer consolidation.
(c)	For the three and six months ended June 30, 2026, preferred unitholders’ distributions include $29 million and $59 million, respectively, of accrued distributions on Sunoco LP’s Series A preferred units, which were issued in September 2025.
(d)	Beginning with the three months ended December 31, 2025, this amount includes the distributable cash flow of Sunoco LP and SunocoCorp, eliminating the distributable cash flow of Sunoco LP that is attributable to SunocoCorp.

ENERGY TRANSFER LP AND SUBSIDIARIES SUMMARY ANALYSIS OF QUARTERLY RESULTS BY SEGMENT (Tabular dollar amounts in millions) (unaudited)
	Three Months Ended June 30,
	2026			2025
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	377	$	284
Interstate transportation and storage		481		470
Midstream		884		768
NGL and refined products transportation and services		1,308		1,033
Crude oil transportation and services		834		732
Investment in Sunoco LP		982		454
Investment in USAC		194		149
All other		6		(24	)
Adjusted EBITDA (consolidated)	$	5,066	$	3,866
The following analysis of segment operating results includes a measure of segment margin. Segment margin is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment margin is similar to the GAAP measure of gross margin, except that segment margin excludes charges for depreciation, depletion and amortization. Among the GAAP measures reported by the Partnership, the most directly comparable measure to segment margin is Segment Adjusted EBITDA; a reconciliation of segment margin to Segment Adjusted EBITDA is included in the following tables for each segment where segment margin is presented.

Intrastate Transportation and Storage
	Three Months Ended June 30,
		2026			2025
Natural gas transported (BBtu/d)		13,814			14,229
Withdrawals from storage natural gas inventory (BBtu)		4,020			—
Revenues	$	596		$	931
Cost of products sold		132			561
Segment margin		464			370
Unrealized gains on commodity risk management activities		(6	)		(21	)
Operating expenses, excluding non-cash compensation expense		(75	)		(61	)
Selling, general and administrative expenses, excluding non-cash compensation expense		(15	)		(10	)
Adjusted EBITDA related to unconsolidated affiliates		8			5
Other		1			1
Segment Adjusted EBITDA	$	377		$	284
Transported volumes of gas on our Texas intrastate pipelines decreased primarily due to lower third-party utilization of firm capacity. Transported volumes reported above exclude volumes attributable to purchases and sales of gas for our pipelines’ own accounts and the optimization of any unused capacity.
Segment Adjusted EBITDA. For the three months ended June 30, 2026 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impact of the following:
an increase of $113 million in realized natural gas sales and other primarily due to wider basis differentials, as well as a $21 million increase from early volumes during the commissioning of the Hugh Brinson Pipeline; and an increase of $5 million in transportation fees due to higher reservation revenues on long-term third-party contracts; partially offset by a decrease of $10 million in storage margin due to unfavorable storage optimization; an increase of $14 million in operating expenses primarily due to a $4 million increase in maintenance and project related expenses, a $4 million increase from one-time expenses, a $4 million increase from the commissioning of the Hugh Brinson pipeline, and increases totaling $2 million from various other operating expenses; and an increase of $5 million in selling, general and administrative expenses primarily due to higher legal fees.

Interstate Transportation and Storage
	Three Months Ended June 30,
		2026			2025
Natural gas transported (BBtu/d)		17,988			18,153
Natural gas sold (BBtu/d)		19			30
Revenues	$	609		$	590
Cost of products sold		4			3
Segment margin		605			587
Operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses		(230	)		(221	)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses		(34	)		(26	)
Adjusted EBITDA related to unconsolidated affiliates		130			130
Other		10			—
Segment Adjusted EBITDA	$	481		$	470
Transported volumes decreased primarily due to lower utilization on our Trunkline, Gulf Run and Mississippi River systems due to lower demand.
Segment Adjusted EBITDA. For the three months ended June 30, 2026 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net impact of the following:
an increase of $18 million in segment margin primarily due to a $12 million increase in parking, storage and liquids revenue and a $10 million increase in transportation revenue from several of our interstate pipeline systems due to higher contracted volumes and higher utilization, partially offset by a $4 million decrease in operational gas sales; and an increase of $10 million in other income primarily due to the realization of proceeds from a shipper bankruptcy settlement; partially offset by an increase of $9 million in operating expenses primarily due to a $4 million increase in maintenance projects, a $3 million increase in employee costs and a $1 million increase in new or renegotiated leases; and an increase of $8 million in selling, general and administrative expenses primarily due to higher allocated costs, excise taxes and insurance expense.

Midstream
	Three Months Ended June 30,
		2026			2025
Gathered volumes (BBtu/d)		22,142			21,329
NGLs produced (MBbls/d)		1,243			1,181
Equity NGLs (MBbls/d)		72			64
Revenues	$	2,821		$	3,135
Cost of products sold		1,392			1,911
Segment margin		1,429			1,224
Operating expenses, excluding non-cash compensation expense		(513	)		(416	)
Selling, general and administrative expenses, excluding non-cash compensation expense		(52	)		(47	)
Adjusted EBITDA related to unconsolidated affiliates		5			6
Other		15			1
Segment Adjusted EBITDA	$	884		$	768
Gathered volumes increased from dry gas gathering in the Northeast and Ark-La-Tex regions as well as increased processing volumes from new and upgraded plants in the Permian region. NGL production increased primarily due to increased Permian plant utilization from new and existing plants.
Segment Adjusted EBITDA. For the three months ended June 30, 2026 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net impact of the following:
an increase of $205 million in segment margin primarily due to higher NGL prices of $88 million, a positive impact of $11 million from natural gas prices, and an $83 million increase due to higher gathered and processed volumes from increased processing capacity and operational efficiencies; and an increase of $14 million in other income due to the realization of proceeds from a shipper bankruptcy settlement; partially offset by an increase of $97 million in operating expenses primarily due to a $46 million increase related to environmental reserves, a $39 million increase related to the adjustment of certain estimates in the prior period and a $15 million increase in employee costs; and an increase of $5 million in selling, general, and administrative expenses primarily due to higher corporate allocations.

NGL and Refined Products Transportation and Services
	Three Months Ended June 30,
		2026			2025
NGL transportation volumes (MBbls/d)		2,641			2,331
Refined products transportation volumes (MBbls/d)		574			599
NGL and refined products terminal volumes (MBbls/d)		1,864			1,553
NGL fractionation volumes (MBbls/d)		1,188			1,150
Revenues	$	7,719		$	5,941
Cost of products sold		5,927			4,635
Segment margin		1,792			1,306
Unrealized gains on commodity risk management activities		(185	)		(34	)
Operating expenses, excluding non-cash compensation expense		(284	)		(230	)
Selling, general and administrative expenses, excluding non-cash compensation expense		(48	)		(41	)
Adjusted EBITDA related to unconsolidated affiliates		31			32
Other		2			—
Segment Adjusted EBITDA	$	1,308		$	1,033
NGL transportation, fractionation, and terminal throughput volumes increased due to higher volumes from the Permian region, as well as increased NGL exports.
Segment Adjusted EBITDA. For the three months ended June 30, 2026 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impacts of the following:
an increase of $212 million in marketing margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to $140 million from higher premiums from the sale of NGLs for export and for domestic supply and a $70 million increase in refined product margins as a result of higher spreads and prices; an increase of $71 million in terminal services margin primarily due to a $63 million increase in fees from loading increased volumes at higher rates for export at our Nederland and Marcus Hook terminals, and an $8 million increase from higher throughput and storage at our refined product terminals; an increase of $28 million in transportation margin due to a $40 million increase related to higher y-grade and NGL throughput, partially offset by a $4 million decrease due to lower refined product transportation volumes due to third-party refinery issues; an increase of $12 million in storage margin primarily due to an increase in fees generated from export volumes, as well as increases related to blending activity due to a more favorable pricing environment; and an increase of $12 million in fractionators and refinery services margin primarily due to higher throughput; partially offset by an increase of $54 million in operating expenses primarily due to a $28 million increase from certain one-time credits recognized in the prior period, a $14 million increase in utilities costs driven by higher volumes across our system, a $6 million increase in employee costs, and increases totaling $5 million from various other operating expenses; and an increase of $7 million in selling, general and administrative expenses primarily due to higher overhead costs and legal fees.

Crude Oil Transportation and Services
	Three Months Ended June 30,
		2026			2025
Crude oil transportation volumes (MBbls/d)		7,336			7,049
Crude oil terminal volumes (MBbls/d)		4,911			4,633
Revenues	$	11,051		$	5,748
Cost of products sold		9,766			4,725
Segment margin		1,285			1,023
Unrealized gains on commodity risk management activities		(181	)		(25	)
Operating expenses, excluding non-cash compensation expense		(231	)		(237	)
Selling, general and administrative expenses, excluding non-cash compensation expense		(45	)		(38	)
Adjusted EBITDA related to unconsolidated affiliates		6			8
Other		—			1
Segment Adjusted EBITDA	$	834		$	732
Crude oil transportation volumes were higher due to higher volumes on our Texas pipeline system, our Permian and Bakken gathering systems, partially offset by lower volume on our Mid-continent pipelines. Crude oil terminal volumes were higher due to higher customer throughput related to strategic petroleum reserve releases and crude export demand at our Gulf Coast terminals. Beginning in the current period, the Partnership has updated its approach for calculating crude oil terminal volumes to be consistent across all terminals; volumes reported for prior periods have been revised accordingly.
Segment Adjusted EBITDA. For the three months ended June 30, 2026 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impact of the following:
an increase of $106 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $62 million increase in optimization gains from more favorable market conditions and higher refined product margins, a $19 million increase in crude gathering revenues, a $17 million increase in transportation revenue, and a $6 million increase from higher crude oil terminal volumes; and a decrease of $6 million in operating expenses primarily due to lower maintenance project related expenses; partially offset by an increase of $7 million in selling, general and administrative expenses due primarily to higher expenses associated with a litigation related contingency.

Investment in Sunoco LP
	Three Months Ended June 30,
		2026			2025
Revenues	$	14,259		$	5,390
Cost of products sold		12,795			4,821
Segment margin		1,464			569
Unrealized gains on commodity risk management activities		(6	)		(7	)
Operating expenses, excluding non-cash compensation expense		(434	)		(162	)
Selling, general and administrative expenses, excluding non-cash compensation expense		(155	)		(47	)
Adjusted EBITDA related to unconsolidated affiliates		75			51
Inventory fair value adjustments		18			40
Other, net		20			10
Segment Adjusted EBITDA	$	982		$	454
The investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.
Segment Adjusted EBITDA. For the three months ended June 30, 2026 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP segment increased due to the net impact of the following:
an increase of $874 million in segment margin (excluding unrealized gains and losses on commodity risk management activities and inventory valuation adjustments) primarily due to recent acquisitions; and an increase of $24 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to the Parkland acquisition and ET-S Permian joint venture; partially offset by an increase of $272 million in operating expenses primarily due to increased costs resulting from recently acquired businesses; and an increase of $108 million in selling, general and administrative expenses primarily due to increased costs resulting from recently acquired businesses, along with one-time transaction-related expenses associated with those acquisitions.

Investment in USAC
	Three Months Ended June 30,
		2026			2025
Revenues	$	342		$	250
Cost of products sold		33			40
Segment margin		309			210
Operating expenses, excluding non-cash compensation expense		(91	)		(47	)
Selling, general and administrative expenses, excluding non-cash compensation expense		(27	)		(14	)
Other		3			—
Segment Adjusted EBITDA	$	194		$	149
The investment in USAC segment reflects the consolidated results of USAC.
Segment Adjusted EBITDA. For the three months ended June 30, 2026 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC segment increased due to the net impact of the following:
an increase of $99 million in segment margin primarily due to the J-W Power Acquisition and increases in USAC’s legacy business; partially offset by an increase of $57 million in operating expense and selling, general and administrative expense primarily related to the J-W Power Acquisition, as well as increased expenses in outside services and professional fees.

All Other
	Three Months Ended June 30,
		2026			2025
Revenues	$	565		$	936
Cost of products sold		502			909
Segment margin		63			27
Unrealized gains on commodity risk management activities		(18	)		(14	)
Operating expenses, excluding non-cash compensation expense		(6	)		—
Selling, general and administrative expenses, excluding non-cash compensation expense		(13	)		(13	)
Adjusted EBITDA related to unconsolidated affiliates		2			2
Other and eliminations		(22	)		(26	)
Segment Adjusted EBITDA	$	6		$	(24	)
Segment Adjusted EBITDA. For the three months ended June 30, 2026 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment increased due to the net impact of the following:
an increase of $49 million in our natural gas marketing business driven by favorable spreads and gains on residue gas sales; partially offset by a decrease of $11 million due to an increase in the intersegment elimination of Sunoco LP’s 32.5% share of ET-S Permian, which is consolidated in our crude oil transportation and services segment and also reflected as an unconsolidated affiliate in our investment in Sunoco LP segment; and a decrease of $13 million in our dual drive compression business.

ENERGY TRANSFER LP AND SUBSIDIARIES SUPPLEMENTAL INFORMATION ON LIQUIDITY (In millions) (unaudited)
The table below provides information on our revolving credit facility. We also have consolidated subsidiaries with revolving credit facilities which are not included in this table.
	Facility Size		Funds Available at June 30, 2026		Maturity Date
Five-Year Revolving Credit Facility	$	5,000	$	3,764	April 11, 2029

ENERGY TRANSFER LP AND SUBSIDIARIES SUPPLEMENTAL INFORMATION ON UNCONSOLIDATED AFFILIATES (In millions) (unaudited)
The table below provides information on an aggregated basis for our unconsolidated affiliates, which are accounted for as equity method investments in the Partnership’s financial statements for the periods presented.
	Three Months Ended June 30,
		2026		2025
Equity in earnings of unconsolidated affiliates:
Citrus	$	38	$	40
MEP		20		18
White Cliffs		7		5
Explorer		5		7
SESH		14		14
Other		24		21
Total equity in earnings of unconsolidated affiliates	$	108	$	105
Adjusted EBITDA related to unconsolidated affiliates:
Citrus	$	87	$	88
MEP		28		26
White Cliffs		12		10
Explorer		9		12
SESH		15		15
Other		45		31
Total Adjusted EBITDA related to unconsolidated affiliates	$	196	$	182
Distributions received from unconsolidated affiliates:
Citrus	$	33	$	36
MEP		30		29
White Cliffs		11		9
Explorer		5		10
SESH		17		15
Other		30		25
Total distributions received from unconsolidated affiliates	$	126	$	124

ENERGY TRANSFER LP AND SUBSIDIARIES SUPPLEMENTAL INFORMATION ON NON-WHOLLY OWNED JOINT VENTURE SUBSIDIARIES (In millions) (unaudited)
The table below provides information on an aggregated basis for our non-wholly owned joint venture subsidiaries, which are reflected on a consolidated basis in our financial statements. The table below excludes Sunoco LP and USAC, which are non-wholly owned subsidiaries that are publicly traded, as well as Sunoco LP’s 32.5% interest in the ET-S Permian joint venture.
	Three Months Ended June 30,
		2026		2025
Adjusted EBITDA of non-wholly owned subsidiaries (100%) ^(a)	$	578	$	566
Our proportionate share of Adjusted EBITDA of non-wholly owned subsidiaries ^(b)		285		275
Distributable Cash Flow of non-wholly owned subsidiaries (100%) ^(c)	$	558	$	544
Our proportionate share of Distributable Cash Flow of non-wholly owned subsidiaries ^(d)		265		255

Below is our ownership percentage of certain non-wholly owned subsidiaries:
Non-wholly owned subsidiary:	Energy Transfer Percentage Ownership ^(e)
Bakken Pipeline	36.4 %
Bayou Bridge	60.0 %
Maurepas	51.0 %
Ohio River System	75.0 %
Permian Express Partners	87.7 %
Red Bluff Express	70.0 %
Rover	32.6 %
Others	various

(a)	Adjusted EBITDA of non-wholly owned subsidiaries reflects the total Adjusted EBITDA of our non-wholly owned subsidiaries on an aggregated basis. This is the amount included in our consolidated non-GAAP measure of Adjusted EBITDA.
(b)	Our proportionate share of Adjusted EBITDA of non-wholly owned subsidiaries reflects the amount of Adjusted EBITDA of such subsidiaries (on an aggregated basis) that is attributable to our ownership interest.
(c)	Distributable Cash Flow of non-wholly owned subsidiaries reflects the total Distributable Cash Flow of our non-wholly owned subsidiaries on an aggregated basis.
(d)	Our proportionate share of Distributable Cash Flow of non-wholly owned subsidiaries reflects the amount of Distributable Cash Flow of such subsidiaries (on an aggregated basis) that is attributable to our ownership interest. This is the amount included in our consolidated non-GAAP measure of Distributable Cash Flow attributable to the partners of Energy Transfer.
(e)	Our ownership reflects the total economic interest held by us and our subsidiaries. In some cases, this percentage comprises ownership interests held in (or by) multiple entities.