Energy Transfer Analyst Meeting Dallas, Texas. November 14, 2012

Energy Transfer Analyst Meeting Dallas, Texas November 14, 2012

Legal Disclaimer This presentation relates to a meeting among members of management of Energy Transfer Partners, L.P. (ETP), Energy Transfer Equity, L.P. (ETE), and Sunoco Logistics Partners L.P. (SXL) and securities analysts to be held in Dallas, Texas on Wednesday, November 14, 2012. At this meeting, members of management of ETP, ETE and SXL may make statements about future events, outlook and expectations related to ETP, ETE, SXL, Southern Union Company (SUG), Panhandle Eastern Pipeline Company, LP (PEPL), and their subsidiaries and this presentation may contain statements about future events, outlook and expectations related to ETP, ETE SXL, SUG and PEPL and their subsidiaries all of which statements are forward-looking statements. Any statement made by a member of management of ETP, ETE or SXL at this meeting 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 ETP, ETE or SXL 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 ETP, ETE, SXL, SUG or PEPL. While ETP, ETE, SXL, SUG and PEPL 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 ETP, ETE, SXL, SUG and PEPL and their subsidiaries to be materially different. These risks and uncertainties are discussed in more detail in the filings made by ETP, ETE, SXL, SUG and PEPL with the Securities and Exchange Commission, copies of which are available to the public. ETP, ETE, SXL, SUG and PEPL 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. 2

Meeting Agenda Opening Remarks Kelcy Warren Commercial Operations and Growth Projects Mackie McCrea Financial Overview Martin Salinas Closing Remarks Kelcy Warren 3

Opening Remarks

The Energy Transfer Evolution 5

1997: 20 Employees New Energy Transfer Assets Energy Transfer Was Formed and Comprised Solely of the Vantex System 6

2002: 300 Employees New Energy Transfer Assets Existing Energy Transfer Assets Acquired Aquila, Rusk County, Whiskey Bay Assets and Louisiana and Southeast Texas Gathering System 7

2003: 318 Employees New Energy Transfer Assets Existing Energy Transfer Assets Acquired Oasis Pipeline Expanding Footprint into Permian Basin 8

2004: 321 Employees New Energy Transfer Assets Existing Energy Transfer Assets Acquired TUFCO and ET Fuel Systems & Completed Bossier Expansion Project 9

2005: 363 Employees New Energy Transfer Assets Existing Energy Transfer Assets Acquired Houston Pipeline System (HPL) 10

2006: 564 Employees New Energy Transfer Assets Existing Energy Transfer Assets Completed FWB North Loop & Acquired Transwestern Interstate Pipeline (TW) 11

2007: 890 Employees New Energy Transfer Assets Existing Energy Transfer Assets Completed FWB Outlet Cleburne to Carthage 42 12

2008: 1,040 Employees New Energy Transfer Assets Existing Energy Transfer Assets Completed FWB, East TX and TW Expansions 13

2009: 1,153 Employees New Energy Transfer Assets Existing Energy Transfer Assets Enlarged Interstate Footprint With Construction of MEP and TW Phoenix Lateral & Finalized Additional FWP Outlets and Katy Expansion 14

2010: 1,933 Employees New Energy Transfer Assets Existing Energy Transfer Assets Established Asset Exposures in Multiple Emerging Shale Plays & Acquired Regency Energy Partners and SEC Energy 15

2011: 2,472 Employees New Energy Transfer Assets Existing Energy Transfer Assets Constructed Eagle Ford Pipelines & Acquired LDH Energy (Lone Star NGL) 16

2012: 14,000 Employees New Energy Transfer Assets Existing Energy Transfer Assets Acquired Southern Union, Sunoco, and GP, IDR & LP Interests in Sunoco Logistics 17

Energy Transfer Today A Leading Midstream Energy Platform ETP Assets Pipelines Processing Storage Treating SXL Assets Pipelines Terminals SUG Assets RGP Assets Pipelines Pipelines/Gathering Storage Processing Trunkline LNG Note: Excludes SUN Retail and SUG Distribution Assets 18

Energy Transfer Has Evolved Interstate Pipeline Build-out Diversified into stable, long-term and low-risk fee-based cash flows LDH Energy Acquisition Contribution of Propane Business to AmeriGas Southern Union Merger Sunoco Acquisition Southern Union Drop-down Established NGL platform which further expanded downstream NGL capabilities in response to producer demand Minimized exposure to weather sensitive non-core business Expanded geographic reach with emphasis on regulated, stable fee-based income Created best in class natural gas, crude oil, NGL and refined product logistics and transportation platform Transferred operational control of SUG assets to ETP to maximize commercial and operational synergies Eagle Ford & NGL Build-out Diversifies ETP into higher-margin rich gas & liquids business Energy Transfer has undertaken several initiatives in response to changing market dynamics to expand the services we provide with an emphasis on geographic, business line and fee-based diversification 19

to Adjust to Changing Market Dynamics $/MMBtu $16.00 $12.00 $8.00 $4.00 Henry Hub (left axis) Inverse Waha-HSC Differential (right axis) 1 $/MMBtu $4.00 $3.00 $2.00 $1.00 $0.00 ($1.00) ($2.00) $0.00 11/1/08 11/1/09 11/1/10 11/1/11 10/31/12 ($3.00) $/Bbl $/Gallon $150 WTI (left axis) NGL Composite (right axis) 2 $2.00 $125 $100 $1.50 $75 $1.00 $50 $25 $0.50 $0 11/1/08 11/1/09 11/1/10 11/1/11 10/31/12 Source: Bloomberg, OPIS 1 HSC represents the Houston Ship Channel natural gas price 2 The natural gas liquids (NGL) composite price is derived from the daily Bloomberg spot price data for natural gas liquids at Mont Belvieu, Texas, weighted by gas processing plant production volumes of each product as reported on Form EIA-816, "Monthly Natural Gas Liquids Report" $0.00 20

Where Are We Headed? Having completed several major transactions over the past year, our focus now is the full integration and optimization of our diversified asset portfolio to enhance unitholder value We have already made significant progress towards our goal of $100 million in annual synergies at Southern Union and are undertaking the same detailed process with Sunoco We aim to simplify our organization over the next 1 2 years in order to provide greater transparency and drive efficiencies The formation of Holdco was the beginning step of our overall simplification strategy of moving assets to ETP and transforming ETE back to a pure play GP Numerous asset optimization opportunities exist which may include the movement of businesses from one part of the family to another or the conversion of assets into different lines of business We are also looking at opportunities to streamline our asset portfolio and to create a more focused organization through the sale or transfer of noncore assets In addition, we are evaluating a number of very attractive growth opportunities associated with existing and recently acquired assets Our core focus is simplifying our structure to provide greater transparency while integrating our portfolio of assets to maximize commercial opportunities and resume distribution growth 21

Commercial Operations and Growth Projects

Our Transformed Business Mix Presents Numerous Exciting Growth Opportunities Recent acquisitions have diversified our business with a greater emphasis on the transportation of liquid hydrocarbons We are well positioned to take advantage of growth in the richer gas shale plays while remaining levered to a rebound in natural gas prices in our intrastate transportation and storage segment Every $0.10/MMBtu increase in basis differentials could create an additional $72 million per year of incremental EBITDA on our intrastate system Every $0.10/MMBtu change in seasonal spread results in $4.5 million of incremental annual EBITDA in our storage operations Our complementary asset portfolio provides us with an opportunity to optimize assets by re-purposing our pipelines for the most efficient and profitable use Our organic growth activities along with recent acquisitions have positioned us for significant growth Highest priorities Completing our projects on time and under budget Focus on running our existing plants, our intrastate and interstate network of pipelines and our NGL pipelines and fractionators as efficiently, as fully and as profitably as possible 23

The Energy Transfer Asset Footprint Natural Gas NGL Pipelines NGL Fractionation NGL Storage NGL Pipelines Gas Gathering Gas Processing Natural Gas Pipelines Natural Gas Storage Natural Gas Pipelines LNG Exports LNG Imports Crude Crude Oil Pipelines Crude Oil Storage Crude Oil Refining Refined Product Storage & Terminalling Refined Products Pipelines Recent acquisitions have diversified Energy Transfer into all areas of the midstream value chain, allowing us to provide enhanced operational capabilities to our customers while better positioning us to respond to changing market dynamics Services added through recent acquisitions 24

Midstream Segment 25

Midstream Highlights Focuses on the gathering, compression, treating, blending, processing, and marketing of natural gas through: Approximately 12,000 miles of consolidated natural gas gathering pipelines 8 natural gas processing plants 17 natural gas treating facilities 5 natural gas conditioning facilities Operations are concentrated in the Austin Chalk, Barnett Shale, Bossier Sands, Eagle Ford Shale, Haynesville Shale, Marcellus Shale, and Permian Basin Objective is to gather non-pipeline quality gas, remove impurities, separate liquids and re-deliver pipeline quality gas and liquids to market Integrated with our intrastate transportation and storage operations to enhance operational capabilities By-passing capabilities at our processing plants protect against uneconomic processing conditions More than $1.2 billion of new Eagle Ford Shale growth projects at attractive EBITDA multiples announced since October 2010 26

ETP Midstream and NGL Segments Strategy Initial Step-out Advance Gathering Footprint System Integration Advance Processing & Takeaway Capacity Extending Vertical Value Chain Completed Under Construction San Cajos 38 miles of 24 /30 Las Tiendas 300 MMcf/d treater Dos Hermanas, Dimitt & Webb 86- miles of 16 & 24 REM 215 miles 30 /42 Tilden field compression Chisholm/Shiner 75 miles of 20 La Grange Plant expansion 100 MMcf/d Liquid handling facilities NGL pipelines Freedom 8 Liberty 10 (115 miles) Chisholm Plant 120 MMcf/d Jackson Plant 800 MMcf/d Kenedy Plant 200 MMcf/d NGL pipelines WT Gateway 16, Justice 20, Spirit 8 (685 miles) Mt. Belvieu Fracs 1 & 2 200,000 Bbl/d HPL/Oasis & Bammel Storage provide access to NGL markets More Than $3.1 Billion of Invested Capital 1,400 miles of 8 42 pipeline 127,000 HP compression 1.6 Bcf/d natural gas processing capacity 400,000 Bbl/d NGL processing capacity 200,000 Bbl/d fractionation capacity 27

ETP Eagle Ford Rich Gas Footprint Initial Step-out W Texas Gateway 16 209,000 Bbl/d La Grange Expansion 100 MMcf/d Chisholm 120 MMcf/d Advance Gathering Footprint System Integration Mt. Belvieu Fracs 1 & 2 200,000 Bbl/d Advance Extending Processing Vertical Value & Takeaway Freedom 8 & Liberty Chain 10 Capacity 75,000 Bbl/d REM 30 & 42 San Cajos 38 miles of 24 /30 Las Tiendas 300 MMcf/d treater Las Bonitas 24 & 30 Dos Hermanas, Dimitt & Webb 86- miles of 16 & 24 Completed Kenedy 200 MMcf/d REM 215 miles La Grange plant 30 /42 expansion 100 Tilden field compression Chisholm\Shiner 75 miles of 20 Chisholm plant 120 MMcf/d MMcf/d Chisholm 20 Jackson Plant 800 Liquid handling facilities MMcf/d Kenedy Plant 200 NGL pipelines Jackson 800 MMcf/d MMcf/d Freedom 8 REM Expansion Liberty 10 (115 miles) NGL pipelines WT Gateway 16, Justice 20, Spirit 8 (685 miles) Working Mt. Belvieu Fracs 1 & 2-200 MBbl/d Spirit HPL\Oasis 8 & Bammel Storage provide access to liquid markets Justice 20 34,000 Bbl/d Dos Hermanas 24 San Cajos 24 & 30 Las Tiendas Treater 300 MMcf/d 28

ETP Eagle Ford Shale Projects with Oasis and HPL 29

ETP Woodford Project (Red River Pipeline) Red River Pipeline 95 miles of 30-inch pipe and 22 miles of 24-inch loop of existing system 450 MMcf/d of initial pipeline capacity In-service September 2012 Godley Plant Expansion 200 MMcf/d Cryo plant at Godley Supported by long-term agreement with XTO/Exxon and EOG Expected in-service by Q3 2013 Currently flowing ~60,000 Mcf/d 30

Southern Union Gas Services ( SUGS ) West Texas Permian Basin Overview 5,500 miles of pipelines Coverage 16 counties in the Permian Basin of West Texas and Southeast New Mexico 525 MMcf/d of cryogenic processing capacity 615 MMcf/d of sour gas treating capacity Nearly 42,000 Bbl/d of NGL production in Q3 2012 Plants connected via high pressure header system providing operation flexibility Attractive downstream markets for natural gas liquids and residue gas 31

SUGS Red Bluff Project 200 MMcf/d processing capacity 220 MMcf/d treating capacity 33 miles of 10 NGL pipeline 25+ miles of large-diameter gathering pipeline 25,000+ HP field compression In-service July 2013 NGL pipeline interconnect with Lone Star 32

SUGS Mi Vida Project 200 MMcf/d processing capacity Existing Mi Vida treating capacity 7 miles of 10 NGL pipeline 24+ miles of large-diameter gathering pipeline 30,000+ HP field compression In-service mid-2014 NGL pipeline interconnect with Lone Star Residue outlet connected to Oasis 33

NGL Transportation and Storage Segment 34

Lone Star NGL Asset Overview Storage Pipeline Transportation Fractionation & Processing Refinery Services ~47 million Bbl of usable NGL storage capacity with an additional 3 million Bbl of Y-grade in progress ~24 million Bbl of brine pond capacity with an additional 6 million Bbl in progress West Texas NGL Pipeline - 1,066 mile 12-inch pipeline with 144,000 Bbl/d of capacity West Texas Gateway Pipeline 570 mile 16-inch pipeline with 209,000 Bbl/d of capacity Two cryogenic processing plants 25,000 Bbl/d fractionator in Geismar, Louisiana Two 100,000 Bbl/d fractionators under construction at Mont Belvieu 82 MMcf/d cryogenic capacity Sea Robin Processing Plant (20% equity interest) 850 MMcf/d of gas capacity and 26,000 Bbl/d of liquids capacity 35

Lone Star NGL Pipeline & Fractionation Mont Belvieu Fractionators Two 100,000 Bbl NGL fractionators under construction at Mont Belvieu Additional Y-grade liquids storage facilities under development A substantial amount of fractionation capacity will be utilized for NGLs from ETP s Justice pipeline Frac 1 expected in-service December 2012 Frac 2 expected in-service Q4 2013 West Texas Gateway Pipeline (NGL) Approximately 570 miles of 16-inch pipe with an initial capacity of 209,000 Bbl/d Lone Star has secured capacity through ETP s Justice NGL pipeline from Jackson County to Mont Belvieu In the process of line packing liquids Expected in-service December 2012 36

Lone Star Mt. Belvieu Fractionator 37

ETP NGL Pipeline Projects Freedom Pipeline 43 mile, 8-inch NGL pipeline 40,000 Bbl/d design capacity In-service September 2011 Liberty Pipeline 93 mile, 12-inch NGL pipeline 90,000 Bbl/d design capacity 50/50 JV with Copano In-service September 2011 Justice Pipeline 130 mile, 20-inch NGL pipeline 340,000 Bbl/d design capacity Expected in-service December 2012 38

Interstate Transportation Segment 39

Interstate Highlights Our pipelines provide access to multiple shale plays, diversified end-user markets and storage facilities High proportion of reservation based fees Transwestern: Substantially all revenues derived from firm reservation fees Tiger: 100% of 2.4 Bcf/d capacity sold under 10- and 15-year fee-based agreements FEP: Approximately 93% of 2.0 Bcf/d capacity sold under 10- and 12- year fee-based agreements FGT: Over 98% of FGT revenue is derived from fixed reservation revenues sold under average of 13-year agreements PEPL and Trunkline: 90% of revenues from reservation charges associated with short-term and long-term firm transportation and storage services Trunkline LNG: ~100% of revenues from reservation charges associated with LNG re-gasification services with all contracts expiring in 2030 Evaluating opportunities to convert and optimize assets from traditional interstate natural gas service to capitalize on changing market conditions 40

Energy Transfer Interstate Overview Over 18,000 miles of Interstate pipelines with ~13.5 Bcf/d of capacity 41

Trunkline Crude Oil Conversion Project Potential Market: 2.05 million Bbl/d refinery market in Beaumont, Port Arthur & Lake Charles area (capacity including Motiva PAR expansion) 2.1+ million Bbl/d refinery market in St. James/Baton Rouge area 1.3+ million Bbl/d refinery market in Houston area Project Status: Filed application for abandonment with the FERC in July 2012 Expect to obtain FERC approval of abandonment by Q2 2013 In-service by mid-2014 Estimated project cost ~$1.5 billion 42

LNG Import Project Overview One of the nation s largest LNG import terminals located in Lake Charles, LA 2.1 Bcf/d of peak send out capacity 9.0 Bcf of storage, 1.1 Bcf/d of processing capacity Fully contracted to BG LNG Services through 2030 Year Milestone 1978 Construction Began 1982 Construction Complete 6.3 Bcf of Storage in 3 LNG Storage Tanks 630,000 Mcf/d of Sendout Capacity 2001 BG Group Signs Firm Capacity Agreement 2002 Phase I Expansion Agreement Signed 2003 104 Cargoes Received Phase II Expansion Agreement Signed 2006 Phase I & II Expansion Placed In-Service Storage Capacity Increased to 9.0 Bcf (1 Additional Tank) Sendout Capacity Increased to 1.8 Bcf/d (2.1 Bcf/d Peak) Addition of Second Unloading Dock Infrastructure Enhancement Project (IEP) Agreement Executed 2010 IEP Placed In-Service Ambient Air Vaporization of Sendout Liquids Extraction Capacity of 1.1 Bcf/d 43

Existing LNG Import Terminal 44

LNG Export Project Overview Project will use existing LNG re-gas infrastructure including storage tanks, terminal facilities, etc. Export capacity up to 15 mtpa (up to 2.0 Bcf/d from three trains) Additional upstream transportation revenue of up to 2.0 Bcf/d associated with this project Currently in commercial negotiations with counterparties No material capital expenditures expected before investment decision has to be made in late 2014 Project Timeline Date FERC Public Scoping Meeting September 2012 Pre-FEED Study Complete Q1 2013 DOE Non-FTA Authorization Received Q1 2013 FERC Application Filed September 2013 FEED Study Complete February 2014 FERC & Air Permit Approval Q4 2014 Final Investment Decision Q4 2014 EPC Contract Bid Package Issued (Turn-Key) EPC Contract Awarded & Construction Starts In-Service Date Train 1 Train 2 Train 3 Q2 2014 Q1 2015 Late 2018 to Mid-2020, Depending on the Number of Trains Note: Subject to change 45

Intrastate Transportation and Storage Segment 46

Intrastate Transportation and Storage Segment Focused on the transportation of natural gas to major markets from various prolific natural gas producing regions Approximately 8,000 miles of intrastate natural gas transportation pipelines Transportation volumes currently 10.0 Bcf/d 74 Bcf of natural gas storage capacity Bammel (64.5 Bcf) Bethel (3.3 Bcf) Bryson (6.2 Bcf) Numerous pipeline transportation opportunities from the Eagle Ford Shale, the Permian Basin and the Woodford Total new built capacity of 6.0 Bcf/d Approximately 73% under long-term fee-based contracts Legacy pipeline capacity of 4.0 Bcf/d Approximately 50% under long-term contracts (combination of fee based and acreage dedications) 47

Sunoco 48

Retail Marketing Overview Sunoco Retail Outlets 2011 Gasoline Volume State Rank Market Share % NY 1 (Tie) 18% PA 1 (Tie) 17% NJ 3 12% CT 4 12% MA 5 10% RI 5 10% 100 352 18 2 1 484 2 92 86 189 584 155 382 263 55 110 21 51 157 50 3 4 3 1 66 1 14 14 23 149 1 40 37 153 75 19 84 114 1 7 25 Co-ops: 19% Dealers: 27% Total: 4.6 billion gallons Retail Sites as of 12/31/11 Distributors: 54% 54 1 93 Co-ops: 417 13 124 27 114 Dealers: 963 Distributors: 3,553 61 458 Total: 4,933 sites 49

Retail Marketing Provides Stable Cash Flow Segment EBITDA ($ millions) $500 $439 $400 $300 $269 $261 Average: $277 $233 $221 $241 Average (ex-2008): $245 $200 $100 $0 2006 2007 2008 2009 2010 2011 50

Sunoco Logistics 51

Shale Opportunities Terminal Nederland Terminal Eagle Point Terminal Explorer (JV) SXL Crude West Shore (JV) SXL Refined Product MVPL (JV) WTG (JV) Wolverine (JV) Yellowstone (JV) Inland (JV) Organic Growth Projects Mariner West Mariner East Allegheny Permian Basin 52

Historical & Forecasted Basin Production Volumes Thousand Bbl/d 2,000 Permian Bakken 1,500 1,000 500 0 1990 1994 1998 2002 2006 2010 2014 2018 2022 Source: North Dakota Authority, EIA, PIRA 53

Financial Overview

Illustrative ETP Holdco Distributable Cash Flow Components Illustrative ETP Holdco DCF Energy Transfer Equity, L.P. + Southern Union Adjusted EBITDA 1 + Sunoco Adjusted EBITDA + A: Class F Distributions from ETP 2 100.0% IDR 1.1% GP 16.7% LP Energy Transfer Partners, L.P. 40% Ownership (Board Majority) C A D B 60% Ownership E ETP Holdco Corp + B: Class E Distributions from ETP 3 = Holdco Adjusted EBITDA - Southern Union Interest Expense - Sunoco Interest Expense - C: Holdco Intercompany Interest Expense 4 - Holdco Cash Taxes 5 - Southern Union Maintenance Capex - Sunoco Maintenance Capex = Holdco Distributable Cash Flow x E: 60% = Holdco Dividend to ETE Assets 6 x D: 40% = Holdco Dividend to ETP Sunoco, Inc. Southern Union Company Note: Actual reporting may differ from illustrative example. For additional details on ETP Holdco cash flows refer to Form 8-K filed 6/20/12 1 Includes distributions on 2.2 million ETP units received as consideration for Citrus drop down 2 90.7 million Class F units @ $3.75 distribution per unit per annum. Class F units do not affect the magnitude of the IDR payout 3 8.9 million Class E units @ $1.41 distribution per unit per annum 4 Interest expense calculated as $2.6 billion X ETP's weighted average cost of debt 5 Through Class F units, Holdco receives a portion of ETP's taxable income / loss 6 Includes ETP s operating assets, unconsolidated affiliates, and SXL LP/GP/IDR interests 55

Illustrative ETP Distributable Cash Flow Components Illustrative ETP DCF E Energy Transfer Partners, L.P. F 40% Ownership (Board Majority) C A G D B 100.0% IDR 2.0% GP 32.4% LP ETP Holdco Corp + D: Holdco Dividend to ETP + E: ETP Asset EBITDA + F: Distributions from Unconsolidated Affiliates 1 + G: Distributions from SXL ETP Adjusted Cash EBITDA + C: ETP Intercompany Interest Income 2 - ETP Interest Expense - ETP Maintenance Capex - ETP Cash Taxes - A: Class F Distributions from ETP 3 - B: Class E Distributions from ETP 4 = ETP Distributable Cash Flow Operating Assets Unconsolidated Affiliates 1 Sunoco Logistics Partners L.P. Note: Actual reporting may differ from illustrative example. For additional details on ETP cash flows refer to Form 8-K filed 6/20/12 1 Includes Citrus, AmeriGas, and FEP 2 Interest expense calculated as $2.6 billion X ETP's weighted average cost of debt 3 90.7 million Class F units @ $3.75 distribution per unit per annum. Class F units do not affect the magnitude of the IDR payout 4 8.9 million Class E units @ $1.41 distribution per unit per annum 56

Illustrative SXL Distribution Cash Flows ETP is positioned to benefit from SXL s significant growth opportunities through future distribution increases ETP benefits from the LP, GP, and IDR interests it owns in SXL SXL currently has an annual distribution per LP unit of $2.07, and will be in the 50% IDR Tier at a distribution per unit of $2.11 (an increase of $0.04 from the current distribution per unit) In addition, ETP will receive GP and IDR distributions on any new SXL equity issued to fund growth Option to drop down projects that are better aligned with SXL s business creates an alternative to funding projects at ETP while continuing participation in future distributable cash flow growth Illustrative SXL Distribution Cash Flows ($ in millions, except for per unit data) ETP SXL LP Units 33.5 33.5 33.5 33.5 33.5 SXL Annual LP Distributions Per Unit $2.07 $2.32 $2.57 $2.82 $3.07 Increase in SXL LP Distributions Per Unit 1 12% 24% 36% 48% 2% Tier 2 $1 $1 $1 $1 $1 15% Tier 2 2 2 2 2 2 37% Tier 2 79 82 82 82 82 50% Tier 2 0 22 48 74 99 Distributions Total $82 $107 $133 $159 $184 Increase in IDR Distributions Total 1 30% 62% 94% 124% LP Distributions Total $69 $78 $86 $94 $102 Increase in LP Distributions Total 1 12% 24% 36% 48% Total SXL Distributions to ETP $151 $185 $219 $253 $286 Increase in Total SXL Distributions to ETP 1 22% 45% 68% 89% Note : These distributions and respective increases are illustrative and not forecasts for SXL distribution increases 1 Increase is from current SXL distribution of $2.07 per unit per annum 2 Includes IDR and 2% General Partner interest 57

Financial Objectives Resume growth in distributions Intense focus on minimizing costs while extracting synergies from recent acquisitions Grow Distributable Cash Flow by targeting projects/assets that provide rates of return well in excess of our cost of capital Achieve and maintain a distribution coverage of at least 1.05x Diversify our business portfolio with an emphasis on stable, long-term fee-based cash flows Generate stable cash flows from a high quality diversified asset base Support growth projects with long-term fee-based contracts Maintain a balanced approach to funding growth with a strong balance sheet and sufficient liquidity Target Debt/Adjusted EBITDA ratio of 4.00x 4.25x Preserve financial flexibility to be able to take advantage of attractive growth projects Manage commodity price exposure Mitigate natural gas price exposure through hedging and fee-based contract structures 58

Diversified Business Profile Adjusted EBITDA by Operating Segment Intrastate Midstream Interstate Propane NGL Retail Marketing Crude/Refined Products 100% 18% 18% 5% 13% 21% 24% 75% 16% 14% 21% 6% 5% 4% 8% 14% 21% 50% 22% 38% 35% 25% 52% 47% 38% 13% 12% 17% 17% 0% 2009 2010 2011 Pro Forma 2012E 2013E 1 1 Note: Adjusted EBITDA reconciliation is in the Supplemental Materials. ETP Adjusted EBITDA excludes Other 1 ETP pro forma for contribution of propane to AmeriGas Partners, L.P., Citrus acquisition, and Sunoco/ETP Holdco transactions. Excludes distributions from AmeriGas Partners, L.P. Assumes full consolidation of SXL and ETP Holdco 59

Energy Transfer s Strong Balance Sheet & Financial Flexibility Energy Transfer has a strong and demonstrated track record of successfully accessing the capital markets Committed to investment grade credit ratings for ETP, SUG, PEPL, and SXL ETP has a $2.5 billion revolving credit facility due 2017 ($1.4 billion available at 10/5/12) 1 SUG has a $700 million maturity credit facility due 2016 ($450 million available at 9/30/12) ETP became co-obligor on SUN notes upon closing of the acquisition on 10/5/12 ETP Pro Forma Debt Capitalization ($ millions) 9/30/12 Energy Transfer Partners Revolving Credit Facility $ 1,112 ETP Senior Notes 7,692 Transwestern Senior Notes 870 Other 7 Sub-total 9,681 Sunoco Senior Notes 965 Sub-total 965 Southern Union Revolving Credit Facility 251 SUG Senior Notes 679 SUG Jr Sub Notes 600 PEPL Senior Notes 1,166 LNG Holdings Term Loan 455 Other 7 Sub-total 3,159 1 Consolidated Total $ 13,805 1 Includes $620 million revolver borrowing for Sunoco Acquisition on 10/5/12 60

Balanced Approach To Funding Growth Total Capital Deployed 1 (millions): Equity + Excess Cash Flow $1,292 $1,204 $3,062 $1,896 $1,328 $834 $3,428 $3,605 $16,648 2 Debt 51% 76% 37% 66% 40% 24% 37% 53% 47% 49% 24% 63% 34% 60% 76% 63% 47% 53% FY 2005 FY 2006 16 Mo. Ended 3 12/31/07 2008 2009 2010 2011 2012 YTD Cumulative 1 Excludes maintenance capital 2 Equity includes net proceeds from issuance of common units, capital contributions from general partner, capital contributions from non-controlling interest, and common units issued in connection with acquisitions. Excess Cash Flow includes net cash provided by operating activities less maintenance capital expenditures and distributions paid plus proceeds from sale of assets and discontinued operations 3 ETP changed from a fiscal year end of 8/31 to a calendar year end at the end of 2007. This column includes the fiscal year ended 8/31/07 plus the four months ended 12/31/07 61

Commodity Exposure Significant fee-based cash flows minimize volatility from commodity price movements As of October 31, 2012, we ve hedged 100% of our 2012 and 16% of our 2013 intrastate retained fuel exposure with swaps: Remainder of 2012: 60,000 MMBtu/d at an average price of $3.79/MMBtu 2013: 10,000 MMBtu/d at an average price of $3.81/MMBtu ETP Commodity Price Sensitivity ($ millions) Hypothetical Price Movement Q3 2012 Annualized Impact 2013 Annual Impact Natural Gas $0.10 / MMBtu $ (1) $ 1 NGL Composite $0.10 / Gallon $ 27 $ 36 SUG Natural Gas $0.10 / MMBtu $ 1 $ 1 NGL Composite $0.10 / Gallon $ 12 $ 17 Note: Natural gas sensitivities net of hedges as of 10/31/12 As of September 30, 2012, we had 46 Bcf of natural gas in storage at our Bammel facility for our own account: This volume has been hedged forward for the next winter withdrawal season Seasonal spreads were locked in at an average of $0.96/MMBtu or $0.08/month 2013 Estimated Average Equity NGL Barrel Composition ETP SUG Pentane+: 10% Pentane+: 16% Iso-Butane: 9% Iso-Butane: 5% We currently have no NGL hedges in place We continue to monitor and evaluate the market for potential future hedging of NGLs N-Butane: 3% Propane: 15% Ethane: 67% N-Butane: 4% Propane: 26% Ethane: 45% 62

Closing Remarks

Key Takeaways We believe our recent acquisitions have created a best in class diversified natural gas, crude oil, NGL, and refined product logistics and transportation platform Our diversified asset portfolio is now better positioned to take advantage of the growth opportunities in crude oil and NGL markets Our natural gas intrastate and interstate businesses are well positioned to benefit from a rebound in natural gas prices with no additional capital investment We intend to execute on optimizing our asset portfolio to take advantage of the commercial opportunities that our recent acquisitions have provided us Trunkline conversion is one of many exciting opportunities that we are pursuing that have arisen from recent acquisitions We will rationalize our business and divest non-core assets including potentially moving assets within the Energy Transfer Family to efficiently integrate our asset portfolio Focused on integrating recent acquisitions to minimize costs and maximize commercial and operational synergies Our goal is to resume distribution growth at an appropriate time while integrating and simplifying the overall family structure in an efficient manner that maximizes value for all stakeholders 64

Supplemental Materials

ETP Capital Growth Projects Project Description Capacity Expected Completion Estimated Cost ($ mm) Midstream Dos Hermanas Pipeline 50-mile, 24-inch pipeline originating in northwest Webb County and extending to ETP's existing Houston Pipeline rich gas gathering system in eastern Webb County 400 MMcf/d In-service Q4 2010 Chisholm Pipeline 83 mile, 20-inch pipeline extending from DeWitt County to ETP's La Grange Processing Plant in 100 MMcf/d, expandable to In-service $68 Fayette County 300 MMcf/d Q2 2011 REM Phase I 160-mile, 30-inch pipeline originating in Dimmitt County and extending to the Chisholm Pipeline for 400 MMcf/d, expandable to In-service $220 ultimate delivery to ETP s processing plants 800 MMcf/d Q4 2011 Chisholm Plant Natural gas processing plant located adjacent to ETP's existing La Grange Plant in Fayette County 120 MMcf/d In-service $70 Q1 2012 REM Phase II 70 mile, 42-inch pipeline expansion, which will extend from the Chisholm Pipeline in DeWitt County 800 MMcf/d In-service $170 east into Jackson County Q3 2012 Jackson Plant Natural gas processing plant located in Jackson County 400 MMcf/d, Phase I Q1 2013 $420 200 MMcf/d, Phase II Q1 2014 200 MMcf/d, Phase III Q1 2014 Red River Gathering Pipeline 117-mile, 24- and 30-inch pipeline from Carter County, Oklahoma to ETP's Godley Plant in Johnson County, Texas 450 MMcf/d, expandable to 550 MMcf/d In-service Q3 2012 $360 Godley Plant Expansion Karnes County Processing Plant Cryogenic processing plant to be constructed at the Godley processing facility in Johnson County, 200 MMcf/d Q3 2013 Texas Natural gas processing plant located in Karnes County 200 MMcf/d Q4 2012 $210 REM Expansion 37 mile, 30-inch pipeline expansion Expands REM to 1 Bcf/d Q4 2013 Sub-total $1,561 $43 NGL (ETP) Freedom Pipeline 43-mile, 8-inch NGL pipeline connecting the Liberty pipeline to ETP's La Grange & Chisholm plants In-service $30 40 Mbbl/d Q3 2011 Liberty Pipeline 93-mile, 12-inch NGL pipeline owned through a 50/50 JV with Copano. Connects the Freedom pipeline In-service $26 to the Formosa plant 90 Mbbl/d Q3 2011 Justice Pipeline 130-mile, 20-inch NGL pipeline from the Jackson Plant to Mont Belvieu 340 Mbbl/d Q4 2012 $365 Sub-total $421 NGL (100%) West Texas Gateway 570-mile, 16-inch NGL pipeline originating in Winkler County and terminating in Jackson County 200 Mbbl/d Q4 2012 $917 Frac I Mont Belvieu NGL fractionator 100 Mbbl/d Q4 2012 $390 Frac II Mont Belvieu NGL fractionator 100 Mbbl/d Q4 2013 $350 Contribution from Regency for its 30% interest ($497) Sub-total $1,160 Total announced ETP growth projects since Q4 2010 (including 70% of Lone Star) $3,142 66

Ratings Summary Moody's S&P Fitch Rating Outlook Rating Outlook Rating Outlook ETP Senior Unsecured Baa3 Stable BBB- Stable BBB- Negative SXL Senior Unsecured Baa3 Stable BBB- Stable BBB Stable SUG Senior Unsecured Baa3 Stable BBB- Stable BBB- Stable PEPL Senior Unsecured Baa3 Stable BBB- Stable BBB- Stable ETE Corporate Rating Ba2 Stable BB Stable BB- Stable Senior Unsecured Ba2 Stable BB Stable BB Stable 67

ETP Non-GAAP Reconciliations LTM + 2008-2012 LTM 9/30 Years Ended December 31, Last Twelve Months Ended ($ millions) 2008 2009 2010 2011 9/30/2012 Net income $ 866.0 $ 791.5 $ 617.2 $ 697.2 $ 1,513.4 Interest expense, net of interest capitalized 265.7 394.3 412.6 474.1 509.7 Income tax expense 6.7 12.8 15.5 18.8 13.3 Depreciation and amortization 262.2 312.8 343.0 430.9 412.9 Non-cash compensation expense 23.5 24.0 27.2 37.5 36.5 (Gains) losses on deconsolidation/disposals of assets 1.3 1.6 5.0 3.2 (1,055.9) Gains on non-hedged interest rate derivatives 51.0 (39.2) (4.6) 77.4 20.8 Unrealized (gains) losses on commodity risk management activities (35.5) (30.0) 78.3 11.4 72.1 Goodwill impairment loss 11.4 - - - - Impairment of investment in affiliate - - 52.6 5.4 - Proportionate share of unconsolidated affiliates' interest, depreciation and allowance for equity funds used during construction - 22.3 22.5 30.0 146.9 Equity in earnings of unconsolidated affiliates - - - - (7.9) Adjusted EBITDA attributable to unconsolidated affiliates - - - - 105.4 Adjusted EBITDA attributable to non-controlling interest - - - (37.8) (58.4) Write-down of assets included in loss from discontinued operations - - - - 145.2 Other, net (includes allowance for equity funds used during construction) (73.3) (12.7) (28.5) (5.4) (5.9) Loss on extinguishment of debt - - - - 115.0 Adjusted EBITDA $ 1,378.9 $ 1,477.4 $ 1,540.9 $ 1,742.6 $ 1,963.1 Management believes Adjusted EBITDA provides useful information to investors as measure of comparison with peer companies, including companies that may have different financing and capital structures. The presentation of Adjusted EBITDA also allows investors to view our performance in a manner similar to the methods used by management and provides additional insight to our operating results There are material limitations to using measures such as Adjusted EBITDA, including the difficulty associated with using it 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 calculation of Adjusted EBITDA 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 gross margin, operating income, net income, and cash flow from operating activities Definition of Adjusted EBITDA The Partnership defines Adjusted EBITDA as total partnership earnings before interest, taxes, depreciation, 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, non-cash impairment charges, and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities includes unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments) 68

Sunoco Retail Non-GAAP Reconciliations Years Ended December 31, ($ millions) 2006 2007 2008 2009 2010 2011 Retail Pretax Income $ 129.0 $ 113.0 $ 329.0 $ 146.0 $ 176.0 $ 169.0 Depreciation and Amoritization 225.0 108.0 110.0 95.0 93.0 92.0 Sunoco Retail EBITDA 1 $ 354.0 $ 221.0 $ 439.0 $ 241.0 $ 269.0 $ 261.0 1 Excludes items deemed to be unusual Management believes Adjusted EBITDA provides useful information to investors as measure of comparison with peer companies, including companies that may have different financing and capital structures. The presentation of Adjusted EBITDA also allows investors to view our performance in a manner similar to the methods used by management and provides additional insight to our operating results There are material limitations to using measures such as Adjusted EBITDA, including the difficulty associated with using it 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 calculation of Adjusted EBITDA 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 gross margin, operating income, net income, and cash flow from operating activities Definition of Adjusted EBITDA The Partnership defines Adjusted EBITDA as total partnership earnings before interest, taxes, depreciation, 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, non-cash impairment charges, and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities includes unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments) 69

Reconciliation of Capital Deployed and Funding Sources Fiscal Years Ended 8/31 Four Months Years Ended 12/31 YTD 9/30 ($ millions) 2005 2006 2007 Ended 12/31/07 2008 2009 2010 2011 2012 Net cash used in investing activities $ 1,133.7 $ 1,244.4 $ 2,158.1 $ 995.9 $ 2,015.6 $ 1,345.8 $ 1,493.8 $ 3,552.4 $ 2,125.9 Proceeds from sale of assets and discontinued operations 196.9 6.9 23.1 21.5 19.4 21.5 27.9 9.3 1,455.8 Non-cash activity 1 2.5 4.0-1.4 2.2 63.3 (588.7) - 105.0 Maintenance capital expenditures (41.0) (51.8) (89.2) (49.0) (141.0) (102.7) (99.3) (134.2) (81.2) Capital deployed $ 1,292.1 $ 1,203.5 $ 2,092.0 $ 969.8 $ 1,896.2 $ 1,327.9 $ 833.8 $ 3,427.5 $ 3,605.5 Net cash provided by operating activities $ 169.4 $ 543.9 $ 1,112.7 $ 245.7 $ 1,258.1 $ 826.9 $ 1,202.3 $ 1,344.4 $ 937.9 Maintenance capital expenditures (41.0) (51.8) (89.2) (49.0) (141.0) (102.7) (99.3) (134.2) (81.2) Distributions paid (207.0) (343.8) (622.5) (176.0) (879.2) (957.3) (1,066.0) (1,159.5) (998.4) Net proceeds from sale of assets and discontinued operations 2 196.9 6.9 23.1 21.5 19.4 21.5 27.9 9.3 705.8 Excess cash flow $ 118.3 $ 155.2 $ 424.1 $ 42.2 $ 257.3 $ (211.6) $ 64.9 $ 60.0 $ 564.1 Net proceeds from issuance of common units $ 507.7 $ 132.4 $ 1,200.0 $ 234.9 $ 373.1 $ 936.3 $ 1,152.2 $ 1,467.0 $ 771.8 Capital contributions from general partner 10.4 2.8 24.5-8.0 3.4 8.9 - - Capital contributions from noncontrolling interest - - - - - - - 645.3 240.1 Non-cash activity 1 2.5 4.0-1.4 2.2 63.3 (588.7) - 105.0 Equity issued $ 520.6 $ 139.2 $ 1,224.5 $ 236.3 $ 383.3 $ 1,003.0 $ 572.5 $ 2,112.2 $ 1,116.9 1 Non-cash activity includes issuances of common units in connection with certain acquisitions (2012, 2009, 2008, four months ended 12/31/07, 2006 and 2005) and redemption of common units in connection with the transfer of ETP s investment in MEP in 2010 2 YTD 9/30/2012, net proceeds from sale of assets and discontinued operations is net of repayment of debt in January 2012 70