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ENERGY TRANSFER Moving America's Energy Investor Presentation August 2026
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Forward-looking Statements / Legal Disclaimer 2 Management of Energy Transfer LP (ET) will provide this presentation to analysts and/or investors throughout August 2026. At the meetings, members of management may make statements about future events, outlook and expectations related to Sunoco LP (SUN), SunocoCorp LLC (SUNC), USA Compression Partners, LP (USAC), and ET (collectively, the Partnerships), and their subsidiaries and this presentation may contain statements about future events, outlook and expectations related to the Partnerships and their subsidiaries, all of which statements are forward-looking statements. These may also include certain statements about the Partnerships’ ability to successfully complete projects and integrate transactions described herein and the possibility that the anticipated benefits of the projects and transactions cannot be fully realized. Any statement made by a member of management of the Partnerships and any statement in this presentation that is not a historical fact will be deemed to be a forward-looking statement. These forward-looking statements rely on a number of assumptions concerning future events that members of management of the Partnerships believe to be reasonable, but these statements are subject to a number of risks, uncertainties and other factors, many of which are outside the control of the Partnerships. While the Partnerships believe that the assumptions concerning these future events are reasonable, we caution that there are inherent risks and uncertainties in predicting these future events that could cause the actual results, performance or achievements of the Partnerships and their subsidiaries to be materially different. These risks and uncertainties are discussed in more detail in the filings made by the Partnerships with the Securities and Exchange Commission, copies of which are available to the public. In addition to the risks and uncertainties disclosed in our SEC filings the Partnerships expressly disclaim any intention or obligation to revise or publicly update any forward-looking statements, whether as a result of new information, future events, or otherwise. This presentation includes certain forward looking non-GAAP financial measures as defined under SEC Regulation G, including estimated adjusted EBITDA. Due to the forward-looking nature of the aforementioned non-GAAP financial measures, management cannot reliably or reasonably predict certain of the necessary components of the most directly comparable forward-looking GAAP measures without unreasonable effort. Accordingly, we are unable to present a quantitative reconciliation of such forward-looking non-GAAP financial measures to their most directly comparable forward-looking GAAP financial measures. All references in this presentation to capacity of a pipeline, processing plant or storage facility relate to maximum capacity under normal operating conditions and with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may reduce the throughput capacity from specified capacity levels.
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High Yield Supported By Strong Cash Flows One-Of-A-Kind Asset Base Exposure To Emerging Industry Trends Well Balanced Fee-Based Earnings Why Invest In ET? 3 ~7% current cash distribution yield¹ Expected Adjusted EBITDA: $18.8B - $19.1B for 2026 (up ~$0.5B from $18.2 - $18.6 at the midpoint) Solid cash distribution coverage ratio Targeting 3% to 5% long-term annual distribution growth rate Unmatched product diversity with gas, NGLs and crude oil All areas contribute with no segment more than 30% Very high fee-based earnings profile with ability to capture upside from market opportunities 1. As of August 7, 2026 Assets located in all major U.S. producing basins and connected to major markets throughout the country ~140,000 miles of energy infrastructure Irreplaceable franchise with unique flexibility and connectivity Significant backlog of growth projects Increasing demand for natural gas infrastructure Growing NGL exports and higher liquids volumes Leverage strategic asset base around key oil basins
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What’s New? 4 1. Energy Transfer excluding SUN and USA Compression capital expenditures • Adjusted EBITDA: ‒ Q2’26: $5.07B; up 31% from Q2’25 • Distributable Cash Flow attributable to partners: ‒ Q2’26: $2.59B; up 32% from Q2’25 • YTD’26 Capital Expenditures: ‒ Growth: $2.6B¹ ‒ Maintenance: $482MM¹ • Updated 2026 Guidance: ‒ Adjusted EBITDA: $18.8B - $19.1B ‒ Expected Growth Capital: ~$5.6B - $5.9B¹ • Announced 19th consecutive increase to quarterly cash distribution to $0.34 per unit; up more than 3% vs Q2’25 Q2’26 Financial Results • Announced fully-subscribed ethane export expansion at Nederland to increase ethane export capacity by 240,000 Bbls/d and LPG export capacity by 55,000 Bbls/d • Signed long-term NGL transportation or fractionation agreements for ~300,000 Bbls/d • Agreement with Crusoe to construct facilities to provide natural gas to support its previously announced expansion at its AI factory campus in Abilene, TX • On the Desert Southwest expansion project, FERC recently completed scoping meetings in communities along the route • Announced Springerville Lateral Project to provide natural gas to new gas-powered generation that is expected to replace two coal-fired plants Strategic ExpansionsOperational Updates • Volumes compared to Q2’25 ‒ NGL transportation volumes up 13% ‒ Total NGL exports up 25% ‒ NGL fractionation volumes up 3% ‒ Crude Oil transportation volumes up 4% ‒ Midstream gathered volumes up 4% • Announced Hugh Brinson pipeline is now in commercial service • Placed 275 MMcf/d Mustang Draw I processing plant into service • Completed a second lateral (14-miles) off the Hugh Brinson Pipeline in Abilene, TX • Completed 90,000 Bbls/d upgrades to Lone Star Express NGL pipeline • Placed 3rd and 4th 10-MW natural-gas fired electric generation facilities into service Indicates new Partnership record
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Nationwide Footprint With Diverse Product Offerings 5 Asset Overview Natural Gas Natural Gas Liquids (NGLs) Crude Refined Products Storage Mont Belvieu NGL Complex Terminals Processing Major Terminals Marcus Hook Terminal Nederland Terminal Midland Terminals Lake Charles RegasHouston Terminal Cushing Terminal
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Fee³ ~90% Spread² 0-5% Commodity 5-10% Well-Balanced, Diversified, Fee-Based Earnings 61. Energy Transfer excluding SUN and USA Compression 2. Spread margin is pipeline basis, cross commodity and time spreads – Spread margin is likely to slightly exceed 5% for 2026 with busines s outperformance due to 1H commodity price volatility 3. Fee margins include transport and storage fees from affiliate customers at market rates Q2 2026 Adjusted EBITDA by Segment Historical Adjusted EBITDA Breakout¹ Midstream 17% NGL & Refined Products 26% Crude Oil 17% Natural Gas Inter & Intrastate Pipelines & Storage 17% SUN, USAC & Other 24%
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Well Positioned At The Intersection Of Many Key Themes 7 ‒ Gas-to-power developments ‒ LNG feedgas Future earnings leverage from ramping growth capex $- $2 $4 $6 $8 $10 $12 $14 $16 $18 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 $ in billions $13.0 $16.0$15.5 $13.7$13.1 $1.4B $1.9B $1.6B $3.0B $4.5BGrowth Capex1: Visible growth drivers across business Natural Gas NGLs Crude Oil ‒ Growing export business ‒ Increasing on-system volumes ‒ Leading Permian franchise ‒ Increasing Canadian volumes flowing south Historical Adjusted EBITDA 2026E Organic Growth Capital: ~$5.6-$5.9 billion¹ 1. Energy Transfer excluding SUN and USA Compression capital expenditures
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Leading Natural Gas Pipeline Footprint Well-Positioned to Meet Growing Electricity Demand 81. Initial volumes; Transporter has center rights to increase capacity, upon their election Increasing interest and commitments for natural gas services to serve large data centers and power plants at or near those sites In advanced negotiations with multiple power plants, data centers, and other demand-based customers to provide significant volumes associated with ET’s natural gas business in Texas, Oklahoma, Arkansas, Louisiana, Ohio, Illinois, Florida and many other states along its pipeline network Signed agreements with Oracle to provide natural gas to three U.S data centers, two of which are in Texas: ~900,000 Mcf/d Added connections to serve 4 new power plant loads in OK: ~300,000 Mcf/d Signed agreements to provide Nexus Hubbard Campus with gas for AI hyperscale campus under construction in Central TX: 150,000 MMcf/d¹ 20-year binding agreement with Entergy Louisiana to provide natural gas to their facilities in Richland Parish, LA: 250,000 MMBtu/d Entered into agreement with Crusoe to construct facilities to provide natural gas to its previously announced AI factory campus in Abilene, TX: Support ~900 MW capacity
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Enhancing Strategic Footprint In Leading Natural Gas Franchise 9 1. Represents ET’s 50% share 2. With certain rights by the transporter to increase capacity upon election Recently Announced Major Gas Pipeline Projects Announced Capex Mainline Pipeline Dec-2024 $2.7B Hugh Brinson – 42” Aug-2025 Dec-2025 Up to $5.6B Desert Southwest Pipeline – 42” Upsized Desert Southwest – 48” Feb-2026 $535mm¹ FGT Phase IX Feb-2026 $110mm¹ FGT South Florida May-2026 $600mm Springerville Lateral Recently Announced Pipeline Laterals Announced Pipeline Laterals Gas Supplied May-2025 & Aug-2025 Oracle Natural Gas Supply (x4) ~900,000 Mcf/d (Total) Nov-2025 Entergy LA/Franklin Farms 250,000+ MMBtu/d Feb-2026 OK Power Plant Connections (x4) ~300,000 Mcf/d (Total) May-2026 AR Center Gas Supply ~150,000 Mcf/d May-2026 Nexus Hubbard Gas Supply ~150,000 Mcf/d² July-2026 Facilities to support Crusoe AI factory campus Support 900 MW Significant future opportunities supported by leading gas network Minimal capital investment required Strong returns with “last mile” connections Available upstream pipeline capacity 5-6x EBITDA build multiple
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Project Name Natural Gas Project Overviews Status Mustang Draw I Processing Plant 275 MMcf/d processing plant in the Midland Basin In Service Mustang Draw II Processing Plant 275 MMcf/d processing plant in the Midland Basin Q4 2026 Natural Gas Fired Electric Gen Constructing 8, 10 MW natural gas-fired electric generation facilities to support Energy Transfer’s operations in Texas 3rd and 4th now in service OK Power Plant Connections Added connections to serve four new power plant loads in Oklahoma for a total of ~300 MMcf/d of new gas supply; supported by long-term contracts with investment-grade counterparties 1st in service; 3rd and 4th ready for service; Last Q4’28 Hugh Brinson Phase I and II ~400-mile, bi-directional intrastate natural gas pipeline from Waha to ET’s extensive pipeline network south of the DFW metroplex; expected to have the ability to transport ~2.2 Bcf/d from west to east, and also transport ~1 Bcf/d from east to west In commercial service with full Phase I Sept. 1, 2026; Phase II Q1 2027 Oracle Natural Gas Supply Multiple long-term agreements with Oracle to supply ~900,000 Mcf/d of natural gas to three U.S. data centers, two of which are in Texas; expected to be sourced from ET’s extensive natural gas pipeline network TX pipes ready for service Nexus Hubbard Gas Supply Agreements to provide long-term, firm natural gas transportation services to support the Nexus Hubbard Campus, where Nexus is constructing a BTM AI hyperscale campus powered by on-site natural gas generation. Initial volumes expected to be ~150 MMcf/d¹ Q4 2026 AR Data Center Gas Supply Precedent Agreement to provide ~150 MMcf/d of firm natural gas transportation service through EGT pipeline to support new data center site in Arkansas Mid-2027 FGT Phase IX Construction of ~90 miles of pipeline looping, as well as new and upgraded compression with capacity of ~525 MMcf/d Q4 2028 Entergy LA / Franklin Farms 20-year binding agreement with Entergy Louisiana to provide at least 250,000 MMBtu/d of firm transportation service to fuel facilities in Richland Parish, LA; includes expanding Tiger pipeline with the construction of an 18-mile, 36" lateral Agmnt begins Dec 2028 Bethel Storage Expansion Constructing new storage cavern at Bethel natural gas storage facility to double working gas storage capacity to over 12 Bcf Q1 2029 Desert Southwest Expansion ~520-mile, 48-inch pipeline to provide up to ~2.3 Bcf/d of natural gas transportation capacity from the Permian Basin to markets in southern New Mexico, Arizona and across the southwest region of the United States By Q4 2029 TW Springerville Lateral 125-mile, 30-inch pipeline with a capacity of ~625MMcf/d; extends south from existing Transwestern Pipeline to new natural gas-powered generation that is expected to replace two coal-fired plants; backed by 20-year agreements Q4 2029 FGT South Florida Construction of ~40-mile, ~230 MMcf/d extension to supply the South Florida area, along with compression and a new meter station Q1 2030 Natural Gas | Announced Growth Projects 101. With certain rights by the transporter to increase capacity upon election
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Hugh Brinson Pipeline Project Serving Premier Texas Markets and Supporting Data Center and AI Growth 11 Further enhances Energy Transfer’s flexibility to deliver natural gas to premier Texas markets and trading hubs, and its ability to support power plant and data center growth Phase I Now In Commercial Service: • ~400 miles of 42” pipeline from Waha and the Midland Basin to Maypearl, TX • 42-mile, 36-inch Midland Lateral to connect ET processing plants in Martin and Midland counties to the Hugh Brinson Pipeline Anticipate Hugh Brinson will be capable of flowing the full Phase I capacity of ~1.5 Bcf/d by September 1, 2026, assuming pipeline activities continue to progress as scheduled • Shipper contracts are coming online in stages based on the contractually specified effective date in each agreement • Expected to utilize Energy Transfer’s extensive pipeline network south of the DFW metroplex to deliver gas to major trading hubs and markets Phase II: Includes the addition of downstream compression • Increases capacity to ~2.2 Bcf/d • Expected in service Q1 2027 Total capital: ~$2.7B – full project now expected to come in under budget Hugh Brinson Pipeline Project DFW Metroplex Maypearl Bethel Supply Market Hub Texas Gas Storage Points of Interest Hugh Brinson Pipeline (New Build) Midland Lateral (New Build) ET Intrastate ET Interstate • Sabine Pass LNG • Golden Pass LNG • Port Arthur LNG Abilene Upon full completion, bi-directional pipeline expected to have the ability transport ~2.2 Bcf/d from west to east, and also ~1 Bcf/d from east to west Hugh Brinson Pipeline Construction
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12 Phoenix Desert Southwest – Transwestern Pipeline Expansion Project ~520-mile, 48-inch pipeline that extends from the heart of the Permian Basin to the Phoenix area in Arizona • Up to ~2.3 Bcf/d of capacity • Expected cost: Up to ~$5.6 billion – ~85% of capital expenditures expected to be in 2027 and beyond • Locked in long lead items like compression and pipe with opportunity to expand, as needed – Includes commitments with U.S. pipe mills to lock in 100% of space and delivery for pipe in Q4 2027 at favorable prices • More than 75% of route expected to be collocated along existing ROW, roads, utility corridors • In March 2026, initiated FERC pre-filing process for the project, as previously scheduled; expect to file the formal certificate application with FERC in Q4 2026 • FERC recently hosted 6 in-person and 2 virtual scoping meetings along the proposed route through TX, NM and AZ • Teams continue to actively engage with elected officials, county leadership, state/federal agencies, landowners and associated communities along the route to communicate project information and updates • Anticipate in service by Q4 2029 Desert Southwest Pipeline Project Waha “With existing pipelines fully subscribed, securing additional natural gas capacity is critical to supporting Arizona’s long-term prosperity. The Desert Southwest Pipeline will significantly increase our state’s energy capacity and diversify our energy resources.” – Arizona Governor Katie Hobbs Expected EBITDA Multiple ~5-6X
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13 Springerville Lateral Project ~125-mile, 30-inch pipeline lateral ~625 MMcf/d of capacity Expected cost: ~$600 million ‒ Locked in pipe and compression costs Backed by 20-year agreements Outreach underway with tribal, state and federal stakeholders Anticipated in service in Q4 2029 Majority of natural gas expected to be sourced from the Permian and San Juan basins Springerville Lateral Project Lateral extending south off existing Transwestern Pipeline to new natural-gas powered generation that is expected to replace two coal-fired power plants This project is expected to enable existing facilities to transition from using coal to natural gas, helping meet growing energy demand with a more reliable and cleaner power source Springerville Lateral Transwestern Pipeline Power Plants
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NGL and Crude Oil Announced Growth Projects 14 Project NGL Project Overviews Status Sabina 2 Pipe Conversion Expanding capacity from 25,000 Bbls/d to ~70,000 Bbls/d to provide additional transportation service between Mont Belvieu and Nederland for multiple products (Initial phase increased capacity to ~40,000 Bbls/d) Initial Phase In Service; Remainder by mid-2026 Gateway NGL Pipeline Debottleneck Project to allow for the full usage of interest in the EPIC Pipeline and optimize deliveries from the Delaware Basin into Gateway Pipeline for deliveries to Mont Belvieu In Service - Q1'26 Lone Star Express Expansion Performing upgrades that are expected to provide more than 90,000 Bbls/d of incremental Permian NGL takeaway capacity In Service – Q2’26 Frac IX 165,000 Bbls/d fractionator at Mont Belvieu Q4 2026 Delaware Basin NGL Pipe Looping Looping ~40 miles of 24” NGL pipeline upstream of Lone Star Express Pipeline to source an incremental ~150,000 Bbls/d of NGLs from the northern Delaware Basin for transportation on ET’s NGL pipeline system Q4 2027 Mont Belvieu Ethane Storage 3 million Bbls ethane storage cavern to support Frac IX and future ethane export expansions 2H 2027 Nederland Refrigerated Storage Expansion Expansion of refrigerated storage at Nederland; expected to increase butane storage to 0.8 MMBbls and propane storage to 1.2 MMBbls 1H 2027 Marcus Hook Terminal Optimization Constructing 900,000 Bbls refrigerated ethane storage tank and ~20,000 Bbls/d of incremental ethane chilling capacity Mid-2027 Nederland Ethane Expansion Increasing ethane export capacity by 240,000 Bbls/d and LPG export capacity by 55,000 Bbls/d; expanding Mont Belvieu to Nederland export pipelines to service increased refrigeration capacity; constructing two additional NGL ship docks 2028 (In Stages) Docks mid-2029 Project Crude Project Overviews Status Price River Terminal Adding new railcar loading facilities, heated storage tank with ~120,000 Bbls of capacity, and two new 6,000-foot storage unit racks to significantly improve storage capacity at the facility; backed by agreement with FourPoint Resources Q4 2026 Southern Illinois Connector Project to connect Enbridge pipeline near Wood River to ET’s assets in Patoka, IL to support delivery of Canadian crude oil to U.S. refiners; recently completed open season that resulted in 100,000 Bbls/d of contracts FID'd Bayou Bridge Expansion of Bayou Bridge crude oil pipeline, which is expected to increase pipeline capacity to up to ~600 thousand Bbls/d, depending on destination and product mix; backed by 10-year term extension and volume increase from demand-pull customer Q1 2027 New
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Leverage To Emerging NGL Growth Trends 15 $2.8B $4.1B FY 2020 FY 2025 NGL & Refined Products segment demonstrates ET’s ability to grow significantly via organic growth Total Growth Capex 2020 – 2025: $6.7B NGL & Refined Products Adjusted EBITDA Major Growth Drivers ‒ Frac VII (2020) LSX Expansion (2020) ‒ Mariner South Expansion (2020) ‒ MHIC Chilling Expansion (2020) ‒ Orbit Ethane Export Project (2021) ‒ ME2/2X (2021 & 2022) ‒ Frac VIII (2023) ‒ Nederland Flexport Expansion (2025 & 2026) ~20% market share of global NGL exports Extended majority of ethane export agreements into 2041, adding 10 years to current contracts Recently announced Nederland ethane expansion to meet customer demand Signed long-term NGL transportation or fractionation agreements for ~300,000 Bbls/d
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Expanding Nederland NGL Export Terminal 16 • In June 2026, announced an expansion of the Nederland NGL Export Terminal to meet additional customer demand • Project includes: o Increasing ethane export capacity at Nederland by 240,000 Bbls/d, as well as adding 55,000 Bbls/d of incremental LPG export capacity o Expanding Mont Belvieu to Nederland export pipeline capacity to service increased refrigeration capacity o Constructing two additional NGL ship docks at Nederland • 100% of ethane export capacity committed under long-term agreements that go into the 2040’s • Expected to be placed in service in stages beginning in 2028 o New docks expected to be complete in mid-2029 • Expected cost: Slightly over $1B Nederland Ethane Export Expansion Project • Construction of new refrigerated storage is already underway o Expected to increase refrigerated propane storage to ~1.2 MMBbls and refrigerated butane storage to ~0.8 MMBbls o Expected in service in the first half of 2027 • Combined with existing 1.3 MMBbls refrigerated ethane tank, provide the largest refrigerated storage capacity for each of these products of any export complex on the U.S. Gulf Coast Refrigerated Storage Expansion Upon completion of current expansions, total NGL export capacity at Nederland ~1.3 MMBbls/d Nederland Terminal This project, combined with its existing wellhead-to-water pipeline system, further establishes Energy Transfer as a best-in-class franchise to provide North American energy to the rest of the world
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Expanding World-Class NGL Export Facilities 17 Placed Flexport Expansion Project into propane and butane service Nederland refrigerated propane and butane storage expansion expected in service Next phase of Nederland Export Expansion Project expected in service (in stages) Nederland Export Expansion Project docks expected in service Marcus Hook Terminal optimization expected in service Mid-2025 1H 2027 2028 Exported first ethylene cargo out of Nederland Flexport Terminal Dec-2025 Mid-2027 Mid-2029 Upon completion of current Nederland and Marcus Hook expansions, total NGL export capacity expected to be 1.7+ MMBbls/d
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NGL Pipeline & Fractionation – Providing Service to Premier Markets 18 Baden Godley Hattiesburg Sea Robin LaGrange/Chisholm Plant Complex Jackson Geismar Sorrento Chalmette Kenedy • Pump and filter upgrades along the pipeline that are expected to provide more than 90,000 Bbls/d of incremental Permian NGL takeaway capacity • Completing debottlenecking on NGL pipes west of Baden facility • Placed into service in Q2 2026 • Total of 8 fractionators at Mont Belvieu; current capacity 1.15mm+ Bbls/d • Volumes on 165,000 Bbls/d Frac IX are expected to ramp up quickly upon its anticipated service late in 2026 Mont Belvieu Fractionation Expansion Lone Star Express Upgrades ET’s total deliverability into Mont Belvieu is now more than ~1.3 million Bbls/d Frac I Frac III Export De-C2 Frac II Frac VII Fracs IV & V Frac VI ET Mont Belvieu Frac VIII • Constructing new 3mm Bbls ethane storage cavern at Mont Belvieu to support Frac IX and future ethane export expansions Mont Belvieu Ethane Storage Cavern Asset Overview EPIC NGL Pipeline UDI¹ ET NGL ET Justice ET Liberty ET Gulf Coast NGL Express ET Gulf Coast NGL/WTX Gateway ET Spirit ET Freedom Mont Belvieu to Nederland System Nederland Terminal Mt. Belvieu NGL Complex Plant Fractionator Processing Plant Storage 1. Energy Transfer owns an undivided interest (UDI) in 80 MBbls/d of capacity in a segment of the EPIC Y -Grade Pipeline, LP (EPIC) pipeline from Orla, TX to Benedum, TX • Looping NGL pipeline upstream of Lone Star Express Pipeline to source an incremental ~150,000 Bbls/d of NGLs from the northern Delaware Basin for transportation on ET’s NGL pipeline system • Expected to be in service in Q4 2027 Delaware Basin NGL Pipe Extension
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Significant Management Ownership 19 0% 2% 4% 6% 8% 10% 12% ET Peers S&P 500 S&P 500 Energy Insider Ownership % Management and Insiders significantly aligned with unitholders Insider Ownership vs Peers¹ Source: Bloomberg/Company Filings Peer Group: ENB, EPD, KMI, MPLX, OKE, TRGP, TRP, PAA, WMB 1. As of May 2026 • Executive Chairman (Kelcy Warren) has never sold an ET unit • Since Jan. 2019, purchased ~66mm ET units for ~$768mm • Co-CEOs hold at least 6x annual base salary in ET units Leadership Support
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Appendix
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~27,170 miles of interstate pipelines with ~33 Bcf/d of throughput capacity and ~148 Bcf/d of working storage capacity ET’s interstate pipelines provide: Stability: ~95% of revenue derived from fixed reservation fees Diversity: Access to multiple shale plays, storage facilities and markets Interstate Natural Gas Pipeline Segment 21 Interstate Highlights PEPL TGC TW FGT SR FEP Tiger MEP Rover Stingray EGT MRT SESH Gulf Run Total Miles of Pipeline 6,300 2,190 2,590 5,375 765 185 200 510 720 335 5,700 1,675 290 335 27,170 Capacity (Bcf/d) 2.8 0.9 2.1 4.4 2.0 2.0 2.4 1.8 3.4 0.4 4.8 1.7 1.1 3.0 32.8 Storage (Bcf) 57.0 13.0 -- -- -- -- -- -- -- -- 29.3 48.9 -- -- 148.2 Ownership 100% 100% 100% 50% 100% 50% 100% 50% 32.6% 100% 100% 100% 50% 100% Asset Overview Pipelines Transwestern Panhandle Eastern EGT FGT MRT SESH Gulf Run Tiger Trunkline Gas Fayetteville Express Rover Sea Robin/Stingray Midcontinent Express Storage Facilities Growth Projects Desert Southwest Pipeline, an expansion of the Transwestern Pipeline, will include an ~520-mile, 48-inch natural gas pipeline with a capacity of up to ~2.3 Bcf/d to connect the Permian Basin with markets in AZ and NM Expanding Tiger pipeline with new, 12-mile lateral with capacity of up to 1 Bcf/d • Will support new 20-year binding agreement with Entergy Louisiana to provide 250,000 MMBtu/d of firm transportation service in NLA Springerville Lateral – ~125-mile, 30-inch pipeline with capacity of ~625 MMcf/d extending south from existing Transwestern Pipeline to natural-gas powered generation that is expected to replace two coal-fired plants • Backed by 20-year agreements and expected in service in Q4’29 FGT Phase IX project includes ~90 miles of pipeline looping and compression facilities with an expected capacity of ~525 MMcf/d; expected in service Q4’28 FGT South Florida project is an ~40-mile pipeline extension with expected capacity of ~230 MMcf/d; also includes compression and a new meter station; expected in service Q1’30¹ 1. Subject to conditions precedent and reaching FID
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Intrastate Natural Gas Pipeline Segment 22 Well-positioned to capture additional revenues from anticipated changes in natural gas supply and demand, including increases in natural gas power demand Strategically taken steps to lock in additional volumes under fee-based, long-term contracts with third-party customers Phase I of the Hugh Brinson Pipeline Project is now in commercial service, providing natural gas takeaway from the Permian Basin to premier markets and trading hubs Constructing new storage cavern at Bethel natural gas storage facility, which will double the natural gas working storage capacity at the facility to over 12 Bcf Pipeline Capacity (Bcf/d) Pipeline (Miles) Storage (Bcf) Bi- Directional Major Connect Hubs ET Fuel Pipeline 5.2 3,270 11.2 Yes Waha, Katy, Carthage Oasis Pipeline 2.0 750 NA Yes Waha, Katy Houston Pipeline System 5.3 3,920 52.5 No HSC, Katy, Aqua Dulce ETC Katy Pipeline 2.9 460 NA No Katy RIGS 2.1 450 NA No Union Power, LA Tech Red Bluff Express 2.0 120 NA No Waha EOIT 2.4 2,200 24.0 Yes OG&E, PSO Trans Pecos Pipeline 1.4 140 NA No Waha Header, Mexico Border Comanche Trail Pipeline 1.1 195 NA No Waha Header, Mexico Border Intrastate Highlights~ 12,200 miles of intrastate pipelines with ~24 Bcf/d of throughput capacity, and ~88 Bcf/d of working storage capacity Asset Overview Pipelines Trans Pecos/Comanche Trail ET Fuel Oasis Houston Pipeline Katy RIGS Red Bluff Express OIT Storage Facilities 1. Expected to be capable of flowing the full Phase I capacity of 1.5 Bcf/d by September 1, 2026
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Midstream Segment 23 Midstream Highlights Extensive Gathering and Processing Footprint • Assets in most of the major U.S. producing basins Since mid-2024, added ~800 MMcf/d of Permian Basin processing capacity in 2025, including: • Added ~50 MMcf/d of capacity at two different Permian Basin processing plants for an incremental ~100 MMcf/d of processing capacity • 200 MMcf/d Lenorah II¹ processing plant in the Midland Basin placed in service in Q2’25 • 200 MMcf/d Badger processing plant in the Delaware Basin placed in service in early Q3’25 • 275 MMcf/d Mustang Draw I processing plant went placed in service in June 2026 Constructing 275 MMcf/d Mustang Draw II processing plant which is expected to be in service in 4Q’26 Current Processing Capacity Bcf/d Basins Served Permian 5.8 Midland, Delaware Midcontinent/Panhandle 2.9 Granite Wash, Cleveland, SCOOP, STACK North Texas 0.7 Barnett, Woodford South Texas 2.5 Eagle Ford. Eagle Bine North Louisiana 0.9 Haynesville, Cotton Valley Williston 0.4 Bakken Powder River 0.3 Powder River Basin Eastern 0.2 Marcellus Utica Current ET Processing CapacityAsset Overview Pipelines Permian Midcontinent/Panhandle South Texas North Texas North Louisiana Eastern Williston Powder River Processing Plants 1. Lenorah II was formerly known as Red Lake IV ~67,500 miles of gathering pipelines with ~13.7 Bcf/d of processing capacity
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Permian Basin Processing Strengthening Position to Meet Growing Demand 24 Permian Basin Footprint Processing Plant Optimizations • Added ~50 MMcf/d of capacity at four different Permian Basin processing plants for an incremental ~200 MMcf/d of capacity Processing Plant Expansions • Placed the 200 MMcf/d Badger plant into service in Q2 2025 • Placed 275 MMcf/d Mustang Draw I processing plant in the Midland Basin into service in June 2026 • Already running near capacity for Midland Basin processing complex • Constructing 275 MMcf/d Mustang Draw II in the Midland Basin • Supported by continued growth from existing customers • Expected to be in service in Q4 2026 • The volumes from the tailgate of these plants will utilize Energy Transfer gas and NGL pipelines for takeaway from the basin Arrowhead II & III Orla East Grey Wolf Badger Lenorah I & II¹ Mustang Draw I & II Currently have ~5.8 Bcf/d of processing capacity in the Permian Basin with significant acreage dedications
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Natural Gas Liquids (NGLs) & Refined Products Segment 25 NGL Storage Total NGL storage ~100 million barrels ~63 million barrels of NGL storage at Mont Belvieu ~10 million barrels of NGL storage at Marcus Hook & Nederland Terminals ~8 million barrels of NGL storage at Spindletop ~5 million barrels of Butane storage at Hattiesburg 8 Mont Belvieu fractionators (over 1.15 MMBbls/d) 165,000 Bbls/d Frac IX expected to go into service in Q4’26 35,000 Bbls/d Geismar Frac (Louisiana) Fractionation Refined Products ~3,760 miles of refined products pipelines in the northeast, midwest and southwest US markets ~35 refined products marketing terminals with ~8 million barrels storage capacity NGL Exports ~1.3 MMBbls/d of total NGL export capacity from Nederland upon completion of current expansions ~400,000 Bbls/d of NGL export capacity from Marcus Hook Terminal NGL Pipeline Transportation ~5,750 miles of NGL pipelines throughout Texas, the midwest and northeast More than 1 MMBbls/d of Permian NGL takeaway to Mont Belvieu • Lone Star Express – ~900-mile NGL pipeline with ~870,000 Bbls/d capacity (currently expanding system to add an incremental 90,000 Bbls/d) • West Texas Gateway - ~510-mile NGL pipeline with ~240,000 Bbls/d capacity (debottlenecking project underway) Mont Belvieu to Nederland Pipeline System • 68-mile propane pipeline with 450,000 Bbls/d capacity • 67-mile butane pipeline with 200,000 Bbls/d capacity • 70-mile ethane pipeline with 380,000 Bbls/d capacity • 59-mile natural gasoline pipeline with 30,000 Bbls/d capacity • 59-mile Sabina 2 natural gasoline pipeline with 40,000 Bbls/d capacity Mariner Pipeline Franchise • The Mariner East Pipeline System can move ~380,000 Bbls/d of NGLs (including ethane) to Marcus Hook • Mariner West Pipeline with ~50,000 Bbls/d capacity Asset Overview NGL Pipelines Refined Products Pipelines Storage Mont Belvieu NGL Complex Terminals Processing/Treating Marcus Hook Terminal Nederland Terminal
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Crude Oil Segment 26 Crude truck fleet of ~365 trucks, ~355 trailers, and ~240 offload facilities, as well as 3rd party truck, rail, pipeline and marine assets Purchase crude oil at the lease from 3,000+ producers, and in-bulk from aggregators at major pipeline interconnections and trading points Market crude oil to refining companies and other traders across asset base Optimize assets to capture time and location spreads Crude Oil Pipelines Nederland, TX - ~30 million barrel capacity Houston, TX - ~18 million barrel capacity ET-S Permian JV - ~11 million barrel capacity Cushing, OK - ~10 million barrel capacity Patoka, IL - ~2 million barrel capacity Marcus Hook - ~1 million barrel capacity Colt Hub - ~1 million barrel capacity Directly connected to 7.8 MMbbls/d (~44%) of domestic refining capacity 1.85 MMbbls/d of ET-owned export capacity on USGC ET owns and operates substantial interests in the following systems/entities: • Bakken Pipeline (36.4%) • Bayou Bridge Pipeline (60%) • Permian Express Partners (87.7%) • ET-S Permian JV (67.5%) ET also owns a 5% interest in the Wink to Webster Pipeline • White Cliffs (51%) • Maurepas (51%) • Permian JV (67.5%) Crude Oil Acquisition & Marketing Crude Oil Terminals 18,000+ miles of crude oil trunk and gathering lines ~ 1 million barrels per day of Permian crude oil takeaway capacity Crude Terminals Crude Pipelines Asset Overview* Major Terminals Houston Terminal Cushing Terminal Patoka Terminal Nederland Terminal Midland Terminals
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Non - GAAP Reconciliations 27
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Energy Transfer LP Reconciliation of Non-GAAP Measures 2021 2021 2024 2025 Full Year Full Year Full Year Full Year Full Year Q1 Q2 YTD Net income 6,687$ 5,868$ 5,294$ 6,565$ 5,708$ 1,976$ 2,530$ 4,506$ Depreciation, depletion and amortization 3,817 4,164 4,385 5,165 5,682 1,583 1,575 3,158 Interest expense, net 2,267 2,306 2,578 3,125 3,474 947 934 1,881 Income tax expense 184 204 303 541 350 135 194 329 Impairment losses and other 21 386 12 52 285 - - - (Gains) losses on interest rate derivatives (61) (293) (36) (6) - - - - Non-cash compensation expense 111 115 130 151 148 42 46 88 Unrealized (gains) losses on commodity risk management activities (162) (42) (3) 56 (130) 536 (396) 140 Inventory valuation adjustments (Sunoco LP) (190) (5) 114 86 156 (444) 18 (426) Losses (gains) on extinguishments of debt 38 - (2) 12 34 7 - 7 Adjusted EBITDA related to unconsolidated affiliates 523 565 691 692 726 196 196 392 Equity in earnings of unconsolidated affiliates (246) (257) (383) (379) (419) (110) (108) (218) Non-operating litigation-related costs - - 627 - - - - - Gain on sale of Sunoco LP West Texas assets - - - (586) - - - - Other, net 57 82 (12) 9 (30) 69 77 146 Adjusted EBITDA (consolidated) 13,046 13,093 13,698 15,483 15,984 4,937 5,066 10,003 Adjusted EBITDA related to unconsolidated affiliates (523) (565) (691) (692) (726) (196) (196) (392) Distributable Cash Flow from unconsolidated affiliates 346 359 485 486 510 135 134 269 Interest expense, net (2,267) (2,306) (2,578) (3,125) (3,474) (947) (934) (1,881) Preferred unitholders' distributions (418) (471) (511) (361) (287) (88) (89) (177) Current income tax expense (44) (18) (100) (265) (173) (43) (119) (162) Transaction-related income taxes - (42) - 179 - - - - Maintenance capital expenditures (581) (821) (860) (1,161) (1,316) (277) (401) (678) Other, net 68 20 41 90 97 26 12 38 Distributable Cash Flow (consolidated) 9,627 9,249 9,484 10,634 10,615 3,547 3,473 7,020 Distributable Cash Flow attributable to Sunoco LP and SunocoCorp (542) (648) (659) (946) (1,263) (526) (594) (1,120) Distributions from Sunoco LP 165 166 173 245 286 99 102 201 Distributable Cash Flow attributable to USAC (100%) (209) (221) (281) (355) (386) (131) (125) (256) Distributions from USAC 97 97 97 97 97 24 24 48 Distributable Cash Flow attributable to noncontrolling interests in other non-wholly-owne (1,113) (1,240) (1,352) (1,335) (1,153) (309) (293) (602) Distributable Cash Flow attributable to the partners of Energy Transfer (a) 8,025 7,403 7,462 8,340 8,196 2,704 2,587 5,291 Transaction-related adjustments 194 44 116 23 6 - - - Distributable Cash Flow attributable to the partners of Energy Transfer, as adjusted (a) 8,219$ 7,447$ 7,578$ 8,363$ 8,202$ 2,704$ 2,587$ 5,291$ 2022 2026 Non-GAAP Reconciliation 28 * See definitions of non-GAAP measures on next slide *
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Non-GAAP Reconciliation 29 Definitions (a) 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. For the calculation of Distributable Cash Flow, the amounts reflected for (i) Adjusted EBITDA related to unconsolidated affiliates, (ii) Distributable Cash Flow from unconsolidated affiliates, and (iii) Distributable Cash Flow attributable to Sunoco LP exclude Sunoco LP’s Adjusted EBITDA and distributable cash flow related to its investment in joint ventures with Energy Transfer, as such amounts are eliminated in the Energy Transfer consolidation. • 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. 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. 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-operatingincome or expense items. Inventoryvaluation 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 overthe 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. 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 deferredincome taxes. For unconsolidated affiliates, Distributable Cash Flow reflects the Partnership’s proportionate share of the investees’ distributable cash flow. 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 availableto be distributed to our partners. In order to reflect the cash flows availablefor distributions to our partners, we have reported Distributable Cash Flow attributable to partners, which is calculated by adjusting Distributable Cash Flow (consolidated), as follows: 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. Distributable Cash Flow is used by management to evaluate our overall performance. Our partnership agreement requires us to distribute all availablecash, and Distributable Cash Flow is calculated to evaluate our ability to fund distributions through cash generated by our operations.