Energy Transfer Q2 2025 Earnings

Energy Transfer Q2 2025 Earnings

• 1. Q2 2025 Earnings August 6, 2025

• 2. Forward-looking Statements / Legal Disclaimer 2 Management of Energy Transfer LP (ET) will provide this presentation in conjunction with ET’s 2nd 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), 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 and integrate transactions described herein and the possibility that the anticipated benefits of the transactions cannot be fully realized. Any statement made by a member of management of the Partnerships at these meetings 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 forwardlooking 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.

• 3. What’s New? 3 Financial Strategic  Energy Transfer volumes compared to Q2’24 ‒ Interstate natural gas transportation up 11% ‒ Midstream gathered volumes up 10%; setting a new partnership record ‒ Crude oil transportation up 9%; setting a new partnership record ‒ Intrastate natural gas transportation up 8% ‒ NGL transportation volumes up 4%; setting a new partnership record ‒ Total NGL exports up 5%; setting a new partnership record ‒ NGL fractionated volumes up 5%  Energy Transfer recently placed its Nederland Flexport NGL Export Expansion Project into ethane and propane service and expects to begin ethylene service in the fourth quarter of this year  Recently commissioned the Lenorah II and Badger processing plants in the Permian Basin, both of which have a capacity of 200 MMcf/d  Adjusted EBITDA: ‒ Q2’25: $3.87B  Distributable Cash Flow attributable to partners: ‒ Q2’25: $1.96B  YTD’25 Capital Expenditures: ‒ Growth: $2.0B¹ ‒ Maintenance: $418MM¹  2025 Growth Capital Guidance: ‒ Expected Growth Capital: ~$5.0B¹  Announced increase to quarterly cash distribution to $0.33 per unit; up more than 3% vs Q2’24  Announced the 1.5 Bcf/d expansion to Transwestern Pipeline. The Desert Southwest expansion project will include a 516-mile, 42-inch natural gas pipeline will connect the Permian Basin with markets in AZ and NM  Reached FID on Phase II of Hugh Brinson Pipeline project. Upon completion, this natural gas pipeline will have the ability to transport ~2.2 Bcf/d from west to east, and also transport ~ 1 Bcf/d from east to west  Reached FID on the construction of a 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  During the second quarter, Lake Charles LNG signed an HOA with MidOcean Energy for the joint development of the LNG project. In addition, Lake Charles signed 20-year SPAs with Kyushu Electric Power Company and Chevron USA² 1. Energy Transfer excluding SUN and USA Compression capital expenditures 2. Subject to Energy Transfer LNG taking a positive final investment decision as well as the satisfaction of other conditions precedent Operational

• 4. Nationwide Footprint With Diverse Product Offerings Across the Value Chain 4 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 Houston Terminal Lake Charles Regas Cushing Terminal

• 5. 37 32 20 83 79 44 77 61 80 40 18 59 35 15 284 80 MW Recently placed into service the second of 8, 10-MW natural gas-fired electric generation facilities: Leading Natural Gas Pipeline Footprint Delivering on Projects to Serve Growing Electricity Demand 5 Total gas-fired power plants within each state ~185 Plants Served Gas-fired power plants served via direct and indirect connections: Energy Transfer is pursuing opportunities to serve growing power loads from new demand centers across its pipeline network Requests to connect to ~200 data centers in 15 states across our footprint Recently completed several agreements with electric utilities in the Midwest to provide connections for new natural gasfired generation that is replacing coalfired generation Requests to connect to 60+ power plants in 14 states for new connections Up to 450,000 Signed agreement with CloudBurst to provide natural gas to data center development in Central Texas: MMBtu/d¹ Total First 10-MW Power Generation Facility 1. Subject to CloudBurst reaching a positive final investment decision with its customer Winkler Co, TX Total data centers within each state 378 151 21 36 16 47 222 53 188 60 5 22 9 26 126 Map Source: EIA and Datacentermap.com 72

• 6. Well-Balanced, Diversified, Fee-Based Earnings 6 1. Spread margin is pipeline basis, cross commodity and time spreads 2. Fee margins include transport and storage fees from affiliate customers at market rates Q2 2025 Adjusted EBITDA by Segment Fee² ~90% Spread1 0-5% Commodity 5-10% Pricing/spread assumptions based on current futures markets 2025E Adjusted EBITDA Breakout Midstream 20% NGL & Refined Products 27% Crude Oil 19% Natural Gas Inter & Intrastate Pipelines & Storage 19% SUN, USAC & Other 15% Contracts Include – Take-or-pay – Long-term tenors – Inflation escalation provisions – Strong counterparties Contracts Include

• 7. Disciplined Growth Targeting Strong Investment Returns & Quick Cash Cycles 7 Midstream • A significant amount of 2025 spend will be directed toward the Permian Basin, including: – Permian Processing Expansions (Badger, Lenorah II² and Mustang Draw) – Processing plant capacity additions (Arrowhead I and II) – Permian treating upgrades – Compression additions – Well connects ~30% NGL & Refined Products • Nederland Flexport NGL expansion • Mont Belvieu Frac IX • Lone Star Express Expansion • Gateway NGL Pipeline Debottlenecking • Marcus Hook Terminal Optimization • Sabina 2 Pipeline Conversion • Nederland refrigerated storage expansion • Storage upgrades at Mont Belvieu and Spindletop ~28% Intrastate Natural Gas Transportation • Hugh Brinson Pipeline • Bethel storage expansion • Small laterals and tie in projects to support new demand growth on TX pipelines ~28% Crude • Williston Basin crude oil and water gathering • Permian Basin crude oil gathering buildout • Optimization projects • Well connects ~6% Interstate & All Other • Laterals and tie-ins to support new demand growth off of existing pipelines • Optimization projects on FGT • Transwestern Pipeline – Desert Southwest Expansion • Natural gas-fired electric generation facilities ~8% 1. Energy Transfer excluding SUN and USA Compression capital expenditures 2. Formerly known as Red Lake IV % of 2025E 2025E Growth Capital: ~$5.0 billion¹

• 8. Natural Gas Growth Project Backlog 1. Formerly known as Red Lake IV 8 Nearly 50% of 2025 growth capital is expected to be spent on natural gas focused projects Project Name Natural Gas Project Overviews Status Permian Processing Upgrades Upgraded four processing plants to add ~200 MMcf/d of incremental processing capacity in West Texas (Included adding 50 MMcf/d at Grey Wolf, Orla East, Arrowhead II and Arrowhead III, respectively) In Service Lenorah II Processing Plant¹ 200 MMcf/d processing plant in the Midland Basin In Service Badger Processing Plant Relocating idle plant to the Delaware Basin to provide an incremental 200 MMcf/d of processing capacity in the Delaware Basin In Service Mustang Draw Processing Plant 275 MMcf/d processing plant in the Midland Basin 2Q 2026 Natural Gas-Fired Electric Generation Constructing 8, 10 MW natural gas-fired electric generation facilities to support Energy Transfer’s operations in Texas Two In Service Remainder 2025-2026 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 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 Transwestern Pipeline - Desert Southwest Expansion Project 516-mile, 42-inch pipeline to provide ~1.5 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 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 Lake Charles LNG Export Terminal Developing large-scale LNG export facility at existing Lake Charles LNG regasification terminal Proposed New New New

• 9. NGL and Other Growth Project Backlog 9 Project Name Other Project Overviews Status Blue Marlin VLCC project from Nederland Terminal; recently approved final FEED study, which keeps the project on pace to meet internal projections Proposed Carbon Capture and Sequestration In May 2024, entered into agreement with CapturePoint that commits CO2 from ET treating facilities in northern Louisiana to the capture and sequestration project being jointly developed by ET and CapturePoint Proposed Blue Ammonia Developing ammonia hub concept at Lake Charles, LA and Nederland, TX that would provide infrastructure services to several blue ammonia facilities, including natural gas supply, CO2 transportation to 3rd party sequestration sites, ammonia storage and deep-water marine loading services Proposed 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 expected to add up to 250,000 Bbls/d of NGL export capacity at Nederland Terminal with flexibility to load various products, based on customer demand Ethane – In Service Propane – In Service Ethylene – Q4 2025 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 Mid-2025 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 Construction Underway 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 New

• 10. Desert Southwest – Transwestern Pipeline Expansion Project 10  516-mile, 42-inch pipeline that extends from the heart of the Permian Basin to the Phoenix area in Arizona • Expected to have a capacity of ~1.5 Bcf/d • Pipeline will increase the supply of natural gas to markets throughout Arizona and New Mexico from Energy Transfer’s premier asset base in the prolific Permian Basin • Project is supported by significant long-term commitments from investment-grade customers • Expected to cost ~$5.3 billion, including ~$0.6 billion of AFUDC, and be in service by Q4 2029 • Expect to launch an open season later in Q3 2025 and expect the remaining capacity to be fully subscribed upon completion of the open season • Depending on the final results of the open season, the project could be efficiently expanded to accommodate additional demand Desert Southwest Pipeline Project Waha Current Asset Overview Transwestern Pipeline Energy Transfer Interstate Energy Transfer Intrastate Phoenix 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

• 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 • Secured majority of pipeline steel (currently being manufactured in U.S. pipe mills) • Capacity of ~1.5 Bcf/d • Phase 1 is completely sold out and backed by long-term, feebased 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  Also includes construction of Midland Lateral • 42-mile, 36-inch lateral to connect ET processing plants in Martin and Midland counties to the Hugh Brinson Pipeline  Phase II: Includes the addition of compression  Upon completion, expect pipeline to be a bi-directional system with the ability to transport ~2.2 Bcf/d from west to east • Also expect to be capable of moving ~ 1 Bcf/d from east to west  When the pipeline goes into service, expect to have more than 2.2 Bcf/d contracted  Total capital of 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

• 12. Expanding World-Class NGL Export Facilities 12 • Flexport expansion project is expected to add up to 250,000 Bbls/d of NGL export capacity o Recently began ethane and propane service, and expect to begin ethylene export service in Q4 2025 o Expected to ramp up throughout remainder of 2025; fully contracted beginning January 1, 2026 • 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 • 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 Term transportation commitments in place Nederland Terminal Sabina 2 Pipeline Marcus Hook Terminal Houston Terminal Nederland Terminal – Flexport Expansion Total NGL Export Capacity Marcus Hook Terminal – Ethane Tank Expansion > 1.4mm Bbls/d Energy Transfer’s market share of worldwide NGL exports remains at ~20%

• 13. Permian Basin Processing Strengthening Position to Meet Growing Demand 13 Permian Basin Footprint  Extensive Permian Basin Footprint: • Currently have ~5.4 Bcf/d of processing capacity in the Permian Basin • Have significant acreage dedications to ET processing plants in the Permian Basin  Processing Plant Optimizations • 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 • Recently placed the 200 MMcf/d Badger plant into service – expected to be at full capacity in next few months • Utilized an idle plant that was relocated to the Delaware Basin • 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 • The volumes from the tailgate of these plants will utilize Energy Transfer gas and NGL pipelines for takeaway from the basin  Lenorah I & II¹ • Following the closing of the WTG acquisition, the 200 MMcf/d Lenorah I processing plant was placed into service • 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  As a result of recent processing upgrades, processed volumes in the Permian Basin recently reached a new record of nearly 5 Bcf/d Over the last year, added approximately 800 MMcf/d of new processing capacity in West Texas Arrowhead Plants II & III Orla East Plant Grey Wolf Plant Badger Plant Lenorah I & II¹ Mustang Draw 1. Lenorah I was formerly known as Red Lake III and Lenorah II was formerly known as Red Lake IV

• 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 Powering assets: ~20% From Solar & Wind 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 ~790,000 Tons of CO2 2023 emissions reduction from Dual Drive: Power Generation  Construction underway on 8 natural gas-fired electric generation facilities to support Energy Transfer’s operations in Texas. The second facility was recently placed into service, with two more expected in service by the end of 2025, and the remainder expected to go into service in 2026

• 15. Appendix / Non-GAAP Reconciliations

• 16. Energy Transfer LP Reconciliation of Non-GAAP Measures 2020 2021 2023 2024 Full Year Full Year Full Year Full Year Full Year Q1 Q2 YTD Net income $ 140 $ 6,687 $ 5,868 $ 5,294 $ 6,565 $ 1,720 $ 1,458 $ 3,178 Depreciation, depletion and amortization 3,678 3,817 4,164 4,385 5,165 1,367 1,384 2,751 Interest expense, net 2,327 2,267 2,306 2,578 3,125 809 865 1,674 Income tax expense 237 184 204 303 541 41 79 120 Impairment losses and other 2,880 21 386 12 52 4 3 7 (Gains) losses on interest rate derivatives 203 (61) (293) (36) (6) - - - Non-cash compensation expense 121 111 115 130 151 37 33 70 Unrealized (gains) losses on commodity risk management activities 71 (162) (42) (3) 56 69 (100) (31) Inventory valuation adjustments (Sunoco LP) 82 (190) (5) 114 86 (61) 40 (21) Losses (gains) on extinguishments of debt 75 38 - (2) 12 2 17 19 Adjusted EBITDA related to unconsolidated affiliates 628 523 565 691 692 167 182 349 Equity in earnings of unconsolidated affiliates (119) (246) (257) (383) (379) (92) (105) (197) 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 45 Adjusted EBITDA (consolidated) 10,531 13,046 13,093 13,698 15,483 4,098 3,866 7,964 Adjusted EBITDA related to unconsolidated affiliates (628) (523) (565) (691) (692) (167) (182) (349) Distributable Cash Flow from unconsolidated affiliates 452 346 359 485 486 111 129 240 Interest expense, net (2,327) (2,267) (2,306) (2,578) (3,125) (809) (865) (1,674) Preferred unitholders' distributions (378) (418) (471) (511) (361) (72) (65) (137) Current income tax expense (27) (44) (18) (100) (265) (57) (55) (112) Transaction-related income taxes - - (42) - 179 - - - Maintenance capital expenditures (520) (581) (821) (860) (1,161) (202) (305) (507) Other, net 74 68 20 41 90 22 13 35 Distributable Cash Flow (consolidated) 7,177 9,627 9,249 9,484 10,634 2,924 2,536 5,460 Distributable Cash Flow attributable to Sunoco LP (100%) (516) (542) (648) (659) (946) (310) (290) (600) Distributions from Sunoco LP 165 165 166 173 245 64 67 131 Distributable Cash Flow attributable to USAC (100%) (221) (209) (221) (281) (355) (89) (90) (179) Distributions from USAC 97 97 97 97 97 24 24 48 Distributable Cash Flow attributable to noncontrolling interests in other non-wholly-owne (1,015) (1,113) (1,240) (1,352) (1,335) (308) (289) (597) 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 4,263 Transaction-related adjustments 55 194 44 116 23 2 1 3 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 $ 4,266 2022 2025 Non-GAAP Reconciliation 16 * See definitions of non-GAAP measures on next slide *

• 17. Non-GAAP Reconciliation 17 Definitions 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 and other non-operating income or expense items. Inventory valuation adjustments that are excluded from the calculation of Adjusted EBITDA represent only the changes in lower of cost or market reserves on inventory that is carried at last-in, first-out (“LIFO”). These amounts are unrealized valuation adjustments applied to Sunoco LP’s fuel volumes remaining in inventory at the end of the period. Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. The use of Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly. 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 available to be distributed to our partners. In order to reflect the cash flows available for distributions to our partners, we have reported Distributable Cash Flow attributable to partners, which is calculated by adjusting Distributable Cash Flow (consolidated), as follows: 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.