Slides
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Q3 2026 Earnings November 3, 2026
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Forward-looking Statements / Legal Disclaimer 2 Management of Energy Transfer LP (ET) will provide this presentation in conjunction with ET’s 3nd quarter 2026 earnings conference call. On the call, 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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What’s New? 3 1. Energy Transfer excluding SUN and USA Compression capital expenditures Adjusted EBITDA: ‒ Q3’26: $5.03B; up 31% from Q3’25 Distributable Cash Flow attributable to partners: ‒ Q3’26: $2.52B; up 33% from Q3’25 YTD’26 Capital Expenditures: ‒ Growth: $3.9B¹ ‒ Maintenance: $766MM¹ Updated 2026 Guidance: ‒ Adjusted EBITDA: $19.7B - $19.9B (up $0.85B from previous midpoint) ‒ Expected Growth Capital: ~$5.4B - $5.6B¹ ‒ Announced 20th consecutive increase to quarterly cash distribution to $0.3425 per unit; up more than 3% vs Q3’25 Q3’26 Financial ResultsOperational Updates Volumes compared to Q3’25 ‒ Intrastate transportation volumes up 14% ‒ Midstream gathered volumes up 6% ‒ NGL export volumes up 9% ‒ NGL transportation volumes up 6% ‒ NGL fractionation volumes up 5% On September 1, 2026, Phase I of the Hugh Brinson Pipeline was placed into full service, ahead of schedule In October, placed 275 MMcf/d Mustang Draw II processing plant into service In the third quarter of 2026, completed the addition of compression and meter facilities on the Rover Pipeline system to support a 250,000 MMBtu/d, 15-year transportation agreement with a Marcellus producer Indicates new Partnership record
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Strategic Acquisition Newly Announced Natural Gas and NGL Activity 4 1. A binding open season is currently underway to solicit additional customer commitments, and final pipeline sizing and capacit y will be determined after the open season South Mississippi Pipeline Project¹ ‒ Expected capacity: ~1.2 Bcf/d ‒ Expected capex: $1.6B (100%) ‒ Expected in-service: 2030 ‒ ET will likely have a 51% ownership interest and be operator Crusoe Abilene Facilities ‒ Added 250,000 MMbtu/d agreement with A-rated Hyperscaler Bear II Processing Plant ‒ Capacity: 200 MMcf/d ‒ In service: Q3 2027 MRT Pipeline - Two new MO power plants ‒ Adds 150,000 MMBtu/d firm natural gas service ‒ Agreements effective late 2027 and mid-2028 EOIT Pipeline – Added 5th, new power plant connection in OK ‒ Total add 400,000 MMBtu/d from five plants Transwestern Pipeline – Cholla Lateral ‒ Expected capacity: 100 MMcf/d ‒ Expected in-service: Q1’29 ‒ Enables conversion of coal plant to natural gas service Strategic Natural Gas Expansions In October, announced plans to acquire Vaquero Midstream for approximately $2.625 billion in cash and ET common units Frac X ‒ Expected capacity: 200,000 Bbls/d ‒ Expected in service: 1H 2029 Nederland Ethane Export Project – Upsized ‒ Increased planned ethane export capacity from 240,000 Bbls/d to ~300,000 Bbls/d ‒ Constructing new 30” pipeline and optimizing Mont Belvieu to Nederland pipeline system Strategic NGL Expansions Since the beginning of 2025, have executed over 9.5 million MMBtu/d of natural gas agreements with demand pull customers
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Fee² ~90% Spread1 0-5% Commodity 5-10% Well-Balanced, Diversified, Fee-Based Earnings 5 1. Spread margin is pipeline basis, cross commodity and time spreads – Spread margin is likely to slightly exceed 5% for 2026 with business outperformance due to 1H commodity price volatility 2. Fee margins include transport and storage fees from affiliate customers at market rates Q3 2026 Adjusted EBITDA by Segment Historical Adjusted EBITDA Breakout Midstream 17% NGL & Refined Products 24% Crude Oil 17% Natural Gas Inter & Intrastate Pipelines & Storage 17% SUN, USAC & Other 25%
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Nationwide Footprint With Diverse Product Offerings Across the Value Chain 6 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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7 Vaquero Acquisition Overview The addition of Vaquero’s assets is expected to further strengthen Energy Transfer's Permian footprint by increasing access to growing natural gas and NGL production volumes while enhancing connectivity to the partnership's broader midstream platform • Existing connections to ET’s Lone Star and Oasis pipelines • Expected to provide growing on-system volumes for downstream natural gas and NGL infrastructure • Well positioned to benefit from continued development across Delaware Basin and provide additional growth opportunities as production expands around ET’s existing infrastructure • Expected to be immediately accretive to DCF per common unit and represents an ~8.5x multiple on 2027 estimated adjusted EBITDA − Anticipate this drops to below 7x as utilization of existing processing capacity is increased • Supported by ~100,000 acreage dedication and high-quality customer base • Average remaining contract life of ~10 years • Expands and enhances ET’s integrated natural gas gathering and processing network • Adds ~300 miles of complementary gas gathering pipelines in the Delaware Basin • Caymus Processing Complex – 3 gas processing trains with ~675 MMcf/d capacity –Acreage to support 2 additional trains – could increase total processing capacity to up to ~1.2 Bcf/d Complementary Assets Strengthen Integrated Network Incremental Revenue Opportunities Across the Value Chain Positive Financial Impact and Stable Cash Flows
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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 Since the beginning of 2025, have executed over 9.5 million MMBtu/d of agreements with demand pull customers, including hyperscalers and power plants Remain 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 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 MMBtu/d Added connections to serve 5 new power plant loads in OK: ~400,000 MMBtu/d Signed agreements to provide Nexus Hubbard Campus with gas for AI hyperscale campus under construction in Central TX: 150,000 MMBtu/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 A-Rated Hyperscaler to support construction of facilities to provide natural gas to Crusoe’s previously announced AI factory campus in Abilene, TX: 250,000 MMBtu/d Two agreements to provide firm natural gas transportation service from MRT Pipeline to two new power plants being constructed in Missouri ~150,000 MMBtu/d
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Enhancing Strategic Footprint In Leading Natural Gas Franchise 9 1. Represents ET’s 50% share 2. Energy Transfer will likely be a 51% owner and operator of this project, with the remaining ownership coming from shippers or shipper affiliates. A binding open season is currently underway to solicit additional customer commitments, and final pipeline sizing and capacity will be determined after the open season 3. 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 Nov-2026 $1.6B² South Mississippi Pipeline Recently Announced Pipeline Laterals Announced Pipeline Laterals Gas Supplied May-2025 & Aug-2025 Oracle Natural Gas Supply (x4) ~900,000 MMBtu/d (Total) Nov-2025 Entergy LA/Franklin Farms 250,000+ MMBtu/d Feb-2026 & Nov-2026 OK Power Plant Connections (x5) ~400,000 MMBtu/d (Total) May-2026 AR Center Gas Supply ~150,000 MMBtu/d May-2026 Nexus Hubbard Gas Supply ~150,000 MMBtu/d³ July-2026 Agreement with A-rated Hyperscaler to support Crusoe AI factory campus 250,000 MMBtu/d 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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Growth With Continued Financial Discipline 10 Intrastate Natural Gas Transportation • Hugh Brinson Pipeline • Data Center expansions • Bethel storage expansion • Small laterals and tie-in projects to support new demand growth on TX pipelines ~27% Midstream • Permian processing expansions (Mustang Draw I & II; Bear II*) • Permian gathering buildout and treating upgrades • Compression additions • Well connects ~26% NGL & Refined Products • Nederland ethane expansion project (Upsized) • Mont Belvieu Frac IX and Frac X* • Storage upgrades at Nederland, Mont Belvieu and Spindletop • Marcus Hook Terminal optimization • Lone Star Express expansion • Sabina 2 Pipeline conversion • Delaware Basin NGL pipe looping ~22% Interstate Natural Gas Transportation • Transwestern Pipeline – Desert Southwest Expansion • FGT Optimization projects • Transwestern Pipeline – Springerville Lateral • Data Center Expansions • Natural gas-fired electric generation facilities • Rover compression and metering facilities* ~14% Crude & All Other • Price River Terminal expansion • Southern Illinois Connector • Bayou Bridge Expansion • Optimization projects and well connects • Natural gas-fired electric generation facilities ~11% * New Project 1. Energy Transfer excluding SUN and USA Compression capital expenditures % of 2026E 2026E Growth Capital¹
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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 In Service 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 in service OK Power Plant Connections Added connections to serve four new power plant loads in Oklahoma for a total of ~400,000 MMBtu/d of new gas supply; supported by long-term contracts with investment-grade counterparties 1st three in service; Remainder 2028 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 over 2.3 Bcf/d from west to east, and also transport ~1 Bcf/d from east to west Full Phase I in service; Phase II Q1 2027 Oracle Natural Gas Supply Multiple long-term agreements with Oracle to supply ~900,000 MMBtu/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 ~150,000 MMBtu/d¹ Q4 2026 AR Data Center Gas Supply Precedent Agreement to provide ~150,000 MMBtu/d of firm natural gas transportation service through EGT pipeline to support new data center site in Arkansas Mid-2027 Bear II Processing Plant 200 MMcf/d processing plant in Delaware Basin Q3 2027 MO Power Plant Connections Constructing pipeline and metering facilities to support two new power plants under construction in Missouri; Expected to provide a total of ~150,000 MMBtu/d of firm natural gas transportation service from MRT Agmnts begin late 2027 & mid-2028 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 ~525-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 ~625 MMcf/d; extends south off existing Transwestern Pipeline to serve two power generating stations transitioning from coal-fired generation to natural gas; 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 Mississippi South Pipeline 215-mile, 36-inch pipeline to provide ~1.2 Bcf/d of firm transportation capacity from a connection near the Perryville Hub to an interconnect on the FGT pipeline in southern Mississippi² 2030 Natural Gas | Announced Growth Projects 11 New 1. With certain rights by the transporter to increase capacity upon election 2. Energy Transfer will likely be a 51% owner and operator of this project, with the remaining ownership coming from shippers or shipper affiliates. A binding open season is currently underway to solicit additional customer commitments, and final pipeline sizing and capacity will be determined after the open season New New
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Hugh Brinson Pipeline Project Serving Premier Texas Markets and Supporting Data Center and AI Growth 12 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 of Hugh Brinson is in service with a capacity of ~1.5 Bcf/d: • ~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 • Shipper contracts are coming online in stages based on the contractually specified effective date in each agreement • Utilizing 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 over 2.3 Bcf/d • Expected in service Q1 2027 Total capital: ~$2.7B – full project now expected to come in under budget Continue to see interest from customers seeking to increase commitments and new customers looking for Permian egress 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 be able to transport over 2.3 Bcf/d from west to east, and also ~1 Bcf/d from east to west Hugh Brinson Pipeline Construction
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13 Phoenix Desert Southwest – Transwestern Pipeline Expansion Project ~525-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 • Approximately 80% of route expected to be collocated along existing ROW, roads, utility corridors • FERC recently hosted 6 in-person and 2 virtual scoping meetings along the proposed route through TX, NM and AZ • Expect to file the formal certificate application with FERC in Q4 2026 • 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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Permian Basin Processing Strengthening Position to Meet Growing Demand 14 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 • 200 MMcf/d Badger plant placed into service in early Q3 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 • Placed 275 MMcf/d Mustang Draw II in the Midland Basin into service in October 2026 • Announced plans to construct 200 MMcf/d Bear II in the Delaware Basin in November 2026 • Will be adjacent to existing Bear processing plant • Expected to be in service Q3 2027 • 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 over 6 Bcf/d of processing capacity in the Permian Basin with significant acreage dedications Bear I & II
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NGL and Crude Oil Announced Growth Projects 15 Project NGL Project Overviews Status 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 incremental ethane chilling capacity to increase ethane export capacity to ~100,000 Bbls/d 2H 2027 Nederland Ethane Expansion Increasing ethane export capacity by ~300,000 Bbls/d and LPG export capacity by 55,000 Bbls/d; constructing new 30” pipeline and optimizing Mont Belvieu to Nederland export pipelines to service increased refrigeration capacity; constructing two additional NGL ship docks 2028 (In Stages) Docks mid-2029 Frac X 200,000 Bbls/d fractionator at Mont Belvieu 1H 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 Upsized
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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: − Increasing ethane export capacity at Nederland by 300,000 Bbls/d (upsized from 240,000 Bbls/d), as well as adding 55,000 Bbls/d of incremental LPG export capacity − Constructing new 30” pipeline and optimizing Mont Belvieu to Nederland export pipeline capacity to service increased refrigeration capacity − 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 − New docks expected to be complete in mid-2029 Expected cost: ~$1.5B Nederland Ethane Export Expansion Project - Updated Construction of new refrigerated storage is already underway − Expected to increase refrigerated propane storage to ~1.2 MMBbls and refrigerated butane storage to ~0.8 MMBbls − 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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NGL Pipeline & Fractionation – Providing Service to Premier Markets 17 Baden Godley Hattiesburg Sea Robin LaGrange/Chisholm Plant Complex Jackson Geismar Sorrento Chalmette Kenedy Completed pump and filter upgrades along the pipeline that provided more than 90,000 Bbls/d of incremental Permian NGL takeaway capacity Completed 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 Announced plans to construct 200,000 Bbls/d Frac X, which is expected in service in 1H 2029 Mont Belvieu Fractionation Expansions Lone Star Express Upgrades Upon completion of Fracs IX & X, total fractionation capacity at Mont Belvieu expected to be ~1.6 MMBbls/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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Appendix / Non - GAAP Reconciliations
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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 Q3 YTD Net income 6,687$ 5,868$ 5,294$ 6,565$ 5,708$ 1,976$ 2,530$ 1,814$ 6,320$ Depreciation, depletion and amortization 3,817 4,164 4,385 5,165 5,682 1,583 1,575 1,599 4,757 Interest expense, net 2,267 2,306 2,578 3,125 3,474 947 934 944 2,825 Income tax expense 184 204 303 541 350 135 194 187 516 Impairment losses and other 21 386 12 52 285 - - 2 2 (Gains) losses on interest rate derivatives (61) (293) (36) (6) - - - - - Non-cash compensation expense 111 115 130 151 148 42 46 49 137 Unrealized (gains) losses on commodity risk management activities (162) (42) (3) 56 (130) 536 (396) 379 519 Inventory valuation adjustments (Sunoco LP) (190) (5) 114 86 156 (444) 18 (19) (445) Losses (gains) on extinguishments of debt 38 - (2) 12 34 7 - - 7 Adjusted EBITDA related to unconsolidated affiliates 523 565 691 692 726 196 196 196 588 Equity in earnings of unconsolidated affiliates (246) (257) (383) (379) (419) (110) (108) (112) (330) 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 (8) 138 Adjusted EBITDA (consolidated) 13,046 13,093 13,698 15,483 15,984 4,937 5,066 5,031 15,034 Adjusted EBITDA related to unconsolidated affiliates (523) (565) (691) (692) (726) (196) (196) (196) (588) Distributable Cash Flow from unconsolidated affiliates 346 359 485 486 510 135 134 147 416 Interest expense, net (2,267) (2,306) (2,578) (3,125) (3,474) (947) (934) (944) (2,825) Preferred unitholders' distributions (418) (471) (511) (361) (287) (88) (89) (81) (258) Current income tax expense (44) (18) (100) (265) (173) (43) (119) (166) (328) Transaction-related income taxes - (42) - 179 - - - - - Maintenance capital expenditures (581) (821) (860) (1,161) (1,316) (277) (401) (419) (1,097) Other, net 68 20 41 90 97 26 12 15 53 Distributable Cash Flow (consolidated) 9,627 9,249 9,484 10,634 10,615 3,547 3,473 3,387 10,407 Distributable Cash Flow attributable to Sunoco LP and SunocoCorp (542) (648) (659) (946) (1,263) (526) (594) (577) (1,697) Distributions from Sunoco LP 165 166 173 245 286 99 102 105 306 Distributable Cash Flow attributable to USAC (100%) (209) (221) (281) (355) (386) (131) (125) (127) (383) Distributions from USAC 97 97 97 97 97 24 24 25 73 Distributable Cash Flow attributable to noncontrolling interests in other non-wholly-owne (1,113) (1,240) (1,352) (1,335) (1,153) (309) (293) (291) (893) 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 2,522 7,813 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$ 2,522$ 7,813$ 2022 2026 Non-GAAP Reconciliation 19 * See definitions of non-GAAP measures on next slide *
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Non-GAAP Reconciliation 20 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- operating income 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 deferred income 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 overallperformance. 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.