SEMG SemGroup Corporation

Filed by Energy Transfer LP pursuant to Rule 425 under the Securities Act of 1933 Subject Company: SemGroup Corporation Commission File No.: 001-34736 Date: November 20, 2019 ENERGY TRANSFER Investor Presentation November 2019Filed by Energy Transfer LP pursuant to Rule 425 under the Securities Act of 1933 Subject Company: SemGroup Corporation Commission File No.: 001-34736 Date: November 20, 2019 ENERGY TRANSFER Investor Presentation November 2019

FORWARD-LOOKING STATEMENTS / LEGAL DISCLAIMER Management of Energy Transfer LP (ET) will provide this presentation to analysts and/or investors at meetings to be held throughout November 2019. 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), Energy Transfer Operating, L.P. (ETO) and ET (collectively, the Partnerships), and their subsidiaries and this presentation may contain statements about future events, outlook and expectations related to the Partnerships and their subsidiaries all of which statements are forward-looking statements. 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. 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. Energy Transfer LP (“Energy Transfer” or “ET”) and SemGroup Corporation (“SemGroup” or “SEMG”) 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 stockholder approval and the satisfaction of the other conditions to the consummation of the proposed transaction, the ability of Energy Transfer to successfully integrate SemGroup’s operations and employees and realize anticipated synergies and cost savings, the potential impact of the announcement or consummation of the proposed transaction on relationships, including with employees, suppliers, customers, competitors and credit rating agencies, 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 Energy Transfer and SemGroup with the Securities and Exchange Commission (the “SEC”), which are available to the public. Energy Transfer and SemGroup undertake no obligation to update publicly or to revise any forward-looking statements, whether as a result of new information, future events or otherwise. Additional Information and Where to Find It In connection with the proposed transaction, ET filed with the SEC a registration statement on Form S-4, including a proxy statement/prospectus. SECURITY HOLDERS ARE URGED TO READ THE REGISTRATION STATEMENT AND PROXY STATEMENT/PROSPECTUS REGARDING THE TRANSACTION CAREFULLY. The registration statement on Form S-4 was declared effective by the SEC on October 30, 2019, and the definitive proxy statement/prospectus was delivered to security holders of record of SemGroup as of October 25, 2019. These documents, and any other documents filed by Energy Transfer and SemGroup 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 Energy Transfer or SemGroup. Participants in the Solicitation Energy Transfer, SemGroup, 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 Energy Transfer is contained in Energy Transfer’s Form 10-K for the year ended December 31, 2018, which was filed with the SEC on February 22, 2019. Information regarding the directors and executive officers of SemGroup is contained in SemGroup’s proxy statement relating to its 2019 Annual Meeting of Stockholders, which was filed with the SEC on April 12, 2019. 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 presentation 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 2 shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended.FORWARD-LOOKING STATEMENTS / LEGAL DISCLAIMER Management of Energy Transfer LP (ET) will provide this presentation to analysts and/or investors at meetings to be held throughout November 2019. 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), Energy Transfer Operating, L.P. (ETO) and ET (collectively, the Partnerships), and their subsidiaries and this presentation may contain statements about future events, outlook and expectations related to the Partnerships and their subsidiaries all of which statements are forward-looking statements. 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. 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. Energy Transfer LP (“Energy Transfer” or “ET”) and SemGroup Corporation (“SemGroup” or “SEMG”) 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 stockholder approval and the satisfaction of the other conditions to the consummation of the proposed transaction, the ability of Energy Transfer to successfully integrate SemGroup’s operations and employees and realize anticipated synergies and cost savings, the potential impact of the announcement or consummation of the proposed transaction on relationships, including with employees, suppliers, customers, competitors and credit rating agencies, 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 Energy Transfer and SemGroup with the Securities and Exchange Commission (the “SEC”), which are available to the public. Energy Transfer and SemGroup undertake no obligation to update publicly or to revise any forward-looking statements, whether as a result of new information, future events or otherwise. Additional Information and Where to Find It In connection with the proposed transaction, ET filed with the SEC a registration statement on Form S-4, including a proxy statement/prospectus. SECURITY HOLDERS ARE URGED TO READ THE REGISTRATION STATEMENT AND PROXY STATEMENT/PROSPECTUS REGARDING THE TRANSACTION CAREFULLY. The registration statement on Form S-4 was declared effective by the SEC on October 30, 2019, and the definitive proxy statement/prospectus was delivered to security holders of record of SemGroup as of October 25, 2019. These documents, and any other documents filed by Energy Transfer and SemGroup 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 Energy Transfer or SemGroup. Participants in the Solicitation Energy Transfer, SemGroup, 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 Energy Transfer is contained in Energy Transfer’s Form 10-K for the year ended December 31, 2018, which was filed with the SEC on February 22, 2019. Information regarding the directors and executive officers of SemGroup is contained in SemGroup’s proxy statement relating to its 2019 Annual Meeting of Stockholders, which was filed with the SEC on April 12, 2019. 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 presentation 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 2 shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended.

ET KEY INVESTMENT HIGHLIGHTS Growth From Organic Well Positioned Assets Solid Financials 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 Seeing strong EBITDA growth from recently Ø Healthy and improving Ø Assets well positioned in completed major growth balance sheet most active basins projects Ø Increased retained cash Ø Integrated assets allow Ø Expect additional EBITDA flow with ~$2.5 – $3.0 solid commercial synergies growth from remainder of billion per year of including gas, crude and projects coming online distribution coverage NGLs through 2020 expected Well positioned for sustainable organic growth and improved financial strength 3ET KEY INVESTMENT HIGHLIGHTS Growth From Organic Well Positioned Assets Solid Financials 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 Seeing strong EBITDA growth from recently Ø Healthy and improving Ø Assets well positioned in completed major growth balance sheet most active basins projects Ø Increased retained cash Ø Integrated assets allow Ø Expect additional EBITDA flow with ~$2.5 – $3.0 solid commercial synergies growth from remainder of billion per year of including gas, crude and projects coming online distribution coverage NGLs through 2020 expected Well positioned for sustainable organic growth and improved financial strength 3

DELIVERING ON ALL FRONTS Operational Q3 2019 Financials Strategic Ø All segments delivered strong Ø Adjusted EBITDA - $2.8 billionØ SEMG transaction adds results strategic growth platform in − Up 8% from Q3’18 deep-water port on the Houston Ø Reported record NGL Ship Channel Ø DCF - $1.5 billion transportation throughput, NGL fractionation volumes, Ø Transaction immediately − Up 10% from Q3’18 midstream gathered volumes, accretive and balance sheet crude volumes Ø YTD Growth Capital - $3.1 friendly billion, with incremental value Ø Arrowhead III Processing Plant from organic growth projects Ø Expands connectivity and came online in July 2019 increases reach into currently Ø Distribution coverage ratio – Ø Red Bluff Express Phase II underserved regions 1.9x completed in August 2019 Ø J.C. Nolan Pipeline went into service in August 2019 Ø Permian Express 4 went into full service October 1, 2019 Integrated franchise provides advantages through energy market cycles 4DELIVERING ON ALL FRONTS Operational Q3 2019 Financials Strategic Ø All segments delivered strong Ø Adjusted EBITDA - $2.8 billionØ SEMG transaction adds results strategic growth platform in − Up 8% from Q3’18 deep-water port on the Houston Ø Reported record NGL Ship Channel Ø DCF - $1.5 billion transportation throughput, NGL fractionation volumes, Ø Transaction immediately − Up 10% from Q3’18 midstream gathered volumes, accretive and balance sheet crude volumes Ø YTD Growth Capital - $3.1 friendly billion, with incremental value Ø Arrowhead III Processing Plant from organic growth projects Ø Expands connectivity and came online in July 2019 increases reach into currently Ø Distribution coverage ratio – Ø Red Bluff Express Phase II underserved regions 1.9x completed in August 2019 Ø J.C. Nolan Pipeline went into service in August 2019 Ø Permian Express 4 went into full service October 1, 2019 Integrated franchise provides advantages through energy market cycles 4

CAPEX OUTLOOK – QUICKER CASH GENERATION CYCLE 2019E Growth Capital: ~$4 billion Ø Reduced CAPEX guidance from previous estimate by $600-800 million Ø 2019E Adjusted EBITDA increased to $11.0 billion to $11.1 billion Ø Excess cash flow, as well as the Series E preferred units issued in April 2019, allowed year-to-date growth capital to be funded without issuance of common equity or debt 2020E Growth Capital: ~$4 billion • Lone Star Express Pipeline • Mariner East system completion (ME2, ME2X) • Nederland LPG facilities NGL & Refined Products • Fractionation plants (VII, VIII) • Orbit export facilities (Nederland and Mt. Belvieu) • 25+ projects < $50mm • Gathering projects (West TX and Northeast) • Compression facilities (West TX) Midstream • ~25 projects < $50mm • Bakken pipeline optimization Crude Oil • Ted Collins Pipeline • ~15 projects < $50mm 2021E+ Backlog of Approved Growth Capital Projects: ~$1.5 billion 5CAPEX OUTLOOK – QUICKER CASH GENERATION CYCLE 2019E Growth Capital: ~$4 billion Ø Reduced CAPEX guidance from previous estimate by $600-800 million Ø 2019E Adjusted EBITDA increased to $11.0 billion to $11.1 billion Ø Excess cash flow, as well as the Series E preferred units issued in April 2019, allowed year-to-date growth capital to be funded without issuance of common equity or debt 2020E Growth Capital: ~$4 billion • Lone Star Express Pipeline • Mariner East system completion (ME2, ME2X) • Nederland LPG facilities NGL & Refined Products • Fractionation plants (VII, VIII) • Orbit export facilities (Nederland and Mt. Belvieu) • 25+ projects < $50mm • Gathering projects (West TX and Northeast) • Compression facilities (West TX) Midstream • ~25 projects < $50mm • Bakken pipeline optimization Crude Oil • Ted Collins Pipeline • ~15 projects < $50mm 2021E+ Backlog of Approved Growth Capital Projects: ~$1.5 billion 5

SEMG ACQUISITION HIGHLIGHTS Immediately Accretive Premier U.S. Gulf Coast Transaction With No Material Terminal With Stable, Take- Credit Impact or-Pay Cash Flows Generates an Aggregate $500MM of DCF 18.2 MMBbl Crude Storage Capacity & Coverage 2020-2022 Export Capabilities Complementary Assets That Liquids-Focused Drive Commercial, Infrastructure With No Direct Operational, Financial and Commodity Price Exposure Cost Synergies Primary Assets are Terminals & Long- Haul Pipelines $170MM+ Annual Run-rate Acquisition is Acquisition is consisten consistent with plans to improve t with plans to improve financial position financial position 6SEMG ACQUISITION HIGHLIGHTS Immediately Accretive Premier U.S. Gulf Coast Transaction With No Material Terminal With Stable, Take- Credit Impact or-Pay Cash Flows Generates an Aggregate $500MM of DCF 18.2 MMBbl Crude Storage Capacity & Coverage 2020-2022 Export Capabilities Complementary Assets That Liquids-Focused Drive Commercial, Infrastructure With No Direct Operational, Financial and Commodity Price Exposure Cost Synergies Primary Assets are Terminals & Long- Haul Pipelines $170MM+ Annual Run-rate Acquisition is Acquisition is consisten consistent with plans to improve t with plans to improve financial position financial position 6

ET & SEMG COMPLEMENTARY ASSETS Expands Crude Oil Asset Footprint Ø Strategic franchise-quality position on the Houston Ship Channel Ø Will provide connectivity along the U.S. Gulf Coast and throughout ET’s system Ø Increases reach into the DJ basin where ET does not have a presence Expands Logistical Optionality Ø Provides additional outlets for Permian, Rockies and Mid-Continent producers Ø Offers deep-water marine access Ø DJ Basin infrastructure optionality SemG SemG SemGr r ro o ou u up p p Crude Crude Crude   O O Oil il il Expected Synergies Natural  Natural  Natural Gas Gas Gas R R Re e efine fine fined P d P d Pr r roducts oducts oducts R R Ro o ose se se V  V  Va a alle lle lley y y   II P II P II Pl l la a an n nt t tØ Utilization rates on existing assets (i.e. Houston P P Pi i ipe pe peline line lines s s Fuel Oil Terminal (“HFOTCO”) docks closer to full White White White   Cliffs  Cliffs  Cliffs P P Pipe ipe ipeline line line capacity) M M Ma a aure ure urep p pa a as s s P P Pi i ipe pe peline line line Ø Presence in new markets generating opportunities Ene Ene Ener r rg g gy y y Tra  Tra  Transfe nsfe nsfer r r for other aspects of portfolio (i.e. Houston Ship Te Te Term rm rmina ina inal l ls s s Channel, DJ Basin) P P Pi i ipe pe peline line lines s s Lake  Lake  Lake C C Ch h ha a ar r rl l les LNG es LNG es LNG Ø Assets with ET’s Nederland terminal and U.S. M M Ma a arine rine riner Ea r Ea r East 2X st 2X st 2X Gulf Coast assets Revo Revo Revol l lu u ut t ti i io o on n n ETCO  ETCO  ETCO P P Pipe ipe ipeline line line Ø Cost efficiencies with combined operations Da Da Dakota kota kota   A A Access  ccess  ccess Pipeline Pipeline Pipeline Trans Pecos  Trans Pecos  Trans Pecos Pipeline Pipeline Pipeline Ø $170MM+ annual run-rate synergies including Com Com Coma a anche nche nche Tra  Tra  Trail  il  il P P Pi i ipe pe peline line line commercial, operational, financial and cost synergies Note: Includes growth projects under construction. 7 Fully-integrated midstream platform enhances ability to offer wide range of services to both domestic and international marketsET & SEMG COMPLEMENTARY ASSETS Expands Crude Oil Asset Footprint Ø Strategic franchise-quality position on the Houston Ship Channel Ø Will provide connectivity along the U.S. Gulf Coast and throughout ET’s system Ø Increases reach into the DJ basin where ET does not have a presence Expands Logistical Optionality Ø Provides additional outlets for Permian, Rockies and Mid-Continent producers Ø Offers deep-water marine access Ø DJ Basin infrastructure optionality SemG SemG SemGr r ro o ou u up p p Crude Crude Crude O O Oil il il Expected Synergies Natural Natural Natural Gas Gas Gas R R Re e efine fine fined P d P d Pr r roducts oducts oducts R R Ro o ose se se V V Va a alle lle lley y y II P II P II Pl l la a an n nt t tØ Utilization rates on existing assets (i.e. Houston P P Pi i ipe pe peline line lines s s Fuel Oil Terminal (“HFOTCO”) docks closer to full White White White Cliffs Cliffs Cliffs P P Pipe ipe ipeline line line capacity) M M Ma a aure ure urep p pa a as s s P P Pi i ipe pe peline line line Ø Presence in new markets generating opportunities Ene Ene Ener r rg g gy y y Tra Tra Transfe nsfe nsfer r r for other aspects of portfolio (i.e. Houston Ship Te Te Term rm rmina ina inal l ls s s Channel, DJ Basin) P P Pi i ipe pe peline line lines s s Lake Lake Lake C C Ch h ha a ar r rl l les LNG es LNG es LNG Ø Assets with ET’s Nederland terminal and U.S. M M Ma a arine rine riner Ea r Ea r East 2X st 2X st 2X Gulf Coast assets Revo Revo Revol l lu u ut t ti i io o on n n ETCO ETCO ETCO P P Pipe ipe ipeline line line Ø Cost efficiencies with combined operations Da Da Dakota kota kota A A Access ccess ccess Pipeline Pipeline Pipeline Trans Pecos Trans Pecos Trans Pecos Pipeline Pipeline Pipeline Ø $170MM+ annual run-rate synergies including Com Com Coma a anche nche nche Tra Tra Trail il il P P Pi i ipe pe peline line line commercial, operational, financial and cost synergies Note: Includes growth projects under construction. 7 Fully-integrated midstream platform enhances ability to offer wide range of services to both domestic and international markets

TRANSFORMING UNDERUTILIZED ASSETS Mont Belvieu – 2011¹ Mont Belvieu – 2019 Frac VI Fracs IV & V Frac VIII Frac VII Frac I Frac II Export De-C2 Proposed Lone Star Frac I Frac III • Fractionators: 0 • Fractionators: 6 • Fractionation capacity: 0 bbls/d • Fractionation capacity: Up to 790,000 bbls/d • Proposed 100,000 bbls/d Frac 1; in-service 2013 • Frac VII under construction; expected in-service Q1 2020 • Potential for incremental 100,000 bbls/d Frac 2 • Frac VIII under construction; expected in-service Q2 2021 Upon completion of Frac VIII in Q2 2021, ET will be capable of fractionating over 1 million barrels per day at Mont Belvieu 8 1. Source: Management Presentation 2011TRANSFORMING UNDERUTILIZED ASSETS Mont Belvieu – 2011¹ Mont Belvieu – 2019 Frac VI Fracs IV & V Frac VIII Frac VII Frac I Frac II Export De-C2 Proposed Lone Star Frac I Frac III • Fractionators: 0 • Fractionators: 6 • Fractionation capacity: 0 bbls/d • Fractionation capacity: Up to 790,000 bbls/d • Proposed 100,000 bbls/d Frac 1; in-service 2013 • Frac VII under construction; expected in-service Q1 2020 • Potential for incremental 100,000 bbls/d Frac 2 • Frac VIII under construction; expected in-service Q2 2021 Upon completion of Frac VIII in Q2 2021, ET will be capable of fractionating over 1 million barrels per day at Mont Belvieu 8 1. Source: Management Presentation 2011

TED COLLINS PIPELINE - A STRATEGIC CONNECTION ON THE U.S. GULF COAST Ø ~75-mile pipeline to connect the Houston Ship Channel and ET’s Nederland Terminal Ø Will provide best-in-class access to multiple markets Ø Houston Ø Beaumont/Port Arthur Ø St. James Ø Initial capacity of 500 MBbl/d+ Ø Will provide immediate access to 1,000 MBbl/d+ of export capacity with plans to double Ø Expected to be in service in 2021 Strategic new pipeline provides increased optionality and enhances value of the Nederland Terminal and Houston Ship Channel assets 9 Note: Pipeline route shown is for illustrative purposes.TED COLLINS PIPELINE - A STRATEGIC CONNECTION ON THE U.S. GULF COAST Ø ~75-mile pipeline to connect the Houston Ship Channel and ET’s Nederland Terminal Ø Will provide best-in-class access to multiple markets Ø Houston Ø Beaumont/Port Arthur Ø St. James Ø Initial capacity of 500 MBbl/d+ Ø Will provide immediate access to 1,000 MBbl/d+ of export capacity with plans to double Ø Expected to be in service in 2021 Strategic new pipeline provides increased optionality and enhances value of the Nederland Terminal and Houston Ship Channel assets 9 Note: Pipeline route shown is for illustrative purposes.

SUCCESSFUL ACQUISITION TRACK RECORD HPL TUFCO Houston Pipeline Co. 2004 2005 2006 2011 2012 2014 2015 2012 2012 2016 2017 Ø ET Management has a proven track record of successfully integrating acquisitions Ø Knowledge of respective assets and businesses facilitates integrations of: Ø Operations Ø Commercial Ø Risk Management Ø Finance / Accounting Ø Information Technology Ø SEMG’s stockholder meeting is scheduled for December 4, 2019. Subject to approval of SEMG’s 10 stockholders, the acquisition is expected to close shortly after receipt of the vote.SUCCESSFUL ACQUISITION TRACK RECORD HPL TUFCO Houston Pipeline Co. 2004 2005 2006 2011 2012 2014 2015 2012 2012 2016 2017 Ø ET Management has a proven track record of successfully integrating acquisitions Ø Knowledge of respective assets and businesses facilitates integrations of: Ø Operations Ø Commercial Ø Risk Management Ø Finance / Accounting Ø Information Technology Ø SEMG’s stockholder meeting is scheduled for December 4, 2019. Subject to approval of SEMG’s 10 stockholders, the acquisition is expected to close shortly after receipt of the vote.

CAPITAL ALLOCATION – CONTINUED FOCUS ON RETURNS Organic Unit Buy- Distribution Debt Projects backs Increases Retirements • Maintain strong investment grade balance sheet Leverage target: 4.0 – 4.5x debt/EBITDA – Continued improvement in debt metrics • Efficiently fund organic growth capital projects – High-grade investment options with increased returns threshold – Majority funded with retained cash flow • Multiple options available after achieving debt targets – Options not mutually exclusive – Unit buy-backs > favorable return at current ET trading price – Distribution increases > goal to have sustainable long-term growth 11CAPITAL ALLOCATION – CONTINUED FOCUS ON RETURNS Organic Unit Buy- Distribution Debt Projects backs Increases Retirements • Maintain strong investment grade balance sheet Leverage target: 4.0 – 4.5x debt/EBITDA – Continued improvement in debt metrics • Efficiently fund organic growth capital projects – High-grade investment options with increased returns threshold – Majority funded with retained cash flow • Multiple options available after achieving debt targets – Options not mutually exclusive – Unit buy-backs > favorable return at current ET trading price – Distribution increases > goal to have sustainable long-term growth 11

DIVERSIFIED EARNINGS MIX WITH PRIMARILY FEE-BASED BUSINESS 1 1 Segment Contract Structure Strength Q3 2019 Adjusted EBITDA by Segment More than 9,300 miles connecting Permian, Fees from transporting SUN, USAC  Crude Oil Bakken and Midcon Basins and terminalling Midstream & Other to U.S. markets, including 15% 12% Nederland terminal Intrastate Fees from dedicated 8% ~60 facilities connected to capacity and take-or- ET’s Lone Star NGL pay contracts, storage pipelines, and new frac NGL & Refined fees and throughput NGL & Refined  expansions will bring total Interstate Products fees, and fractionation Products fractionation capacity at the 16% fees, which are 24% Mont Belvieu complex to primarily frac-or-pay more than 900 Mbpd structures Crude Oil 25% Interstate Fees based on Connected to all major U.S. Transport & reserved capacity, supply basins and demand Storage regardless of usage markets, including exports Minimum volume 2018 Breakout Significant acreage commitment (MVC), dedications, including acreage dedication, Fee-Based Margin 85-90% Midstream assets in Permian, Eagle utilization-based fees Ford, and Marcellus/Utica and percent of Commodity Margin 5-7% Basins proceeds (POP) Spread Margin² 5-7% Largest intrastate pipeline system in the U.S. with Intrastate Reservation charges interconnects to TX Transport & and transport fees Diversified customer base includes producers, markets, as well as major Storage based on utilization midstream providers and major integrated consumption areas throughout the US global oil companies 12 1 Energy Transfer Operating Segments 2 Spread margin is pipeline basis, cross commodity and time spreadsDIVERSIFIED EARNINGS MIX WITH PRIMARILY FEE-BASED BUSINESS 1 1 Segment Contract Structure Strength Q3 2019 Adjusted EBITDA by Segment More than 9,300 miles connecting Permian, Fees from transporting SUN, USAC Crude Oil Bakken and Midcon Basins and terminalling Midstream & Other to U.S. markets, including 15% 12% Nederland terminal Intrastate Fees from dedicated 8% ~60 facilities connected to capacity and take-or- ET’s Lone Star NGL pay contracts, storage pipelines, and new frac NGL & Refined fees and throughput NGL & Refined expansions will bring total Interstate Products fees, and fractionation Products fractionation capacity at the 16% fees, which are 24% Mont Belvieu complex to primarily frac-or-pay more than 900 Mbpd structures Crude Oil 25% Interstate Fees based on Connected to all major U.S. Transport & reserved capacity, supply basins and demand Storage regardless of usage markets, including exports Minimum volume 2018 Breakout Significant acreage commitment (MVC), dedications, including acreage dedication, Fee-Based Margin 85-90% Midstream assets in Permian, Eagle utilization-based fees Ford, and Marcellus/Utica and percent of Commodity Margin 5-7% Basins proceeds (POP) Spread Margin² 5-7% Largest intrastate pipeline system in the U.S. with Intrastate Reservation charges interconnects to TX Transport & and transport fees Diversified customer base includes producers, markets, as well as major Storage based on utilization midstream providers and major integrated consumption areas throughout the US global oil companies 12 1 Energy Transfer Operating Segments 2 Spread margin is pipeline basis, cross commodity and time spreads

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 • Marcellus natural gas takeaway to the Midwest, Gulf Coast, and • Access to multiple shale plays, storage facilities and markets 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 Gas T&S Coast • 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 Gas T&S • Key assets: ET Fuel Pipeline, Oasis Pipeline, Houston Pipeline Gulf Coast System, ETC Katy Pipeline • More than 40,000 miles of gathering pipelines with ~8+ Bcf/d of • Gathering and processing build out in Texas and Marcellus/Utica processing capacity • Synergies with ET downstream assets Midstream • Significant growth projects ramping up to full capacity over the next • Majority of projects placed in-service underpinned by long-term, two years fee-based 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- • Liquids volumes from our midstream segment culminate in the ET NGL & Refined party 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 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 contracts; expandable with pump station modifications • Permian Express 4 expected to provide Midland & Delaware Basin • Significant Permian takeaway abilities crude oil takeaway to various markets, including Nederland, TX Crude Oil • 28 million barrel Nederland crude oil terminal on the Gulf Coast • Permian Express Partners joint venture with ExxonMobil • Bakken crude takeaway to Gulf Coast refineries 13FULLY INTEGRATED PLATFORM SPANNING THE ENTIRE MIDSTREAM VALUE CHAIN Ø Involvement in Major Midstream Themes Across the Best Basins and Logistics Hubs Franchise Strengths Opportunities • Marcellus natural gas takeaway to the Midwest, Gulf Coast, and • Access to multiple shale plays, storage facilities and markets 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 Gas T&S Coast • 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 Gas T&S • Key assets: ET Fuel Pipeline, Oasis Pipeline, Houston Pipeline Gulf Coast System, ETC Katy Pipeline • More than 40,000 miles of gathering pipelines with ~8+ Bcf/d of • Gathering and processing build out in Texas and Marcellus/Utica processing capacity • Synergies with ET downstream assets Midstream • Significant growth projects ramping up to full capacity over the next • Majority of projects placed in-service underpinned by long-term, two years fee-based 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- • Liquids volumes from our midstream segment culminate in the ET NGL & Refined party 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 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 contracts; expandable with pump station modifications • Permian Express 4 expected to provide Midland & Delaware Basin • Significant Permian takeaway abilities crude oil takeaway to various markets, including Nederland, TX Crude Oil • 28 million barrel Nederland crude oil terminal on the Gulf Coast • Permian Express Partners joint venture with ExxonMobil • Bakken crude takeaway to Gulf Coast refineries 13

SIGNIFICANT MANAGEMENT OWNERSHIP Insider Ownership vs Peers Kelcy Warren Unit Purchases Insider Ownership vs Major Indices ET CEO Unit Purchases 16% 10,000 9,504 14.5% > 9.5mm units in last 12 months 9,000 14% 8,000 3,464 12% 7,000 10% 6,000 8% 5,000 3,040 4,000 6% 3,000 4% 1,000 2.7% 2,000 500 2.0% 1.7% 2% 1.2% 1,000 1,500 0% 0 11 ET AMZ AMZI S&P 500 S&P 500 11/12/2018 11/13/2018 11/19/2018 5/20/2019 8/19/2019 Energy Ø On November 14, 2019 ET’s CFO purchased 18,000 units, valued at ~$201,000 Ø On November 15, 2019 ET’s President & COO purchased 25,000 units, valued at ~$290,000 14 Source: Bloomberg/Company Filings 1.  Excludes ET Insider Ownership % Units (000s)SIGNIFICANT MANAGEMENT OWNERSHIP Insider Ownership vs Peers Kelcy Warren Unit Purchases Insider Ownership vs Major Indices ET CEO Unit Purchases 16% 10,000 9,504 14.5% > 9.5mm units in last 12 months 9,000 14% 8,000 3,464 12% 7,000 10% 6,000 8% 5,000 3,040 4,000 6% 3,000 4% 1,000 2.7% 2,000 500 2.0% 1.7% 2% 1.2% 1,000 1,500 0% 0 11 ET AMZ AMZI S&P 500 S&P 500 11/12/2018 11/13/2018 11/19/2018 5/20/2019 8/19/2019 Energy Ø On November 14, 2019 ET’s CFO purchased 18,000 units, valued at ~$201,000 Ø On November 15, 2019 ET’s President & COO purchased 25,000 units, valued at ~$290,000 14 Source: Bloomberg/Company Filings 1. Excludes ET Insider Ownership % Units (000s)

FORESEE SIGNIFICANT EBITDA GROWTH IN 2019 FROM COMPLETION OF PROJECT BACKLOG PROJECT SCOPE IN-SERVICE TIMING NGL & Refined Products Lone Star Frac VI 150 Mbpd fractionator at Mont Belvieu complex In service Q1 2019 Lone Star Frac VII 150 Mbpd fractionator at Mont Belvieu complex Q1 2020 Lone Star Frac VIII 150 Mbpd fractionator at Mont Belvieu complex Q2 2021 24-inch, 352 mile expansion to LS Express Pipeline adding 400,000 bbls/d Lone Star Express Expansion Q4 2020 from Wink, TX to Fort Worth, TX Mariner East 2 NGLs from Marcellus Shale to MHIC with 275Mbpd capacity upon full completion In service Q4 2018 Mariner East 2X Increase NGL takeaway from the Marcellus to the East Coast w/ storage at Marcus Hook complex Mid-2020 J.C. Nolan Diesel Pipeline 30,000 bbls/d diesel pipeline from Hebert, TX to newly-constructed terminal in Midland, TX In service Q3 2019 800,000 bbl refrigerated ethane storage tank and 175,000 bbl/d ethane refrigeration facility and 20-inch Orbit Ethane Export Terminal Q4 2020 ethane pipeline to connect Mont Belvieu to export terminal Midstream Plant complete; awaiting Revolution 110 miles of gas gathering pipeline, cryogenic processing plant, NGL pipelines, and frac facility in PA pipeline restart Arrowhead II 200 MMcf/d cryogenic processing plant in Delaware Basin In service Q4 2018 Arrowhead III 200 MMcf/d cryogenic processing plant in Delaware Basin In service Q3 2019 Crude Oil (1) Permian Express 3 Provides incremental Permian takeaway capacity, with total capacity of 140Mbpd In service Q4 2017/Sept. 2018 (1) Bayou Bridge 212 mile crude pipeline connecting Nederland to Lake Charles / St. James, LA In service Q1 2019 (1) Permian Express 4 Provides incremental Permian takeaway capacity, with total capacity of 120Mbpd Fully in service Oct. 1, 2019 Interstate Transport & Storage (1) Rover Pipeline 712 mile pipeline from Ohio / West Virginia border to Defiance, OH and Dawn, Ontario Fully in service Q4 2018 Intrastate Transport & Storage (1) Old Ocean Pipeline 24-inch, 160,000 Mmbtu/d natural gas pipeline from Maypearl, TX to Hebert, TX In service Q2 2018 Red Bluff Express Pipeline 80-mile pipeline with capacity of at least 1.4 Bcf/d; extension will add an incremental 25 miles of pipeline Fully in service Q3 2019 36-inch natural gas pipeline expansion, providing 160,000 Mmbtu/d of additional capacity from WTX for (1) NTP Pipeline Expansion In service January 2019 deliveries into Old Ocean 15 (1) Joint VentureFORESEE SIGNIFICANT EBITDA GROWTH IN 2019 FROM COMPLETION OF PROJECT BACKLOG PROJECT SCOPE IN-SERVICE TIMING NGL & Refined Products Lone Star Frac VI 150 Mbpd fractionator at Mont Belvieu complex In service Q1 2019 Lone Star Frac VII 150 Mbpd fractionator at Mont Belvieu complex Q1 2020 Lone Star Frac VIII 150 Mbpd fractionator at Mont Belvieu complex Q2 2021 24-inch, 352 mile expansion to LS Express Pipeline adding 400,000 bbls/d Lone Star Express Expansion Q4 2020 from Wink, TX to Fort Worth, TX Mariner East 2 NGLs from Marcellus Shale to MHIC with 275Mbpd capacity upon full completion In service Q4 2018 Mariner East 2X Increase NGL takeaway from the Marcellus to the East Coast w/ storage at Marcus Hook complex Mid-2020 J.C. Nolan Diesel Pipeline 30,000 bbls/d diesel pipeline from Hebert, TX to newly-constructed terminal in Midland, TX In service Q3 2019 800,000 bbl refrigerated ethane storage tank and 175,000 bbl/d ethane refrigeration facility and 20-inch Orbit Ethane Export Terminal Q4 2020 ethane pipeline to connect Mont Belvieu to export terminal Midstream Plant complete; awaiting Revolution 110 miles of gas gathering pipeline, cryogenic processing plant, NGL pipelines, and frac facility in PA pipeline restart Arrowhead II 200 MMcf/d cryogenic processing plant in Delaware Basin In service Q4 2018 Arrowhead III 200 MMcf/d cryogenic processing plant in Delaware Basin In service Q3 2019 Crude Oil (1) Permian Express 3 Provides incremental Permian takeaway capacity, with total capacity of 140Mbpd In service Q4 2017/Sept. 2018 (1) Bayou Bridge 212 mile crude pipeline connecting Nederland to Lake Charles / St. James, LA In service Q1 2019 (1) Permian Express 4 Provides incremental Permian takeaway capacity, with total capacity of 120Mbpd Fully in service Oct. 1, 2019 Interstate Transport & Storage (1) Rover Pipeline 712 mile pipeline from Ohio / West Virginia border to Defiance, OH and Dawn, Ontario Fully in service Q4 2018 Intrastate Transport & Storage (1) Old Ocean Pipeline 24-inch, 160,000 Mmbtu/d natural gas pipeline from Maypearl, TX to Hebert, TX In service Q2 2018 Red Bluff Express Pipeline 80-mile pipeline with capacity of at least 1.4 Bcf/d; extension will add an incremental 25 miles of pipeline Fully in service Q3 2019 36-inch natural gas pipeline expansion, providing 160,000 Mmbtu/d of additional capacity from WTX for (1) NTP Pipeline Expansion In service January 2019 deliveries into Old Ocean 15 (1) Joint Venture

CRUDE OIL SEGMENT – BAKKEN PIPELINE PROJECT 1 Bakken Pipeline System • 1,915 mile system connecting Bakken production to ET’s Nederland terminal on the Gulf Coast • Placed into service June, 2017 • Recently completed successful open season to bring current system capacity to 570,000 barrels per day • Currently conducting an open season to further optimize system capacity to serve growing demand for additional takeaway • Upon completion of the permitting phase, expect to provide up to ~30,000 barrels per day of early service capacity by mid-2020, utilizing current system configuration Delivery Points Origin Sites Bakken Pipeline 16 Nederland Terminal (1) Ownership is ET: 36.37%, MarEn: 36.75%, PSXP: 25%, XOM: ~2% CRUDE OIL SEGMENT – BAKKEN PIPELINE PROJECT 1 Bakken Pipeline System • 1,915 mile system connecting Bakken production to ET’s Nederland terminal on the Gulf Coast • Placed into service June, 2017 • Recently completed successful open season to bring current system capacity to 570,000 barrels per day • Currently conducting an open season to further optimize system capacity to serve growing demand for additional takeaway • Upon completion of the permitting phase, expect to provide up to ~30,000 barrels per day of early service capacity by mid-2020, utilizing current system configuration Delivery Points Origin Sites Bakken Pipeline 16 Nederland Terminal (1) Ownership is ET: 36.37%, MarEn: 36.75%, PSXP: 25%, XOM: ~2%

CRUDE OIL SEGMENT – PERMIAN EXPRESS PIPELINES Permian Express 1 Permian Express 2 • 16-inch, ~380-mile pipeline • 20- & 24-inch, ~400-mile pipeline • 150,000 barrels per day of capacity • 230,000 barrels per day of capacity • Provides transportation from Wichita Falls, TX to Nederland, • Provides transportation from Midland, TX to Nederland, TX TX • Contracted under long-term agreements • Contracted under long-term agreements Wichita Falls Ringgold Colorado City Lea Station Corsicana Permian Express 4 Loving Station Permian Express Terminal • 24-inch, ~400-mile pipeline • 120,000 barrels per day of capacity ET Nederland Terminal • Provides transportation from Colorado City, TX to Nederland, TX • Contracted under long-term agreements Permian Express 3 • Fully in service October 1, 2019 • 20- & 24-inch, ~400-mile pipeline • 140,000 barrels a day of capacity • Provides transportation from Midland, TX to Nederland, TX 1 million+ barrels per day of Permian • Contracted under long-term agreements crude take-away capacity with the addition of Permian Express 4¹ - Delaware Basin Pipeline - Permian Express 1 17 - Permian Express 2, 3, & 4 - Nederland Access Pipeline (1) Includes West Texas Gulf and Amdel pipelinesCRUDE OIL SEGMENT – PERMIAN EXPRESS PIPELINES Permian Express 1 Permian Express 2 • 16-inch, ~380-mile pipeline • 20- & 24-inch, ~400-mile pipeline • 150,000 barrels per day of capacity • 230,000 barrels per day of capacity • Provides transportation from Wichita Falls, TX to Nederland, • Provides transportation from Midland, TX to Nederland, TX TX • Contracted under long-term agreements • Contracted under long-term agreements Wichita Falls Ringgold Colorado City Lea Station Corsicana Permian Express 4 Loving Station Permian Express Terminal • 24-inch, ~400-mile pipeline • 120,000 barrels per day of capacity ET Nederland Terminal • Provides transportation from Colorado City, TX to Nederland, TX • Contracted under long-term agreements Permian Express 3 • Fully in service October 1, 2019 • 20- & 24-inch, ~400-mile pipeline • 140,000 barrels a day of capacity • Provides transportation from Midland, TX to Nederland, TX 1 million+ barrels per day of Permian • Contracted under long-term agreements crude take-away capacity with the addition of Permian Express 4¹ - Delaware Basin Pipeline - Permian Express 1 17 - Permian Express 2, 3, & 4 - Nederland Access Pipeline (1) Includes West Texas Gulf and Amdel pipelines

NGL & REFINED PRODUCTS SEGMENT – MARINER EAST SYSTEM Comprehensive Marcellus/Utica Shale solution reaching local, regional and international markets Ø Provides NGL transportation from OH / Western PA to the Marcus Hook Industrial Complex on the East Coast Ø Supported by long-term, fee-based contracts Ø Diversified customer base includes producers, midstream providers and major integrated energy companies Ø System easily expandable to meet future demand Mariner East 2 Mariner East 2X Mariner East 1 • Placed into initial service December 2018 • Expected to be in-service mid-2020 • Currently providing transportation, storage & terminalling services • NGL transportation, storage & terminalling • Transportation, storage and terminalling • Approximate capacity of 70,000 barrels per services services for ethane, propane, butane, C3+, day natural gasoline, condensate and refined • Capacity of 275,000 barrels per day upon full products completion, with ability to expand as needed ME2 Pipeline Existing Third Party Pipeline ME1 Pipeline SXL Terminal Facilities Third Party Facility Pennsylvania Propane Delivery Marcellus Shale Formation 18NGL & REFINED PRODUCTS SEGMENT – MARINER EAST SYSTEM Comprehensive Marcellus/Utica Shale solution reaching local, regional and international markets Ø Provides NGL transportation from OH / Western PA to the Marcus Hook Industrial Complex on the East Coast Ø Supported by long-term, fee-based contracts Ø Diversified customer base includes producers, midstream providers and major integrated energy companies Ø System easily expandable to meet future demand Mariner East 2 Mariner East 2X Mariner East 1 • Placed into initial service December 2018 • Expected to be in-service mid-2020 • Currently providing transportation, storage & terminalling services • NGL transportation, storage & terminalling • Transportation, storage and terminalling • Approximate capacity of 70,000 barrels per services services for ethane, propane, butane, C3+, day natural gasoline, condensate and refined • Capacity of 275,000 barrels per day upon full products completion, with ability to expand as needed ME2 Pipeline Existing Third Party Pipeline ME1 Pipeline SXL Terminal Facilities Third Party Facility Pennsylvania Propane Delivery Marcellus Shale Formation 18

NGL & REFINED PRODUCTS SEGMENT – ORBIT ETHANE EXPORT PROJECT Orbit Export Pipeline and Facility Orbit Pipeline JV Ø Orbit Joint Venture with Satellite Petrochemical USA Corp includes construction of a new ethane export terminal on the U.S. Gulf Coast to provide ethane to Satellite Ø At the terminal, Orbit is constructing • 800,000 barrel refrigerated ethane storage tank • 175,000 barrel per day ethane refrigeration facility • 20-inch ethane pipeline originating at our Mont Belvieu facilities, that will make deliveries to the export terminal, as well as domestic markets in the region Ø ET will be the operator of the Orbit assets, provide storage and marketing services for Satellite, and provide Satellite with approximately 150,000 barrels per day of ethane under a long-term, demand-based agreement Construction of Satellite’s Ethane Receiving Terminal Ø In addition, ET is constructing and will wholly-own the infrastructure required to supply ethane to the pipeline and to load ethane onto carriers destined for Satellite’s newly- constructed ethane crackers in China Ø Subject to Chinese Government approval, expect all facilities in the U.S. and China to be ready for commercial service in the 4th quarter of 2020 19NGL & REFINED PRODUCTS SEGMENT – ORBIT ETHANE EXPORT PROJECT Orbit Export Pipeline and Facility Orbit Pipeline JV Ø Orbit Joint Venture with Satellite Petrochemical USA Corp includes construction of a new ethane export terminal on the U.S. Gulf Coast to provide ethane to Satellite Ø At the terminal, Orbit is constructing • 800,000 barrel refrigerated ethane storage tank • 175,000 barrel per day ethane refrigeration facility • 20-inch ethane pipeline originating at our Mont Belvieu facilities, that will make deliveries to the export terminal, as well as domestic markets in the region Ø ET will be the operator of the Orbit assets, provide storage and marketing services for Satellite, and provide Satellite with approximately 150,000 barrels per day of ethane under a long-term, demand-based agreement Construction of Satellite’s Ethane Receiving Terminal Ø In addition, ET is constructing and will wholly-own the infrastructure required to supply ethane to the pipeline and to load ethane onto carriers destined for Satellite’s newly- constructed ethane crackers in China Ø Subject to Chinese Government approval, expect all facilities in the U.S. and China to be ready for commercial service in the 4th quarter of 2020 19

NGL & REFINED PRODUCTS SEGMENT – PIPELINE AND FRACTIONATION EXPANSION Mont Belvieu Fractionation Expansions Lone Star Express Expansion • Total of 6 fractionators at Mont Belvieu • 24-inch, 352-mile expansion • 150,000 bbls/d Frac VI went into service in February 2019 • Will add 400 thousand bbls/d of NGL pipeline capacity from • Frac VII will have a capacity of 150 thousand bbls/d and is expected Lone Star’s pipeline system near Wink, Texas to the Lone Star in-service in Q1 2020 Express 30-inch pipeline south of Fort Worth, Texas th • Announced plans to construct 8 fractionator at Mont Belvieu in • Expected in-service in Q4 2020 August 2019 • Upon completion of Frac VIII in Q2 2021, ET will be capable of Ft. Worth, TX fractionating over 1 million barrels per day at Mont Belvieu Godley Plant Baden Storage Hattiesburg Storage Geismar Chalmette Mont Belvieu Fractionator Plant Fractionation Sea Robin & Storage Plant Sorrento Plant LaGrange/Chisholm Plant Complex Kenedy Plant Jackson Plant Frac VI Fracs IV & V Frac VIII Frac VII Frac I Existing Lone Star Frac II ETP Justice Mariner South ETP-Copano Liberty JV ETP Freedom Export De-C2 Lone Star Express Mont Belvieu Fractionation and Storage Lone Star Express Expansion Nederland Terminal Lone Star West Texas Gateway Plant Frac III ETP Spirit Storage 20NGL & REFINED PRODUCTS SEGMENT – PIPELINE AND FRACTIONATION EXPANSION Mont Belvieu Fractionation Expansions Lone Star Express Expansion • Total of 6 fractionators at Mont Belvieu • 24-inch, 352-mile expansion • 150,000 bbls/d Frac VI went into service in February 2019 • Will add 400 thousand bbls/d of NGL pipeline capacity from • Frac VII will have a capacity of 150 thousand bbls/d and is expected Lone Star’s pipeline system near Wink, Texas to the Lone Star in-service in Q1 2020 Express 30-inch pipeline south of Fort Worth, Texas th • Announced plans to construct 8 fractionator at Mont Belvieu in • Expected in-service in Q4 2020 August 2019 • Upon completion of Frac VIII in Q2 2021, ET will be capable of Ft. Worth, TX fractionating over 1 million barrels per day at Mont Belvieu Godley Plant Baden Storage Hattiesburg Storage Geismar Chalmette Mont Belvieu Fractionator Plant Fractionation Sea Robin & Storage Plant Sorrento Plant LaGrange/Chisholm Plant Complex Kenedy Plant Jackson Plant Frac VI Fracs IV & V Frac VIII Frac VII Frac I Existing Lone Star Frac II ETP Justice Mariner South ETP-Copano Liberty JV ETP Freedom Export De-C2 Lone Star Express Mont Belvieu Fractionation and Storage Lone Star Express Expansion Nederland Terminal Lone Star West Texas Gateway Plant Frac III ETP Spirit Storage 20

MIDSTREAM SEGMENT – PERMIAN BASIN INFRASTRUCTURE BUILDOUT Ø ET 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, ET has continued to build out its Permian infrastructure Processing Expansions • 600 mmcf/d of processing capacity online in 2016 and 2017 • 200 mmcf/d Arrowhead II processing plant went into service at end of October 2018; running full today • 200 MMcf/d Arrowhead III in the Delaware Basin went into service July 2019 and is expected to be full by year-end 2020 • Additional 200 MMcf/d processing plant expected in service by end of 2019 Red Bluff Express Pipeline • 1.4 Bcf/d natural gas pipeline through heart of the Delaware Basin rd • Connects Orla plant, as well as 3 party plants, to Waha/Oasis header • Went into service May 2018 • 25-mile expansion completed early August 2019 Will have ~2.7 Bcf/d of processing capacity in the Permian Basin upon completion of current processing expansion 21MIDSTREAM SEGMENT – PERMIAN BASIN INFRASTRUCTURE BUILDOUT Ø ET 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, ET has continued to build out its Permian infrastructure Processing Expansions • 600 mmcf/d of processing capacity online in 2016 and 2017 • 200 mmcf/d Arrowhead II processing plant went into service at end of October 2018; running full today • 200 MMcf/d Arrowhead III in the Delaware Basin went into service July 2019 and is expected to be full by year-end 2020 • Additional 200 MMcf/d processing plant expected in service by end of 2019 Red Bluff Express Pipeline • 1.4 Bcf/d natural gas pipeline through heart of the Delaware Basin rd • Connects Orla plant, as well as 3 party plants, to Waha/Oasis header • Went into service May 2018 • 25-mile expansion completed early August 2019 Will have ~2.7 Bcf/d of processing capacity in the Permian Basin upon completion of current processing expansion 21

RENEWED COMMITMENT TO DEVELOP LAKE CHARLES LNG EXPORT TERMINAL Export Project • Executed Project Framework Agreement in March 2019 • Issued Invitation to Tender to U.S. and international consortia to bid for Engineering, Procurement and Construction contract in May 2019 • Final investment decision (FID) to be mutually determined • 50/50 partnership – Energy Transfer – Shell US LNG, LLC • Convert existing LNG import facility to export terminal Current Terminal Assets • Fully permitted • 152-acre site – Utilizes existing infrastructure • Two existing deep-water docks to accommodate ships • Strategically located 3 up to 215,000 m capacity – Abundant natural gas supply 3 • Four LNG storage tanks with capacity of 425,000 m – Proximity to major pipelines • Estimated export capacity of ~16.5 22 million tonnes per yearRENEWED COMMITMENT TO DEVELOP LAKE CHARLES LNG EXPORT TERMINAL Export Project • Executed Project Framework Agreement in March 2019 • Issued Invitation to Tender to U.S. and international consortia to bid for Engineering, Procurement and Construction contract in May 2019 • Final investment decision (FID) to be mutually determined • 50/50 partnership – Energy Transfer – Shell US LNG, LLC • Convert existing LNG import facility to export terminal Current Terminal Assets • Fully permitted • 152-acre site – Utilizes existing infrastructure • Two existing deep-water docks to accommodate ships • Strategically located 3 up to 215,000 m capacity – Abundant natural gas supply 3 • Four LNG storage tanks with capacity of 425,000 m – Proximity to major pipelines • Estimated export capacity of ~16.5 22 million tonnes per year

APPENDIXAPPENDIX

CRUDE OIL SEGMENT Crude Oil Pipelines Crude Oil Acquisition & Marketing Ø ~9,524 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 (36.4%) interconnections and trading locations • Bayou Bridge Pipeline (60%)Ø Marketing crude oil to major pipeline interconnections and trading locations • Permian Express Partners (87.7%) 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 - ~28 million barrel capacity Ø Northeast Crude Terminals - ~3 million barrel capacity Ø Midland, TX Crude Terminal - ~2 million barrel capacity ET Opportunities Ø Delaware Basin Pipeline has ability to expand by 100 mbpd • Permian Express 4 went into full service October 1, 2019 Midland Nederland 24CRUDE OIL SEGMENT Crude Oil Pipelines Crude Oil Acquisition & Marketing Ø ~9,524 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 (36.4%) interconnections and trading locations • Bayou Bridge Pipeline (60%)Ø Marketing crude oil to major pipeline interconnections and trading locations • Permian Express Partners (87.7%) 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 - ~28 million barrel capacity Ø Northeast Crude Terminals - ~3 million barrel capacity Ø Midland, TX Crude Terminal - ~2 million barrel capacity ET Opportunities Ø Delaware Basin Pipeline has ability to expand by 100 mbpd • Permian Express 4 went into full service October 1, 2019 Midland Nederland 24

NGL & REFINED PRODUCTS SEGMENT NGL Storage NGL Pipeline Transportation Fractionation Ø TET Mont Belvieu Storage Hub ~46 million Ø ~4,750 miles of NGL Pipelines Ø 6 Mont Belvieu fractionators (up to 790 Mbpd) barrels NGL storage throughout Texas and Northeast Ø 40 Mbpd King Ranch, 25 Mbpd Geismar Ø 3 million barrel Mont Belvieu cavern under Ø Announced Lone Star expansion Ø 50 Mbpd Houston DeEthanizer and 30 to 50 Mbpd development Ø 352 mile, 24-inch NGL pipeline Marcus Hook C3+ Frac in service Q4 2017 Ø ~7 million barrels of NGL storage at Marcus Ø In-service Q4 2020Ø 150 Mbpd Frac VI placed in-service Q1 2019 Hook, Nederland and Inkster Ø 150 Mbpd Frac VII in-service Q1 2020 Ø Hattiesburg Butane Storage ~3 million Ø 150 Mbpd Frac VIII in-service Q2 2021 barrels ET NGL & Refined Products Assets 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 (Placed into initial service Q4 2018) Marcus Ø Total NGL volumes moved through Marcus Hook Hook reached as much as ~300 Mbpd for during Q3 2019 Ø ME2X expected in-service late 2019 Refined Products Ø ~2,200 miles of refined products pipelines in the northeast, Midwest and southwest US markets Ø 35 refined products marketing terminals with 8 million barrels storage capacity Mont Belvieu Nederland 25 (1) Upon full completionNGL & REFINED PRODUCTS SEGMENT NGL Storage NGL Pipeline Transportation Fractionation Ø TET Mont Belvieu Storage Hub ~46 million Ø ~4,750 miles of NGL Pipelines Ø 6 Mont Belvieu fractionators (up to 790 Mbpd) barrels NGL storage throughout Texas and Northeast Ø 40 Mbpd King Ranch, 25 Mbpd Geismar Ø 3 million barrel Mont Belvieu cavern under Ø Announced Lone Star expansion Ø 50 Mbpd Houston DeEthanizer and 30 to 50 Mbpd development Ø 352 mile, 24-inch NGL pipeline Marcus Hook C3+ Frac in service Q4 2017 Ø ~7 million barrels of NGL storage at Marcus Ø In-service Q4 2020Ø 150 Mbpd Frac VI placed in-service Q1 2019 Hook, Nederland and Inkster Ø 150 Mbpd Frac VII in-service Q1 2020 Ø Hattiesburg Butane Storage ~3 million Ø 150 Mbpd Frac VIII in-service Q2 2021 barrels ET NGL & Refined Products Assets 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 (Placed into initial service Q4 2018) Marcus Ø Total NGL volumes moved through Marcus Hook Hook reached as much as ~300 Mbpd for during Q3 2019 Ø ME2X expected in-service late 2019 Refined Products Ø ~2,200 miles of refined products pipelines in the northeast, Midwest and southwest US markets Ø 35 refined products marketing terminals with 8 million barrels storage capacity Mont Belvieu Nederland 25 (1) Upon full completion

MIDSTREAM SEGMENT Midstream Asset Map Midstream Highlights Ø Volume growth in key regions: • Q3 2019 gathered volumes reach a record 14 million mmbtu/d, and NGLs produced were ~574,000 bbls/d Ø Permian Capacity Additions: • 200 MMcf/d Rebel II processing plant came online in April 2018 PA • 200 MMcf/d Arrowhead II processing plant came online in OH October 2018 MD • 200 MMcf/d Arrowhead III processing plant came online in WV July 2019 • Additional 200 MMcf/d processing plant in the Delaware Basin expected in service by end of 2019 Current Processing Capacity Bcf/d Basins Served Permian 2.5 Permian, Midland, Delaware Midcontinent/Panhandle 0.9 Granite Wash, Cleveland North Texas 0.7 Barnett, Woodford South Texas 1.9 Eagle Ford North Louisiana 1.4 Haynesville, Cotton Valley Southeast Texas 0.4 Eagle Ford, Eagle Bine Eastern 0.2 Marcellus Utica 26 More than 40,000 miles of gathering pipelines with ~ 8+ Bcf/d of processing capacityMIDSTREAM SEGMENT Midstream Asset Map Midstream Highlights Ø Volume growth in key regions: • Q3 2019 gathered volumes reach a record 14 million mmbtu/d, and NGLs produced were ~574,000 bbls/d Ø Permian Capacity Additions: • 200 MMcf/d Rebel II processing plant came online in April 2018 PA • 200 MMcf/d Arrowhead II processing plant came online in OH October 2018 MD • 200 MMcf/d Arrowhead III processing plant came online in WV July 2019 • Additional 200 MMcf/d processing plant in the Delaware Basin expected in service by end of 2019 Current Processing Capacity Bcf/d Basins Served Permian 2.5 Permian, Midland, Delaware Midcontinent/Panhandle 0.9 Granite Wash, Cleveland North Texas 0.7 Barnett, Woodford South Texas 1.9 Eagle Ford North Louisiana 1.4 Haynesville, Cotton Valley Southeast Texas 0.4 Eagle Ford, Eagle Bine Eastern 0.2 Marcellus Utica 26 More than 40,000 miles of gathering pipelines with ~ 8+ Bcf/d of processing capacity

INTERSTATE PIPELINE SEGMENT 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 benefit from placing Rover in full service Sea Robin • In addition, expect to receive significant revenues from backhaul capabilities on Panhandle and Trunkline Gulf PEPL TGC TW FGT SR FEP Tiger MEP States Rover Total Miles of Pipeline 6,402 2,231 2,614 5,344 785 185 197 512 10 713 18,993 Capacity (Bcf/d) 2.8 0.9 2.1 3.4 2.0 2.0 2.4 1.8 0.1 3.25 20.75 OwnedStorage (Bcf)73.4 13 -------- ------ -- 86.4 Ownership 100% 100% 100% 50% 100% 50% 100% 50% 100% 32.6% 27 ~18,990 miles of interstate pipelines with ~21Bcf/d of throughput capacityINTERSTATE PIPELINE SEGMENT 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 benefit from placing Rover in full service Sea Robin • In addition, expect to receive significant revenues from backhaul capabilities on Panhandle and Trunkline Gulf PEPL TGC TW FGT SR FEP Tiger MEP States Rover Total Miles of Pipeline 6,402 2,231 2,614 5,344 785 185 197 512 10 713 18,993 Capacity (Bcf/d) 2.8 0.9 2.1 3.4 2.0 2.0 2.4 1.8 0.1 3.25 20.75 OwnedStorage (Bcf)73.4 13 -------- ------ -- 86.4 Ownership 100% 100% 100% 50% 100% 50% 100% 50% 100% 32.6% 27 ~18,990 miles of interstate pipelines with ~21Bcf/d of throughput capacity

INTRASTATE PIPELINE SEGMENT Intrastate Asset Map Intrastate Highlights Ø Continue to expect volumes to Mexico to grow, particularly on Trans-Pecos and Comanche Trail pipelines 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 Ø Phase I went into service in Q2 2018 and Phase II went into service in August 2019 In Service Capacity  Pipeline  Storage  Bi‐Directional  Major Connect  (Bcf/d) (Miles) Capacity (Bcf) Capabilities Hubs Trans Pecos & Comanche  Waha Header,  • ~ 9,400 miles of intrastate pipelines 2.5 338 NA No  Trail Pipelines Mexico Border Waha, Katy,  ET Fuel Pipeline 5.2 3,150 11.2 Yes • ~21 Bcf/d of throughput capacity Carthage Oasis Pipeline 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,  RIGS 2.1 450 NA No LA Tech Red Bluff Express 1.4 100 NA No Waha 28INTRASTATE PIPELINE SEGMENT Intrastate Asset Map Intrastate Highlights Ø Continue to expect volumes to Mexico to grow, particularly on Trans-Pecos and Comanche Trail pipelines 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 Ø Phase I went into service in Q2 2018 and Phase II went into service in August 2019 In Service Capacity Pipeline Storage Bi‐Directional Major Connect (Bcf/d) (Miles) Capacity (Bcf) Capabilities Hubs Trans Pecos & Comanche Waha Header, • ~ 9,400 miles of intrastate pipelines 2.5 338 NA No Trail Pipelines Mexico Border Waha, Katy, ET Fuel Pipeline 5.2 3,150 11.2 Yes • ~21 Bcf/d of throughput capacity Carthage Oasis Pipeline 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, RIGS 2.1 450 NA No LA Tech Red Bluff Express 1.4 100 NA No Waha 28

NON-GAAP RECONCILIATION Pro Forma for Mergers Full Year 2018 2019 2017 Q1 Q2 Q3 Q4 YTD Q1 Q2 Q3 YTD $ 1,208 $ 1,161 $ 3,549 Net income $ 2,366 $ 489 $ 633 $ 1,391 $ 852 $ 3,365 $ 1,180 - - - (Income) loss from discontinued operations 177 237 26 2 - 265 - 578 579 1,747 Interest expense, net 1,922 466 510 535 544 2,055 590 - 12 62 Impairment losses 1,039 - - - 431 431 50 34 54 214 Income tax expense (benefit) from continuing operations (1,833) (10) 68 (52) (2) 4 126 785 784 2,343 Depreciation, depletion and amortization 2,554 665 694 750 750 2,859 774 29 27 85 Non-cash compensation expense 99 23 32 27 23 105 29 122 175 371 (Gains) losses on interest rate derivatives 37 (52) (20) (45) 70 (47) 74 Unrealized (gains) losses on commodity risk management activities (59) 87 265 (97) (244) 11 (49) 23 (65) (91) Losses on extinguishments of debt 89 106 - - 6 112 18 - - 18 Inventory valuation adjustments (24) (25) (32) 7 135 85 (93) (4) 26 (71) Impairment of investment in unconsolidated affiliates 313 - - - - - - - - - Equity in (earnings) losses of unconsolidated affiliates (144) (79) (92) (87) (86) (344) (65) (77) (82) (224) Adjusted EBITDA related to unconsolidated affiliates 716 156 168 179 152 655 146 163 161 470 Adjusted EBITDA from discontinued operations 223 (20) (5) - - (25) - - - - Other, net (155) (41) 15 (33) 38 (21) 17 (37) (46) (66) Adjusted EBITDA (consolidated) 7,320 2,002 2,262 2,577 2,669 9,510 2,797 2,824 2,786 8,407 Adjusted EBITDA related to unconsolidated affiliates (716) (156) (168) (179) (152) (655) (146) (163) (161) (470) Distributable Cash Flow from unconsolidated affiliates 431 104 99 109 95 407 93 107 107 307 Interest expense, net (1,958) (468) (510) (535) (544) (2,057) (590) (578) (579) (1,747) Preferred unitholders' distributions (12) (24) (41) (51) (54) (170) (53) (64) (68) (185) Current income tax (expense) benefit (39) (468) 27 (24) (7) (472) (28) 7 (2) (23) Transaction-related income taxes - 480 (10) - - 470 - - - - Maintenance capital expenditures (479) (91) (126) (156) (137) (510) (92) (170) (178) (440) Other, net 67 7 7 16 19 49 18 19 19 56 Distributable Cash Flow (consolidated) 4,614 1,386 1,540 1,757 1,889 6,572 1,999 1,982 1,924 5,905 Distributable Cash Flow attributable to Sunoco LP (100%) (449) (84) (99) (147) (115) (445) (97) (101) (133) (331) Distributions from Sunoco LP 259 41 41 41 43 166 41 41 41 123 Distributable Cash Flow attributable to USAC (100%) - - (46) (47) (55) (148) (55) (54) (55) (164) Distributions from USAC - - 31 21 21 73 21 21 24 66 Distributable Cash Flow attributable to PennTex Midstream Partners, LP (100%) (19) - - - - - - - - - Distributions from PennTex Midstream Partners, LP 8 - - - - - - - - - Distributable Cash Flow attributable to noncontrolling interests in other non-wholly-owned subsidiaries (350) (147) (181) (253) (294) (875) (251) (293) (283) (827) Distributable Cash Flow attributable to the partners of ET - pro forma for ETO and Sunoco Logistics mergers 4,063 1,196 1,286 1,372 1,489 5,343 1,658 1,596 1,518 4,772 Transaction-related adjustments 57 (1) 14 12 27 52 (2) 5 3 6 Distributable Cash Flow attributable to the partners of ET, as adjusted - pro forma for ETO and Sunoco Logistics mergers $ 4,120 $ 1,195 $ 1,300 $ 1,384 $ 1,516 $ 5,395 $ 1,656 $ 1,601 $ 1,521 $ 4,778 Notes The closing of the ETO Merger has impacted the Partnership’s calculation of Distributable Cash Flow attributable to partners, as well as the number of ET Common Units outstanding and the amount of distributions to be paid to partners. In order to provide information on a comparable basis for pre-ETO Merger and post-ETO Merger periods, the Partnership has included certain pro forma information. Pro forma Distributable Cash Flow attributable to partners reflects the following ETO Merger related impacts: • ETO is reflected as a wholly-owned subsidiary and pro forma Distributable Cash Flow attributable to partners reflects ETO’s consolidated Distributable Cash Flow (less certain other adjustments, as follows). • Distributions from Sunoco LP and USAC include distributions to both ET and ETO. • Distributions from PennTex are separately included in Distributable Cash Flow attributable to partners. • Distributable Cash Flow attributable to noncontrolling interest in our other non-wholly-owned subsidiaries is subtracted from consolidated Distributable Cash Flow to calculate Distributable Cash Flow attributable to partners. Pro forma distributions to partners include actual distributions to legacy ET partners, as well as pro forma distributions to legacy ETO partners. Pro forma distributions to ETO partners are calculated assuming (i) historical ETO common units converted under the terms of the ETO Merger and (ii) distributions on such converted common units were paid at the historical rate paid on ET Common Units. Pro forma Common Units outstanding include actual Common Units outstanding, in addition to Common Units assumed to be issued in the ETO Merger, which are based on historical ETO common units converted under the terms of the ETO Merger. For the year ended December 31, 2017, the calculation of Distributable Cash Flow and the amounts reflected for distributions to partners and common units outstanding also reflect the pro forma impacts of the Sunoco Logistics Merger as though the merger had occurred on January 1, 2017. Definitions Adjusted EBITDA, Distributable Cash Flow and distribution coverage ratio are non-GAAP financial measures used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating results of ET's fundamental business activities and should not be considered in isolation or as a substitute for net income, income from operations, cash flows from operating activities, or other GAAP measures. There are material limitations to using measures such as Adjusted EBITDA, Distributable Cash Flow and distribution coverage ratio, including the difficulty associated with using either as the sole measure to compare the results of one company to another, and the inability to analyze certain significant items that directly affect a company’s net income or loss or cash flows. In addition, our calculations of Adjusted EBITDA, Distributable Cash Flow and distribution coverage ratio may not be consistent with similarly titled measures of other companies and should be viewed in conjunction with measurements that are computed in accordance with GAAP, such as segment margin, operating income, net income and cash flow from operating activities. We define Adjusted EBITDA as total partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Adjusted EBITDA reflects amounts for less than wholly-owned subsidiaries based on 100% of the subsidiaries’ results of operations. Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. Distributable Cash Flow is used by management to evaluate our overall performance. Our partnership agreement requires us to distribute all available cash, and Distributable Cash Flow is calculated to evaluate our ability to fund distributions through cash generated by our operations. We define Distributable Cash Flow as net income, adjusted for certain non-cash items, less distributions to preferred unitholders and maintenance capital expenditures. Non-cash items include depreciation, depletion and amortization, non-cash compensation expense, amortization included in interest expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and deferred income taxes. For unconsolidated affiliates, Distributable Cash Flow reflects the Partnership’s proportionate share of the investee’s distributable cash flow. On a consolidated basis, Distributable Cash Flow includes 100% of the Distributable Cash Flow of ET's consolidated subsidiaries. However, to the extent that noncontrolling interests exist among the Partnership’s subsidiaries, the Distributable Cash Flow generated by our subsidiaries may not be available to be distributed to our partners. In order to reflect the cash flows available for distributions to the partners of ET, the Partnership has reported Distributable Cash Flow attributable to the partners of ET, which is calculated by adjusting Distributable Cash Flow (consolidated), as follows: • For subsidiaries with publicly traded equity interests, other than ETO, Distributable Cash Flow (consolidated) includes 100% of Distributable Cash Flow attributable to such subsidiary, and Distributable Cash Flow attributable to the our partners includes distributions to be received by the parent company with respect to the periods presented. • For consolidated joint ventures or similar entities, where the noncontrolling interest is not publicly traded, Distributable Cash Flow (consolidated) includes 100% of Distributable Cash Flow attributable to such subsidiaries, but Distributable Cash Flow attributable to the partners reflects only the amount of Distributable Cash Flow of such subsidiaries that is attributable to our ownership interest. For Distributable Cash Flow attributable to partners, as adjusted, certain transaction-related and non-recurring expenses that are included in net income are excluded. 29 Distribution coverage ratio for the three months ended September 30, 2019 is calculated as Distributable Cash Flow attributable to partners, as adjusted, divided by distributions expected to be paid to the partners of ET in respect of the third quarter of 2019, which expected distributions total $809 million. NON-GAAP RECONCILIATION Pro Forma for Mergers Full Year 2018 2019 2017 Q1 Q2 Q3 Q4 YTD Q1 Q2 Q3 YTD $ 1,208 $ 1,161 $ 3,549 Net income $ 2,366 $ 489 $ 633 $ 1,391 $ 852 $ 3,365 $ 1,180 - - - (Income) loss from discontinued operations 177 237 26 2 - 265 - 578 579 1,747 Interest expense, net 1,922 466 510 535 544 2,055 590 - 12 62 Impairment losses 1,039 - - - 431 431 50 34 54 214 Income tax expense (benefit) from continuing operations (1,833) (10) 68 (52) (2) 4 126 785 784 2,343 Depreciation, depletion and amortization 2,554 665 694 750 750 2,859 774 29 27 85 Non-cash compensation expense 99 23 32 27 23 105 29 122 175 371 (Gains) losses on interest rate derivatives 37 (52) (20) (45) 70 (47) 74 Unrealized (gains) losses on commodity risk management activities (59) 87 265 (97) (244) 11 (49) 23 (65) (91) Losses on extinguishments of debt 89 106 - - 6 112 18 - - 18 Inventory valuation adjustments (24) (25) (32) 7 135 85 (93) (4) 26 (71) Impairment of investment in unconsolidated affiliates 313 - - - - - - - - - Equity in (earnings) losses of unconsolidated affiliates (144) (79) (92) (87) (86) (344) (65) (77) (82) (224) Adjusted EBITDA related to unconsolidated affiliates 716 156 168 179 152 655 146 163 161 470 Adjusted EBITDA from discontinued operations 223 (20) (5) - - (25) - - - - Other, net (155) (41) 15 (33) 38 (21) 17 (37) (46) (66) Adjusted EBITDA (consolidated) 7,320 2,002 2,262 2,577 2,669 9,510 2,797 2,824 2,786 8,407 Adjusted EBITDA related to unconsolidated affiliates (716) (156) (168) (179) (152) (655) (146) (163) (161) (470) Distributable Cash Flow from unconsolidated affiliates 431 104 99 109 95 407 93 107 107 307 Interest expense, net (1,958) (468) (510) (535) (544) (2,057) (590) (578) (579) (1,747) Preferred unitholders' distributions (12) (24) (41) (51) (54) (170) (53) (64) (68) (185) Current income tax (expense) benefit (39) (468) 27 (24) (7) (472) (28) 7 (2) (23) Transaction-related income taxes - 480 (10) - - 470 - - - - Maintenance capital expenditures (479) (91) (126) (156) (137) (510) (92) (170) (178) (440) Other, net 67 7 7 16 19 49 18 19 19 56 Distributable Cash Flow (consolidated) 4,614 1,386 1,540 1,757 1,889 6,572 1,999 1,982 1,924 5,905 Distributable Cash Flow attributable to Sunoco LP (100%) (449) (84) (99) (147) (115) (445) (97) (101) (133) (331) Distributions from Sunoco LP 259 41 41 41 43 166 41 41 41 123 Distributable Cash Flow attributable to USAC (100%) - - (46) (47) (55) (148) (55) (54) (55) (164) Distributions from USAC - - 31 21 21 73 21 21 24 66 Distributable Cash Flow attributable to PennTex Midstream Partners, LP (100%) (19) - - - - - - - - - Distributions from PennTex Midstream Partners, LP 8 - - - - - - - - - Distributable Cash Flow attributable to noncontrolling interests in other non-wholly-owned subsidiaries (350) (147) (181) (253) (294) (875) (251) (293) (283) (827) Distributable Cash Flow attributable to the partners of ET - pro forma for ETO and Sunoco Logistics mergers 4,063 1,196 1,286 1,372 1,489 5,343 1,658 1,596 1,518 4,772 Transaction-related adjustments 57 (1) 14 12 27 52 (2) 5 3 6 Distributable Cash Flow attributable to the partners of ET, as adjusted - pro forma for ETO and Sunoco Logistics mergers $ 4,120 $ 1,195 $ 1,300 $ 1,384 $ 1,516 $ 5,395 $ 1,656 $ 1,601 $ 1,521 $ 4,778 Notes The closing of the ETO Merger has impacted the Partnership’s calculation of Distributable Cash Flow attributable to partners, as well as the number of ET Common Units outstanding and the amount of distributions to be paid to partners. In order to provide information on a comparable basis for pre-ETO Merger and post-ETO Merger periods, the Partnership has included certain pro forma information. Pro forma Distributable Cash Flow attributable to partners reflects the following ETO Merger related impacts: • ETO is reflected as a wholly-owned subsidiary and pro forma Distributable Cash Flow attributable to partners reflects ETO’s consolidated Distributable Cash Flow (less certain other adjustments, as follows). • Distributions from Sunoco LP and USAC include distributions to both ET and ETO. • Distributions from PennTex are separately included in Distributable Cash Flow attributable to partners. • Distributable Cash Flow attributable to noncontrolling interest in our other non-wholly-owned subsidiaries is subtracted from consolidated Distributable Cash Flow to calculate Distributable Cash Flow attributable to partners. Pro forma distributions to partners include actual distributions to legacy ET partners, as well as pro forma distributions to legacy ETO partners. Pro forma distributions to ETO partners are calculated assuming (i) historical ETO common units converted under the terms of the ETO Merger and (ii) distributions on such converted common units were paid at the historical rate paid on ET Common Units. Pro forma Common Units outstanding include actual Common Units outstanding, in addition to Common Units assumed to be issued in the ETO Merger, which are based on historical ETO common units converted under the terms of the ETO Merger. For the year ended December 31, 2017, the calculation of Distributable Cash Flow and the amounts reflected for distributions to partners and common units outstanding also reflect the pro forma impacts of the Sunoco Logistics Merger as though the merger had occurred on January 1, 2017. Definitions Adjusted EBITDA, Distributable Cash Flow and distribution coverage ratio are non-GAAP financial measures used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating results of ET's fundamental business activities and should not be considered in isolation or as a substitute for net income, income from operations, cash flows from operating activities, or other GAAP measures. There are material limitations to using measures such as Adjusted EBITDA, Distributable Cash Flow and distribution coverage ratio, including the difficulty associated with using either as the sole measure to compare the results of one company to another, and the inability to analyze certain significant items that directly affect a company’s net income or loss or cash flows. In addition, our calculations of Adjusted EBITDA, Distributable Cash Flow and distribution coverage ratio may not be consistent with similarly titled measures of other companies and should be viewed in conjunction with measurements that are computed in accordance with GAAP, such as segment margin, operating income, net income and cash flow from operating activities. We define Adjusted EBITDA as total partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Adjusted EBITDA reflects amounts for less than wholly-owned subsidiaries based on 100% of the subsidiaries’ results of operations. Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. Distributable Cash Flow is used by management to evaluate our overall performance. Our partnership agreement requires us to distribute all available cash, and Distributable Cash Flow is calculated to evaluate our ability to fund distributions through cash generated by our operations. We define Distributable Cash Flow as net income, adjusted for certain non-cash items, less distributions to preferred unitholders and maintenance capital expenditures. Non-cash items include depreciation, depletion and amortization, non-cash compensation expense, amortization included in interest expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and deferred income taxes. For unconsolidated affiliates, Distributable Cash Flow reflects the Partnership’s proportionate share of the investee’s distributable cash flow. On a consolidated basis, Distributable Cash Flow includes 100% of the Distributable Cash Flow of ET's consolidated subsidiaries. However, to the extent that noncontrolling interests exist among the Partnership’s subsidiaries, the Distributable Cash Flow generated by our subsidiaries may not be available to be distributed to our partners. In order to reflect the cash flows available for distributions to the partners of ET, the Partnership has reported Distributable Cash Flow attributable to the partners of ET, which is calculated by adjusting Distributable Cash Flow (consolidated), as follows: • For subsidiaries with publicly traded equity interests, other than ETO, Distributable Cash Flow (consolidated) includes 100% of Distributable Cash Flow attributable to such subsidiary, and Distributable Cash Flow attributable to the our partners includes distributions to be received by the parent company with respect to the periods presented. • For consolidated joint ventures or similar entities, where the noncontrolling interest is not publicly traded, Distributable Cash Flow (consolidated) includes 100% of Distributable Cash Flow attributable to such subsidiaries, but Distributable Cash Flow attributable to the partners reflects only the amount of Distributable Cash Flow of such subsidiaries that is attributable to our ownership interest. For Distributable Cash Flow attributable to partners, as adjusted, certain transaction-related and non-recurring expenses that are included in net income are excluded. 29 Distribution coverage ratio for the three months ended September 30, 2019 is calculated as Distributable Cash Flow attributable to partners, as adjusted, divided by distributions expected to be paid to the partners of ET in respect of the third quarter of 2019, which expected distributions total $809 million.

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SemGroup (NYSE:SEMG)
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From Oct 2023 to Oct 2024