Filed by Energy Transfer Equity, L.P. pursuant to Rule 425 under the Securities Act of 1933 Subject Company: Energy Transfer Partners, L.P. Commission File No.: 001-31219 Date: August 15, 2018 ENERGY TRANSFER EQUITY & ENERGY TRANSFER PARTNERS 2018 Citi One-on-One MLP / Midstream Infrastructure Conference August 15-16, 2018Filed by Energy Transfer Equity, L.P. pursuant to Rule 425 under the Securities Act of 1933 Subject Company: Energy Transfer Partners, L.P. Commission File No.: 001-31219 Date: August 15, 2018 ENERGY TRANSFER EQUITY & ENERGY TRANSFER PARTNERS 2018 Citi One-on-One MLP / Midstream Infrastructure Conference August 15-16, 2018
FORWARD-LOOKING STATEMENTS / LEGAL DISCLAIMER th th Management of Energy Transfer Equity, L.P. (ETE) and Energy Transfer Partners, L.P. (ETP) will provide this presentation to analysts at meetings to be held on August 15 and 16 , 2018. At the meetings, members of management may make statements about future events, outlook and expectations related to Panhandle Eastern Pipe Line Company, LP (PEPL), Sunoco LP (SUN), USA Compression Partners, LP (USAC), ETP and ETE (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. 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. 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. 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. Additional Information and Where to Find It ETE has filed with the SEC a registration statement on Form S-4, which includes a proxy statement of ETP that also constitutes a prospectus of ETE (the “Proxy Statement/Prospectus”). The registration statement on Form S-4 has not been declared effective by the SEC, and the definitive Proxy Statement/Prospectus has not yet been delivered to ETP common unitholders. SECURITY HOLDERS ARE URGED TO READ THE PROXY STATEMENT/PROSPECTUS AND THE REGISTRATION STATEMENT REGARDING THE TRANSACTION CAREFULLY WHEN THEY BECOME AVAILABLE. These documents (when they become available), and any other documents filed by ETE or ETP with the SEC, may be obtained free of charge at the SEC’s website, at www.sec.gov. In addition, investors and security holders will be able to obtain free copies of the registration statement and the Proxy Statement/Prospectus by phone, e-mail or written request by contacting the investor relations department of ETE or ETP at the numbers and addresses set forth below: Energy Transfer Equity, L.P. Energy Transfer Partners, L.P. 8111 Westchester Drive, Suite 600 Dallas, TX 75225 Attn: Investor Relations Phone: (214) 981-0700 InvestorRelations@energytransfer.com Forward-Looking Statements This presentation includes “forward-looking” statements. Forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may” or similar expressions help identify forward-looking statements. ETE and ETP cannot give any assurance that expectations and projections about future events will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. These risks and uncertainties include the risks that the proposed transaction may not be consummated or the benefits contemplated therefrom may not be realized. Additional risks include: the ability to obtain requisite regulatory and unitholder approval and the satisfaction of the other conditions to the consummation of the proposed transaction, the potential impact of the announcement or consummation of the proposed transaction on relationships, including with employees, suppliers, customers, competitors and credit rating agencies, and the ability to achieve revenue, DCF and EBITDA growth, and volatility in the price of oil, natural gas, and natural gas liquids. Actual results and outcomes may differ materially from those expressed in such forward-looking statements. These and other risks and uncertainties are discussed in more detail in filings made by ETE and ETP with the Securities and Exchange Commission (the “SEC”), which are available to the public. ETE and ETP undertake no obligation to update publicly or to revise any forward-looking statements, whether as a result of new information, future events or otherwise. Participants in the Solicitation ETE, ETP and their respective directors and executive officers may be deemed to be participants in the solicitation of proxies in connection with the proposed merger. Information regarding the directors and executive officers of ETE is contained in ETE’s Form 10-K for the year ended December 31, 2017, which was filed with the SEC on February 23, 2018. Information regarding the directors and executive officers of ETP is contained in ETP’s Form 10-K for the year ended December 31, 2017, which was filed with the SEC on February 23, 2018. Additional information regarding the interests of participants in the solicitation of proxies in connection with the proposed merger will be included in the proxy statement/prospectus. No Offer or Solicitation This communication is for informational purposes only and does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval, in any jurisdiction, pursuant to the proposed merger or otherwise, nor shall there be any sale, issuance, exchange or transfer of the securities referred to in this document in any jurisdiction in contravention of applicable law. No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended. 2FORWARD-LOOKING STATEMENTS / LEGAL DISCLAIMER th th Management of Energy Transfer Equity, L.P. (ETE) and Energy Transfer Partners, L.P. (ETP) will provide this presentation to analysts at meetings to be held on August 15 and 16 , 2018. At the meetings, members of management may make statements about future events, outlook and expectations related to Panhandle Eastern Pipe Line Company, LP (PEPL), Sunoco LP (SUN), USA Compression Partners, LP (USAC), ETP and ETE (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. 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. 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. 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. Additional Information and Where to Find It ETE has filed with the SEC a registration statement on Form S-4, which includes a proxy statement of ETP that also constitutes a prospectus of ETE (the “Proxy Statement/Prospectus”). The registration statement on Form S-4 has not been declared effective by the SEC, and the definitive Proxy Statement/Prospectus has not yet been delivered to ETP common unitholders. SECURITY HOLDERS ARE URGED TO READ THE PROXY STATEMENT/PROSPECTUS AND THE REGISTRATION STATEMENT REGARDING THE TRANSACTION CAREFULLY WHEN THEY BECOME AVAILABLE. These documents (when they become available), and any other documents filed by ETE or ETP with the SEC, may be obtained free of charge at the SEC’s website, at www.sec.gov. In addition, investors and security holders will be able to obtain free copies of the registration statement and the Proxy Statement/Prospectus by phone, e-mail or written request by contacting the investor relations department of ETE or ETP at the numbers and addresses set forth below: Energy Transfer Equity, L.P. Energy Transfer Partners, L.P. 8111 Westchester Drive, Suite 600 Dallas, TX 75225 Attn: Investor Relations Phone: (214) 981-0700 InvestorRelations@energytransfer.com Forward-Looking Statements This presentation includes “forward-looking” statements. Forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may” or similar expressions help identify forward-looking statements. ETE and ETP cannot give any assurance that expectations and projections about future events will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. These risks and uncertainties include the risks that the proposed transaction may not be consummated or the benefits contemplated therefrom may not be realized. Additional risks include: the ability to obtain requisite regulatory and unitholder approval and the satisfaction of the other conditions to the consummation of the proposed transaction, the potential impact of the announcement or consummation of the proposed transaction on relationships, including with employees, suppliers, customers, competitors and credit rating agencies, and the ability to achieve revenue, DCF and EBITDA growth, and volatility in the price of oil, natural gas, and natural gas liquids. Actual results and outcomes may differ materially from those expressed in such forward-looking statements. These and other risks and uncertainties are discussed in more detail in filings made by ETE and ETP with the Securities and Exchange Commission (the “SEC”), which are available to the public. ETE and ETP undertake no obligation to update publicly or to revise any forward-looking statements, whether as a result of new information, future events or otherwise. Participants in the Solicitation ETE, ETP and their respective directors and executive officers may be deemed to be participants in the solicitation of proxies in connection with the proposed merger. Information regarding the directors and executive officers of ETE is contained in ETE’s Form 10-K for the year ended December 31, 2017, which was filed with the SEC on February 23, 2018. Information regarding the directors and executive officers of ETP is contained in ETP’s Form 10-K for the year ended December 31, 2017, which was filed with the SEC on February 23, 2018. Additional information regarding the interests of participants in the solicitation of proxies in connection with the proposed merger will be included in the proxy statement/prospectus. No Offer or Solicitation This communication is for informational purposes only and does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval, in any jurisdiction, pursuant to the proposed merger or otherwise, nor shall there be any sale, issuance, exchange or transfer of the securities referred to in this document in any jurisdiction in contravention of applicable law. No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended. 2
ETP HIGHLIGHTSETP HIGHLIGHTS
ETP KEY INVESTMENT HIGHLIGHTS Growth From Organic Solid Financials Well Positioned Assets Investments Ø Stable cash flow profile Ø Completing multi-year Ø Fully integrated platform capex program with minimal contract roll- spanning entire midstream offs value chain Ø Beginning to see strong EBITDA growth from Ø Healthy and improving Ø Assets well positioned in recently completed major balance sheet most active basins growth projects Ø Strong funding activity in Ø Integrated assets allow Ø Expect additional EBITDA 2017 and YTD 2018 solid commercial synergies resulting in majority of growth from remainder of across entire midstream 2018 pre-funded projects coming online value chain, including gas, through 2020 crude and NGLs 4ETP KEY INVESTMENT HIGHLIGHTS Growth From Organic Solid Financials Well Positioned Assets Investments Ø Stable cash flow profile Ø Completing multi-year Ø Fully integrated platform capex program with minimal contract roll- spanning entire midstream offs value chain Ø Beginning to see strong EBITDA growth from Ø Healthy and improving Ø Assets well positioned in recently completed major balance sheet most active basins growth projects Ø Strong funding activity in Ø Integrated assets allow Ø Expect additional EBITDA 2017 and YTD 2018 solid commercial synergies resulting in majority of growth from remainder of across entire midstream 2018 pre-funded projects coming online value chain, including gas, through 2020 crude and NGLs 4
RECENT HIGHLIGHTS • ETP Adjusted EBITDA (consolidated): $2.05 billion, up more than 30% year-over-year • Distributable Cash Flow attributable to the partners of ETP: $1.32 billion, up nearly 40% year-over-year • ETE Distributable Cash Flow, as adjusted: $407 million Q2 2018 Earnings • Distribution per ETP common unit paid August 14, 2018: $0.565 ($2.26 per ETP common unit annualized) • Distribution per ETE common unit will be paid August 20, 2018: $0.305 ($1.22 per ETE common unit annualized) • Distribution coverage ratio: ETP - 1.23x; ETE – 1.15x • In July 2018, ETP issued $445 million of its 7⅝% Series D Fixed-To-Floating Rate Cumulative Redeemable Perpetual Preferred Units Series D Perpetual • Provide a cost-effective means of raising equity capital, and ETP used the proceeds to repay amounts outstanding under its Preferred Units revolving credit facilities and for general partnership purposes • The securities received 50% equity treatment from all three ratings agencies • In August 2018, ETP and ETE entered into a merger agreement pursuant to which ETP will merge with a wholly-owned subsidiary of ETE, with ETP unitholders (other than ETE subsidiaries) receiving 1.28 ETE common units in exchange for each ETE / ETP ETP common unit owned Simplification • The transaction is expected to close in the fourth quarter of 2018, subject to approval by a majority of the unaffiliated unitholders of ETP and other customary closing conditions • In May 2018, ETP announced the receipt of approval to place the remaining portion of Phase 2 of the Rover pipeline in service, effective June 1, 2018, allowing for use of 100% of Rover’s 3.25 Bcf/d mainline capacity Growth Project • In May 2018, ETP placed into service Red Bluff Express Pipeline, a 1.4 Bcf/d natural gas pipeline that runs through the heart of the Delaware basin and connects the ETP Orla Plant and multiple third-party plants to ETP’s Waha Oasis Header Updates • In July 2018, ETP placed into service Frac V, a 120,000 barrel per day fractionator located in Mont Belvieu, Texas that is fully subscribed under multiple long-term, fixed-fee contracts 5RECENT HIGHLIGHTS • ETP Adjusted EBITDA (consolidated): $2.05 billion, up more than 30% year-over-year • Distributable Cash Flow attributable to the partners of ETP: $1.32 billion, up nearly 40% year-over-year • ETE Distributable Cash Flow, as adjusted: $407 million Q2 2018 Earnings • Distribution per ETP common unit paid August 14, 2018: $0.565 ($2.26 per ETP common unit annualized) • Distribution per ETE common unit will be paid August 20, 2018: $0.305 ($1.22 per ETE common unit annualized) • Distribution coverage ratio: ETP - 1.23x; ETE – 1.15x • In July 2018, ETP issued $445 million of its 7⅝% Series D Fixed-To-Floating Rate Cumulative Redeemable Perpetual Preferred Units Series D Perpetual • Provide a cost-effective means of raising equity capital, and ETP used the proceeds to repay amounts outstanding under its Preferred Units revolving credit facilities and for general partnership purposes • The securities received 50% equity treatment from all three ratings agencies • In August 2018, ETP and ETE entered into a merger agreement pursuant to which ETP will merge with a wholly-owned subsidiary of ETE, with ETP unitholders (other than ETE subsidiaries) receiving 1.28 ETE common units in exchange for each ETE / ETP ETP common unit owned Simplification • The transaction is expected to close in the fourth quarter of 2018, subject to approval by a majority of the unaffiliated unitholders of ETP and other customary closing conditions • In May 2018, ETP announced the receipt of approval to place the remaining portion of Phase 2 of the Rover pipeline in service, effective June 1, 2018, allowing for use of 100% of Rover’s 3.25 Bcf/d mainline capacity Growth Project • In May 2018, ETP placed into service Red Bluff Express Pipeline, a 1.4 Bcf/d natural gas pipeline that runs through the heart of the Delaware basin and connects the ETP Orla Plant and multiple third-party plants to ETP’s Waha Oasis Header Updates • In July 2018, ETP placed into service Frac V, a 120,000 barrel per day fractionator located in Mont Belvieu, Texas that is fully subscribed under multiple long-term, fixed-fee contracts 5
SIGNIFICANT GEOGRAPHIC FOOTPRINT ACROSS THE FAMILY Recently In-service & Asset Overview Announced Growth Projects Bayou Bridge Lake Charles LNG Marcus Hook Energy Transfer Assets Rover Pipeline Dakota Access Pipeline Eagle Point Terminals Revolution System ETCO Pipeline Nederland Mariner East Phase 2 Comanche Trail Pipeline Midland Trans-Pecos Pipeline 6SIGNIFICANT GEOGRAPHIC FOOTPRINT ACROSS THE FAMILY Recently In-service & Asset Overview Announced Growth Projects Bayou Bridge Lake Charles LNG Marcus Hook Energy Transfer Assets Rover Pipeline Dakota Access Pipeline Eagle Point Terminals Revolution System ETCO Pipeline Nederland Mariner East Phase 2 Comanche Trail Pipeline Midland Trans-Pecos Pipeline 6
A TRULY UNIQUE FRANCHISE Natural NGLs Crude Gas Oil Gather ~ 11.6 million Fractionate One of the largest Transport ~19 More than 7.9 billion Transport ~4.2 mmbtu/d of gas & ~470,000 bbls/d of planned LNG million mmbtu/d of gallons of annual million barrels 513,000 bbls/d of NGLs at Mont Export facilities in natural gas motor fuel sales crude oil per day NGLs produced Belvieu the US 7A TRULY UNIQUE FRANCHISE Natural NGLs Crude Gas Oil Gather ~ 11.6 million Fractionate One of the largest Transport ~19 More than 7.9 billion Transport ~4.2 mmbtu/d of gas & ~470,000 bbls/d of planned LNG million mmbtu/d of gallons of annual million barrels 513,000 bbls/d of NGLs at Mont Export facilities in natural gas motor fuel sales crude oil per day NGLs produced Belvieu the US 7
FULLY INTEGRATED PLATFORM SPANNING THE ENTIRE MIDSTREAM VALUE CHAIN Ø Involvement in Major Midstream Themes Across the Best Basins and Logistics Hubs Franchise Strengths Opportunities • Access to multiple shale plays, storage facilities and markets • Marcellus natural gas takeaway to the Midwest, Gulf Coast, and Canada Interstate Natural • Approximately 95% of revenue from reservation fee contracts • Well positioned to capitalize on changing market dynamics • Backhaul to LNG exports and new petrochemical demand on Gulf Coast Gas T&S • Key assets: Rover, PEPL, FGT, Transwestern, Trunkline, Tiger • Well positioned to capture additional revenues from anticipated changes in natural gas supply and demand • Natural gas exports to Mexico • Largest intrastate natural gas pipeline and storage system on the Intrastate Natural Gulf Coast • Additional demand from LNG and petrochemical development on Gulf Gas T&S • Key assets: ET Fuel Pipeline, Oasis Pipeline, Houston Pipeline Coast System, ETC Katy Pipeline • ~33,000 miles of gathering pipelines with ~6.9 Bcf/d of processing • Gathering and processing build out in Texas and Marcellus/Utica capacity • Synergies with ETP downstream assets Midstream • Significant growth projects ramping up to full capacity over the next two • Projects placed in-service underpinned by long-term, fee-based years contracts • World-class integrated platform for processing, transporting, • Increased volumes from transporting and fractionating volumes from fractionating, storing and exporting NGLs Permian/Delaware and Midcontinent basins • Fastest growing NGLs business in Mont Belvieu via Lone Star • Increased fractionation volumes as large NGL fractionation third-party • Liquids volumes from our midstream segment culminate in the ETE NGL & Refined agreements expire family’s Mont Belvieu / Mariner South / Nederland Gulf Coast Products Complex • Permian NGL takeaway • Mariner East provides significant Appalachian liquids takeaway • New ethane and ethylene export opportunities from Gulf Coast capacity connecting NGL volumes to local, regional and international markets via Marcus Hook • Bakken Crude Oil pipeline supported by long-term, fee-based • Permian Express 3 expected to provide Midland & Delaware Basin contracts; expandable to 570,000 bpd with pump station modifications crude oil takeaway to various markets, including Nederland, TX • Significant Permian takeaway abilities with potential to provide the • Permian Express Partners Joint Venture with ExxonMobil Crude Oil market with ~1 million barrels of crude oil takeaway • Also aggressively pursuing larger project to move barrels from the • ~400,000 barrels per day crude oil export capacity from Nederland Permian Basin to Nederland, providing shipper capacity to ETP storage • 26 million barrel Nederland crude oil terminal on the Gulf Coast facilities and header systems 8 • Bakken crude takeaway to Gulf Coast refineriesFULLY INTEGRATED PLATFORM SPANNING THE ENTIRE MIDSTREAM VALUE CHAIN Ø Involvement in Major Midstream Themes Across the Best Basins and Logistics Hubs Franchise Strengths Opportunities • Access to multiple shale plays, storage facilities and markets • Marcellus natural gas takeaway to the Midwest, Gulf Coast, and Canada Interstate Natural • Approximately 95% of revenue from reservation fee contracts • Well positioned to capitalize on changing market dynamics • Backhaul to LNG exports and new petrochemical demand on Gulf Coast Gas T&S • Key assets: Rover, PEPL, FGT, Transwestern, Trunkline, Tiger • Well positioned to capture additional revenues from anticipated changes in natural gas supply and demand • Natural gas exports to Mexico • Largest intrastate natural gas pipeline and storage system on the Intrastate Natural Gulf Coast • Additional demand from LNG and petrochemical development on Gulf Gas T&S • Key assets: ET Fuel Pipeline, Oasis Pipeline, Houston Pipeline Coast System, ETC Katy Pipeline • ~33,000 miles of gathering pipelines with ~6.9 Bcf/d of processing • Gathering and processing build out in Texas and Marcellus/Utica capacity • Synergies with ETP downstream assets Midstream • Significant growth projects ramping up to full capacity over the next two • Projects placed in-service underpinned by long-term, fee-based years contracts • World-class integrated platform for processing, transporting, • Increased volumes from transporting and fractionating volumes from fractionating, storing and exporting NGLs Permian/Delaware and Midcontinent basins • Fastest growing NGLs business in Mont Belvieu via Lone Star • Increased fractionation volumes as large NGL fractionation third-party • Liquids volumes from our midstream segment culminate in the ETE NGL & Refined agreements expire family’s Mont Belvieu / Mariner South / Nederland Gulf Coast Products Complex • Permian NGL takeaway • Mariner East provides significant Appalachian liquids takeaway • New ethane and ethylene export opportunities from Gulf Coast capacity connecting NGL volumes to local, regional and international markets via Marcus Hook • Bakken Crude Oil pipeline supported by long-term, fee-based • Permian Express 3 expected to provide Midland & Delaware Basin contracts; expandable to 570,000 bpd with pump station modifications crude oil takeaway to various markets, including Nederland, TX • Significant Permian takeaway abilities with potential to provide the • Permian Express Partners Joint Venture with ExxonMobil Crude Oil market with ~1 million barrels of crude oil takeaway • Also aggressively pursuing larger project to move barrels from the • ~400,000 barrels per day crude oil export capacity from Nederland Permian Basin to Nederland, providing shipper capacity to ETP storage • 26 million barrel Nederland crude oil terminal on the Gulf Coast facilities and header systems 8 • Bakken crude takeaway to Gulf Coast refineries
FULLY INTEGRATED SERVICES BY REGION ETP Services By Region Midstream Natural Gas Liquids Crude Interstate Intrastate Bakken Marcellus/Utica MidCon/Panhandle North Texas Permian Basin Ark-La-Tex Eagle Ford/SE Texas 9FULLY INTEGRATED SERVICES BY REGION ETP Services By Region Midstream Natural Gas Liquids Crude Interstate Intrastate Bakken Marcellus/Utica MidCon/Panhandle North Texas Permian Basin Ark-La-Tex Eagle Ford/SE Texas 9
ETP ASSETS ALIGNED WITH MAJOR U.S. DRILLING REGIONS ETP Rig Count Vs. Total US Rig Count¹ ETP Rig Count¹ Vs. Lower 48 US Rig Count Rigs: 59 Rigs: 37 Rigs: 99 Rigs: 12 Rigs: 443 Rigs: 52 Ø Significant growth opportunities from bolt-on projects • Bolt-on projects are typically lower Rigs: 95 cost, higher return ETP’s gas and crude gathering assets are located in counties where ~70% of total US rigs are currently drilling 10 (1) Source: Drilling Info; ETP rig count includes only rigs operating in counties in which ETP has assets/operations. As of 5-16-2018.ETP ASSETS ALIGNED WITH MAJOR U.S. DRILLING REGIONS ETP Rig Count Vs. Total US Rig Count¹ ETP Rig Count¹ Vs. Lower 48 US Rig Count Rigs: 59 Rigs: 37 Rigs: 99 Rigs: 12 Rigs: 443 Rigs: 52 Ø Significant growth opportunities from bolt-on projects • Bolt-on projects are typically lower Rigs: 95 cost, higher return ETP’s gas and crude gathering assets are located in counties where ~70% of total US rigs are currently drilling 10 (1) Source: Drilling Info; ETP rig count includes only rigs operating in counties in which ETP has assets/operations. As of 5-16-2018.
FULLY INTEGRATED MIDSTREAM/LIQUIDS PLATFORM ACROSS NORTH AMERICA The ability to integrate an end-to-end liquids solution will better serve customers and alleviate bottlenecks currently faced by producers Ma Marc rcus us H Hook ook: : The The future future Mont Mont Be Belv lvie ieu u of of tthe he North North • 800 acre site: inbound and outbound pipeline along with infrastructure connectivity • Logistically and financially advantaged for exports being 1,500 miles closer to Europe, significantly reducing shipping cost. • Advantaged to local and regional markets • No ship channel restriction, compared to the Houston Ship Channel • 4 seaborne export docks can accommodate VLGC sized vessels • ETP’s Rover, Revolution and Mariner East systems provide long-term growth potential Lone Star Lone Star is the fastest is the fastest g grow rowiing ng N NGLs business GLs business iin n Mo Mon ntt Bel Belv viieu eu Legacy Legacy Energy Transfer Sunoco Logistics • Fracs I, II, III, IV and V in service. Frac VI expected in-service Q2 2019 • Plot plan in place for an additional Frac on existing footprint (7 fractionators in total) NGL Pipelines Refined Products/NGL • Total Frac capacity potentially 800,000 bpd Crude Projects¹ Crude • ~2,000 miles of NGL pipelines with fully-expanded capacity of ~1,300,000 bpd • Storage capacity of 53 millions barrels NGL Projects Growth Projects • ~200,000 bpd LPG export terminal Facility • ETP’s Lone Star presence in Mont Belvieu combined with its Nederland terminal provide LNG Facilities opportunities for multiple growth projects Fractionator • Potential ethane and ethylene projects delivering Lone Star fractionated products to Nederland for export 11 11 (1) Via joint venturesFULLY INTEGRATED MIDSTREAM/LIQUIDS PLATFORM ACROSS NORTH AMERICA The ability to integrate an end-to-end liquids solution will better serve customers and alleviate bottlenecks currently faced by producers Ma Marc rcus us H Hook ook: : The The future future Mont Mont Be Belv lvie ieu u of of tthe he North North • 800 acre site: inbound and outbound pipeline along with infrastructure connectivity • Logistically and financially advantaged for exports being 1,500 miles closer to Europe, significantly reducing shipping cost. • Advantaged to local and regional markets • No ship channel restriction, compared to the Houston Ship Channel • 4 seaborne export docks can accommodate VLGC sized vessels • ETP’s Rover, Revolution and Mariner East systems provide long-term growth potential Lone Star Lone Star is the fastest is the fastest g grow rowiing ng N NGLs business GLs business iin n Mo Mon ntt Bel Belv viieu eu Legacy Legacy Energy Transfer Sunoco Logistics • Fracs I, II, III, IV and V in service. Frac VI expected in-service Q2 2019 • Plot plan in place for an additional Frac on existing footprint (7 fractionators in total) NGL Pipelines Refined Products/NGL • Total Frac capacity potentially 800,000 bpd Crude Projects¹ Crude • ~2,000 miles of NGL pipelines with fully-expanded capacity of ~1,300,000 bpd • Storage capacity of 53 millions barrels NGL Projects Growth Projects • ~200,000 bpd LPG export terminal Facility • ETP’s Lone Star presence in Mont Belvieu combined with its Nederland terminal provide LNG Facilities opportunities for multiple growth projects Fractionator • Potential ethane and ethylene projects delivering Lone Star fractionated products to Nederland for export 11 11 (1) Via joint ventures
GROWTH FROM ORGANIC INVESTMENTSGROWTH FROM ORGANIC INVESTMENTS
ORGANIC GROWTH ENHANCES THE COMBINED ENTITY’S STRONG FOOTHOLD IN THE MOST PROLIFIC PRODUCING BASINS (1) 2017 Bakken Crude Pipeline 2013 Mariner West 2014 Mariner East 1 - Propane 2015 Allegheny Access Active in 9 of the top 10 basins by active (1) 2016 Ohio River System rig count with a rapidly increasing Mariner East 1 – Ethane and Propane NE PA Expansion Projects footprint in the most prolific US onshore 2017 Rover Pipeline (includes making PEPL/TGC bi- plays (1)* directional 2018 Mariner East 2* Revolution Pipeline* 2019 Mariner East 2X Expansion* 2010 Fayetteville Express Pipeline –185 mile (1) 42” gas pipeline 2009 Phoenix Lateral added to Transwestern 2009 Midcontinent Express pipeline – 260-mile, 36” and 42” gas pipeline JV – 500 mile gas pipeline from Woodford (1) and Barnett 2014 Granite Wash 2013 Permian Express 1 Extension 2014 Rebel Plant Permian Express 1 expansion 2007 Expanded Godley Plant to 400 MMcf/d 2015 Permian Express 2 2008 Expanded Godley Plant to 600 MMcf/d Mi Vida Plant Eight 36” & 42” gas pipelines totaling 419 miles 2016 Permian Longview & Louisiana Extension Texas Independence Pipeline – 148 mile 42” gas pipeline Delaware Basin Extension 2013 Godley Plant – expanded to 700 MMcf/d Orla Plant Lone Star Express 2017 Panther Plant 2007 First 42” gas pipeline in Texas (1) Trans-Pecos / Comanche Trail 2010 Tiger Pipeline – 175 mile 42” gas pipeline Arrowhead Plant 2015 Alamo Plant Permian Express 3 Phase 1 2018 Rebel II 2011 Freedom (43 miles) and Liberty NGL Pipelines (93 Red Bluff Express Pipeline (1) miles) Arrowhead II* 2012 ETP Justice Pipeline 2019 Red Bluff Express Pipeline Expansion* Lone Star Fractionator I 2020 J.C. Nolan Diesel Pipeline* 2013 Lone Star Fractionator II Jackson Plant 2014 Nueces Crossover 2010 Dos Hermanas Pipeline – 50 mile, 24” gas pipeline 2015 Mariner South 2011 Chisholm Pipeline – 83 miles Lone Star Fractionator III Rich Eagle Ford Mainline (“REM”) Phase I – 160 miles 2016 Lone Star Fractionator IV 2012 Chisholm Plant, Kenedy Plant, and REM Phase II (1) Bayou Bridge Phase I (1) Lone Star West Texas Gateway 2018 Bayou Bridge Phase II * 2014 REM expanded to exceed 1 Bcf/d Lone Star Fractionator V Rio Bravo Crude Conversion 2019 Lone Star Fractionator VI* 2014 Eaglebine Express (1) Eagle Ford Expansion Project 2020 Orbit Ethane Export Facility* 2015 Kenedy II Plant (REM II) 2020+ Lake Charles LNG Facility (60% ETE/40% ETP)* * Growth project under development (1) Joint venture. 13ORGANIC GROWTH ENHANCES THE COMBINED ENTITY’S STRONG FOOTHOLD IN THE MOST PROLIFIC PRODUCING BASINS (1) 2017 Bakken Crude Pipeline 2013 Mariner West 2014 Mariner East 1 - Propane 2015 Allegheny Access Active in 9 of the top 10 basins by active (1) 2016 Ohio River System rig count with a rapidly increasing Mariner East 1 – Ethane and Propane NE PA Expansion Projects footprint in the most prolific US onshore 2017 Rover Pipeline (includes making PEPL/TGC bi- plays (1)* directional 2018 Mariner East 2* Revolution Pipeline* 2019 Mariner East 2X Expansion* 2010 Fayetteville Express Pipeline –185 mile (1) 42” gas pipeline 2009 Phoenix Lateral added to Transwestern 2009 Midcontinent Express pipeline – 260-mile, 36” and 42” gas pipeline JV – 500 mile gas pipeline from Woodford (1) and Barnett 2014 Granite Wash 2013 Permian Express 1 Extension 2014 Rebel Plant Permian Express 1 expansion 2007 Expanded Godley Plant to 400 MMcf/d 2015 Permian Express 2 2008 Expanded Godley Plant to 600 MMcf/d Mi Vida Plant Eight 36” & 42” gas pipelines totaling 419 miles 2016 Permian Longview & Louisiana Extension Texas Independence Pipeline – 148 mile 42” gas pipeline Delaware Basin Extension 2013 Godley Plant – expanded to 700 MMcf/d Orla Plant Lone Star Express 2017 Panther Plant 2007 First 42” gas pipeline in Texas (1) Trans-Pecos / Comanche Trail 2010 Tiger Pipeline – 175 mile 42” gas pipeline Arrowhead Plant 2015 Alamo Plant Permian Express 3 Phase 1 2018 Rebel II 2011 Freedom (43 miles) and Liberty NGL Pipelines (93 Red Bluff Express Pipeline (1) miles) Arrowhead II* 2012 ETP Justice Pipeline 2019 Red Bluff Express Pipeline Expansion* Lone Star Fractionator I 2020 J.C. Nolan Diesel Pipeline* 2013 Lone Star Fractionator II Jackson Plant 2014 Nueces Crossover 2010 Dos Hermanas Pipeline – 50 mile, 24” gas pipeline 2015 Mariner South 2011 Chisholm Pipeline – 83 miles Lone Star Fractionator III Rich Eagle Ford Mainline (“REM”) Phase I – 160 miles 2016 Lone Star Fractionator IV 2012 Chisholm Plant, Kenedy Plant, and REM Phase II (1) Bayou Bridge Phase I (1) Lone Star West Texas Gateway 2018 Bayou Bridge Phase II * 2014 REM expanded to exceed 1 Bcf/d Lone Star Fractionator V Rio Bravo Crude Conversion 2019 Lone Star Fractionator VI* 2014 Eaglebine Express (1) Eagle Ford Expansion Project 2020 Orbit Ethane Export Facility* 2015 Kenedy II Plant (REM II) 2020+ Lake Charles LNG Facility (60% ETE/40% ETP)* * Growth project under development (1) Joint venture. 13
ETP PROJECTS PROVIDE VISIBILITY FOR FUTURE EBITDA GROWTH TPP CTP Bakken Arrowhead PE3 Phase I Rebel II Processing Plant ETP has a significant number of Old Ocean Pipeline growth projects coming online that Red Bluff Express Pipeline will contribute incremental cash flows Lone Star Frac V Phase I Rover Phase II Revolution System Mariner East 2 Mariner East 2 Arrowhead II Phase I Bayou Bridge Phase II NTP Pipeline Expansion PE3 PE3 Lone Star Frac VI Mariner East 2X Red Bluff Express Pipeline Expansion J.C. Nolan Diesel Pipeline Orbit Ethane Export Facility 14 2017 2018 2019 2020 Under Development Ramping UpETP PROJECTS PROVIDE VISIBILITY FOR FUTURE EBITDA GROWTH TPP CTP Bakken Arrowhead PE3 Phase I Rebel II Processing Plant ETP has a significant number of Old Ocean Pipeline growth projects coming online that Red Bluff Express Pipeline will contribute incremental cash flows Lone Star Frac V Phase I Rover Phase II Revolution System Mariner East 2 Mariner East 2 Arrowhead II Phase I Bayou Bridge Phase II NTP Pipeline Expansion PE3 PE3 Lone Star Frac VI Mariner East 2X Red Bluff Express Pipeline Expansion J.C. Nolan Diesel Pipeline Orbit Ethane Export Facility 14 2017 2018 2019 2020 Under Development Ramping Up
FORESEE SIGNIFICANT EBITDA GROWTH IN 2018 FROM COMPLETION OF PROJECT BACKLOG Project Description Project Timing Trans-Pecos & Comanche Collective 337 miles of natural gas pipelines with 2.5 Bcf/d capacity in the Permian In Service Q1 2017 (1) Trail Pipelines (2) 30” pipeline from North Dakota to Patoka Hub, interconnection with ETCO to reach Nederland In Service June 2017 Bakken Crude Pipeline 200 MMcf/d cryogenic processing plant in Midland Basin In Service Q3 2017 Arrowhead Processing Plant 100 Mbpd Q4 2017 Permian Express 3 Provides incremental Permian takeaway capacity, with total capacity of 140Mbpd Remainder Q4 2018 200 MMcf/d cryogenic processing plant near existing Rebel plant In Service Q2 2018 Rebel II Processing Plant (3) Old Ocean Pipeline 24-inch, 160,000 Mmbtu/d natural gas pipeline from Maypearl, TX to Hebert, TX In Service Q2 2018 ~80-mile pipeline with capacity of at least 1.4 bcf/d will connect Orla Plant to the Waha Plant to Red Bluff Express Pipeline Q2 2018 / 2H 2019 provide residue takeaway; new extension will add an incremental 25 miles of pipeline (4) Rover Pipeline 712 mile pipeline from Ohio / West Virginia border to Defiance, OH and Dawn, ON Aug. 31, 2017 – Q2 2018 110 miles of gas gathering pipeline, cryogenic processing plant, NGL pipelines, and fractionation Revolution Q3 2018 facility in PA Lone Star Frac V Additional 120 Mbpd fractionator at Mont Belvieu complex In Service July 2018 NGLs from Ohio/PA Marcellus Shale to the Marcus Hook Industrial Complex with 275Mbpd Mariner East 2 End of Q3 2018 capacity upon full completion Arrowhead II 200 MMcf/d cryogenic processing plant in Midland Basin Q4 2018 (5) Crude pipeline connecting Nederland to Lake Charles / St. James, LA Q2 2016 / Q4 2018 Bayou Bridge 36-inch natural gas pipeline expansion, providing 160,000 Mmbtu/d of additional capacity from (3) NTP Pipeline Expansion End of 2018 WTX for deliveries into Old Ocean Increase NGL takeaway from the Marcellus to the East Coast w/storage at Marcus Hook Mariner East 2X Q2/Q3 2019 Industrial Complex Lone Star Frac VI Additional 140 Mbpd fractionator at Mont Belvieu complex Q2 2019 J.C. Nolan Diesel Pipeline 30,000 bbls/d diesel pipeline from Hebert, TX to newly-constructed terminal in Midland, TX Q3 2020 Orbit Ethane Export 800,000 bbl refrigerated ethane storage tank and 175,000 bbl/d ethane refrigeration facility and End of 2020 20-inch ethane pipeline to connect Mont Belvieu to export terminal Terminal (1) JV with Carso Energy and Mastec, Inc: ETP – 16%, Mastec – 33%, Carso – 51% (3) 50/50 JV with Enterprise (5) JV with Phillips 66 Partners: 60% ETP ownership/operator; 40% Phillips 66 Partners 15 (2) JV with MarEn and PSXP; ETP ownership ~36.37%; MarEn, 36.75%; PSXP, 25% (4) 32.56% ETP; 35% Traverse; 32.44% Blackstone (6) Pending FID, which is subject to execution of commercial off-take commitments and acceptable engineering and construction bidsFORESEE SIGNIFICANT EBITDA GROWTH IN 2018 FROM COMPLETION OF PROJECT BACKLOG Project Description Project Timing Trans-Pecos & Comanche Collective 337 miles of natural gas pipelines with 2.5 Bcf/d capacity in the Permian In Service Q1 2017 (1) Trail Pipelines (2) 30” pipeline from North Dakota to Patoka Hub, interconnection with ETCO to reach Nederland In Service June 2017 Bakken Crude Pipeline 200 MMcf/d cryogenic processing plant in Midland Basin In Service Q3 2017 Arrowhead Processing Plant 100 Mbpd Q4 2017 Permian Express 3 Provides incremental Permian takeaway capacity, with total capacity of 140Mbpd Remainder Q4 2018 200 MMcf/d cryogenic processing plant near existing Rebel plant In Service Q2 2018 Rebel II Processing Plant (3) Old Ocean Pipeline 24-inch, 160,000 Mmbtu/d natural gas pipeline from Maypearl, TX to Hebert, TX In Service Q2 2018 ~80-mile pipeline with capacity of at least 1.4 bcf/d will connect Orla Plant to the Waha Plant to Red Bluff Express Pipeline Q2 2018 / 2H 2019 provide residue takeaway; new extension will add an incremental 25 miles of pipeline (4) Rover Pipeline 712 mile pipeline from Ohio / West Virginia border to Defiance, OH and Dawn, ON Aug. 31, 2017 – Q2 2018 110 miles of gas gathering pipeline, cryogenic processing plant, NGL pipelines, and fractionation Revolution Q3 2018 facility in PA Lone Star Frac V Additional 120 Mbpd fractionator at Mont Belvieu complex In Service July 2018 NGLs from Ohio/PA Marcellus Shale to the Marcus Hook Industrial Complex with 275Mbpd Mariner East 2 End of Q3 2018 capacity upon full completion Arrowhead II 200 MMcf/d cryogenic processing plant in Midland Basin Q4 2018 (5) Crude pipeline connecting Nederland to Lake Charles / St. James, LA Q2 2016 / Q4 2018 Bayou Bridge 36-inch natural gas pipeline expansion, providing 160,000 Mmbtu/d of additional capacity from (3) NTP Pipeline Expansion End of 2018 WTX for deliveries into Old Ocean Increase NGL takeaway from the Marcellus to the East Coast w/storage at Marcus Hook Mariner East 2X Q2/Q3 2019 Industrial Complex Lone Star Frac VI Additional 140 Mbpd fractionator at Mont Belvieu complex Q2 2019 J.C. Nolan Diesel Pipeline 30,000 bbls/d diesel pipeline from Hebert, TX to newly-constructed terminal in Midland, TX Q3 2020 Orbit Ethane Export 800,000 bbl refrigerated ethane storage tank and 175,000 bbl/d ethane refrigeration facility and End of 2020 20-inch ethane pipeline to connect Mont Belvieu to export terminal Terminal (1) JV with Carso Energy and Mastec, Inc: ETP – 16%, Mastec – 33%, Carso – 51% (3) 50/50 JV with Enterprise (5) JV with Phillips 66 Partners: 60% ETP ownership/operator; 40% Phillips 66 Partners 15 (2) JV with MarEn and PSXP; ETP ownership ~36.37%; MarEn, 36.75%; PSXP, 25% (4) 32.56% ETP; 35% Traverse; 32.44% Blackstone (6) Pending FID, which is subject to execution of commercial off-take commitments and acceptable engineering and construction bids
CRUDE OIL SEGMENT-BAKKEN PIPELINE PROJECT Project Details Ø Dakota Access Pipeline connects Bakken production to Patoka Hub, IL, with interconnection to Energy Transfer Crude Oil Pipeline (Trunkline conversion) to reach 1,172 miles of new Nederland and the Gulf Coast 30” • Have commitments, including shipper flexibility and walk-up for an initial capacity of ~470,000 barrels per day • Open season in early 2017 increased the total to ~525,000 barrels per day • Expandable to 570,000 barrels per day with pump station modifications • Went into service and began collecting demand charges on the initial committed capacity June (1) 1, 2017 Trunkline Conversion 743 miles of mostly 30” to crude service • Q2 2018 volumes averaged over 470,000 barrels Project Average Asset Cost Contract Delivery Points Project Name Type Miles ($bn) In-service Duration Origin Sites (2) Dakota Access Crude pipelines 1,172 $4.8 June 1, 2017 8.5 yrs Dakota Access Pipeline (1) (2) ETCO Pipeline Crude pipelines 743 Energy Transfer Crude Oil Pipeline Bayou Bridge Pipeline Note: Gross JV project cost where applicable Nederland Terminal (1) 676 miles of converted pipeline + 67 miles of new build 16 (2) Ownership is ETP-~36.37%, MarEn-36.75%, PSXP-25% CRUDE OIL SEGMENT-BAKKEN PIPELINE PROJECT Project Details Ø Dakota Access Pipeline connects Bakken production to Patoka Hub, IL, with interconnection to Energy Transfer Crude Oil Pipeline (Trunkline conversion) to reach 1,172 miles of new Nederland and the Gulf Coast 30” • Have commitments, including shipper flexibility and walk-up for an initial capacity of ~470,000 barrels per day • Open season in early 2017 increased the total to ~525,000 barrels per day • Expandable to 570,000 barrels per day with pump station modifications • Went into service and began collecting demand charges on the initial committed capacity June (1) 1, 2017 Trunkline Conversion 743 miles of mostly 30” to crude service • Q2 2018 volumes averaged over 470,000 barrels Project Average Asset Cost Contract Delivery Points Project Name Type Miles ($bn) In-service Duration Origin Sites (2) Dakota Access Crude pipelines 1,172 $4.8 June 1, 2017 8.5 yrs Dakota Access Pipeline (1) (2) ETCO Pipeline Crude pipelines 743 Energy Transfer Crude Oil Pipeline Bayou Bridge Pipeline Note: Gross JV project cost where applicable Nederland Terminal (1) 676 miles of converted pipeline + 67 miles of new build 16 (2) Ownership is ETP-~36.37%, MarEn-36.75%, PSXP-25%
CRUDE OIL SEGMENT-CRUDE EXPANSION PROJECTS Permian Crude Projects Permian Express 3 Ø Expected to provide Midland & Delaware Basin producers new crude oil takeaway capacity (utilizing existing pipelines) from this rapidly growing area to multiple markets, including the 26 million barrel ETP Nederland, Texas terminal facility Ø Total PE3 capacity expected to be 140,000 barrels per day (formerly PE3 Phase I) Ø Placed ~100,000 barrels of capacity into-service - Delaware Basin Pipeline in Q4 2017, with remaining capacity expected to - Permian Express 2 & 3 come online in Q4 2018 - Nederland Access Pipeline Ø Completed successful open season for up to - 30” Crude Project¹ 50,000 additional barrels per day, which represents the remaining available capacity on PE3 1 Approximate route of potential new 30” crude pipeline New 30-Inch Crude Pipeline Ø Making significant progress on new 30-inch crude pipeline JV project with Magellan and other strategic shippers Ø Will provide flexibility from the Permian Basin for deliveries to East Houston, and to the significant market and refinery corridor in the Nederland / Beaumont areas Ø Expected to have an initial capacity of ~600,000 barrels per day, expandable to one million barrels per day 17CRUDE OIL SEGMENT-CRUDE EXPANSION PROJECTS Permian Crude Projects Permian Express 3 Ø Expected to provide Midland & Delaware Basin producers new crude oil takeaway capacity (utilizing existing pipelines) from this rapidly growing area to multiple markets, including the 26 million barrel ETP Nederland, Texas terminal facility Ø Total PE3 capacity expected to be 140,000 barrels per day (formerly PE3 Phase I) Ø Placed ~100,000 barrels of capacity into-service - Delaware Basin Pipeline in Q4 2017, with remaining capacity expected to - Permian Express 2 & 3 come online in Q4 2018 - Nederland Access Pipeline Ø Completed successful open season for up to - 30” Crude Project¹ 50,000 additional barrels per day, which represents the remaining available capacity on PE3 1 Approximate route of potential new 30” crude pipeline New 30-Inch Crude Pipeline Ø Making significant progress on new 30-inch crude pipeline JV project with Magellan and other strategic shippers Ø Will provide flexibility from the Permian Basin for deliveries to East Houston, and to the significant market and refinery corridor in the Nederland / Beaumont areas Ø Expected to have an initial capacity of ~600,000 barrels per day, expandable to one million barrels per day 17
CRUDE OIL SEGMENT-BAYOU BRIDGE PIPELINE PROJECT Project Details Bayou Bridge Pipeline Map Ø Joint venture between Phillips 66 Partners (40%) and ETP (60%, operator) Ø 30” Nederland to Lake Charles segment went into service in April 2016 Ø 24” St. James segment expected to be complete in the fourth quarter of 2018 Ø Light and heavy service Ø Project highlights synergistic nature of ETP crude platform and creates additional growth opportunities and market diversification 18CRUDE OIL SEGMENT-BAYOU BRIDGE PIPELINE PROJECT Project Details Bayou Bridge Pipeline Map Ø Joint venture between Phillips 66 Partners (40%) and ETP (60%, operator) Ø 30” Nederland to Lake Charles segment went into service in April 2016 Ø 24” St. James segment expected to be complete in the fourth quarter of 2018 Ø Light and heavy service Ø Project highlights synergistic nature of ETP crude platform and creates additional growth opportunities and market diversification 18
NGL & REFINED PROJECTS SEGMENT: MARINER EAST SYSTEM Ø A comprehensive Marcellus Shale solution reaching local, regional and international markets Ø Will transport Natural Gas Liquids from OH / Western PA to the Marcus Hook Industrial Complex on the East Coast Ø Supported by long-term, fee-based contracts Mariner East 2: Mariner East 1: Mariner East 2x: • Expected to be in initial service end of • Currently in-service for Propane & • Expected to be in-service Q2/Q3 Q3 2018 Ethane transportation, storage & 2019 terminalling services • NGL transportation, storage & • Transportation, storage and terminalling services • Approximate capacity of 70,000 terminalling services for ethane, barrels per day propane, butane, C3+, natural • Capacity of 275,000 barrels per day gasoline, condensate and refined upon full completion, with ability to products expand as needed 19NGL & REFINED PROJECTS SEGMENT: MARINER EAST SYSTEM Ø A comprehensive Marcellus Shale solution reaching local, regional and international markets Ø Will transport Natural Gas Liquids from OH / Western PA to the Marcus Hook Industrial Complex on the East Coast Ø Supported by long-term, fee-based contracts Mariner East 2: Mariner East 1: Mariner East 2x: • Expected to be in initial service end of • Currently in-service for Propane & • Expected to be in-service Q2/Q3 Q3 2018 Ethane transportation, storage & 2019 terminalling services • NGL transportation, storage & • Transportation, storage and terminalling services • Approximate capacity of 70,000 terminalling services for ethane, barrels per day propane, butane, C3+, natural • Capacity of 275,000 barrels per day gasoline, condensate and refined upon full completion, with ability to products expand as needed 19
MIDSTREAM SEGMENT: PERMIAN BASIN INFRASTRUCTURE BUILDOUT Ø ETP is nearing capacity in both the Delaware and Midland Basins due to continued producer demand and strong growth outlook in the Permian Ø As a result of this demand, ETP has continued to build out its Permian infrastructure • Brought 600 mmcf/d of processing capacity online in 2016 and 2017 • Brought 200 mmcf/d Rebel II processing plant online at the end of April 2018 • Expect 200 mmcf/d Arrowhead II processing plant to be placed into service in Q4 2018 20MIDSTREAM SEGMENT: PERMIAN BASIN INFRASTRUCTURE BUILDOUT Ø ETP is nearing capacity in both the Delaware and Midland Basins due to continued producer demand and strong growth outlook in the Permian Ø As a result of this demand, ETP has continued to build out its Permian infrastructure • Brought 600 mmcf/d of processing capacity online in 2016 and 2017 • Brought 200 mmcf/d Rebel II processing plant online at the end of April 2018 • Expect 200 mmcf/d Arrowhead II processing plant to be placed into service in Q4 2018 20
MIDSTREAM SEGMENT: REVOLUTION SYSTEM PROJECT Project Details Revolution Project Map Ø System is located in Pennsylvania’s Marcellus/Upper Devonian Shale rich-gas area Ø Rich-gas, complete solution system Ø Currently 20 miles of 16” in-service Ø Build out assets will include: • 110 miles of 20”, 24” & 30” gathering pipelines • Cryogenic processing plant with de- ethanizer • Natural gas residue pipeline with direct connect to Rover pipeline • Purity ethane pipeline to Mariner East system • C3+ pipeline and storage to Mariner East system • Fractionation facility located at Marcus Hook facility Ø Multiple customers committed to project, • Opportunity to connect Revolution system to Mariner East system to move which include volume commitments and a additional NGL volumes out of the Marcellus / Utica large acreage dedication • Potential to increase product flows to Marcus Hook Ø The Revolution processing plant is complete and will go into full service once Rover has received full approval of the remaining supply 21 lateralsMIDSTREAM SEGMENT: REVOLUTION SYSTEM PROJECT Project Details Revolution Project Map Ø System is located in Pennsylvania’s Marcellus/Upper Devonian Shale rich-gas area Ø Rich-gas, complete solution system Ø Currently 20 miles of 16” in-service Ø Build out assets will include: • 110 miles of 20”, 24” & 30” gathering pipelines • Cryogenic processing plant with de- ethanizer • Natural gas residue pipeline with direct connect to Rover pipeline • Purity ethane pipeline to Mariner East system • C3+ pipeline and storage to Mariner East system • Fractionation facility located at Marcus Hook facility Ø Multiple customers committed to project, • Opportunity to connect Revolution system to Mariner East system to move which include volume commitments and a additional NGL volumes out of the Marcellus / Utica large acreage dedication • Potential to increase product flows to Marcus Hook Ø The Revolution processing plant is complete and will go into full service once Rover has received full approval of the remaining supply 21 laterals
INTERSTATE SEGMENT: MARCELLUS/UTICA ROVER PIPELINE Project Details Rover Project Map Ø Sourcing natural gas from the Marcellus and Utica shales Ø Connectivity to numerous markets in the U.S. and Canada • Midwest: Panhandle Eastern and ANR Pipeline near Defiance, Ohio • Michigan: MichCon, Consumers • Trunkline Zone 1A (via PEPL/Trunkline) • Canada: Union Gas Dawn Hub in Ontario, Canada Ø 712 miles of new pipeline with capacity of 3.25 Bcf/d Ø 3.1 Bcf/d contracted under long-term, fee-based agreements Ø 32.56% owned by ETP / 32.44% owned by Blackstone / 35% owned by Traverse Midstream 1 Partners LLC Timeline Ø Phase IA began natural gas service on August 31, 2017; Phase IB began natural gas service in mid- December 2017 Ø Received FERC approval to place additional Phase II facilities into service, allowing for the full commercial operational capability of the Market North Zone segments Ø 100% of Rover mainline capacity in-service Ø Submitted in-service requests to FERC for Majorsville on May 7, 2018, and Burgettstown on February 13, 2018 Ø Plan to file for Sherwood / CGT laterals by mid-August 2018 22 1) On October 31, 2017, ETP closed on the previously announced sale of a 32.44% equity interest in an entity holding interest in the Rover Pipeline Project to a fund managed by Blackstone Energy Partners. The transaction was structured as a sale of a 49.9% interest in ET Rover Pipeline, an entity that owned a 65% interest in Rover.INTERSTATE SEGMENT: MARCELLUS/UTICA ROVER PIPELINE Project Details Rover Project Map Ø Sourcing natural gas from the Marcellus and Utica shales Ø Connectivity to numerous markets in the U.S. and Canada • Midwest: Panhandle Eastern and ANR Pipeline near Defiance, Ohio • Michigan: MichCon, Consumers • Trunkline Zone 1A (via PEPL/Trunkline) • Canada: Union Gas Dawn Hub in Ontario, Canada Ø 712 miles of new pipeline with capacity of 3.25 Bcf/d Ø 3.1 Bcf/d contracted under long-term, fee-based agreements Ø 32.56% owned by ETP / 32.44% owned by Blackstone / 35% owned by Traverse Midstream 1 Partners LLC Timeline Ø Phase IA began natural gas service on August 31, 2017; Phase IB began natural gas service in mid- December 2017 Ø Received FERC approval to place additional Phase II facilities into service, allowing for the full commercial operational capability of the Market North Zone segments Ø 100% of Rover mainline capacity in-service Ø Submitted in-service requests to FERC for Majorsville on May 7, 2018, and Burgettstown on February 13, 2018 Ø Plan to file for Sherwood / CGT laterals by mid-August 2018 22 1) On October 31, 2017, ETP closed on the previously announced sale of a 32.44% equity interest in an entity holding interest in the Rover Pipeline Project to a fund managed by Blackstone Energy Partners. The transaction was structured as a sale of a 49.9% interest in ET Rover Pipeline, an entity that owned a 65% interest in Rover.
SOLID FINANCIALSSOLID FINANCIALS
PRIMARILY FEE-BASED BUSINESS MIX Stability of Cash Flows Q2 2018 Segment Margin by Segment • Midstream: Approximately 80% fee-based margins from All Other minimum volume commitment, acreage dedication and 3% throughput-based contracts Intrastate 12% • NGL & Refined Products: Transportation revenue from Midstream Fee dedicated capacity and take-or-pay contracts, storage 20% revenues consisting of both storage fees and throughput fees, and fractionation fees, which are primarily frac-or- pay structures Interstate Midstream Non‐Fee • Interstate Transportation & Storage: Approximately 14% 6% 95% firm reservation charges based on amount of firm capacity reserved, regardless of usage • Crude Oil: Primarily fee-based revenues derived from the transporting and terminalling of crude oil • Intrastate: Primarily fixed-fee reservation charges, NGL & Refined transport fees based on actual throughput, and storage Crude Products fees 19% 26% 24PRIMARILY FEE-BASED BUSINESS MIX Stability of Cash Flows Q2 2018 Segment Margin by Segment • Midstream: Approximately 80% fee-based margins from All Other minimum volume commitment, acreage dedication and 3% throughput-based contracts Intrastate 12% • NGL & Refined Products: Transportation revenue from Midstream Fee dedicated capacity and take-or-pay contracts, storage 20% revenues consisting of both storage fees and throughput fees, and fractionation fees, which are primarily frac-or- pay structures Interstate Midstream Non‐Fee • Interstate Transportation & Storage: Approximately 14% 6% 95% firm reservation charges based on amount of firm capacity reserved, regardless of usage • Crude Oil: Primarily fee-based revenues derived from the transporting and terminalling of crude oil • Intrastate: Primarily fixed-fee reservation charges, NGL & Refined transport fees based on actual throughput, and storage Crude Products fees 19% 26% 24
STRONG FOCUS ON THE BALANCE SHEET AND LIQUIDITY POSITION Improving leverage metrics Focus on liquidity and the balance sheet Ø Liquidity update: Further • On December 1, 2017, the Partnership entered into a new $4 deleveraging 1 billion 5-year revolving credit facility, and $1 billion 364-day Debt/Adjusted EBITDA expected credit facility to replace the legacy ETP and legacy SXL credit driven by facilities 1 EBITDA 5.54x growth Ø Recent credit-supportive strategic actions: 5.40x • In November 2017, ETP raised $1.48 billion through Series A 4.81x and Series B Perpetual Preferred Units. These securities 4.45x 4.27x received 50% equity treatment from all three ratings agencies 4.13x 2 4.00x • On February 7, 2018, SUN repurchased approximately 17.3 million SUN common units owned by ETP for approximately $540 million. ETP used the proceeds to repay amounts outstanding under its revolving credit facility • On April 2, 2018, ETP sold its CDM compression business to USA Compression Partners (USAC) for $1.232 billion in cash, 19.2 million USAC common units, and 6.4 million USAC Class B units • In April 2018, ETP issued $450 million of its 7.375% Series C Perpetual Preferred Units. These securities received 50% equity treatment from all three ratings agencies • In July 2018, ETP issued $445 million of its 7.625% Series D Perpetual Preferred Units. These securities also received 50% equity treatment from all three ratings agencies 25 1 EBITDA and Adjusted EBITDA represents ETP consolidated on a last quarter annualized basis. See reconciliation of non-GAAP measures in the Appendix to this presentation. 2 Pro forma for Class C unit offering and cash proceeds from USAC transaction, debt/adjusted EBITDA would have been 4.23xSTRONG FOCUS ON THE BALANCE SHEET AND LIQUIDITY POSITION Improving leverage metrics Focus on liquidity and the balance sheet Ø Liquidity update: Further • On December 1, 2017, the Partnership entered into a new $4 deleveraging 1 billion 5-year revolving credit facility, and $1 billion 364-day Debt/Adjusted EBITDA expected credit facility to replace the legacy ETP and legacy SXL credit driven by facilities 1 EBITDA 5.54x growth Ø Recent credit-supportive strategic actions: 5.40x • In November 2017, ETP raised $1.48 billion through Series A 4.81x and Series B Perpetual Preferred Units. These securities 4.45x 4.27x received 50% equity treatment from all three ratings agencies 4.13x 2 4.00x • On February 7, 2018, SUN repurchased approximately 17.3 million SUN common units owned by ETP for approximately $540 million. ETP used the proceeds to repay amounts outstanding under its revolving credit facility • On April 2, 2018, ETP sold its CDM compression business to USA Compression Partners (USAC) for $1.232 billion in cash, 19.2 million USAC common units, and 6.4 million USAC Class B units • In April 2018, ETP issued $450 million of its 7.375% Series C Perpetual Preferred Units. These securities received 50% equity treatment from all three ratings agencies • In July 2018, ETP issued $445 million of its 7.625% Series D Perpetual Preferred Units. These securities also received 50% equity treatment from all three ratings agencies 25 1 EBITDA and Adjusted EBITDA represents ETP consolidated on a last quarter annualized basis. See reconciliation of non-GAAP measures in the Appendix to this presentation. 2 Pro forma for Class C unit offering and cash proceeds from USAC transaction, debt/adjusted EBITDA would have been 4.23x
ETE ACQUISITION OF ETP OVERVIEWETE ACQUISITION OF ETP OVERVIEW
TRANSACTION OVERVIEW · Energy Transfer Equity, LP (“ETE”) and Energy Transfer Partners, LP (“ETP”) have entered into a merger agreement providing for the acquisition of ETP by ETE for $27 billion in ETE units – 1.280x ETE common units for each public ETP common unit, implying a price of $23.59 per unit based on ETE’s closing price immediately prior to the announcement of the transaction – Represents an 11% premium to the previous day’s ETP closing price and a 15% premium to 10-day VWAP · Transaction expected to be immediately accretive to ETE’s distributable cash flow per unit · Expect to maintain ETE distribution per unit and significantly increase cash coverage and retained cash flow · ETP unitholders to benefit from stronger pro forma cash distribution coverage and reduced cost of capital · Expect the pro forma partnership to receive investment-grade credit ratings · ETP’s incentive distribution rights will be eliminated · Transaction subject to customary approvals, including the approval by a majority of the unaffiliated ETP unitholders – ETE filed its registration statement on Form S-4 with the SEC on August 14, 2018 – The transaction is expected to close in Q4 2018 27TRANSACTION OVERVIEW · Energy Transfer Equity, LP (“ETE”) and Energy Transfer Partners, LP (“ETP”) have entered into a merger agreement providing for the acquisition of ETP by ETE for $27 billion in ETE units – 1.280x ETE common units for each public ETP common unit, implying a price of $23.59 per unit based on ETE’s closing price immediately prior to the announcement of the transaction – Represents an 11% premium to the previous day’s ETP closing price and a 15% premium to 10-day VWAP · Transaction expected to be immediately accretive to ETE’s distributable cash flow per unit · Expect to maintain ETE distribution per unit and significantly increase cash coverage and retained cash flow · ETP unitholders to benefit from stronger pro forma cash distribution coverage and reduced cost of capital · Expect the pro forma partnership to receive investment-grade credit ratings · ETP’s incentive distribution rights will be eliminated · Transaction subject to customary approvals, including the approval by a majority of the unaffiliated ETP unitholders – ETE filed its registration statement on Form S-4 with the SEC on August 14, 2018 – The transaction is expected to close in Q4 2018 27
STRATEGIC RATIONALE • Transaction will simplify Energy Transfer’s corporate structure SIMPLIFIES OWNERSHIP • Further aligns economic interests within the Energy Transfer family STRUCTURE • Responsive to investor sentiment regarding structural evolution of midstream sector ELIMINATES IDR • Removing the growing IDR burden for ETP will reduce the cost of equity for the combined entity BURDEN AND IMPROVES COST • Improved cost of capital promotes the ability to compete for organic growth and strategic opportunities OF CAPITAL • Increases retained cash flow to accelerate deleveraging INCREASES RETAINED CASH – ETE pro forma expected to generate $2.5 – $3.0 billion of excess retained cash flow per annum FLOW AND – Reduces common and preferred equity funding needs ENHANCES CREDIT PROFILE • Expect the pro forma partnership to receive investment-grade credit ratings • Increased distribution coverage provides distribution stability and long-term growth prospects LONGER-TERM DISTRIBUTION – ~1.6x – 1.9x pro forma distribution coverage ratio enhances funding optionality and reduces SUSTAINABILITY reliance on capital markets 28STRATEGIC RATIONALE • Transaction will simplify Energy Transfer’s corporate structure SIMPLIFIES OWNERSHIP • Further aligns economic interests within the Energy Transfer family STRUCTURE • Responsive to investor sentiment regarding structural evolution of midstream sector ELIMINATES IDR • Removing the growing IDR burden for ETP will reduce the cost of equity for the combined entity BURDEN AND IMPROVES COST • Improved cost of capital promotes the ability to compete for organic growth and strategic opportunities OF CAPITAL • Increases retained cash flow to accelerate deleveraging INCREASES RETAINED CASH – ETE pro forma expected to generate $2.5 – $3.0 billion of excess retained cash flow per annum FLOW AND – Reduces common and preferred equity funding needs ENHANCES CREDIT PROFILE • Expect the pro forma partnership to receive investment-grade credit ratings • Increased distribution coverage provides distribution stability and long-term growth prospects LONGER-TERM DISTRIBUTION – ~1.6x – 1.9x pro forma distribution coverage ratio enhances funding optionality and reduces SUSTAINABILITY reliance on capital markets 28
ILLUSTRATIVE TRANSACTION STRUCTURE – ETE acquires all of the outstanding ETP common units 1 (excluding units owned by ETE or its subsidiaries) in a unit-for-unit exchange at a fixed exchange ratio of 1.280x LE GP Management / Public ETE Insider Unitholders 2 • ETP debt and preferred equity remain in place 2 – The general partner of ETE will be issued new Class A 1 units of ETE such that the general partner and its Energy Transfer affiliates will retain their current voting interest in ETE Equity Public ETP (NYSE: ETE) Unitholders • The Class A units will not be entitled to cash distributions and otherwise have no economic 3 attributes Energy ETP Preferred Transfer ETP Bondholders • The Class A units are not convertible or Equityholders Partners exchangeable for ETE common units (NYSE: ETP) 3 – ETE expects to refinance its term loan and revolver at which point its senior notes become unsecured • No change of control triggered in ETE’s existing notes 29ILLUSTRATIVE TRANSACTION STRUCTURE – ETE acquires all of the outstanding ETP common units 1 (excluding units owned by ETE or its subsidiaries) in a unit-for-unit exchange at a fixed exchange ratio of 1.280x LE GP Management / Public ETE Insider Unitholders 2 • ETP debt and preferred equity remain in place 2 – The general partner of ETE will be issued new Class A 1 units of ETE such that the general partner and its Energy Transfer affiliates will retain their current voting interest in ETE Equity Public ETP (NYSE: ETE) Unitholders • The Class A units will not be entitled to cash distributions and otherwise have no economic 3 attributes Energy ETP Preferred Transfer ETP Bondholders • The Class A units are not convertible or Equityholders Partners exchangeable for ETE common units (NYSE: ETP) 3 – ETE expects to refinance its term loan and revolver at which point its senior notes become unsecured • No change of control triggered in ETE’s existing notes 29
ENHANCED PRO FORMA BALANCE SHEET AND LIQUIDITY POSITION CONSERVATIVE AND FLEXIBLE FINANCIAL POLICY DEBT EXCHANGE OVERVIEW · Expect to maintain ETE distribution per unit at current level · Meaningfully higher retained cash flow to drive further deleveraging Refinance Term Loan and Revolver Term loan / Credit - ~$2.5 – $3.0 billion per year of distribution coverage Facility Lenders Energy Transfer expected Equity (NYSE: ETE) - ~1.6x – 1.9x expected coverage ratio · Expect to fund majority of growth capex with retained cash ETE expects to flow make exchange offer of ETE Notes into ETP · Target leverage metrics consistent with strong investment Notes grade ratings Energy · Ample liquidity through $5 billion credit facility to provide Transfer balance sheet flexibility Partners (NYSE: ETP) SIMPLIFIED FINANCIAL STRUCTURE STRENGTHENS BALANCE SHEET AND CREDIT PROFILE AND POSITIONS THE COMPANY FOR FUTURE GROWTH 30ENHANCED PRO FORMA BALANCE SHEET AND LIQUIDITY POSITION CONSERVATIVE AND FLEXIBLE FINANCIAL POLICY DEBT EXCHANGE OVERVIEW · Expect to maintain ETE distribution per unit at current level · Meaningfully higher retained cash flow to drive further deleveraging Refinance Term Loan and Revolver Term loan / Credit - ~$2.5 – $3.0 billion per year of distribution coverage Facility Lenders Energy Transfer expected Equity (NYSE: ETE) - ~1.6x – 1.9x expected coverage ratio · Expect to fund majority of growth capex with retained cash ETE expects to flow make exchange offer of ETE Notes into ETP · Target leverage metrics consistent with strong investment Notes grade ratings Energy · Ample liquidity through $5 billion credit facility to provide Transfer balance sheet flexibility Partners (NYSE: ETP) SIMPLIFIED FINANCIAL STRUCTURE STRENGTHENS BALANCE SHEET AND CREDIT PROFILE AND POSITIONS THE COMPANY FOR FUTURE GROWTH 30
ETE CLASS A UNIT OVERVIEW – Under the ETE partnership agreement, the general partner of ETE, LE GP, has a contractual right to purchase common units from ETE whenever ETE issues common units so that LE GP can maintain its and its affiliates’ collective equity interest percentage in ETE – LE GP and its affiliates currently own approximately 31.0% of the outstanding ETE common units, and following the merger, would own approximately 13.5% of the outstanding ETE common units if it did not exercise its preemptive rights – In connection with the ETP merger, LE GP will agree to waive its preemptive right to purchase additional ETE common units as partial consideration for the issuance of a new series of Class A units to LE GP – Summary terms of Class A units • Represent limited partner interest in ETE that will not be entitled to any cash distributions and will have no other economic attributes • Class A units will be entitled to one vote per Class A unit and will vote together with ETE common units as a single class • The number of Class A Units issued to LE GP will be such that LE GP and its affiliates will maintain their combined current voting interest in ETE following the issuance of ETE common units in the merger • For as long as Kelcy Warren continues as a director or officer of LE GP, upon issuance of additional common units following the closing of the merger, ETE will issue additional Class A Units to LE GP such that the Class A Units will continue to represent, in the aggregate, the same voting interest as they represent upon the closing of the merger 31ETE CLASS A UNIT OVERVIEW – Under the ETE partnership agreement, the general partner of ETE, LE GP, has a contractual right to purchase common units from ETE whenever ETE issues common units so that LE GP can maintain its and its affiliates’ collective equity interest percentage in ETE – LE GP and its affiliates currently own approximately 31.0% of the outstanding ETE common units, and following the merger, would own approximately 13.5% of the outstanding ETE common units if it did not exercise its preemptive rights – In connection with the ETP merger, LE GP will agree to waive its preemptive right to purchase additional ETE common units as partial consideration for the issuance of a new series of Class A units to LE GP – Summary terms of Class A units • Represent limited partner interest in ETE that will not be entitled to any cash distributions and will have no other economic attributes • Class A units will be entitled to one vote per Class A unit and will vote together with ETE common units as a single class • The number of Class A Units issued to LE GP will be such that LE GP and its affiliates will maintain their combined current voting interest in ETE following the issuance of ETE common units in the merger • For as long as Kelcy Warren continues as a director or officer of LE GP, upon issuance of additional common units following the closing of the merger, ETE will issue additional Class A Units to LE GP such that the Class A Units will continue to represent, in the aggregate, the same voting interest as they represent upon the closing of the merger 31
KEY TAKEAWAYS • Diversified business model, together with the geographical diversity of our assets, continues to Business allow our businesses to demonstrate resiliency. The underlying fundamentals of our business Diversity are strong and we believe we are in a great position for growth • Nearing the conclusion of major project backlog spend, and continue to foresee significant Capex EBITDA growth in 2018 from the completion of these projects Program • The majority of these projects are backed by long-term, fee-based contracts Balance • Will remain prudent as it relates to the balance sheet, lowering leverage and increasing coverage and liquidity Sheet Family • Energy Transfer Equity, LP (“ETE”) and Energy Transfer Partners, LP (“ETP”) have entered into a Structure merger agreement providing for the acquisition of ETP by ETE for $27 billion in ETE units • Expect to maintain ETE distribution per unit, and significantly increase cash coverage and retained Distribution cash flow post closing of the merger of ETE and ETP TRANSACTION CREATES ~$90 BILLION ENTERPRISE UNDER A SIMPLIFIED STRUCTURE WITH ENHANCED FINANCIAL FLEXIBILITY AND LOWER COST OF CAPITAL 32KEY TAKEAWAYS • Diversified business model, together with the geographical diversity of our assets, continues to Business allow our businesses to demonstrate resiliency. The underlying fundamentals of our business Diversity are strong and we believe we are in a great position for growth • Nearing the conclusion of major project backlog spend, and continue to foresee significant Capex EBITDA growth in 2018 from the completion of these projects Program • The majority of these projects are backed by long-term, fee-based contracts Balance • Will remain prudent as it relates to the balance sheet, lowering leverage and increasing coverage and liquidity Sheet Family • Energy Transfer Equity, LP (“ETE”) and Energy Transfer Partners, LP (“ETP”) have entered into a Structure merger agreement providing for the acquisition of ETP by ETE for $27 billion in ETE units • Expect to maintain ETE distribution per unit, and significantly increase cash coverage and retained Distribution cash flow post closing of the merger of ETE and ETP TRANSACTION CREATES ~$90 BILLION ENTERPRISE UNDER A SIMPLIFIED STRUCTURE WITH ENHANCED FINANCIAL FLEXIBILITY AND LOWER COST OF CAPITAL 32
APPENDIXAPPENDIX
CRUDE OIL SEGMENT Crude Oil Pipelines Crude Oil Acquisition & Marketing Ø ~9,360 miles of crude oil trunk and gathering lines located in the Southwest and Ø Crude truck fleet of approximately 370 trucks Midwest United States Ø Purchase crude at the wellhead from ~3,000 producers Ø Controlling interest in 3 crude oil pipeline systems in bulk from aggregators at major pipeline • Bakken Pipeline (~36.37%) interconnections and trading locations • Bayou Bridge Pipeline (60%)Ø Marketing crude oil to major pipeline interconnections and trading locations • Permian Express Partners (~88%) Ø Marketing crude oil to major, integrated oil companies, independent refiners and resellers through various types of sale and exchange transactions Ø Storing inventory during contango market conditions Crude Oil Terminals Ø Nederland, TX Crude Terminal - ~26 million barrel capacity Ø Northeast Crude Terminals - ~3 million barrel capacity Ø Midland, TX Crude Terminal - ~2 million barrel capacity ETP Opportunities Ø Delaware Basin Pipeline has ability to expand by 100 mbpd • Evaluating Permian Express 4 Expansion Project (formerly PE3 Phase II) • Aggressively pursuing larger project to move barrels from the Permian Basin to Nederland Midland Nederland 34CRUDE OIL SEGMENT Crude Oil Pipelines Crude Oil Acquisition & Marketing Ø ~9,360 miles of crude oil trunk and gathering lines located in the Southwest and Ø Crude truck fleet of approximately 370 trucks Midwest United States Ø Purchase crude at the wellhead from ~3,000 producers Ø Controlling interest in 3 crude oil pipeline systems in bulk from aggregators at major pipeline • Bakken Pipeline (~36.37%) interconnections and trading locations • Bayou Bridge Pipeline (60%)Ø Marketing crude oil to major pipeline interconnections and trading locations • Permian Express Partners (~88%) Ø Marketing crude oil to major, integrated oil companies, independent refiners and resellers through various types of sale and exchange transactions Ø Storing inventory during contango market conditions Crude Oil Terminals Ø Nederland, TX Crude Terminal - ~26 million barrel capacity Ø Northeast Crude Terminals - ~3 million barrel capacity Ø Midland, TX Crude Terminal - ~2 million barrel capacity ETP Opportunities Ø Delaware Basin Pipeline has ability to expand by 100 mbpd • Evaluating Permian Express 4 Expansion Project (formerly PE3 Phase II) • Aggressively pursuing larger project to move barrels from the Permian Basin to Nederland Midland Nederland 34
CRUDE OIL SEGMENT - PERMIAN EXPRESS PARTNERS Permian Express Partners Joint Venture Details Ø Strategic joint venture with ExxonMobil (ETP owns ~88% and is the operator) Ø Combines key crude oil pipeline network of both companies and aligns ETP’s Permian takeaway assets with ExxonMobil’s crude pipeline network 35CRUDE OIL SEGMENT - PERMIAN EXPRESS PARTNERS Permian Express Partners Joint Venture Details Ø Strategic joint venture with ExxonMobil (ETP owns ~88% and is the operator) Ø Combines key crude oil pipeline network of both companies and aligns ETP’s Permian takeaway assets with ExxonMobil’s crude pipeline network 35
NGL & REFINED PRODUCTS SEGMENT NGL Storage Fractionation NGL Pipeline Transportation Ø TET Mont Belvieu Storage Hub ~50 million Ø 4 Mont Belvieu fractionators (420+ Mbpd)Ø ~4,300 miles of NGL Pipelines throughout Texas and barrels NGL storage, ~600 Mbpd throughput Northeast Ø 40 Mbpd King Ranch, 25 Mbpd Geismar Ø 3 million barrel Mont Belvieu cavern under Ø ~ 1,300 Mbpd of raw make transport capacity in Texas Ø 50 Mbpd Houston DeEthanizer and 30 to 50 development Mbpd Marcus Hook C3+ Frac in service Q4 Ø ~ 1,130 Mbpd of purity NGL pipeline capacity Ø ~7 million barrels of NGL storage at Marcus 2017 Ø 732 Mbpd on the Gulf Coast Hook, Nederland and Inkster Ø 120 Mbpd Frac V in-service July 2018 Ø 398 Mbpd in the Northeast Ø Hattiesburg Butane Storage ~3 million Ø 140 Mbpd Frac VI in-service Q2 2019 barrels Mariner Franchise Ø ~200 Mbpd Mariner South LPG from Mont Belvieu to Nederland Ø 50 Mbpd Mariner West ethane to Canada Ø 70 Mbpd ME1 ethane and propane to Marcus Hook (1) Ø 275 Mbpd ME2 NGLs to Marcus Hook (Initial in- service Q3 2018) Ø ME2X expected in-service Q2/Q3 2019 Marcus Hook Refined Products Ø ~2,200 miles of refined products pipelines in the northeast, Midwest and southwest US markets Ø 40 refined products marketing terminals with 8 million barrels storage capacity Mont Belvieu Nederland 36 (1) Upon full completionNGL & REFINED PRODUCTS SEGMENT NGL Storage Fractionation NGL Pipeline Transportation Ø TET Mont Belvieu Storage Hub ~50 million Ø 4 Mont Belvieu fractionators (420+ Mbpd)Ø ~4,300 miles of NGL Pipelines throughout Texas and barrels NGL storage, ~600 Mbpd throughput Northeast Ø 40 Mbpd King Ranch, 25 Mbpd Geismar Ø 3 million barrel Mont Belvieu cavern under Ø ~ 1,300 Mbpd of raw make transport capacity in Texas Ø 50 Mbpd Houston DeEthanizer and 30 to 50 development Mbpd Marcus Hook C3+ Frac in service Q4 Ø ~ 1,130 Mbpd of purity NGL pipeline capacity Ø ~7 million barrels of NGL storage at Marcus 2017 Ø 732 Mbpd on the Gulf Coast Hook, Nederland and Inkster Ø 120 Mbpd Frac V in-service July 2018 Ø 398 Mbpd in the Northeast Ø Hattiesburg Butane Storage ~3 million Ø 140 Mbpd Frac VI in-service Q2 2019 barrels Mariner Franchise Ø ~200 Mbpd Mariner South LPG from Mont Belvieu to Nederland Ø 50 Mbpd Mariner West ethane to Canada Ø 70 Mbpd ME1 ethane and propane to Marcus Hook (1) Ø 275 Mbpd ME2 NGLs to Marcus Hook (Initial in- service Q3 2018) Ø ME2X expected in-service Q2/Q3 2019 Marcus Hook Refined Products Ø ~2,200 miles of refined products pipelines in the northeast, Midwest and southwest US markets Ø 40 refined products marketing terminals with 8 million barrels storage capacity Mont Belvieu Nederland 36 (1) Upon full completion
MIDSTREAM ASSETS Midstream Asset Map Midstream Highlights Ø Volume growth in key regions: • Q1 2018 gathered volumes averaged ~11.3 million mmbtu/d, and NGLs produced were ~503,000 bbls/d, both up over Q1 2017 Ø Permian Capacity Additions: • 200 MMcf/d Panther processing plant in the Midland Basin PA came online in January 2017 OH • 200 MMcf/d Arrowhead processing plant in the Delaware MD Basin came online early Q3 2017 WV • 200 MMcf/d Rebel II processing plant came online in April 2018 • Due to continued strong demand in the Permian, nearing capacity in both the Delaware and Midland basins • Expect 200 MMcf/d Arrowhead II processing plant to come online in Q4 2018 Current Processing Capacity Bcf/d Basins Served Permian 2.1 Permian, Midland, Delaware Midcontinent/Panhandle 0.9 Granite Wash, Cleveland North Texas 0.7 Barnett, Woodford South Texas 1.9 Eagle Ford North Louisiana 1.0 Haynesville, Cotton Valley Southeast Texas 0.4 Eagle Ford, Eagle Bine Eastern - Marcellus Utica 37 More than 40,000 miles of gathering pipelines with ~ 7.1 Bcf/d of processing capacityMIDSTREAM ASSETS Midstream Asset Map Midstream Highlights Ø Volume growth in key regions: • Q1 2018 gathered volumes averaged ~11.3 million mmbtu/d, and NGLs produced were ~503,000 bbls/d, both up over Q1 2017 Ø Permian Capacity Additions: • 200 MMcf/d Panther processing plant in the Midland Basin PA came online in January 2017 OH • 200 MMcf/d Arrowhead processing plant in the Delaware MD Basin came online early Q3 2017 WV • 200 MMcf/d Rebel II processing plant came online in April 2018 • Due to continued strong demand in the Permian, nearing capacity in both the Delaware and Midland basins • Expect 200 MMcf/d Arrowhead II processing plant to come online in Q4 2018 Current Processing Capacity Bcf/d Basins Served Permian 2.1 Permian, Midland, Delaware Midcontinent/Panhandle 0.9 Granite Wash, Cleveland North Texas 0.7 Barnett, Woodford South Texas 1.9 Eagle Ford North Louisiana 1.0 Haynesville, Cotton Valley Southeast Texas 0.4 Eagle Ford, Eagle Bine Eastern - Marcellus Utica 37 More than 40,000 miles of gathering pipelines with ~ 7.1 Bcf/d of processing capacity
INTERSTATE PIPELINE ASSETS Interstate Asset Map Interstate Highlights Our interstate pipelines provide: Ø Stability • Approximately 95% of revenue is derived from fixed reservation fees Ø Diversity Rover • Access to multiple shale plays, storage facilities and markets Trunkline Ø Growth Opportunities Transwestern Fayetteville Express • Well positioned to capitalize on changing supply and demand dynamics Gulf States Florida Gas Transmission Tiger • Expect earnings to pick up once Rover is in service Sea Robin • In addition, expect to receive significant revenues from backhaul capabilities on Panhandle and Trunkline Gulf (1) (2) PEPL TGC TW FGT SR FEP Tiger MEP States Rover Total Miles of Pipeline 5,980 2,220 2,570 5,360 830 185 195 500 10 713 18,563 Capacity (Bcf/d) 2.8 0.9 2.1 3.1 2.0 2.0 2.4 1.8 0.1 3.3 20.5 OwnedStorage (Bcf)83.9 13 -------- ------ -- 96.9 Ownership 100% 100% 100% 50% 100% 50% 100% 50% 100% 32.6% ~18,600 miles of interstate pipelines with ~21Bcf/d of throughput capacity currently in-service 38 (1) After abandonment of 30” line being connected to crude service (2) 100% of mainline capacity in-service. Request has been submitted to FERC to place additional facilities into serviceINTERSTATE PIPELINE ASSETS Interstate Asset Map Interstate Highlights Our interstate pipelines provide: Ø Stability • Approximately 95% of revenue is derived from fixed reservation fees Ø Diversity Rover • Access to multiple shale plays, storage facilities and markets Trunkline Ø Growth Opportunities Transwestern Fayetteville Express • Well positioned to capitalize on changing supply and demand dynamics Gulf States Florida Gas Transmission Tiger • Expect earnings to pick up once Rover is in service Sea Robin • In addition, expect to receive significant revenues from backhaul capabilities on Panhandle and Trunkline Gulf (1) (2) PEPL TGC TW FGT SR FEP Tiger MEP States Rover Total Miles of Pipeline 5,980 2,220 2,570 5,360 830 185 195 500 10 713 18,563 Capacity (Bcf/d) 2.8 0.9 2.1 3.1 2.0 2.0 2.4 1.8 0.1 3.3 20.5 OwnedStorage (Bcf)83.9 13 -------- ------ -- 96.9 Ownership 100% 100% 100% 50% 100% 50% 100% 50% 100% 32.6% ~18,600 miles of interstate pipelines with ~21Bcf/d of throughput capacity currently in-service 38 (1) After abandonment of 30” line being connected to crude service (2) 100% of mainline capacity in-service. Request has been submitted to FERC to place additional facilities into service
INTRASTATE PIPELINE ASSETS Intrastate Asset Map Intrastate Highlights Ø Continue to expect volumes to Mexico to grow, particularly with the startup of Trans-Pecos and Comanche Trail in Q1 2017, which will result in increased demand for transport services through ETP’s existing pipeline network rd Ø Have seen an increase in 3 party activity on both of these pipes, mostly via backhaul services being provided to the Trans-Pecos header Ø Well positioned to capture additional revenues from anticipated changes in natural gas supply and demand in the next five years Ø Red Bluff Express Pipeline connects the Orla Plant, as well as rd 3 party plants, to the Waha Oasis Header, and went into service in Q2 2018 Ø An expansion to Red Bluff Express is expected online in 2H 2019 In Service Capacity Pipeline Storage Bi‐Directional Major Connect (Bcf/d) (Miles) Capacity (Bcf) Capabilities Hubs Trans Pecos & Comanche Waha Header, • ~ 8,700 miles of intrastate pipelines 2.5 338 NA No Trail Pipelines Mexico Border Waha, Katy, ET Fuel Pipeline 5.2 2,780 11.2 Yes • ~20 Bcf/d of throughput capacity Carthage Oasis Pipeline 1.2 750 NA Yes Waha, Katy HSC, Katy, Houston Pipeline System 5.3 3,920 52.5 No Aqua Dulce ETC Katy Pipeline 2.4 460 NA No Katy Union Power, 1 RIGS 2.1 450 NA No LA Tech Red Bluff Express 1.4 100 NA No Waha 39 (1) ETP owns a 49.99% general partnership interestINTRASTATE PIPELINE ASSETS Intrastate Asset Map Intrastate Highlights Ø Continue to expect volumes to Mexico to grow, particularly with the startup of Trans-Pecos and Comanche Trail in Q1 2017, which will result in increased demand for transport services through ETP’s existing pipeline network rd Ø Have seen an increase in 3 party activity on both of these pipes, mostly via backhaul services being provided to the Trans-Pecos header Ø Well positioned to capture additional revenues from anticipated changes in natural gas supply and demand in the next five years Ø Red Bluff Express Pipeline connects the Orla Plant, as well as rd 3 party plants, to the Waha Oasis Header, and went into service in Q2 2018 Ø An expansion to Red Bluff Express is expected online in 2H 2019 In Service Capacity Pipeline Storage Bi‐Directional Major Connect (Bcf/d) (Miles) Capacity (Bcf) Capabilities Hubs Trans Pecos & Comanche Waha Header, • ~ 8,700 miles of intrastate pipelines 2.5 338 NA No Trail Pipelines Mexico Border Waha, Katy, ET Fuel Pipeline 5.2 2,780 11.2 Yes • ~20 Bcf/d of throughput capacity Carthage Oasis Pipeline 1.2 750 NA Yes Waha, Katy HSC, Katy, Houston Pipeline System 5.3 3,920 52.5 No Aqua Dulce ETC Katy Pipeline 2.4 460 NA No Katy Union Power, 1 RIGS 2.1 450 NA No LA Tech Red Bluff Express 1.4 100 NA No Waha 39 (1) ETP owns a 49.99% general partnership interest
INTRASTATE SEGMENT: MEXICO (CFE) Waha Header System Ø 6 Bcf/d Header System Ø Will connect to: • Trans-Pecos & Comanche Trail Pipelines • ETP’s vast interstate and intrastate pipeline network Comanche Trail Pipeline rd • Multiple 3 party pipelines Ø ~195 miles of 42” intrastate natural gas pipeline from Waha header to Mexico border Ø Capacity of 1.135 Bcf/d Ø Markets: Interconnect with San Isidro Pipeline at US-Mexico border Ø ETP Ownership:16% Ø In-Service: Q1 2017 Trans-Pecos Pipeline Ø 143 miles of 42” intrastate natural gas pipeline and header system Ø Capacity of 1.356 Bcf/d Ø Markets: Interconnect with Mexico’s 42” Ojinaga Pipeline at US-Mexico border Ø ETP Ownership:16% Ø In-Service: Q1 2017 40INTRASTATE SEGMENT: MEXICO (CFE) Waha Header System Ø 6 Bcf/d Header System Ø Will connect to: • Trans-Pecos & Comanche Trail Pipelines • ETP’s vast interstate and intrastate pipeline network Comanche Trail Pipeline rd • Multiple 3 party pipelines Ø ~195 miles of 42” intrastate natural gas pipeline from Waha header to Mexico border Ø Capacity of 1.135 Bcf/d Ø Markets: Interconnect with San Isidro Pipeline at US-Mexico border Ø ETP Ownership:16% Ø In-Service: Q1 2017 Trans-Pecos Pipeline Ø 143 miles of 42” intrastate natural gas pipeline and header system Ø Capacity of 1.356 Bcf/d Ø Markets: Interconnect with Mexico’s 42” Ojinaga Pipeline at US-Mexico border Ø ETP Ownership:16% Ø In-Service: Q1 2017 40
ETP NON-GAAP FINANCIAL MEASURES 41ETP NON-GAAP FINANCIAL MEASURES 41
ETP NON-GAAP FINANCIAL MEASURES Segment Margin is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment Margin is similar to the GAAP measure of gross margin, except that Segment Margin excludes charges for depreciation, depletion and amortization. Following is a reconciliation of Segment Margin to operating income, as reported in the Partnership’s consolidated statements of operations: 42ETP NON-GAAP FINANCIAL MEASURES Segment Margin is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment Margin is similar to the GAAP measure of gross margin, except that Segment Margin excludes charges for depreciation, depletion and amortization. Following is a reconciliation of Segment Margin to operating income, as reported in the Partnership’s consolidated statements of operations: 42
ETE NON-GAAP FINANCIAL MEASURES 2016 2017 2018 Full Year Q1 Q2 Q3 Q4 YTD Q1 Q2 YTD Net income attributable to partners $ 995 $ 239 $ 212 $ 252 $ 251 $ 954 $ 3 63 $ 355 $ 718 Equity in earnings related to investments in ETP, Sunoco LP and USAC (1,374) (325) (273) (310) (335) (1,243) (414) (420) (834) Total cash distributions from investments in subsidiaries 1,459 262 284 317 311 1,174 443 454 897 Amortization included in interest expense (excluding ETP, Sunoco LP and USAC) 12 23 22 9 2 35 Lake Charles LNG maintenance capital expenditures — — — (1) (1) (2) — — — Other non-cash (excluding ETP, Sunoco LP and USAC) 56 34 10 10 34 88 6 11 17 Distributable Cash Flow 1,148 212 236 270 262 980 400 403 803 Transaction-related expenses 59 3 4 1 1 9 (5) 4 (1) Distributable Cash Flow, as adjusted $ 1,207 $ 215 $ 240 $ 271 $ 263 $ 989 $ 3 95 $ 407 $ 802 Total cash distributions to be paid to the partners of ETE 974 251 251 257 266 1025 266 354 620 Distribution coverage ratio 1.24x 0.86x 0.96x 1.05x 0.99x 0.96x 1.48x 1.15x 1.29x Distributable Cash Flow and Distributable Cash Flow, as adjusted. The Partnership defines Distributable Cash Flow and Distributable Cash Flow, as adjusted, for a period as cash distributions expected to be received in respect of such period in connection with the Partnership’s investments in limited and general partner interests, net of the Partnership’s cash expenditures for general and administrative costs and interest expense. The Partnership’s definitions of Distributable Cash Flow and Distributable Cash Flow, as adjusted, also include distributable cash flow from Lake Charles LNG to the Partnership. For Distributable Cash Flow, as adjusted, certain transaction-related expenses that are included in net income are excluded. Distributable Cash Flow is a significant liquidity measure used by the Partnership’s senior management to compare net cash flows generated by the Partnership to the distributions the Partnership expects to pay its unitholders. Due to cash expenses incurred from time to time in connection with the Partnership’s merger and acquisition activities and other transactions, Distributable Cash Flow, as adjusted, is also a significant liquidity measure used by the Partnership’s senior management to compare net cash flows generated by the Partnership to the distributions the Partnership expects to pay its unitholders. Using these measures, the Partnership’s management can compute the coverage ratio of estimated cash flows for a period to planned cash distributions for such period. Distributable Cash Flow and Distributable Cash Flow, as adjusted, are also important non-GAAP financial measures for our limited partners since these indicate to investors whether the Partnership’s investments are generating cash flows at a level that can sustain or support an increase in quarterly cash distribution levels. Financial measures such as Distributable Cash Flow and Distributable Cash Flow, as adjusted, are quantitative standards used by the investment community with respect to publicly traded partnerships because the value of a partnership unit is in part measured by its yield (which in turn is based on the amount of cash distributions a partnership can pay to a unitholder). The GAAP measure most directly comparable to Distributable Cash Flow, and Distributable Cash Flow, as adjusted, is net income for ETE on a stand-alone basis (the “Parent Company”). Distribution Coverage Ratio. The Partnership defines Distribution Coverage Ratio for a period as Distributable Cash Flow, as adjusted, divided by total cash distributions expected to be paid to the partners of ETE in respect of such period. 43ETE NON-GAAP FINANCIAL MEASURES 2016 2017 2018 Full Year Q1 Q2 Q3 Q4 YTD Q1 Q2 YTD Net income attributable to partners $ 995 $ 239 $ 212 $ 252 $ 251 $ 954 $ 3 63 $ 355 $ 718 Equity in earnings related to investments in ETP, Sunoco LP and USAC (1,374) (325) (273) (310) (335) (1,243) (414) (420) (834) Total cash distributions from investments in subsidiaries 1,459 262 284 317 311 1,174 443 454 897 Amortization included in interest expense (excluding ETP, Sunoco LP and USAC) 12 23 22 9 2 35 Lake Charles LNG maintenance capital expenditures — — — (1) (1) (2) — — — Other non-cash (excluding ETP, Sunoco LP and USAC) 56 34 10 10 34 88 6 11 17 Distributable Cash Flow 1,148 212 236 270 262 980 400 403 803 Transaction-related expenses 59 3 4 1 1 9 (5) 4 (1) Distributable Cash Flow, as adjusted $ 1,207 $ 215 $ 240 $ 271 $ 263 $ 989 $ 3 95 $ 407 $ 802 Total cash distributions to be paid to the partners of ETE 974 251 251 257 266 1025 266 354 620 Distribution coverage ratio 1.24x 0.86x 0.96x 1.05x 0.99x 0.96x 1.48x 1.15x 1.29x Distributable Cash Flow and Distributable Cash Flow, as adjusted. The Partnership defines Distributable Cash Flow and Distributable Cash Flow, as adjusted, for a period as cash distributions expected to be received in respect of such period in connection with the Partnership’s investments in limited and general partner interests, net of the Partnership’s cash expenditures for general and administrative costs and interest expense. The Partnership’s definitions of Distributable Cash Flow and Distributable Cash Flow, as adjusted, also include distributable cash flow from Lake Charles LNG to the Partnership. For Distributable Cash Flow, as adjusted, certain transaction-related expenses that are included in net income are excluded. Distributable Cash Flow is a significant liquidity measure used by the Partnership’s senior management to compare net cash flows generated by the Partnership to the distributions the Partnership expects to pay its unitholders. Due to cash expenses incurred from time to time in connection with the Partnership’s merger and acquisition activities and other transactions, Distributable Cash Flow, as adjusted, is also a significant liquidity measure used by the Partnership’s senior management to compare net cash flows generated by the Partnership to the distributions the Partnership expects to pay its unitholders. Using these measures, the Partnership’s management can compute the coverage ratio of estimated cash flows for a period to planned cash distributions for such period. Distributable Cash Flow and Distributable Cash Flow, as adjusted, are also important non-GAAP financial measures for our limited partners since these indicate to investors whether the Partnership’s investments are generating cash flows at a level that can sustain or support an increase in quarterly cash distribution levels. Financial measures such as Distributable Cash Flow and Distributable Cash Flow, as adjusted, are quantitative standards used by the investment community with respect to publicly traded partnerships because the value of a partnership unit is in part measured by its yield (which in turn is based on the amount of cash distributions a partnership can pay to a unitholder). The GAAP measure most directly comparable to Distributable Cash Flow, and Distributable Cash Flow, as adjusted, is net income for ETE on a stand-alone basis (the “Parent Company”). Distribution Coverage Ratio. The Partnership defines Distribution Coverage Ratio for a period as Distributable Cash Flow, as adjusted, divided by total cash distributions expected to be paid to the partners of ETE in respect of such period. 43