Slides
Page 1
Q4 2025 Earnings February 17, 2026
Page 2
Forward-looking Statements / Legal Disclaimer 2 Management of Energy Transfer LP (ET) will provide this presentation in conjunction with ET’s 4th quarter 2025 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.
Page 3
2025 – Delivering Results 3 Delivered FY’25 Adj. EBITDA of nearly $16B – a new partnership record Growth Capital¹ was ~$4.5 billion Increased 4Q’25 quarterly cash distribution to $0.335 per unit ‒ Up more than 3 % vs Q4’24 ET volumes FY’25 compared to FY’24 ‒ Record Crude oil transportation volumes - up 6% ‒ Record NGL fractionation volumes - up 2% ‒ Record NGL transportation volumes - up 6% ‒ Record total NGL exports - up 9% ‒ Record Midstream gathered volumes - up 5% ‒ Record Interstate natural gas transported - up 7% Completed open seasons on FGT for two new projects to meet growing demand across Florida ‒ Phase IX – designed to include construction of up to 82 miles of pipeline looping and new and upgraded compression to expand capacity across market area ‒ South Florida – designed to include construction of new 37-mile pipeline lateral and related facilities to enhance system reliability and efficiency in South Florida Oklahoma Interstate power team recently added connections to serve three new power plant loads in Oklahoma, totaling ~190,000 Mcf/d, which are expected online in Q2 2026 Recently began flowing gas on first pipeline lateral to a data center campus near Abilene, Texas Announced increased pipe diameter on Desert Southwest expansion project to 48 inches, which is expected to increase capacity to up to 2.3 Bcf/d Announced suspension of development of Lake Charles LNG project in order to focus on allocating capital toward significant backlog of natural gas pipeline infrastructure projects Financial Operational Strategic 1. Energy Transfer excluding SUN and USA Compression capital expenditures Midstream 20% NGL & Refined Products 26% Crude Oil 18% Natural Gas Inter & Intrastate Pipelines & Storage 20% SUN, USAC & Other 16% FY 2025 Adjusted EBITDA by Segment
Page 4
2026 Outlook Growth With Continued Financial Discipline 4 1. As calculated by all three primary rating agencies 2. Energy Transfer excluding SUN and USA Compression capital expenditures 3. Spread margin is pipeline basis, cross commodity and time spreads 4. Fee margins include transport and storage fees from affiliate customers at market rates Adjusted EBITDA Outlook 2026 Adjusted EBITDA Guidance: $17.45 to $17.85 billion Driven by new projects expected to ramp up and/or come online in 2026, including: – Nederland Flexport NGL expansion – Mustang Draw I and II – Hugh Brinson Pipeline Phase I – NGL projects on Lone Star Express and Gateway Pipelines – Natural gas pipeline projects serving data center facilities Expect to continue to target long-term annual distribution growth rate of 3% to 5% per year Expect to maintain leverage target of 4.0-4.5x EBITDA¹ 2026 Growth Capital Guidance: $5 billion to $5.5 billion² Majority invested on projects enhancing natural gas and NGL network, including: – Desert Southwest Pipeline – Hugh Brinson Pipeline – Natural gas pipeline projects serving data center facilities – Mustang Draw I and II – Frac IX – Nederland and Marcus Hook terminal expansion projects Remain focused on disciplined growth Expected to generate returns in the mid-teens Growth Capital Outlook Fee4 ~90% Spread3 0-5% Commodity 5-10% Pricing/spread assumptions based on current futures markets 2026E Adjusted EBITDA Breakout 2026E fee-based breakout expected to be substantially the same as 2025
Page 5
Nationwide Footprint With Diverse Product Offerings Across the Value Chain 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
Page 6
37 32 20 79 44 77 61 80 40 18 59 35 15 284397 161 21 37 21 70 210 70 195 61 11 22 11 24 107 88 83 Leading Natural Gas Pipeline Footprint Well-Positioned to Meet Growing Electricity Demand 6 Total gas-fired power plants within each state Total data centers within each state Map Source: EIA and Datacentermap.com1. Within the last year ~900,000 Mcf/d Signed agreements with Oracle to provide natural gas to three U.S data centers, two of which are in Texas: 250,000 MMBtu/d 20-year binding agreement with Entergy Louisiana to provide natural gas to their facilities in Richland Parish, LA: ~190,000 Mcf/d Added connections to serve 3 new power plant loads in Oklahoma: Working on multiple transactions in several states outside of TX and LA that have a high likelihood of reaching FID Demand Pull Contracts From End Users, Data Centers and Utilities Expected To Provide Significant Revenue Growth Contracted pipeline capacity¹ 6+ Bcf/d Weighted average life 18 years Expected revenue from firm transportation fees $25+ billion
Page 7
Growth With Continued Financial Discipline 7 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 ~26% NGL & Refined Products • Nederland refrigerated storage expansion • Mont Belvieu Frac IX • Marcus Hook Terminal optimization • Lone Star Express expansion • Sabina 2 Pipeline conversion • Delaware Basin NGL pipe looping • Storage upgrades at Mont Belvieu and Spindletop ~25% Midstream • Permian processing expansions (Mustang Draw I & II) • Permian gathering buildout and treating upgrades • Compression additions • Well connects ~23% Interstate • Transwestern Pipeline – Desert Southwest Expansion • FGT Optimization projects • Data Center Expansions • Natural gas-fired electric generation facilities ~16% Crude & All Other • Price River Terminal expansion • Southern Illinois Connector • Optimization projects and well connects • Natural gas-fired electric generation facilities ~10% 1. Energy Transfer excluding SUN and USA Compression capital expenditures % of 2026E 2026E Growth Capital: ~$5.0-$5.5 billion¹
Page 8
Natural Gas Growth Project Backlog 8 Project Name Natural Gas Project Overviews Status Mustang Draw Processing Plant 275 MMcf/d processing plant in the Midland Basin Q2 2026 Mustang Draw II Processing Plant 275 MMcf/d processing plant in the Midland Basin Q4 2026 Natural Gas-Fired Electric Generation Constructing 8, 10 MW natural gas-fired electric generation facilities to support Energy Transfer’s operations in Texas 3rd plant Q1 2026 Remainder ready for service in 2026¹ 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. These are expected to be sourced from ET’s extensive natural gas pipeline network First lateral flowing Remainder mid-2026 Oklahoma Power Plant Connections Adding connections to serve three new power plant loads in Oklahoma totaling ~190,000 Mcf/d Q2 2026 Hugh Brinson Pipeline Phase I & II 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 Phase I – Q4 2026 Phase II – Q1 2027 Bethel Storage Expansion Constructing new storage cavern at Bethel natural gas storage facility to double working gas storage capacity to over 12 Bcf Late 2028 FGT Phase IX Construction of up to 82 miles of pipeline looping, as well as new and upgraded compression. Could expand FGT capacity by up to 550 MMcf/d Q4 2028 Entergy LA Natural Gas Supply / Tiger Lateral 20-year binding agreement with Entergy Louisiana to provide initial 250,000 MMBtu/d of firm transportation service to fuel facilities in Richland Parish, LA; includes expanding Tiger pipeline with the construction of a 12-mile lateral with capacity of up to 1 Bcf/d Agreement begins Dec. 2028 Transwestern Pipeline - Desert Southwest Expansion Project 516-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 FGT South Florida Construction of new, 37-mile lateral to supply the South Florida area, along with compression and a new meter station Q1 2030 Fermi America Natural Gas Supply 10-year agreement with Fermi America to provide pipeline interconnection and initial gas supply of ~300,000 MMBtu/d to Fermi’s Hyper Grid campus outside of Amarillo, TX Subject to Fermi’s election CloudBurst Natural Gas Supply Long-term agreement with CloudBurst to provide firm natural gas supply to data center in Central Texas Subject to CloudBurst FID with customer New New Upsized New
Page 9
NGL, Crude and Other Growth Project Backlog 9 Project Name NGL Project Overviews Status Sabina 2 Pipeline 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 Nederland Flexport NGL Expansion Expansion added up to 250,000 Bbls/d of NGL export capacity at Nederland Terminal with flexibility to load various products, based on customer demand In Service Gateway NGL Pipeline Debottlenecking 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 Nearing Completion Lone Star Express Expansion Performing upgrades that are expected to provide more than 90,000 Bbls/d of incremental Permian NGL takeaway capacity Mid-2026 Mont Belvieu Frac IX 165,000 Bbls/d fractionator at Mont Belvieu Q4 2026 Delaware Basin NGL Pipe Looping 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 1H 2027 Marcus Hook Terminal Optimization Constructing 900,000 Bbls refrigerated ethane storage tank and approximately 20,000 Bbls/d of incremental ethane chilling capacity Q3 2027 Nederland Refrigerated Storage Expansion Expansion of refrigerated storage at Nederland; expected to increase butane storage by 33% and propane storage by 100% Construction Underway Sabina 1 Pipeline Continue to have discussions to provide transportation for potentially multiple products from Mont Belvieu to Houston Ship Channel Proposed Project Name Crude Project Highlights 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 Recently FID’d Dakota Access North Project Working with Enbridge to provide for capacity of ~250,000 Bbls/d of Canadian crude oil through Dakota Access Pipeline Expect to take FID by mid-2026
Page 10
Waha Phoenix Desert Southwest – Transwestern Pipeline Expansion Project 10 ~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, excluding AFUDC – ~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 • Expected route collocated along existing ROW, roads, utility corridors • Teams have been actively engaging with elected officials, county leadership and associated communities along the route to communicate project information and updates • To date, have engaged with over 275 stakeholders who have interest in or are involved in the project • Anticipate in service by Q4 2029 Desert Southwest Pipeline Project Current Asset Overview Transwestern Pipeline Energy Transfer Interstate Energy Transfer Intrastate Desert Southwest will provide reliable economic supplies of natural gas to support the long-term energy needs for utilities and energy providers in the region driven by population growth, high-tech industry demand and data center expansion Recently upsized pipeline diameter from 42 to 48” which will increase capacity from ~1.5 Bcf/d to up to 2.3 Bcf/d
Page 11
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: Construction underway on ~400 miles of 42” pipeline from Waha and the Midland Basin to Maypearl, TX • 100% of 42” pipeline has been delivered to pipe yards • Capacity of ~1.5 Bcf/d • Phase 1 is completely sold out and backed by long-term, fee- based commitments with strong investment-grade counterparties • Expected to utilize Energy Transfer’s extensive pipeline network south of the DFW metroplex to deliver gas to major trading hubs and markets • Expected in service in Q4 2026; however, if stay on current schedule, should have the ability to flow some early volumes prior to Phase I in service Phase I also includes construction of 42-mile, 36-inch Midland Lateral to connect ET processing plants in Martin and Midland counties to the Hugh Brinson Pipeline Phase II: Includes the addition of compression • Increases capacity to ~2.2 Bcf/d • Expected in service Q1 2027 Fully contracted from west to east; also have growing amount of volumes committed on backhaul that is expected to add significant upside with no additional capital Total capital for Phase 1 and Phase 2 expected to be ~$2.7B 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 completion, bi-directional pipeline expected to have the ability transport ~2.2 Bcf/d from west to east, and also transport ~1 Bcf/d from east to west
Page 12
Expanding World-Class NGL Export Facilities 12 • Flexport expansion project is added up to 250,000 Bbls/d of NGL export capacity o Ethane and propane in service o Ethylene export in service – exported first ethylene cargo in Dec. 2025 • Building new refrigerated storage, which will increase butane storage capacity by a third and double Energy Transfer’s propane storage capacity o Project will further increase ability to keep customers’ ships loading on time • Combined costs of both projects expected to be ~$1.5B • Construction underway on 900,000 Bbls refrigerated ethane storage tank and approximately 20,000 Bbls/d of incremental ethane chilling capacity • Expected in service in Q3 2027 • Mont Belvieu to Energy Transfer’s Nederland Terminal o Upon completion in mid-2026, will have the ability to flow at least 70,000 Bbls/d and provide much needed incremental transportation capacity to Nederland to meet the growing demand for natural gasoline products o Initial phase went into service in Q4 2024 and increased the capacity from 25,000 Bbls/d to ~40,000 Bbls/d o Firm transportation commitments in place Nederland Terminal Sabina 2 Pipeline Marcus Hook Terminal Houston Terminal Nederland Terminal – Flexport Expansion Marcus Hook Terminal – Ethane Tank Expansion Total NGL Export Capacity > 1.4mm Bbls/d Energy Transfer’s market share of worldwide NGL exports remains at ~20%
Page 13
Permian Basin Processing Strengthening Position to Meet Growing Demand 13 Permian Basin Footprint Processing Plant Optimizations • Since mid-2024, added ~50 MMcf/d of capacity at four different Permian Basin processing plants for an incremental ~200 MMcf/d of processing capacity Processing Plant Expansions • Placed the 200 MMcf/d Badger plant into service in Q2 2025 • Constructing Mustang Draw plant, which is expected to provide an incremental 275 MMcf/d of processing capacity in the Midland Basin • Expected to be in service in Q2 2026 • Constructing Mustang Draw II, which will have a capacity of 275 MMcf/d • 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 Lenorah I & II¹ • 200 MMcf/d Lenorah I processing plant placed into service following the closing of the WTG acquisition in July 2024 • 200 MMcf/d Lenorah II processing plant was placed in service in the Midland Basin in Q2 2025 – the plant is currently running at full capacity Arrowhead II & III Orla East Grey Wolf Badger Lenorah I & II¹ Mustang Draw I & II 1. Lenorah I was formerly known as Red Lake III and Lenorah II was formerly known as Red Lake IV Currently have ~5.4 Bcf/d of processing capacity in the Permian Basin with significant acreage dedications
Page 14
Leveraging asset base and expertise to develop projects to reduce environmental footprint 14 Dual Drive Compression Proprietary technology that offers the industry a more efficient compression system, helping reduce greenhouse gas emissions Renewable Fuels Utilizing our extensive gas system, ET is able to safely and reliably transport renewable natural gas (RNG) Solar ET has entered into dedicated solar contracts to help support the operations of our assets Repurpose Existing Assets Pursuing opportunities to utilize ET’s significant asset footprint to develop solar and wind projects, and transportation of renewable fuels, CO2 and other products ~20% From Solar & Wind Powering assets: 80 MW Total Constructing 8, 10- MW natural gas-fired electric generation facilities Carbon Capture Utilization and Sequestration In May 2024, entered into an agreement with CapturePoint that commits CO2 from Energy Transfer treating facilities in northern Louisiana to the capture and sequestration project being jointly developed by CapturePoint and Energy Transfer Ammonia Projects Continue to develop an ammonia hub concept at Lake Charles, LA and Nederland, TX where existing Energy Transfer facilities have deep water access, which would allow Energy Transfer to provide critical infrastructure services to several blue ammonia facilities 2024 Corporate Responsibility Report now available at energytransfer.com ~822,000 Tons of CO2 2024 emissions reduction from Dual Drive & CCS: Power Generation Construction underway on 8 natural gas-fired electric generation facilities to support Energy Transfer’s operations in Texas. The third facility is expected in service in Q1 2026, with the remaining five facilities expected to be fully constructed and ready for service later in 2026
Page 15
Appendix / Non - GAAP Reconciliations
Page 16
Non-GAAP Reconciliation 16 * See definitions of non-GAAP measures on next slide * Energy Transfer LP Reconciliation of Non-GAAP Measures 2020 2021 2023 2024 Full Year Full Year Full Year Full Year Full Year Q1 Q2 Q3 Q4 Full Year Net income 140$ 6,687$ 5,868$ 5,294$ 6,565$ 1,720$ 1,458$ 1,292$ 1,238$ 5,708$ Depreciation, depletion and amortization 3,678 3,817 4,164 4,385 5,165 1,367 1,384 1,440 1,491 5,682 Interest expense, net 2,327 2,267 2,306 2,578 3,125 809 865 890 910 3,474 Income tax expense 237 184 204 303 541 41 79 87 143 350 Impairment losses and other 2,880 21 386 12 52 4 3 1 277 285 (Gains) losses on interest rate derivatives 203 (61) (293) (36) (6) - - - - - Non-cash compensation expense 121 111 115 130 151 37 33 40 38 148 Unrealized (gains) losses on commodity risk management activities 71 (162) (42) (3) 56 69 (100) (1) (98) (130) Inventory valuation adjustments (Sunoco LP) 82 (190) (5) 114 86 (61) 40 (10) 187 156 Losses (gains) on extinguishments of debt 75 38 - (2) 12 2 17 12 3 34 Adjusted EBITDA related to unconsolidated affiliates 628 523 565 691 692 167 182 193 184 726 Equity in earnings of unconsolidated affiliates (119) (246) (257) (383) (379) (92) (105) (116) (106) (419) Impairment of investment in unconsolidated affiliates 129 - - - - - - - - - Non-operating litigation-related costs - - - 627 - - - - - - Gain on sale of Sunoco LP West Texas assets - - - - (586) - - - - - Other, net 79 57 82 (12) 9 35 10 10 (85) (30) Adjusted EBITDA (consolidated) 10,531 13,046 13,093 13,698 15,483 4,098 3,866 3,838 4,182 15,984 Adjusted EBITDA related to unconsolidated affiliates (628) (523) (565) (691) (692) (167) (182) (193) (184) (726) Distributable Cash Flow from unconsolidated affiliates 452 346 359 485 486 111 129 128 142 510 Interest expense, net (2,327) (2,267) (2,306) (2,578) (3,125) (809) (865) (890) (910) (3,474) Preferred unitholders' distributions (378) (418) (471) (511) (361) (72) (65) (61) (89) (287) Current income tax expense (27) (44) (18) (100) (265) (57) (55) (27) (34) (173) Transaction-related income taxes - - (42) - 179 - - - - - Maintenance capital expenditures (520) (581) (821) (860) (1,161) (202) (305) (347) (462) (1,316) Other, net 74 68 20 41 90 22 13 26 36 97 Distributable Cash Flow (consolidated) 7,177 9,627 9,249 9,484 10,634 2,924 2,536 2,474 2,681 10,615 Distributable Cash Flow attributable to Sunoco LP and SunocoCorp (516) (542) (648) (659) (946) (310) (290) (319) (344) (1,263) Distributions from Sunoco LP 165 165 166 173 245 64 67 68 87 286 Distributable Cash Flow attributable to USAC (100%) (221) (209) (221) (281) (355) (89) (90) (103) (104) (386) Distributions from USAC 97 97 97 97 97 24 24 25 24 97 Distributable Cash Flow attributable to noncontrolling interests in other non-wholly-owne (1,015) (1,113) (1,240) (1,352) (1,335) (308) (289) (251) (305) (1,153) Distributable Cash Flow attributable to the partners of Energy Transfer (a) 5,687 8,025 7,403 7,462 8,340 2,305 1,958 1,894 2,039 8,196 Transaction-related adjustments 55 194 44 116 23 2 1 1 2 6 Distributable Cash Flow attributable to the partners of Energy Transfer, as adjusted (a) 5,742$ 8,219$ 7,447$ 7,578$ 8,363$ 2,307$ 1,959$ 1,895$ 2,041$ 8,202$ 2022 2025
Page 17
Non-GAAP Reconciliation 17 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. 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 overthe operations and resulting revenuesand 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 preferredunitholders 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 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.