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•	Natural gas operations, including the following:

•	natural gas midstream and intrastate transportation and storage; and

•	interstate natural gas transportation and storage.

•	Crude oil, NGLs and refined product transportation, terminalling services and acquisition and marketing activities, as well as NGL storage and fractionation services.

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In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. As discussed below, in July 2017, the Partnership contributed a portion of its ownership interest in Dakota Access and ETCO to PEP. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.

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In February 2017, Sunoco Logistics formed PEP, a strategic joint venture with ExxonMobil. Sunoco Logistics contributed its Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines, Hawkins gathering system, an idle pipeline in southern Oklahoma, and its Patoka, Illinois terminal. Assets contributed to PEP by ExxonMobil were reflected at fair value on the Partnership’s consolidated balance sheet at the date of the contribution, including $547 million of intangible assets and $435 million of property, plant and equipment.

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In April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed a merger transaction (the “Sunoco Logistics Merger”) in which Sunoco Logistics acquired Energy Transfer Partners, L.P. in a unit-for-unit transaction, with the Energy Transfer Partners, L.P. unitholders receiving 1.5 common units of Sunoco Logistics for each Energy Transfer Partners, L.P. common unit they owned. In connection with the merger, Sunoco Logistics was renamed Energy Transfer Partners, L.P. and Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE.

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In July 2017, ETP contributed an approximate 15% ownership interest in Dakota Access and ETCO to PEP, which resulted in an increase in ETP’s ownership interest in PEP to approximately 88%. ETP maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP is reflected as a consolidated subsidiary of the Partnership. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets. ExxonMobil’s contribution resulted in an increase of $988 million in noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest” in the consolidated statement of equity.

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In October 2017, ETP completed the previously announced contribution transaction with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners, pursuant to which ETP exchanged a 49.9% interest in the holding company that owns 65% of the Rover pipeline (“Rover Holdco”). As a result, Rover Holdco is now owned 50.1% by ETP and 49.9% by Blackstone. Upon closing, Blackstone contributed funds to reimburse ETP for its pro rata share of the Rover construction costs incurred by ETP through the closing date, along with the payment of additional amounts subject to certain adjustments.

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In January 2018, ETP entered into a contribution agreement (“CDM Contribution Agreement”) with ETP GP, ETC Compression, LLC, USAC and ETE, pursuant to which ETP will contribute to USAC 100% of the membership interests of CDM and CDM E&T for aggregate consideration of $1.7 billion, consisting of USAC common units, new USAC Class B units and cash. The Class B units will be substantially similar to USAC common units, except the Class B units will not receive distributions paid with respect to USAC common units prior to the one year anniversary of the closing date of the CDM Contribution Agreement. Each Class B Unit will convert into one USAC common unit on such one year anniversary. In connection with the foregoing, ETP entered into a purchase agreement with ETE, ETP LLC, USAC Holdings and, for certain limited purposes, R/C IV USACP Holdings, L.P., pursuant to which ETE and ETP LLC will acquire from USAC Holdings (i) all of the outstanding interests in the general partner of USAC and (ii) 12,466,912 USAC common units for $250 million in cash. The transactions are expected to close in the first half of 2018, subject to customary closing conditions.

•	In June 2017, ETP announced that the Dakota Access Pipeline and the Energy Transfer Crude Oil Pipeline (collectively, the “Bakken Pipeline”) were placed in commercial service.

•	ETP announced that Phase 1A and Phase 1B of the Rover pipeline were placed in service in August 2017 and December 2017, respectively.

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•	purchasing crude oil at both the wellhead from producers, and in bulk from aggregators at major pipeline interconnections and trading locations;

•	storing inventory during contango market conditions (when the price of crude oil for future delivery is higher than current prices);

•	buying and selling crude oil of different grades, at different locations in order to maximize value;

•	transporting crude oil using the pipelines, terminals and trucks or, when necessary or cost effective, pipelines, terminals or trucks owned and operated by third parties; and

•	marketing crude oil to major integrated oil companies, independent refiners and resellers through various types of sale and exchange transactions.

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We own an equity method investment in limited partnership units of Sunoco LP. As of December 31, 2017, our investment consisted of 43.5 million units, representing 43.6% of Sunoco LP’s total outstanding common units. Subsequent to Sunoco LP’s repurchase of a portion of its common units on February 7, 2018, our investment consists of 26.2 million units, representing 31.8% of Sunoco LP’s total outstanding common units.

•	Our wholly-owned subsidiary, Sunoco, Inc., owns an approximate 33% non-operating interest in PES, a refining joint venture with The Carlyle Group, L.P., which owns a refinery in Philadelphia.

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We conduct marketing operations in which we market the natural gas that flows through our gathering and intrastate transportation assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other suppliers and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices of natural gas, less the costs of transportation. For the off-system gas, we purchase gas or act as an agent for small independent producers that may not have marketing operations.

•	We own a natural gas compression equipment business with operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas.

•	We own 100% of the membership interests of Energy Transfer Group, L.L.C. (“ETG”), which owns all of the partnership interests of Energy Transfer Technologies, Ltd. (“ETT”). ETT provides compression services to customers engaged in the transportation of natural gas, including our other segments.

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•	We own a 40% interest in the parent of LCL, which is developing a LNG liquefaction project, as described further under “Asset Overview – All Other” below.

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We own and operate a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems. We also own and operate a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management. These assets are primarily owned through CDM and CDM E&T. As discussed in “Recent Developments” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in January 2018, we entered into an agreement to contribute these assets to USAC.

•	We are involved in the management of coal and natural resources properties and the related collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. These operations also include end-user coal handling facilities.

•	We also own PEI Power Corp. and PEI Power II, which own and operate a facility in Pennsylvania that generates a total of 75 megawatts of electrical power.

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The ET Fuel System serves some of the most prolific production areas in the United States and is comprised of intrastate natural gas pipeline and related natural gas storage facilities. The ET Fuel System has many interconnections with pipelines providing direct access to power plants, other intrastate and interstate pipelines, and has bi-directional capabilities. It is strategically located near high-growth production areas and provides access to the Waha Hub near Midland, Texas, the Katy Hub near Houston, Texas and the Carthage Hub in East Texas, the three major natural gas trading centers in Texas.

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The Oasis Pipeline is primarily a 36-inch natural gas pipeline. It has bi-directional capabilities with approximately 1.2 Bcf/d of throughput capacity moving west-to-east and greater than 750 MMcf/d of throughput capacity moving east-to-west. The Oasis pipeline connects to the Waha and Katy market hubs and has many interconnections with other pipelines, power plants, processing facilities, municipalities and producers.

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The HPL System is an extensive network of intrastate natural gas pipelines, an underground Bammel storage reservoir and related transportation assets. The system has access to multiple sources of historically significant natural gas supply reserves from South Texas, the Gulf Coast of Texas, East Texas and the western Gulf of Mexico, and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City and other cities located along the Gulf Coast of Texas. The HPL System is well situated to gather and transport gas in many of the major gas producing areas in Texas including a strong presence in the key Houston Ship Channel and Katy Hub markets, allowing us to play an important role in the Texas natural gas markets. The HPL System also offers its shippers off-system opportunities due to its numerous interconnections with other pipeline systems, its direct access to multiple market hubs at Katy, the Houston Ship Channel and Agua Dulce, as well as our Bammel storage facility.

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The East Texas Pipeline connects three treating facilities, one of which we own, with our Southeast Texas System. The East Texas pipeline serves producers in East and North Central Texas and provided access to the Katy Hub. The East Texas pipeline expansions include the 36-inch East Texas extension to connect our Reed compressor station in Freestone County to our Grimes County compressor station, the 36-inch Katy expansion connecting Grimes to the Katy Hub, and the 42-inch Southeast Bossier pipeline connecting our Cleburne to Carthage pipeline to the HPL System.

•	RIGS is a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets. The Partnership owns a 49.99% general partner interest in RIGS.

•	Comanche Trail is a 195-mile intrastate pipeline that delivers natural gas from the Waha Hub near Midland, Texas to the United States/Mexico border near San Elizario, Texas. The Partnership owns a 16% membership interest in and operates Comanche Trail.

•	Trans-Pecos is a 143-mile intrastate pipeline that delivers natural gas from the Waha Hub near Midland, Texas to the United States/Mexico border near Presidio, Texas. The Partnership owns a 16% membership interest in and operates Trans-Pecos.

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The Florida Gas Transmission Pipeline (“FGT”) is an open-access interstate pipeline system with a mainline capacity of 3.1 Bcf/d and approximately 5,360 miles of pipelines extending from south Texas through the Gulf Coast region of the United States to south Florida. The FGT system receives natural gas from various onshore and offshore natural gas producing basins. FGT is the principal transporter of natural gas to the Florida energy market, delivering over 66% of the natural gas consumed in the state. In addition, FGT’s system operates and maintains over 81 interconnects with major interstate and intrastate natural gas pipelines, which provide FGT’s customers access to diverse natural gas producing regions. FGT’s customers include electric utilities, independent power producers, industrials and local distribution companies. FGT is owned by Citrus, a 50/50 joint venture with KMI.

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The Transwestern Pipeline is an open-access interstate natural gas pipeline extending from the gas producing regions of West Texas, eastern and northwestern New Mexico, and southern Colorado primarily to pipeline interconnects off the east end of its system and to pipeline interconnects at the California border. The Transwestern Pipeline has bi-directional capabilities and access to three significant gas basins: the Permian Basin in West Texas and eastern New Mexico; the San Juan Basin in northwestern New Mexico and southern Colorado; and the Anadarko Basin in the Texas and Oklahoma panhandles. Natural gas sources from the San Juan Basin and surrounding producing areas can be delivered eastward to Texas intrastate and mid-continent connecting pipelines and natural gas market hubs as well as westward to markets in Arizona, Nevada and California. Transwestern’s Phoenix Lateral Pipeline, with a throughput capacity of 660 MMcf/d, connects the Phoenix area to the Transwestern mainline. Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users.

•	The Panhandle Eastern Pipe Line’s transmission system consists of four large diameter pipelines with bi-directional capabilities, extending approximately 1,300 miles from producing areas in the Anadarko Basin of Texas, Oklahoma and Kansas through Missouri, Illinois, Indiana, Ohio and into Michigan.

•	The Trunkline Gas Pipeline’s transmission system consists of one large diameter pipeline with bi-directional capabilities, extending approximately 1,400 miles from the Gulf Coast areas of Texas and Louisiana through Arkansas, Mississippi, Tennessee, Kentucky, Illinois, Indiana and Michigan.

•	The Tiger Pipeline is an approximately 195-mile interstate natural gas pipeline with bi-directional capabilities, that connects to our dual 42-inch pipeline system near Carthage, Texas, extends through the heart of the Haynesville Shale and ends near Delhi, Louisiana, with interconnects to at least seven interstate pipelines at various points in Louisiana.

•	The Fayetteville Express Pipeline is an approximately 185-mile interstate natural gas pipeline that originates near Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. The Fayetteville Express Pipeline is owned by a 50/50 joint venture with KMI.

•	The Sea Robin Pipeline’s transmission system consists of two offshore Louisiana natural gas supply systems extending approximately 120 miles into the Gulf of Mexico.

•	The Rover Pipeline is a new 713-mile natural gas pipeline designed to transport 3.25 Bcf/d of domestically produced natural gas from the Marcellus and Utica Shale production areas to markets across the United States as well as into the Union Gas Dawn Storage Hub in Ontario, Canada, for redistribution back into the United States or into the Canadian market.

•	The Midcontinent Express Pipeline is an approximately 500-mile interstate pipeline stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipeline System in Butler, Alabama. The Midcontinent Express Pipeline is owned by a 50/50 joint venture with KMI.

•	Gulf States owns a 10-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.

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The Southeast Texas System is an integrated system that gathers, compresses, treats, processes, dehydrates and transports natural gas from the Austin Chalk trend and Eagle Ford shale formation. The Southeast Texas System is a large natural gas gathering system covering thirteen counties between Austin and Houston. This system is connected to the Katy Hub through the East Texas Pipeline and is also connected to the Oasis Pipeline. The Southeast Texas System includes two natural gas processing plant (La Grange and Alamo) with aggregate capacity of 410 MMcf/d and natural gas treating facilities with aggregate capacity of 510 MMcf/d. The La Grange and Alamo processing plants are natural gas processing plants that process the rich gas that flows through our gathering system to produce residue gas and NGLs. Residue gas is delivered into our intrastate pipelines and NGLs are delivered into our NGL pipelines to Lone Star.

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The Eagle Ford Gathering System consists of 30-inch and 42-inch natural gas gathering pipelines with over 1.4 Bcf/d of capacity originating in Dimmitt County, Texas, and extending to both our King Ranch gas plant in Kleberg County, Texas and Jackson plant in Jackson County, Texas. The Eagle Ford Gathering System includes four processing plants (Chisholm, Kenedy, Jackson and King Ranch) with aggregate capacity of 1.92 Bcf/d and multiple natural gas treating facilities with combined capacity of 1.81 Bcf/d. Our Chisholm, Kenedy, Jackson and King Ranch processing plants are connected to our intrastate transportation pipeline systems for deliveries of residue gas and are also connected with our NGL pipelines for delivery of NGLs to Lone Star.

•	Our Northern Louisiana assets are comprised of several gathering systems in the Haynesville Shale with access to multiple markets through interconnects with several pipelines, including our Tiger Pipeline. Our Northern Louisiana assets include the Bistineau, Creedence, and Tristate Systems, which collectively include three natural gas treating facilities, with aggregate capacity of 1.19 Bcf/d.

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Our PennTex Midstream System is primarily located in Lincoln Parish, Louisiana, and consists of the Lincoln Parish plant, a 200 MMcf/d design-capacity cryogenic natural gas processing plant located near Arcadia, Louisiana, the Mt. Olive plant, a 200 MMcf/d design-capacity cryogenic natural gas processing plant located near Ruston, Louisiana, with on-site liquids handling facilities for inlet gas; a 35-mile rich gas gathering system that provides producers with access to our processing plants and third-party processing capacity; a 15-mile residue gas pipeline that provides market access for natural gas from our processing plants, including connections with pipelines that provide access to the Perryville Hub and other markets in the Gulf Coast region; and a 40-mile NGL pipeline that provides connections to the Mont Belvieu market for NGLs produced from our processing plants.

•	The Ark-La-Tex assets gather, compress, treat and dehydrate natural gas in several parishes in north and west Louisiana and several counties in East Texas. These assets also include cryogenic natural gas processing facilities, a refrigeration plant, a conditioning plant, amine treating plants, and an interstate NGL pipeline. Collectively, the eight natural gas processing

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•	Through the gathering and processing systems described above and their interconnections with RIGS in north Louisiana, we offer producers wellhead-to-market services, including natural gas gathering, compression, processing, treating and transportation.

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The North Central Texas System is an integrated system located in four counties in North Central Texas that gathers, compresses, treats, processes and transports natural gas from the Barnett and Woodford Shales. Our North Central Texas assets include our Godley and Crescent plants, which process rich gas produced from the Barnett Shale and STACK play, with aggregate capacity of 715 MMcf/d and aggregate treating capacity of 212 MMcf/d. The Godley plant is integrated with the ET Fuel System.

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The Permian Basin Gathering System offers wellhead-to-market services to producers in eleven counties in West Texas, as well as two counties in New Mexico which surround the Waha Hub, one of Texas’s developing NGL-rich natural gas market areas. As a result of the proximity of our system to the Waha Hub, the Waha Gathering System has a variety of market outlets for the natural gas that we gather and process, including several major interstate and intrastate pipelines serving California, the mid-continent region of the United States and Texas natural gas markets. The NGL market outlets includes Lone Star’s liquids pipelines. The Permian Basin Gathering System includes ten processing facilities (Waha, Coyanosa, Red Bluff, Halley, Jal, Keyston, Tippet, Orla, Panther and Rebel) with an aggregate processing capacity of 1.62 Bcf/d, treating capacity of 1.58 Bcf/d, and one natural gas conditioning facility with aggregate capacity of 200 MMcf/d.

•	We own a 50% membership interest in Mi Vida JV, a joint venture which owns a 200 MMcf/d cryogenic processing plant in West Texas. We operate the plant and related facilities on behalf of Mi Vida JV.

•	We own a 33.33% membership interest in Ranch JV, which processes natural gas delivered from the NGL-rich Bone Spring and Avalon Shale formations in West Texas. The joint venture owns a 25 MMcf/d refrigeration plant and a 125 MMcf/d cryogenic processing plant.

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The Mid-Continent Systems are located in two large natural gas producing regions in the United States, the Hugoton Basin in southwest Kansas, and the Anadarko Basin in western Oklahoma and the Texas Panhandle. These mature basins have continued to provide generally long-lived, predictable production volume. Our Mid-Continent assets are extensive systems that gather, compress and dehydrate low-pressure gas. The Mid-Continent Systems include fourteen natural gas processing facilities (Mocane, Beaver, Antelope Hills, Woodall, Wheeler, Sunray, Hemphill, Phoenix, Hamlin, Spearman, Red Deer, Lefors, Cargray and Gray) with an aggregate capacity of 885 MMcf/d and one natural gas treating facility with aggregate capacity of 20 MMcf/d.

•	We operate our Mid-Continent Systems at low pressures to maximize the total throughput volumes from the connected wells. Wellhead pressures are therefore adequate to allow for flow of natural gas into the gathering lines without the cost of wellhead compression.

•	We also own the Hugoton Gathering System that has 1,900 miles of pipeline extending over nine counties in Kansas and Oklahoma. This system is operated by a third party.

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The Eastern Region assets are located in nine counties in Pennsylvania, three counties in Ohio, three counties in West Virginia, and gather natural gas from the Marcellus and Utica basins. Our Eastern Region assets include approximately 500 miles of natural gas gathering pipeline, natural gas trunklines, fresh-water pipelines, and nine gathering and processing systems. The fresh water pipeline system and Ohio gathering assets are held by jointly-owned entities.

•	We also own a 51% membership interest in Aqua – PVR, a joint venture that transports and supplies fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania.

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We and Traverse ORS LLC, a subsidiary of Traverse Midstream Partners LLC, own a 75% and 25% membership interest, respectively, in the ORS joint venture. On behalf of ORS, we operate its Ohio Utica River System (the “ORS System”), which consists of 47 miles of 36-inch and 13 miles of 30-inch gathering trunklines that delivers up to 2.1 Bcf/d to Rockies Express Pipeline (“REX”), Texas Eastern Transmission, and others.

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(1)	Additionally, the Sea Robin Processing Plant and Refinery Services have residue capacities of 850 MMcf/d and 54 MMcf/d, respectively.

(2)	Miles of pipeline as reported to PHMSA.

•	The Lone Star Express System is an interstate NGL pipeline consisting of 24-inch and 30-inch long-haul transportation pipeline that delivers mixed NGLs from processing plants in the Permian Basin, the Barnett Shale, and from East Texas to the Mont Belvieu NGL storage facility.

•	The West Texas Gateway Pipeline transports NGLs produced in the Permian and Delaware Basins and the Eagle Ford Shale to Mont Belvieu, Texas.

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The Mariner East pipeline transports NGLs from the Marcellus and Utica Shales areas in Western Pennsylvania, West Virginia and Eastern Ohio to destinations in Pennsylvania, including our Marcus Hook Industrial Complex on the Delaware River, where they are processed, stored and distributed to local, domestic and waterborne markets. The first phase of the project, referred to as Mariner East 1, consisted of interstate and intrastate propane and ethane service and commenced operations in the fourth quarter of 2014 and the first quarter of 2016, respectively. The second phase of the project, referred to as Mariner East 2, will expand the total takeaway capacity to 345 MBbls/d for interstate and intrastate propane, ethane and butane service, and is expected to commence operations in the second quarter of 2018.

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•	The Mariner South pipeline is part of a joint project with Lone Star to deliver export-grade propane and butane products from Lone Star’s Mont Belvieu, Texas storage and fractionation complex to our marine terminal in Nederland, Texas.

•	The Mariner West pipeline provides transportation of ethane from the Marcellus shale processing and fractionating areas in Houston, Pennsylvania to Marysville, Michigan and the Canadian border. Mariner West commenced operations in the fourth quarter of 2013, with capacity to transport approximately 50 MBbls/d.

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Refined products pipelines include approximately 2,200 miles of refined products pipelines in several regions of the United States. The pipelines primarily provide transportation in the northeast, midwest, and southwest United States markets. These operations include our controlling financial interest in Inland Corporation (“Inland”). The mix of products delivered varies seasonally, with gasoline demand peaking during the summer months, and demand for heating oil and other distillate fuels peaking in the winter. In addition, weather conditions in the areas served by the refined products pipelines affect both the demand for, and the mix of, the refined products delivered through the pipelines, although historically, any overall impact on the total volume shipped has been short-term. The products transported in these pipelines include multiple grades of gasoline, and middle distillates, such as heating oil, diesel and jet fuel. Rates for shipments on these product pipelines are regulated by the FERC and other state regulatory agencies, as applicable.

•	Other NGL pipelines include the 127-mile Justice pipeline with capacity of 375 MBbls/d, the 45-mile Freedom pipeline with a capacity of 56 MBbls/d, the 20-mile Spirit pipeline with a capacity of 20 MBbls/d and a 50% interest in the 87-mile Liberty pipeline with a capacity of 140 MBbls/d.

•	Our Mont Belvieu storage facility is an integrated liquids storage facility with over 50 million Bbls of salt dome capacity providing 100% fee-based cash flows. The Mont Belvieu storage facility has access to multiple NGL and refined products pipelines, the Houston Ship Channel trading hub, and numerous chemical plants, refineries and fractionators.

•	Our Mont Belvieu fractionators handle NGLs delivered from several sources, including the Lone Star Express pipeline and the Justice pipeline. Fractionator V is currently under construction and is scheduled to be operational by the third quarter of 2018.

•	Sea Robin is a rich gas processing plant located on the Sea Robin Pipeline in southern Louisiana. The plant is connected to nine interstate and four intrastate residue pipelines, as well as various deep-water production fields.

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Refinery Services consists of a refinery off-gas processing unit and an O-grade NGL fractionation / Refinery-Grade Propylene (“RGP”) splitting complex located along the Mississippi River refinery corridor in southern Louisiana.  The off-gas processing unit cryogenically processes refinery off-gas, and the fractionation / RGP splitting complex fractionates the streams into higher value components.  The O-grade fractionator and RGP splitting complex, located in Geismar, Louisiana, is connected by approximately 103 miles of pipeline to the Chalmette processing plant, which has a processing capacity of 54 MMcf/d.

•	The Hattiesburg storage facility is an integrated liquids storage facility with approximately 3 million Bbls of salt dome capacity, providing 100% fee-based cash flows.

•	The Nederland terminal, in addition to crude oil activities, also provides approximately 1 million Bbls of storage and distribution services for NGLs in connection with the Mariner South pipeline, which provides transportation of propane and butane products from the Mont Belvieu region to the Nederland terminal, where such products can be exported via ship.

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The Marcus Hook Industrial Complex includes fractionation, terminalling and storage assets, with a capacity of approximately 2 million Bbls of NGL storage capacity in underground caverns, 3 million Bbls of above-ground refrigerated storage, and related commercial agreements. The terminal has a total active refined products storage capacity of approximately 1 million Bbls. The facility can receive NGLs and refined products via marine vessel, pipeline, truck and rail, and can deliver via marine vessel, pipeline and truck. In addition to providing NGLs storage and terminalling services to both affiliates and third-party customers, the Marcus Hook Industrial Complex currently serves as an off-take outlet for the Mariner East 1 pipeline, and will provide similar off-take capabilities for the Mariner East 2 pipeline when it commences operations.

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The Inkster terminal, located near Detroit, Michigan, consists of multiple salt caverns with a total storage capacity of approximately 1 million Bbls of NGLs. We use the Inkster terminal’s storage in connection with the Toledo North pipeline system and for the storage of NGLs from local producers and a refinery in Western Ohio. The terminal can receive and ship by pipeline in both directions and has a truck loading and unloading rack.

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We have approximately 40 refined products terminals with an aggregate storage capacity of approximately 8 million Bbls that facilitate the movement of refined products to or from storage or transportation systems, such as a pipeline, to other transportation systems, such as trucks or other pipelines. Each facility typically consists of multiple storage tanks and is equipped with automated truck loading equipment that is operational 24 hours a day.

•	In addition to crude oil service, the Eagle Point terminal can accommodate three marine vessels (ships or barges) to receive and deliver refined products to outbound ships and barges. The tank farm has a total active refined products storage capacity

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The Marcus Hook Tank Farm has a total refined products storage capacity of approximately 2 million Bbls of refined products storage. The tank farm historically served Sunoco Inc.’s Marcus Hook refinery and generated revenue from the related throughput and storage. In 2012, the main processing units at the refinery were idled in connection with Sunoco Inc.’s exit from its refining business. The terminal continues to receive and deliver refined products via pipeline and now primarily provides terminalling services to support movements on our refined products pipelines.

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The Eastern refined products pipelines consists of approximately 470 miles of 6-inch to 24-inch diameters refined product pipelines in Eastern, Central and North Central Pennsylvania, approximately 162 miles of 8-inch refined products pipeline in western New York and approximately 182 miles of various diameters refined products pipeline in New Jersey (including 80 miles of the 16-inch diameter Harbor Pipeline).

•	The Mid-Continent refined products pipelines primarily consists of approximately 212 miles of 3-inch to 12-inch refined products pipelines in Ohio, approximately 85 miles of 6-inch to 12-inch refined products pipeline in Western Pennsylvania and approximately 52 miles of 8-inch refined products pipeline in Michigan.

•	The Southwest refined products pipelines is located in Eastern Texas and consists primarily of approximately 300 miles of 8-inch diameter refined products pipeline.

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The Inland refined products pipeline, approximately 350 miles of pipeline in Ohio, consists of 72 miles of 12-inch diameter refined products pipeline in Northwest Ohio, 205 miles of 10-inch diameter refined products pipeline in vicinity of Columbus, Ohio, 53 miles of 8-inch diameter refined products pipeline in western Ohio and the remaining refined products pipeline primarily consists of 5-inch diameter pipeline in Northeast Ohio.

(1)	Miles of pipeline as reported to PHMSA.

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Bakken Pipeline. Dakota Access and ETCO are collectively referred to as the “Bakken Pipeline.” The Bakken Pipeline is a 1,915 mile pipeline with an initial capacity of 470 MBbls/d, expandable to 570 MBbls/d, that transports domestically produced crude oil from the Bakken/Three Forks production areas in North Dakota to a storage and terminal hub outside of Patoka, Illinois, or to gulf coast connections including our crude terminal in Nederland Texas.

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Bayou Bridge Pipeline. The Bayou Bridge Pipeline is a joint venture between ETP and Phillips 66, in which ETP has a 60% ownership interest and serves as the operator of the pipeline. Phase I of the pipeline, which consists of a 30-inch pipeline from Nederland, Texas to Lake Charles, Louisiana, went into service in April 2016. Phase II of the pipeline, which will consist of 24-inch pipe from Lake Charles, Louisiana to St. James, Louisiana, is expected to be completed in the second half of 2018.

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Permian Express Pipelines. The Permian Express pipelines are part of the PEP joint venture and include Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines, as well as the Longview to Louisiana and Pegasus pipelines contributed to this joint venture by ExxonMobil. These pipelines are comprised of crude oil trunk pipelines and crude oil gathering pipelines in Texas and Oklahoma and provide takeaway capacity from the Permian Basin, which origins in multiple locations in Western Texas.

•	Other Crude Oil pipelines include the Mid-Valley pipeline system which originates in Longview, Texas and passes through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky and Ohio and terminates in Samaria, Michigan. This pipeline provides crude oil to a number of refineries, primarily in the Midwest United States.

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Nederland. The Nederland terminal, located on the Sabine-Neches waterway between Beaumont and Port Arthur, Texas, is a large marine terminal providing storage and distribution services for refiners and other large transporters of crude oil and NGLs. The terminal receives, stores, and distributes crude oil, NGLs, feedstocks, lubricants, petrochemicals, and bunker oils (used for fueling ships and other marine vessels), and also blends lubricants. The terminal currently has a total storage capacity of approximately 26 million Bbls in approximately 150 above ground storage tanks with individual capacities of up to 660 MBbls.

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•	Fort Mifflin. The Fort Mifflin terminal complex is located on the Delaware River in Philadelphia, Pennsylvania and includes the Fort Mifflin terminal, the Hog Island wharf, the Darby Creek tank farm and connecting pipelines. Revenues are generated from the Fort Mifflin terminal complex by charging fees based on throughput.

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Eagle Point. The Eagle Point terminal is located in Westville, New Jersey and consists of docks, truck loading facilities and a tank farm. The docks are located on the Delaware River and can accommodate three marine vessels (ships or barges) to receive and deliver crude oil, intermediate products and refined products to outbound ships and barges. The tank farm has a total active storage capacity of approximately 1 million Bbls and can receive crude oil via barge and rail and deliver via ship and barge, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.

•	Midland. The Midland terminal is located in Midland, Texas and was acquired in November 2016 from Vitol. The facility includes approximately 2 million Bbls of crude oil storage, a combined 14 lanes of truck loading and unloading, and provides access to the Permian Express 2 transportation system.

•	Marcus Hook Industrial Complex. The Marcus Hook Industrial Complex can receive crude oil via marine vessel and can deliver via marine vessel and pipeline. The terminal has a total active crude oil storage capacity of approximately 1 million Bbls.

•	Patoka, Illinois Terminal. The Patoka, Illinois terminal is a tank farm and was contributed by ExxonMobil to the PEP joint venture and is located in Marion County, Illinois. The facility includes 234 acres of owned land and provides for approximately 2 million Bbls of crude oil storage.

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Sunoco LP. We have an equity method investment in limited partnership units of Sunoco LP. As of December 31, 2017, our investment consisted of 43.5 million units, representing 43.6% of Sunoco LP’s total outstanding common units. Subsequent to Sunoco LP’s repurchase of a portion of its common units on February 7, 2018, our investment consists of 26.2 million units, representing 31.8% of Sunoco LP’s total outstanding common units.

•	PES. We have a non-controlling interest in PES, comprising 33% of PES’ outstanding common units. As discussed in “Segment Overview - All Other” above, PES Holdings and eight affiliates filed for Chapter 11 bankruptcy protection on January 21, 2018.

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•	approve the siting, construction and operation of new facilities;

•	review and approve transportation rates;

•	determine the types of services our regulated assets are permitted to perform;

•	regulate the terms and conditions associated with these services;

•	permit the extension or abandonment of services and facilities;

•	require the maintenance of accounts and records; and

•	authorize the acquisition and disposition of facilities.

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•	the amount of natural gas, NGLs, crude oil and refined products transported in our pipelines and gathering systems;

•	the level of throughput in our processing and treating operations;

•	the fees we charge and the margins we realize for our services;

•	the price of natural gas, NGLs, crude oil and refined products;

•	the relationship between natural gas, NGL and crude oil prices;

•	the amount of cash distributions we receive with respect to the Sunoco LP common units that our subsidiaries own;

•	the weather in our operating areas;

•	the level of competition from other midstream, transportation and storage and other energy providers;

•	the level of our operating costs;

•	prevailing economic conditions; and

•	the level and results of our derivative activities.

•	the level of capital expenditures we make;

•	the level of costs related to litigation and regulatory compliance matters;

•	the cost of acquisitions, if any;

•	the levels of any margin calls that result from changes in commodity prices;

•	our debt service requirements;

•	fluctuations in our working capital needs;

•	our ability to borrow under our revolving credit facility;

•	our ability to access capital markets;

•	restrictions on distributions contained in our debt agreements; and

•	the amount of cash reserves established by our General Partner in its discretion for the proper conduct of our business.

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•	the current proportionate ownership interest of our Unitholders in us will decrease;

•	the amount of cash available for distribution on each Common Unit or partnership security may decrease;

•	the ratio of taxable income to distributions may increase;

•	the relative voting strength of each previously outstanding Common Unit may be diminished; and

•	the market price of the Common Units or partnership securities may decline.

•	Unitholders’ current proportionate ownership interest in Sunoco LP will decrease;

•	the amount of cash available for distribution on each common unit or partnership security may decrease;

•	the ratio of taxable income to distributions may increase;

•	the relative voting strength of each previously outstanding common unit may be diminished; and

•	the market price of Sunoco LP common units may decline.

•	a significant portion of our and our subsidiaries’ cash flow from operations will be dedicated to the payment of principal and interest on outstanding debt and will not be available for other purposes, including payment of distributions;

•	covenants contained in our and our subsidiaries’ existing debt agreements require us and them, as applicable, to meet financial tests that may adversely affect our flexibility in planning for and reacting to changes in our business;

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•	our and our subsidiaries’ ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership, corporate or limited liability company purposes, as applicable, may be limited;

•	we may be at a competitive disadvantage relative to similar companies that have less debt;

•	we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level; and

•	failure by us or our subsidiaries to comply with the various restrictive covenants of our respective debt agreements could negatively impact our ability to incur additional debt, including our ability to utilize the available capacity under our revolving credit facility, and our ability to pay our distributions.

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•	the right to share in the Partnership’s profits and losses;

•	the right to share in the Partnership’s distributions;

•	the rights upon dissolution and liquidation of the Partnership;

•	whether, and the terms upon which, the Partnership may redeem the securities;

•	whether the securities will be issued, evidenced by certificates and assigned or transferred; and

•	the right, if any, of the security to vote on matters relating to the Partnership, including matters relating to the relative rights, preferences and privileges of such security.

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•	to provide for the proper conduct of our business and the businesses of our operating subsidiaries (including reserves for future capital expenditures and for our anticipated future credit needs);

•	to provide funds for distributions to our Unitholders and our General Partner for any one or more of the next four calendar quarters; or

•	to comply with applicable law or any of our loan or other agreements.

•	economic downturns;

•	deteriorating capital market conditions;

•	declining market prices for natural gas, NGLs and other commodities;

•	terrorist attacks or threatened attacks on our facilities or those of other energy companies; and

•	the overall health of the energy industry, including the bankruptcy or insolvency of other companies.

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•	eliminates all standards of care and duties other than those set forth in our partnership agreement, including fiduciary duties, to the fullest extent permitted by law;

•	permits our General Partner to make a number of decisions in its “sole discretion,” which standard entitles our General Partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;

•	provides that our General Partner is entitled to make other decisions in its “reasonable discretion;”

•	generally provides that affiliated transactions and resolutions of conflicts of interest must be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our General Partner may consider the interests of all parties involved, including its own;

•	provides that unless our General Partner has acted in bad faith, the action taken by our General Partner shall not constitute a breach of its fiduciary duty;

•	provides that our General Partner may resolve any conflicts of interest involving us and our General Partner and its affiliates, and any resolution of a conflict of interest by our General Partner that is “fair and reasonable” to us will be deemed approved by all partners, including the Unitholders, and will not constitute a breach of the partnership agreement;

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provides that our General Partner may, but is not required, in connection with its resolution of a conflict of interest, to seek “special approval” of such resolution by appointing a conflicts committee of the General Partner’s board of directors composed of two or more independent directors to consider such conflicts of interest and to recommend action to the board of directors, and any resolution of the conflict of interest by the conflicts committee shall be conclusively deemed “fair and reasonable” to us;

•	provides that our General Partner may consult with consultants and advisors and, subject to certain restrictions, is conclusively deemed to have acted in good faith when it acts in reliance on the opinion of such consultants and advisors; and

•	provides that our General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions if our General Partner and those other persons acted in good faith.

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Our partnership agreement limits the liability and reduces the fiduciary duties of our General Partner while also restricting the remedies available to our Unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. Unitholders are deemed to have consented to some actions and conflicts of interest that might otherwise be deemed a breach of fiduciary or other duties under applicable state law. Our General Partner is allowed to take into account the interests of parties in addition to us in resolving conflicts of interest, thereby limiting its fiduciary duties to us.

•	Our General Partner is allowed to take into account the interests of parties in addition to us, including ETE, in resolving conflicts of interest, thereby limiting its fiduciary duties to us.

•	Our General Partner’s affiliates, including ETE, are not prohibited from engaging in other businesses or activities, including those in direct competition with us.

•	Our General Partner determines the amount and timing of our asset purchases and sales, capital expenditures, borrowings, repayments of debt, issuances of equity and debt securities and cash reserves, each of which can affect the amount of cash that is distributed to Unitholders and to ETE.

•	Neither our partnership agreement nor any other agreement requires ETE or its affiliates to pursue a business strategy that favors us. The directors and officers of the general partners of ETE have a fiduciary duty to make decisions in the best interest of their members, limited partners and Unitholders, which may be contrary to our best interests.

•	Some of the directors and officers of ETE who provide advice to us also may devote significant time to the businesses of ETE and will be compensated by them for their services.

•	Our General Partner determines which costs, including allocated overhead costs, are reimbursable by us.

•	Our General Partner is allowed to resolve any conflicts of interest involving us and our General Partner and its affiliates, and any resolution of a conflict of interest by our General Partner that is fair and reasonable to us will be deemed approved by all partners and will not constitute a breach of the partnership agreement.

•	Our General Partner controls the enforcement of obligations owed to us by it.

•	Our General Partner decides whether to retain separate counsel, accountants or others to perform services for us.

•	Our General Partner is not restricted from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.

•	Our General Partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, may be entitled to be indemnified by us.

•	In some instances, our General Partner may cause us to borrow funds in order to permit the payment of distributions, even if the purpose or effect of the borrowing is to make incentive distributions.

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•	the level of domestic natural gas, NGL, and oil production;

•	the level of natural gas, NGL, and oil imports and exports, including liquefied natural gas;

•	actions taken by natural gas and oil producing nations;

•	instability or other events affecting natural gas and oil producing nations;

•	the impact of weather and other events of nature on the demand for natural gas, NGLs and oil;

•	the availability of storage, terminal and transportation systems, and refining, processing and treating facilities;

•	the price, availability and marketing of competitive fuels;

•	the demand for electricity;

•	activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of oil and natural gas;

•	the cost of capital needed to maintain or increase production levels and to construct and expand facilities

•	the impact of energy conservation and fuel efficiency efforts; and

•	the extent of governmental regulation, taxation, fees and duties.

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•	because we are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;

•	because we are unable to raise financing for such acquisitions on economically acceptable terms; or

•	because we are outbid by competitors, some of which are substantially larger than us and have greater financial resources and lower costs of capital then we do.

•	fail to realize anticipated benefits, such as new customer relationships, cost-savings or cash flow enhancements;

•	decrease our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;

•	significantly increase our interest expense or financial leverage if we incur additional debt to finance acquisitions;

•	encounter difficulties operating in new geographic areas or new lines of business;

•	incur or assume unanticipated liabilities, losses or costs associated with the business or assets acquired for which we are not indemnified or for which the indemnity is inadequate;

•	be unable to hire, train or retrain qualified personnel to manage and operate our growing business and assets;

•	less effectively manage our historical assets, due to the diversion of management’s attention from other business concerns; or

•	incur other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.

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•	operating a larger combined organization in new geographic areas and new lines of business;

•	hiring, training or retaining qualified personnel to manage and operate our growing business and assets;

•	integrating management teams and employees into existing operations and establishing effective communication and information exchange with such management teams and employees;

•	diversion of management’s attention from our existing business;

•	assimilation of acquired assets and operations, including additional regulatory programs;

•	loss of customers or key employees;

•	maintaining an effective system of internal controls in compliance with the Sarbanes-Oxley Act of 2002 as well as other regulatory compliance and corporate governance matters; and

•	integrating new technology systems for financial reporting.

•	we are unable to identify pipeline construction opportunities with favorable projected financial returns;

•	we are unable to obtain necessary governmental approvals and contracts with qualified contractors and vendors on acceptable terms;

•	we are unable to raise financing for our identified pipeline construction opportunities; or

•	we are unable to secure sufficient transportation commitments from potential customers due to competition from other pipeline construction projects or for other reasons.

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•	terms and conditions of service;

•	the types of services interstate pipelines may or must offer their customers;

•	construction of new facilities;

•	acquisition, extension or abandonment of services or facilities;

•	reporting and information posting requirements;

•	accounts and records; and

•	relationships with affiliated companies involved in all aspects of the natural gas and energy businesses.

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•	perform ongoing assessments of pipeline integrity;

•	identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

•	improve data collection, integration and analysis;

•	repair and remediate the pipeline as necessary; and

•	implement preventive and mitigating actions.

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(1)	Distributions are shown in the quarter with respect to which they relate. Please see “Cash Distribution Policy” below for a discussion of our policy regarding the payment of distributions.

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•	Less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the General Partner to:

•	provide for the proper conduct of our business;

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•	comply with applicable law and/or debt instrument or other agreement (including reserves for future capital expenditures and for our future capital needs); or

•	provide funds for distributions to Unitholders and our General Partner in respect of any one or more of the next four quarters.

•	Plus all cash on hand on the date of determination of Available Cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our credit facilities and in all cases used solely for working capital purposes or to pay distributions to partners.

•	our cash balance on the closing date of our initial public offering; plus

•	$15 million (as described below); plus

•	all of our cash receipts since the closing of our initial public offering, excluding cash from interim capital transactions such as borrowings that are not working capital borrowings, sales of equity and debt securities and sales or other dispositions of assets outside the ordinary course of business; plus

•	our working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; plus

•	legacy ETP’s operating surplus at the time of closing of the merger between legacy ETP and the Partnership in April 2017; less

•	all of our operating expenditures after the closing of our initial public offering, including the repayment of working capital borrowings, but not the repayment of other borrowings, and including maintenance capital expenditures; less

•	the amount of our cash reserves that our General Partner deems necessary or advisable to provide funds for future operating expenditures.

•	borrowings other than working capital borrowings;

•	sales of our debt and equity securities; and

•	sales or other disposition of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirements or replacements of assets.

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•	First, 100% to all Common Unitholders, Class E Unitholders and Class G Unitholders and the general partner, in accordance with their percentage interests, until each Common Unit has received $0.075 per unit for such quarter (the “minimum quarterly distribution”);

•	Second, 100% to all Common Unitholders, Class E Unitholders and Class G Unitholders and the general partner, in accordance with their respective percentage interests, until each Common Unit has received $0.0833 per unit for such quarter (the “first target distribution”);

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Third, (i) to the general partner in accordance with its percentage interest, (ii) 13% to the holders of the IDRs, pro rata, and (iii) to all Common Unitholders, Class E Unitholders and Class G Unitholders, pro rata, a percentage equal to 100% less the percentages applicable to the general partner and holders of the IDRs, until each Common Unit has received $0.0958 per unit for such quarter (the “second target distribution”);

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Fourth, (i) to the general partner in accordance with its percentage interest, (ii) 35% to the holders of the IDRs, pro rata, and (iii) to all Common Unitholders, Class E Unitholders and Class G Unitholders, pro rata, a percentage equal to 100% less the percentages applicable to the general partner and holders of the IDRs, until each Common Unit has received $0.2638 per unit for such quarter (the “third target distribution”); and

•	Fifth, thereafter, (i) to the general partner in accordance with its percentage interest, (ii) 48% to the holder of the IDRs, pro rata, and (iii) to all Common Unitholders, Class E Unitholders and Class G Unitholders, pro rata, a percentage equal to 100% less the percentages applicable to the general partner and holders of the IDRs.

•	First, to all of our Unitholders and to our General Partner, in accordance with their percentage interests, until we distribute for each Common Unit, an amount of available cash from capital surplus equal to our initial public offering price; and

•	Thereafter, we will make all distributions of Available Cash from capital surplus as if they were from operating surplus.

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(1)	Represents cash distributions of legacy Sunoco Logistics through the closing of the Sunoco Logistics Merger and ETP thereafter.

(2)	Represents cash distributions on legacy ETP common units through the closing of the Sunoco Logistics Merger.

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•	Natural gas operations, including the following:

•	natural gas midstream and intrastate transportation and storage; and

•	interstate natural gas transportation and storage.

•	Crude oil, NGLs and refined product transportation, terminalling services and acquisition and marketing activities, as well as NGL storage and fractionation services.

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Intrastate transportation and storage – Revenue is principally generated from fees charged to customers to reserve firm capacity on or move gas through our pipelines on an interruptible basis. Our interruptible or short-term business is generally impacted by basis differentials between delivery points on our system and the price of natural gas. The basis differentials that primarily impact our interruptible business are primarily among receipt points between West Texas to East Texas or segments thereof. When narrow or flat spreads exist, our open capacity may be underutilized and go unsold. Conversely, when basis differentials widen, our interruptible volumes and fees generally increase. The fee structure normally consists of a monetary fee and fuel retention. Excess fuel retained after consumption, if any, is typically sold at market prices. In addition to transport fees, we generate revenue from purchasing natural gas and transporting it across our system. The natural gas is then sold to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies. The HPL System purchases natural gas at the wellhead for transport and selling. Other pipelines with access to West Texas supply, such as Oasis and ET Fuel, may also purchase gas at the wellhead and other supply sources for transport across our system to be sold at market on the east side of our system. This activity allows our intrastate transportation and storage segment to capture the current basis differentials between delivery points on our system or to capture basis differentials that were previously locked in through hedges. Firm capacity long-term contracts are typically not subject to price differentials between shipping locations.

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Interstate transportation and storage – The majority of our interstate transportation and storage revenues are generated through firm reservation charges that are based on the amount of firm capacity reserved for our firm shippers regardless of usage. Tiger, FEP, Transwestern, Panhandle, MEP and Gulf States shippers have made long-term commitments to pay reservation charges for the firm capacity reserved for their use.  In addition to reservation revenues, additional revenue sources include interruptible transportation charges as well as usage rates and overrun rates paid by firm shippers based on their actual capacity usage.

•	Midstream – Revenue is principally dependent upon the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipelines as well as the level of natural gas and NGL prices.

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NGL and refined products transportation and services – Liquids transportation revenue is principally generated from fees charged to customers under dedicated contracts or take-or-pay contracts. Under a dedicated contract, the customer agrees to deliver the total output from particular processing plants that are connected to the NGL pipeline. Take-or-pay contracts have minimum throughput commitments requiring the customer to pay regardless of whether a fixed volume is transported. Transportation fees are market-based, negotiated with customers and competitive with regional regulated pipelines.

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Crude oil transportation and services – Revenues are generated by charging tariffs for transporting crude oil though our pipelines as well as by charging fees for terminalling services at our facilities. Revenues are also generated by acquiring and marketing crude oil. Generally, crude oil purchases are entered into in contemplation of or simultaneously with corresponding sale transactions involving physical deliveries, which enables us to secure a profit on the transaction at the time of purchase.

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(1)	For the year ended December 31, 2017, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by HPC, which reduced the Partnership’s equity in earnings by $185 million.

(2)	For the years ended December 31, 2017 and 2016, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by Sunoco LP, which reduced the Partnership’s equity in earnings by $176 million and $277 million, respectively.

(3)	These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.

•	Segment margin, operating expenses, and selling, general and administrative expenses. These amounts represent the amounts included in our consolidated financial statements that are attributable to each segment.

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•	Unrealized gains or losses on commodity risk management activities and inventory valuation adjustments. These are the unrealized amounts that are included in cost of products sold to calculate segment margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized losses are added back and the unrealized gains are subtracted to calculate the segment measure.

•	Non-cash compensation expense. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate the segment measure.

•	Adjusted EBITDA related to unconsolidated affiliates. These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates. Amounts reflected are calculated consistently with our definition of Adjusted EBITDA.

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•	an increase of $74 million in natural gas sales and other (excluding net changes in unrealized gains and losses of $6 million) primarily due to higher realized gains from pipeline optimization activity;

•	an increase of $10 million in retained fuel sales (excluding net changes in unrealized gains and losses of $4 million) primarily due to higher market prices. The average spot price at the Houston Ship Channel location increased 22% for the year ended December 31, 2017 compared to the prior year; and

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an increase of $3 million in adjusted EBITDA related to unconsolidated affiliates primarily due to an increase of $16 million related to two new joint venture pipelines placed in service in 2017, offset by a decrease of $6 million due to lower demand volumes related to renegotiation of a contract on our Louisiana intrastate pipeline system in 2017 and a decrease of $7 million due to a reserve recorded in 2017 pursuant to the bankruptcy filing of a transport customer on our Louisiana intrastate system; offset by

•	a decrease in transportation fees of $57 million due to renegotiated contracts resulting in lower billed volumes. This decrease was offset by increased margin from optimization activity recorded in natural gas sales and other;

•	a decrease of $11 million in storage margin (excluding net changes in unrealized gains and losses of $14 million related to fair value inventory adjustments and unrealized gains and losses on derivatives), as discussed below; and

•	an increase of $6 million in operating expenses primarily due to higher compression fuel expense relating to increased market price and run times at various compressor stations.

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a net decrease of $35 million in revenues primarily due to a decrease in reservation revenues of $45 million on the Panhandle, Trunkline, and Transwestern pipelines, a decrease of $17 million in gas parking service related revenues on the Panhandle and Trunkline pipelines primarily due to lack of customer demand resulting from weak spreads, a decrease of $19 million in revenues on the Tiger pipeline due to contract restructuring, and a decrease of $5 million on the Sea Robin pipeline due to producer maintenance and production declines. These decreases were partially offset by $55 million of incremental revenues from the placement in partial service of the Rover pipeline effective August 31, 2017; offset by

•	a decrease in operating expenses of $6 million primarily due to lower allocated costs of $8 million and lower lease storage expense of $4 million due to expiration of a lease. These decreases were partially offset by higher ad valorem taxes resulting from higher valuations;

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an increase in adjusted EBITDA from unconsolidated affiliates of $4 million due to an increase of $6 million related to a legal settlement, an increase of $3 million resulting from higher sales of short term firm capacity on Citrus and $2 million related to higher tax gross up income from reimbursable projects on Citrus. These increases were partially offset by lower reservation revenues on MEP primarily due to a contract modification and expiring contracts; and

•	an increase in other of $5 million primarily due to higher tax gross up income from reimbursable projects.

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•	an increase of $150 million in non-fee based margins due to higher crude oil and NGL prices;

•	an increase of $60 million in non-fee based margin (excluding net changes in unrealized gains and losses of $30 million) due to volume increases in the Permian, Northeast and South Texas regions, partially offset by volume declines in the North Texas and the Mid-Continent/Panhandle regions;

•	an increase of $80 million in fee-based revenue due to minimum volume commitments in the South Texas region, as well as volume increases in the Permian and Northeast regions. These increases were partially offset by volume declines in the North Texas and the Mid-Continent/Panhandle regions;

•	an increase of $64 million in fee-based revenue due to recent acquisitions, including PennTex; and

•	a decrease in selling, general and administrative expenses of $6 million primarily due to a favorable impact from the adjustment of certain reserves that had previously been recorded in connection with contingent matters. This decrease was partially offset by a decrease in capitalized overhead of $11 million and an increase in shared services allocation of $14 million; partially offset by

•	an increase in operating expenses of $17 million primarily due to recent acquisitions, including PennTex.

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•	an increase in transportation margin of $124 million primarily due to increased throughput on our Texas NGL pipelines resulting from increased producer services as noted above and the ramp up of volumes on our Mariner East system;

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an increase in fractionation and refinery services margin of $81 million (excluding changes in unrealized gains and losses of $3 million) primarily due to higher NGL volumes from most major producing regions feeding our Mont Belvieu fractionation facility, the first full year of service for our fourth fractionator at Mont Belvieu, Texas, and a $17 million increase from blending gains as a result of improved market pricing, as noted above;

•	an increase in terminal services margin of $29 million due to a $43 million increase resulting from higher throughput volumes at our Marcus Hook and Nederland NGL terminals. This increase was partially offset by a $14 million decrease resulting from lower refined products terminal throughput and the sale of one of our refined product terminals in April of 2017; and

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•	an increase in storage margin of $6 million primarily due to a $4 million increase from Hattiesburg storage caverns as a result of a new storage contract effective in April 2017 as well as a $2 million increase from propane and butane blending gains as a result of improved market pricing; offset by

•	a decrease in marketing margin of $54 million (excluding changes in unrealized gains of $95 million) primarily due to the timing of the recognition of margin from optimization activities;

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an increase in operating expenses of $37 million due to a $16 million increase related to the fourth fractionator being placed into service in October 2016, a $11 million increase related to higher utility expenses on our Texas NGL pipes, a $5 million increase due to higher right-of-way expenses primarily on our legacy Sunoco Logistics assets, and a $4 million increase from our Mont Belvieu storage assets primarily due to higher employee costs; and

•	an increase in general and administrative expenses of $8 million due to higher allocations.

•	an increase of $724 million resulting primarily from placing our Bakken Pipeline in service in the second quarter of 2017, as well as the acquisition of a crude oil gathering system in West Texas, and the addition of a joint venture crude transportation assets;

•	an increase of $90 million from existing transport assets due to increased volumes throughout the system; and

•	an increase of $16 million from increased throughput fees and tank rentals, primarily from increased activity at our Nederland, Texas crude terminal; offset by

•	a decrease of $78 million in margin from our crude oil acquisition and marketing business resulting from less favorable market price spreads particularly in the first three quarters of 2017;

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an increase of $183 million in operating expenses primarily due to an increase of $130 million resulting primarily from placing the Bakken Pipeline as well as certain joint venture crude transportation assets in service in the first and second quarters of 2017, an increase of $46 million due to higher utilities, line testing, and environmental costs from existing transport assets, an increase of $6 million for losses related to Hurricane Harvey; and

•	an increase of $24 million in selling, general and administrative expenses primarily due to merger fees and legal and environmental reserves.

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our equity method investment in limited partnership units of Sunoco LP. As of December 31, 2017, our investment consisted of 43.5 million units, representing 43.6% of Sunoco LP’s total outstanding common units. Subsequent to Sunoco LP’s repurchase of a portion of its common units on February 7, 2018, our investment consists of 26.2 million units, representing 31.8% of Sunoco LP’s total outstanding common units;

•	our natural gas marketing and compression operations;

•	a non-controlling interest in PES, comprising 33% of PES’ outstanding common units; and

•	our investment in coal handling facilities.

•	a decrease of $90 million related to the termination of management fees paid by ETE that ended in 2016;

•	an increase of $17 million in selling, general and administrative expenses primarily from higher transaction-related expenses; and

•	a decrease of $31 million from the mark-to-market of physical system gas and settled derivatives; partially offset by

•	an increase of $33 million in Adjusted EBITDA related to our investment in PES;

•	a one-time fee of $15 million received from a joint venture affiliate;

•	an increase of $20 million in crude and power trading activates, primarily from the liquidation of crude inventories; and

•	a decrease of $11 million in expenses related to our compression business.

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(1)	For the year ended December 31, 2016, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by Sunoco LP, which reduced the Partnership’s equity in earnings by $277 million.

(2)	These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.

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•	an increase of $3 million in transportation fees, despite lower throughput volumes, due to fees from renegotiated and newly initiated fixed fee contracts primarily on our Houston Pipeline system;

•	an increase of $34 million in natural gas sales (excluding changes in unrealized losses of $17 million) primarily due to higher realized gains from the buying and selling of gas along our system;

•	a decrease of $9 million from the sale of retained fuel, primarily due to lower market prices and lower volumes. The average spot price at the Houston Ship Channel location decreased 5% for the year ended December 31, 2016 compared to the prior year;

•	an increase of $37 million in storage margin (excluding net changes in unrealized amounts of $28 million related to fair value inventory adjustments and unrealized gains and losses on derivatives), as discussed below; and

•	a decrease of $3 million in general and administrative expenses primarily due to lower legal fees and insurance costs, as well as allocations between segments.

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a decrease of $26 million in revenues due to contract restructuring on the Tiger pipeline, a decrease of $17 million due to lower reservation revenues on the Panhandle and Trunkline pipelines from capacity sold at lower rates and lower sales of capacity in the Phoenix and San Juan areas on the Transwestern pipeline, a decrease of $14 million due to the transfer of one of the Trunkline pipelines which was repurposed from natural gas service to crude oil service, a decrease of $11 million due to the expiration of a transportation rate schedule on the Transwestern pipeline, and a decrease of $10 million on the Sea Robin pipeline due to declines in production and third-party maintenance. These decreases were partially offset by higher reservation revenues on the Transwestern pipeline of $18 million, primarily from a growth project, and higher parking revenues of $9 million, primarily on the Panhandle and Trunkline pipelines; partially offset by

•	an increase of $8 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to higher margins from sales of additional capacity on Citrus of $6 million and lower operating expenses of $5 million, offset by lower margins on MEP of $4 million due to a customer bankruptcy;

•	a decrease of $2 million in operating expenses primarily due to lower maintenance project costs of $5 million and lower allocated costs of $3 million. These decreases were partially offset by an increase of $7 million in ad valorem tax expense due to higher current year assessments of $2 million and a prior period credit and settlement of ad valorem taxes in 2015 of $5 million;

•	a decrease of $5 million in selling, general and administrative expenses primarily due to $5 million in lower allocated costs; and

•	an increase of $3 million in other primarily due to the tax gross-up associated with reimbursable projects on the Transwestern and Panhandle pipelines.

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•	a decrease of $16 million in fee-based margin due to volume declines in the South Texas, North Texas, and Mid-Continent/Panhandle regions, partially offset by increased gathering and processing volumes in the Permian region and the impact of recent acquisitions, including PennTex and the King Ranch assets;

•	an increase of $40 million in general and administrative expenses primarily due to costs associated with the acquisition of PennTex and changes in capitalized overhead and accruals;

•	an increase of $5 million in operating expenses primarily due to the King Ranch acquisition in the second quarter of 2015 and assets recently placed in service in the Permian and Eagle Ford regions; and

•	a decrease of $92 million (excluding unrealized gains of $67 million) in non-fee based margin due to lower benefit from settled derivatives used to hedge commodity margins; partially offset by

•	an increase of $44 million in non-fee based margin due to volume increases in the Permian region, partially offset by volume declines in the South Texas, North Texas, and Mid-Continent/Panhandle regions; and

•	an increase of $3 million in non-fee based margin due to higher crude oil and NGL prices, partially offset by lower natural gas prices.

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•

an increase of $36 million in storage margin primarily due to increased volumes from our Mont Belvieu fractionators. Throughput volumes, on which we earn a fee in our storage assets, increased 34% resulting in an increase of $18 million compared to the prior year. We also realized an increase of $8 million due to increased demand for our leased storage capacity as a result of more favorable market conditions. Finally, we realized increased terminal fees and pipeline lease fees of $8 million, as well as increased blending gains of $2 million resulting from higher volumes during the 2016 period;

•	an increase of $239 million in NGL and refined product transportation and terminal margin due to the ramp-up of several organic growth projects, including Mariner East 1, Mariner South and Allegheny Access as well as increased volumes from all producing regions, with the Permian region being the most significant among them;

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•	a $4 million increase in contributions from joint venture interests primarily driven by the acquisition of an additional 1.7% ownership interest in Explorer Pipeline Company; and

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an increase of $118 million in NGL processing and fractionation margin (excluding net changes in unrealized gains and losses of $11 million) primarily due to higher NGL volumes from all producing regions, as detailed in our transport fees explanation above. We placed approximately 118 MBbls/d of fractionation capacity in-service in 2016, allowing our Mont Belvieu fractionators to handle the significant increase in volumes from year to year. Additional barrels fractionated and an associated increase in blending gains at our fractionators resulted in a margin increase of $101 million. We delivered approximately 26% more barrels to our Mariner South LPG export terminal in the 2016 period, which resulted in an increase of $22 million in cargo loading fees and blending fees compared to the prior year. These gains were offset by an increase in storage fees paid of $2 million, and a decrease in margin from our refinery services operations of $3 million; partially offset by

•	a decrease in marketing margin of $42 million (excluding net changes in unrealized gains and losses of $50 million) due to lower spreads compared to prior year as well as the timing of the withdrawal of NGL component product inventory and the recognition of margin from other optimization activities; and

•	an increase of $33 million in operating expenses primarily due to increased costs associated with organic growth projects such as our third fractionator at Mont Belvieu, Mariner East 1, Mariner South and Allegheny Access.

•	an increase of $158 million resulting primarily from placing our Permian Express II pipeline in service in the third quarter of 2015, as well as the acquisition of a crude oil gathering system in West Texas;

•	an increase of $49 million from existing assets due to increased volumes throughout the system;

•	an increase of $31 million from our crude terminals assets, largely related to the Nederland facility; and

•	an increase of $74 million from our crude oil acquisition and marketing activity; offset by

•	an increase of $5 million in selling, general and administrative expenses.

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•	our retail marketing operations prior to the transfer of the general partner interest of Sunoco LP from ETP to ETE in 2015 and completion of the dropdown of remaining Retail Marketing interests from ETP to Sunoco LP in March 2016;

•	our equity method investment in limited partnership units of Sunoco LP consisting of 43.5 million units, representing 44.3% of Sunoco LP’s total outstanding common units;

•	our natural gas marketing and compression operations;

•	a non-controlling interest in PES, comprising 33% of PES’ outstanding common units; and

•	our investment in coal handling facilities.

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a decrease of $308 million due to the transfer and contribution of our retail marketing assets to Sunoco LP. The consolidated results of Sunoco LP are reflected in the results for All Other above through June 2015. Effective July 1, 2015, Sunoco LP was deconsolidated, and the results for All Other reflect Adjusted EBITDA related to unconsolidated affiliates for our limited partner interests in Sunoco LP. The impact of the deconsolidation of Sunoco LP reduced segment margin, operating expenses and selling, general and administrative expenses; the impact to Segment Adjusted EBITDA is offset by the incremental Adjusted EBITDA related to unconsolidated affiliates from our equity method investment in Sunoco LP subsequent to the deconsolidation; and

•	a decrease of $76 million in Adjusted EBITDA related to our investment in PES.

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(1)	Includes capital expenditures related to our proportionate ownership of the Bakken, Rover and Bayou Bridge pipeline projects.

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(1)	Borrowings under 364-day credit facilities were classified as long-term debt based on the Partnership’s ability and intent to refinance such borrowings on a long-term basis.

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•	incur indebtedness;

•	grant liens;

•	enter into mergers;

•	dispose of assets;

•	make certain investments;

•	make Distributions (as defined in the ETP Credit Facilities) during certain Defaults (as defined in the ETP Credit Facilities) and during any Event of Default (as defined in the ETP Credit Facilities);

•	engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;

•	engage in transactions with affiliates; and

•	enter into restrictive agreements.

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•	prohibition of certain incremental secured indebtedness;

•	prohibition of certain liens / negative pledge;

•	limitations on uses of loan proceeds;

•	limitations on asset sales and purchases;

•	limitations on permitted business activities;

•	limitations on mergers and acquisitions;

•	limitations on investments;

•	limitations on transactions with affiliates; and

•	maintenance of commercially reasonable insurance coverage.

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•	$1.00 billion aggregate principal amount of 4.875%, senior notes due 2023;

•	$800 million aggregate principal amount of 5.50% senior notes due 2026; and

•	$400 million aggregate principal amount of 5.875% senior notes due 2028.

(1)

Interest payments on long-term debt are based on the principal amount of debt obligations as of December 31, 2017. With respect to variable rate debt, the interest payments were estimated using the interest rate as of December 31, 2017. To the extent interest rates change, our contractual obligations for interest payments will change. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for further discussion.

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(2)

We define a purchase commitment as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on us that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions. We have long and short-term product purchase obligations for refined product and energy commodities with third-party suppliers. These purchase obligations are entered into at either variable or fixed prices. The purchase prices that we are obligated to pay under variable price contracts approximate market prices at the time we take delivery of the volumes. Our estimated future variable price contract payment obligations are based on the December 31, 2017 market price of the applicable commodity applied to future volume commitments. Actual future payment obligations may vary depending on market prices at the time of delivery. The purchase prices that we are obligated to pay under fixed price contracts are established at the inception of the contract. Our estimated future fixed price contract payment obligations are based on the contracted fixed price under each commodity contract. Obligations shown in the table represent estimated payment obligations under these contracts for the periods indicated.

(3)

Expected contributions to fund our pension and postretirement benefit plans were included in “Other” above. Environmental liabilities, asset retirement obligations, unrecognized tax benefits, contingency accruals and deferred revenue, which were included in “Other non-current liabilities” in our consolidated balance sheets, were excluded from the table above as the amounts do not represent contractual obligations or, in some cases, the amount and/or timing of the cash payments is uncertain.

(4)	Excludes non-current deferred tax liabilities of $2.88 billion due to uncertainty of the timing of future cash flows for such liabilities.

(1)	Includes general partner and limited partner interests, based on the proportionate ownership of each.

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(1)	Net of Class I unit distributions

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•

A $223 million impairment was recorded related to the goodwill associated with CDM. In January 2018, the Partnership announced the contribution of CDM to USAC. Based on the Partnership’s anticipated proceeds in the contribution transaction, the implied fair value of the CDM reporting unit was less than the Partnership’s carrying value. As the Partnership believes that the contribution consideration also represented an appropriate estimate of fair value as of the 2017 annual impairment test date, the Partnership recorded an impairment for the difference between the carrying value and the fair value of the reporting unit. Subsequent to the impairment, a total of $253 million of goodwill remains in the CDM reporting unit, which amount is subject to further impairment based on changes in the contribution transaction prior to closing or any other factors affecting the fair value of the CDM reporting unit. Assuming the contribution transaction closes, the remaining CDM goodwill balance will be derecognized; if the transaction does not close, then the CDM goodwill balance will remain on the Partnership’s consolidated balance sheet and will continue to be tested for impairment in the future.

•	A $262 million impairment was recorded related to the goodwill associated with the Partnership’s interstate transportation and storage reporting units, and a $229 million impairment was recorded related to the goodwill associated with the general partner of Panhandle in the all other segment. These impairments were due to a reduction in management’s forecasted future

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A $79 million impairment was recorded related to the goodwill associated the Partnership’s refined products transportation and services reporting unit. Subsequent to the Sunoco Logistics Merger, the Partnership restructured the internal reporting of legacy Sunoco Logistics’ business to be consistent with the internal reporting of legacy ETP. Subsequent to this reallocation the carrying value of certain refined products reporting units was less than the estimated fair value due to a reduction in management’s forecasted future cash flows from the related reporting units, and the goodwill associated with those reporting units was fully impaired. No goodwill remained in the respective reporting units subsequent to the impairment.

•	A $127 million impairment of property, plant and equipment related to Sea Robin primarily due to a reduction in expected future cash flows due to an increase during 2017 in insurance costs related to offshore assets.

•	A $141 million impairment of the Partnership’s equity method investment in FEP. The Partnership concluded that the carrying value of its investment in FEP was other than temporarily impaired based on an anticipated decrease in production in the Fayetteville basin and a customer re-contracting with a competitor during 2017.

•	A $172 million impairment of the Partnership’s equity method investment in HPC primarily due to a decrease in projected future revenues and cash flows driven be the bankruptcy of one of HPC’s major customers in 2017 and an expectation that contracts expiring in the next few years will be renewed at lower tariff rates and lower volumes.

•	A $638 million goodwill impairment and a $133 million impairment to property, plant and equipment were recorded in the interstate transportation and storage segment primarily due to decreases in projected future revenues and cash flows driven by changes in the markets that these assets serve.

•	A $32 million goodwill impairment was recorded in the midstream segment primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices.

•	A $308 million impairment of the Partnership’s equity method investment in MEP. The Partnership concluded that the carrying value of its investment in MEP was other than temporarily impaired based on commercial discussions with current and potential shippers on MEP during 2016, which negatively affected the outlook for long-term transportation contract rates.

•	A $99 million goodwill impairment related to Transwestern primarily due to market declines in current and expected future commodity prices in the fourth quarter of 2015.

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A $106 million goodwill impairment, a $24 million impairment of intangible assets, and a $110 million impairment to property, plant and equipment related to Lone Star Refinery Services primarily due to changes in assumptions related to potential future revenues and market declines in current and expected future commodity prices, as well as economic obsolescence identified as a result of low utilization.

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•	the volumes transported on our pipelines and gathering systems;

•	the level of throughput in our processing and treating facilities;

•	the fees we charge and the margins we realize for our gathering, treating, processing, storage and transportation services;

•	the prices and market demand for, and the relationship between, natural gas and NGLs;

•	energy prices generally;

•	the prices of natural gas and NGLs compared to the price of alternative and competing fuels;

•	the general level of petroleum product demand and the availability and price of NGL supplies;

•	the level of domestic oil, natural gas and NGL production;

•	the availability of imported oil, natural gas and NGLs;

•	actions taken by foreign oil and gas producing nations;

•	the political and economic stability of petroleum producing nations;

•	the effect of weather conditions on demand for oil, natural gas and NGLs;

•	availability of local, intrastate and interstate transportation systems;

•	the continued ability to find and contract for new sources of natural gas supply;

•	availability and marketing of competitive fuels;

•	the impact of energy conservation efforts;

•	energy efficiencies and technological trends;

•	governmental regulation and taxation;

•	changes to, and the application of, regulation of tariff rates and operational requirements related to our interstate and intrastate pipelines;

•	hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs;

•	competition from other midstream companies and interstate pipeline companies;

•	loss of key personnel;

•	loss of key natural gas producers or the providers of fractionation services;

•	reductions in the capacity or allocations of third-party pipelines that connect with our pipelines and facilities;

•	the effectiveness of risk-management policies and procedures and the ability of our liquids marketing counterparties to satisfy their financial commitments;

•	the nonpayment or nonperformance by our customers;

•	regulatory, environmental, political and legal uncertainties that may affect the timing and cost of our internal growth projects, such as our construction of additional pipeline systems;

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•	risks associated with the construction of new pipelines and treating and processing facilities or additions to our existing pipelines and facilities, including difficulties in obtaining permits and rights-of-way or other regulatory approvals and the performance by third-party contractors;

•	the availability and cost of capital and our ability to access certain capital sources;

•	a deterioration of the credit and capital markets;

•	risks associated with the assets and operations of entities in which we own less than a controlling interests, including risks related to management actions at such entities that we may not be able to control or exert influence;

•	the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses;

•	changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations; and

•	the costs and effects of legal and administrative proceedings.

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(1)	Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.

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(1)	Floating rates are based on 3-month LIBOR.

(2)	Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.

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•	annually review and approve goals and objectives relevant to compensation of the CEO, if applicable;

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•	annually evaluate the CEO’s performance in light of these goals and objectives, and make recommendations to the Board of Directors with respect to the CEO’s compensation levels, if applicable, based on this evaluation;

•	based on input from, and discussion with, the CEO, make recommendations to the Board of Directors with respect to non-CEO executive officer compensation, including incentive compensation and compensation under equity- based plans;

•	make determinations with respect to the grant of equity-based awards to executive officers under our equity incentive plans;

•	periodically evaluate the terms and administration of ETP’s short-term and long-term incentive plans to assure that they are structured and administered in a manner consistent with ETP’s goals and objectives;

•	periodically evaluate incentive compensation and equity-related plans and consider amendments, if appropriate;

•	periodically evaluate the compensation of the directors;

•	retain and terminate any compensation consultant to be used to assist in the evaluation of director, CEO or executive officer compensation; and

•	perform other duties as deemed appropriate by the Board of Directors.

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•	On June 26, 2017, an amendment to the original Form 3 for Mr. Warren on May 5, 2017 was filed to correct an inadvertent clerical error in the number of ETP common units indirectly owned by Mr. Warren;

•	On June 26, 2017, an amendment to the Form 4 filed for Mr. Warren on May 2, 2017 was filed to correct an inadvertent clerical error in the number of ETP common units indirectly owned by Mr. Warren;

•	On May 12, 2017, an amendment to the original Form 3 for Mr. Ramsey on May 5, 2017 was filed to correct an inadvertent clerical error in the number of ETP common units beneficially owned by Mr. Ramsey;

•	On May 12, 2017, an amendment to the Form 4 filed for Mr. Ramsey on May 2, 2017 was filed to correct an inadvertent clerical error in the number of ETP common units beneficially owned by Mr. Ramsey;

•	On May 19, 2017, an amendment to the original Form 3 filed for Mr. Grimm on May 5, 2017 was filed to correct an inadvertent clerical error in the number of ETP common units beneficially owned by Mr. Grimm;

•	On May 19, 2017, an amendment to the Form 4 filed for Mr. Grimm on May 2, 2017 was filed to correct an inadvertent clerical error in the number of ETP common units and ETP restricted units acquired and beneficially owned by Mr. Grimm;

•	On May 12, 2017, an amendment to the original Form 3 filed for Mr. Sturrock on May 5, 2017 was filed to correct an inadvertent clerical error in the number of ETP common units beneficially owned by Mr. Sturrock;

•	On May 12, 2017, an amendment to the Form 4 filed for Mr. Sturrock on May 2, 2017 was filed to correct an inadvertent clerical error in the number of ETP common units and ETP restricted units beneficially owned by Mr. Sturrock;

•	On May 12, 2017, an amendment to the original Form 3 filed for Mr. Wright on May 5, 2017 was filed to correct an inadvertent clerical error in the number of ETP common units beneficially owned by Mr. Wright; and

•	On May 12, 2017, an amendment to the Form 4 filed for Mr. Wright on May 2, 2017 was filed to correct an inadvertent clerical error in the number of ETP common units beneficially owned by Mr. Wright.

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•	Kelcy L. Warren, Chairman and Chief Executive Officer;

•	Thomas E. Long, Chief Financial Officer and Group Chief Financial Officer of ETE’s general partner;

•	Marshall S. (Mackie) McCrea, III, Group Chief Operating Officer and Chief Commercial Officer

•	Matthew S. Ramsey, President and Chief Operating Officer;

•	James M. Wright, General Counsel and Assistant Secretary;

•	Michael J. Hennigan, Former President and Chief Executive Officer of Sunoco Partners LLC; and

•	Peter J. Gvazdauskas, Former Chief Financial Officer and Treasurer of Sunoco Partners LLC.

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•	reward executives with an industry-competitive total compensation package of targeted base salaries and significant incentive opportunities yielding a total compensation package approaching the top-quartile of the market;

•	attract, retain and reward talented executive officers and key management employees by providing total compensation competitive with that of other executive officers and key management employees employed by publicly traded limited partnerships of similar size and in similar lines of business;

•	motivate executive officers and key employees to achieve strong financial and operational performance;

•	emphasize performance-based or “at-risk” compensation; and

•	reward individual performance.

•	annual base salary;

•	non-equity incentive plan compensation consisting solely of discretionary cash bonuses;

•	time-vested restricted unit or phantom awards under the equity incentive plan(s);

•	payment of distribution equivalent rights (“DERs”) on unvested time-based restricted unit or phantom unit awards under the equity incentive plan(s);

•	vesting of previously issued time-based restricted unit/phantom unit awards issued pursuant to the ETP equity incentive plan(s) or the equity incentive plan(s) of its affiliates;

•	401(k) plan employer contributions; and

•	severance payments where applicable.

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(1)	The discretionary cash bonus amounts for named executive officers for 2017 reflect cash bonuses approved by the ETE Compensation Committee and the ETP Compensation Committee, as applicable, in February 2018 that are expected to be paid on or before March 15, 2018.

(2)

Equity award amounts reflect the aggregate grant date fair value of unit awards granted for the periods presented, computed in accordance with FASB ASC Topic 718. For Messrs. Long, McCrea and Ramsey, amounts include equity awards of our subsidiaries and/or affiliates, as reflected in the “Grants of Plan-Based Awards Table.” See Note 9 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for additional assumptions underlying the value of the equity awards.

(3)	During 2017, Mr. Wright had an unrealized loss of $3,245 in his account balance under the DC Plan.

(4)

The amounts reflected for 2017 in this column include (i) matching contributions to the 401(k) plan made by ETP on behalf of the named executive officers of $13,500 for each of Messrs. Long, Ramsey, McCrea and Wright, $12,750 for Mr. Hennigan and $9,846 for Mr. Gvazdauskas, (ii) the dollar value of life insurance premiums paid for the benefit of the named executive officers, (iii) $348,173 in severance payments for Mr. Hennigan, and (iv) $5,475,506 to Mr. Hennigan, which represents the value of the accelerated restricted common units under the ETP Plan as consideration for the restrictive covenant contained in the Hennigan Separation Agreement. The amounts reflected for all periods exclude distribution payments in connection with distribution equivalent rights on unvested unit awards, because the dollar value of such distributions are factored into the grant date fair value reported in the “Unit Awards” column of the Summary Compensation Table at the time that the unit awards and distribution equivalent rights were originally granted. For 2017, distribution payments in connection with

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(5)	Mr. Warren voluntarily determined that his salary would be reduced to $1.00 per year (plus an amount sufficient to cover his allocated payroll deductions for health and welfare benefits). He also does not accept a cash bonus or any equity awards under the equity incentive plans.

(6)

Mr. Ramsey serves as a member of the board of directors of ETE, the owner of our General Partner. Mr. Ramsey’s other compensation for 2015 does not include $104,400 of director fees paid in cash by ETE. Mr. Ramsey was also a non-employee director of Sunoco LP during 2015, until his November appointment to our General Partner, and his 2015 other compensation does not include $354,210 of director fees paid in cash by Sunoco LP.

(7)

The amounts shown for Mr. Hennigan reflect the change in present value for all defined benefit pension plans and supplemental executive retirement plans in which he participated. The applicable disclosure rules require the change in pension value be shown as “$0” if the actual calculation of the change in pension value is less than zero (i.e., a decrease). The decrease in SCIRP pension value for Mr. Hennigan was $49,762 for 2015. The year-over-year change in actuarial present value of Mr. Hennigan’s pension benefits under the SCIRP for 2015 was negative because Sunoco, Inc. terminated the SCIRP on October 31, 2014. Mr. Hennigan elected to receive his accrued SCIRP benefit in the form of a lump sum. Because the estimate of the present value of his SCIRP benefit at year-end 2014 assumed that Mr. Hennigan (under the Final Average Pay formula) had a 90 percent probability of electing a lump sum rather than an annuity (which would be transferred to an insurance company with a premium of 47.5%) at December 1, 2015 as part of the plan termination, the change in actuarial present value from the estimate at year-end 2014 was negative because no such premium was paid, resulting in a lower present value of his benefit. Mr. Hennigan did not have any above market preferential payments on deferred compensation during 2017, 2016 or 2015.

(1)	We have computed the grant date fair value of unit awards in accordance with FASB ASC Topic 718, as further described above and in Note 9 to our consolidated financial statements.

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(1)

In connection with the April 28, 2017 merger between ETP and Sunoco Logistics, each outstanding unvested ETP restricted unit converted into 1.5 units of Sunoco Logistics, maintaining the same terms as the original ETP award. In connection with the merger, Sunoco Logistics changed its name to Energy Transfer Partners, L.P. Certain of these outstanding awards represent ETP awards that converted into Sunoco Logistics awards in connection with the merger.

(2)	ETP and Sunoco LP common unit awards outstanding vest as follows:

•	at a rate of 60% in December 2020 and 40% in December 2022 for awards granted in December 2017;

•	at a rate of 60% in December 2019 and 40% in December 2021 for awards granted in December 2016;

•	at a rate of 60% in December 2018 and 40% in December 2020 for awards granted in January 2015 and December 2015;

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•	100% in December 2019 for the remaining outstanding portion of awards granted in December 2014 and November 2015; and

•	100% in December 2018 for the remaining outstanding portion of all other awards.

(3)	Market value was computed as the number of unvested awards as of December 31, 2017 multiplied by the closing price of our Common Units or Sunoco LP or ETE common units, accordingly, on December 31, 2017.

(1)	Amounts presented represent the number of units subject to awards that vested during 2017 and the value realized upon vesting of such units, which is calculated as the number of units subject to vesting multiplied by the closing price of our Common Units upon the vesting date.

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1.

It was determined that, as of December 31, 2017, the applicable employee populations consisted of 8,494 with all of the identified individuals being employed in the United States. This population consisted of all of our full-time and part-time employees. We did not engage any independent contractors in 2017 that are required to be included in our employee population for the CEO pay ratio evaluation.

2.	To identify the “median employee” from our employee population, we compared the total earnings of our employees as reflected in our payroll records as reported on Form W-2 for 2017.

3.	We identified our median employee using W-2 reporting and applied this compensation measure consistently to all of our employees required to be included in the calculation. We did not make any cost of living adjustments in identifying the “median employee”.

4.

Once we identified our median employee, we combined all elements of the employee’s compensation for 2017 resulting in an annual compensation of $115,226. The difference between such employee’s total earnings and the employee’s total compensation represents the estimated value of the employee’s health care benefits (estimated for the employee and such employee’s eligible dependents at $10,800) and the employee’s 401(k) matching contribution and profit sharing contribution (estimated at $5,846 per employee, includes $3,633 per employee on average matching contribution and $2,213 per employee on average profit sharing contribution (employees earning over $175,000 in base are ineligible for profit sharing)).

5.	With respect to Mr. Warren, we used the amount reported in the “Total” column of our 2017 Summary Compensation Table under this Item 11.

(1)	Fees paid in cash are based on amounts paid during the period.

(2)	Unit award amounts reflect the aggregate grant date fair value of awards granted based on the market price of Common Units as of the grant date.

(3)	Upon completion of the Sunoco Logistics Merger, the unvested unit awards of the former board members of the general partner of Sunoco Logistics were vested in full.

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*	Less than 1%

(1)

Unless otherwise indicated, the address for all beneficial owners listed above is 8111 Westchester Drive, Suite 600, Dallas, Texas 75225.  The address for Mr. McCrea is 800 E. Sonterra Blvd., San Antonio, Texas 78258.  The address for Mr. Hennigan is 3807 West Chester Pike, Newtown Square, Pennsylvania 19073.  The address for Sunoco, Inc. is 3801 West Chester Pike, Newtown Square, Pennsylvania, 19073. The address for ALPS Advisors, Inc. is 1290 Broadway, Suite 1100, Denver, Colorado 80203.

(2)	Beneficial ownership for the purposes of the foregoing table is defined by Rule 13d-3 under the Exchange Act. Under that rule, a person is generally considered to be the beneficial owner of a security if he has or shares the power to vote or direct the voting thereof or to dispose or direct the disposition thereof or has the right to acquire either of those powers within sixty (60) days.

(3)

Due to the ownership by certain officers and directors of the general partner of ETE of equity interests in ETE (either directly or through one or more entities) and due to their positions as directors of the general partner of ETE, they may be deemed to beneficially own the limited partnership interests held by ETE, to the extent of their respective interests therein. Any such deemed ownership is not reflected in the table.

(4)	Total includes 4,443 common units held in a trust for the benefit of Mr. Skidmore’s daughter over which Mr. Skidmore has voting power. Mr. Skidmore disclaims beneficial ownership of such units.

(5)	Includes 85,605 units held by RCD Stock Holdings, LLC and 458,595 units held by Avatar BW, Ltd.

(6)	ETE owns all member interests of Energy Transfer Partners, L.L.C and all of the Class A limited partner interests and Class B limited partner interests in Energy Transfer Partners GP, L.P. Energy Transfer Partners, L.L.C. is the general partner of Energy Transfer Partners GP, L.P. with a 0.01% general partner interest. LE GP, LLC, the general partner of ETE, may be

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(7)

Information reflected herein for ALPS Advisors, Inc. (“AAI”) is based on its Schedule 13G filed on February 6, 2018. AAI, a registered investment adviser, furnishes investment advice to investment companies registered under the Investment Company Act of 1940 (collectively referred to as the “Funds”). In its role as investment advisor, AAI has voting and/or investment power over the ETP common units that are owned by the Funds, and may be deemed to be the beneficial owner of the ETP common units held by the Funds. However, all units reported in this table are owned by the Funds. AAI disclaims beneficial ownership of such common units. The Funds have the right to receive or the power to direct the receipt of dividends from, or the proceeds from the sale of ETP common units held in their respective accounts. Alerian MLP ETF is an investment company registered under the Investment Company Act of 1940 and is one of the Funds to which AAI provides investment advice. The interest of Alerian MLP ETF, as reported in its February 6, 2018 Schedule 13G, amounted to 59,348,430 common units, or 5.1% of the total outstanding ETP common units.

(8)	The Partnership indirectly owns 100% of the common stock of Heritage Holdings, Inc.

(9)	The Partnership indirectly owns 100% of the common stock of Sunoco, Inc.

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(1)

Includes fees for audits of annual financial statements of our companies, reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC and services related to the audit of our internal control over financial reporting.

(2)	Includes fees in 2016 for financial statement audits and interim reviews of subsidiary entities in connection with contribution and sale transactions. Includes fees in 2016 in connection with the service organization control report on Panhandle’s centralized data center.

(3)	Includes fees related to state and local tax consultation.

•	the auditors’ internal quality-control procedures;

•	any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors;

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•	the independence of the external auditors;

•	the aggregate fees billed by our external auditors for each of the previous two years; and

•	the rotation of the lead partner.

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1.	OPERATIONS AND BASIS OF PRESENTATION:

•	References to “ETLP” refer to Energy Transfer, LP subsequent to the close of the merger;

•	References to “Sunoco Logistics” refer to the entity named Sunoco Logistics Partners L.P. prior to the close of the merger; and

•	References to “ETP” refer to the consolidated entity named Energy Transfer Partners, L.P. subsequent to the close of the merger.

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2.	ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:

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3.	ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:

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(1)	None of the goodwill is expected to be deductible for tax purposes.

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4.	ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES:

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(1)	For the year ended December 31, 2017, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by HPC, which reduced the Partnership’s equity in earnings by $185 million.

(2)	For the years ended December 31, 2017 and 2016, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by Sunoco LP, which reduced the Partnership’s equity in earnings by $176 million and $277 million, respectively.

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5.	NET INCOME (LOSS) PER LIMITED PARTNER UNIT:

6.	DEBT OBLIGATIONS:

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(1)	As of December 31, 2017 management had the intent and ability to refinance the $650 million 2.50% senior notes due June 15, 2018 and the $600 million 6.70% senior notes due July 1, 2018, and therefore neither was classified as current.

(2)	Borrowings under 364-day credit facilities were classified as long-term debt based on the Partnership’s ability and intent to refinance such borrowings on a long-term basis.

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•	incur indebtedness;

•	grant liens;

•	enter into mergers;

•	dispose of assets;

•	make certain investments;

•	make Distributions (as defined in the ETP Credit Facilities) during certain Defaults (as defined in the ETP Credit Facilities) and during any Event of Default (as defined in the ETP Credit Facilities);

•	engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;

•	engage in transactions with affiliates; and

•	enter into restrictive agreements.

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•	prohibition of certain incremental secured indebtedness;

•	prohibition of certain liens / negative pledge;

•	limitations on uses of loan proceeds;

•	limitations on asset sales and purchases;

•	limitations on permitted business activities;

•	limitations on mergers and acquisitions;

•	limitations on investments;

•	limitations on transactions with affiliates; and

•	maintenance of commercially reasonable insurance coverage.

7.	LEGACY ETP PREFERRED UNITS:

8.	EQUITY:

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(1)	The historical common units presented have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.

(2)	Represents the Sunoco Logistics common units outstanding at the close of the Sunoco Logistics Merger. See Note 1 for discussion on the accounting treatment of the Sunoco Logistics Merger.

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9.	UNIT-BASED COMPENSATION PLANS:

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10.	INCOME TAXES:

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11.	REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:

•	$1.00 billion aggregate principal amount of 4.875%, senior notes due 2023;

•	$800 million aggregate principal amount of 5.50% senior notes due 2026; and

•	$400 million aggregate principal amount of 5.875% senior notes due 2028.

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(1)	Includes contingent rentals totaling $26 million for the year ended December 31, 2015.

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•	Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties.

•	Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.

•	Legacy sites related to Sunoco, Inc. that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that Sunoco, Inc. no longer operates, closed and/or sold refineries and other formerly owned sites.

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Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of December 31, 2017, Sunoco, Inc. had been named as a PRP at approximately 43 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.

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12.	DERIVATIVE ASSETS AND LIABILITIES:

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(1)	Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.

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(1)	Floating rates are based on 3-month LIBOR.

(2)	Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.

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13.	RETIREMENT BENEFITS:

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(1)	Comprised of approximately 100% equities as of December 31, 2017.

(1)	Comprised of approximately 100% equities as of December 31, 2016.

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(1)	Primarily comprised of approximately 48% equities, 51% fixed income securities and 1% cash as of December 31, 2017.

(1)	Primarily comprised of approximately 31% equities, 66% fixed income securities and 3% cash as of December 31, 2016.

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14.	RELATED PARTY TRANSACTIONS:

15.	REPORTABLE SEGMENTS:

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16.	QUARTERLY FINANCIAL DATA (UNAUDITED):

17.	CONSOLIDATING GUARANTOR FINANCIAL INFORMATION

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1.	I have reviewed this annual report on Form 10-K of Energy Transfer Partners, L.P. (the "registrant");

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize, and report financial information; and

b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

1.	I have reviewed this annual report on Form 10-K of Energy Transfer Partners, L.P. (the "registrant");

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize, and report financial information; and

b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

(1)	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

(1)	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.