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The merger resulted in the legal acquiree (pre-merger ETP) being treated as the surviving consolidated entity from an accounting perspective, while the surviving entity from a legal perspective was the registrant (the entity named Sunoco Logistics Partners L.P. prior to the merger). Therefore, for the pre-merger periods, the registrant’s consolidated financial statements have been retrospectively revised to reflect the consolidated financial statements of the legal acquiree (pre-merger ETP) as the predecessor to the post-merger combined entity.

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In connection with the merger, the unitholders of pre-merger ETP received 1.5 common units of the registrant for each common unit of pre-merger ETP they owned. As pre-merger ETP was treated as the predecessor of the post-merger combined entity, the historical common units and net income or loss per limited partner unit amounts presented in the accompanying financial statements and other information have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange.

•	Subsequent to the merger, the combined entity changed the presentation of its reportable segments. Accordingly, the accompanying financial statements and other information have been retrospectively revised to reflect the post-merger reportable segments.

•	Condensed consolidating financial information has been included in the notes to the consolidated financial statements pursuant to Rule 3-10 of Regulation S-X. The condensed consolidating financial information has been presented as if the merger occurred on January 1, 2014 (the beginning of the earliest period presented in the accompanying financial statements).

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•	We own an 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 wholly-owned subsidiary, Sunoco, Inc., owns an approximate 33% non-operating interest in PES, a refining joint venture with The Carlyle Group, L.P. (“The Carlyle Group”), 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 all of the outstanding equity interests of 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.

•	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.

•	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.

•	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 Coal Handling, which owns and operates 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.

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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 5,325 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.

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•	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 1,920 MMcf/d and one natural gas treating facility with capacity of 930 MMcf/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 1,186 MMcf/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

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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 facilities (Dubach, Dubberly, Lisbon, Salem, Elm Grove, Minden, Ada and Brookeland) have an aggregate capacity of 1,025 MMcf/d.

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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)	See description of the legacy Sunoco Logistics assets below.

•	The Lone Star Express System is an intrastate 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.

•	Legacy Sunoco Logistics NGL pipelines, including:

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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 345,000 Bbls/d for interstate and intrastate propane, ethane and butane service, and is expected to commence operations in the third quarter of 2017.

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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 Sunoco Logistics’ marine terminal in Nederland, Texas. The pipeline has a capacity of approximately 200,000 Bbls/d and can be scaled depending on shipper interest.

◦	The Mariner West pipeline provides transportation of ethane products from the Marcellus shale processing and fractionating areas in Houston, Texas and Pennsylvania to Marysville, Michigan and the Canadian border. Mariner West commenced operations in the fourth quarter 2013, with capacity to transport approximately 50,000 Bbls/d of NGLs and other products.

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Legacy Sunoco Logistics refined products pipelines include approximately 1,800 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 Sunoco Logistics’ 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 375,000 Bbls/d, the 45-mile Freedom pipeline with a capacity of 56,000 Bbls/d, the 15-mile Spirit pipeline with a capacity of 20,000 Bbls/d, the 82-mile Rio Bravo crude oil pipeline with a capacity of 100,000 Bbls/d and a 50% interest in the 87-mile Liberty pipeline with a capacity of 140,000 Bbls/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 product 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.

•	Sea Robin is a rich gas processing plant located on the Sea Robin Pipeline in southern Louisiana. The plant, which 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 and O-grade NGL fractionation complex located along the Mississippi River refinery corridor in southern Louisiana that cryogenically processes refinery off-gas and fractionates the O-grade NGL stream into its higher value components. The O-grade fractionator, located in Geismar, Louisiana, is connected by approximately 100 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 barrels 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 delivered via ship.

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The Marcus Hook Industrial Complex includes terminalling and storage assets, with a capacity of approximately 3 million barrels of NGL storage capacity in underground caverns, and related commercial agreements. The facility can receive NGLs 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 barrels 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 barrels 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.

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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 of approximately 6 million barrels, and provides customers with access to the facility via barge and pipeline. The terminal can deliver via barge, truck or pipeline, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.

•	The Marcus Hook Industrial Complex can receive refined products via marine vessel, pipeline, truck and rail, and can deliver via marine vessel, pipeline and truck. The terminal has a total active refined products storage capacity of approximately 2 million barrels.

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The Marcus Hook Tank Farm has a total refined products storage capacity of approximately 2 million barrels 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 Sunoco Logistics’ refined products pipelines.

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Southwest United States Pipelines. The Southwest pipelines include crude oil trunk pipelines and crude oil gathering pipelines in Texas and Oklahoma. This includes the Permian Express 2 pipeline project which provides takeaway capacity from the Permian Basin, with origins in multiple locations in Western Texas: Midland, Garden City and Colorado City. Our fourth quarter 2016 acquisition of a West Texas crude oil system from Vitol Inc. and the remaining ownership interest in PET facilitates connection of its Permian Express 2 pipeline to terminal assets in Midland and Garden City, Texas.

•	Midwest United States Pipelines. We own a controlling financial interest in 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 barrels in approximately 150 above ground storage tanks with individual capacities of up to 660,000 Bbls.

•	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 barrels and can receive crude oil via barge and rail and deliver via 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 barrels of crude oil storage, a combined 14 lanes of truck loading and unloading, and will provide access to the Permian Express 2 transportation system.

•	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);

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•	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.

•	Sunoco LP. We have an 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.

•	PES. We have a non-controlling interest in PES, comprising 33% of PES’ outstanding common units.

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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 through ET Interstate and Panhandle. ET Interstate is the parent company of Transwestern, ETC FEP, ETC Tiger, CrossCountry, ETC MEP and ET Rover. Panhandle is the parent company of the Trunkline and Sea Robin transmission systems.

•	Liquids operations, including NGL transportation, storage and fractionation services and refined products transportation.

•	Crude oil transportation, terminalling services and acquisition and marketing activities.

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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 through our pipelines as well as by charging fees for terminalling services for 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, 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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•	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.

•	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 $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 the Midcontinent Express pipeline 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 $209 million related to legacy ETP’s NGLs operations, as follows:

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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 year over 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 $80 million in legacy ETP’s NGL transportation fees due to higher NGL transport volumes from all producing regions, with the Permian region being the most significant among them; and

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an increase of $107 million in legacy ETP’s NGL processing and fractionation margin (excluding an increase in unrealized 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 118,000bbls/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 year over year. These gains were offset by an increase in storage fees paid of $2 million, and a decrease in margin from our refinery services segment of $3 million; partially offset by

•	a decrease of $24 million in other margin due to the timing of the withdrawal and sale of NGL component product inventory; and

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an increase of $20 million in legacy ETP’s operating expenses primarily due to increased costs associated with our third fractionator at Mont Belvieu and higher ad valorem expenses, partially offset by lower project related expenses. The remainder of the increase in operating expenses in the table above is related to legacy Sunoco Logistics’ NGLs and refined products operations, the results of which are discussed separately below;

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an increase of $65 million in Adjusted EBITDA from legacy Sunoco Logistics’ refined products operations driven primarily by improved operating results from refined products pipelines of $32 million, which benefited from higher volumes on Allegheny Access pipeline, and higher results from refined products acquisition and marketing activities of $21 million. Improved contributions from refined product joint venture interests of $6 million and higher earnings attributable to refined products terminals of $5 million also contributed to the increase; partially offset by

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a decrease in Adjusted EBITDA from legacy Sunoco Logistics’ NGLs operations of $16 million, largely attributable to lower operating results from our NGLs acquisition and marketing activities of $106 million due to lower volumes and margins compared to the prior year. These factors were largely offset by increased volumes and fees from our Mariner NGLs projects of $90 million, which includes our NGLs pipelines and Marcus Hook and Nederland facilities.

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•	an increase of $20 million in crude transport fees, primarily resulting from placing in-service the first phase of the Bayou Bridge pipeline in April 2016, and from placing crude gathering assets in West Texas in-service during the 2016 period; and

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an increase of $31 million from legacy Sunoco Logistics’ crude oil operations, primarily due to improved results from our crude oil pipelines of $155 million which benefited from the expansion capital projects which commenced operations in 2016 and 2015, and the fourth quarter 2016 acquisition from Vitol, including the remaining interest in SunVit. Higher results from our crude oil terminals of $31 million, largely related to Nederland facility, and improved contributions from crude oil joint venture interests of $16 million also contributed to the increase. These positive factors were largely offset by a decrease in operating results from our crude oil acquisition and marketing activities of $166 million, which includes transportation and storage fees related to our crude oil pipelines and terminal facilities, due to lower crude oil differentials and decreased volumes compared to the prior year.

•	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;

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•	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, an entity that owns and operates end-user 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)	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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a decrease of $13 million in natural gas sales and other margin (excluding changes in unrealized gains of $8 million) primarily due to a $19 million decrease in commercial optimization activity as a result of weather driven gains in 2014 not reoccurring in 2015, a $4 million decrease from processing and producer marketing services on our Houston Pipeline System, offset by $10 million in lower losses due to volume adjustments across our pipeline system;

•	a decrease of $17 million in storage margin, as discussed below; and

•	a decrease of $44 million from the sale of retained fuel (excluding changes in unrealized gains of $3 million) due to significantly lower market prices. The average spot price at the Houston Ship Channel location for the year ended December 31, 2015 decreased by $1.76, or 41%, to $2.57 as compared to $4.32 for the prior year period; partially offset by

•	an increase of $36 million in transportation fees margin primarily due to increased revenue from renegotiated and newly initiated long-term fixed capacity fee contracts on our Houston Pipeline system;

•	a decrease of $2 million in selling, general and administrative expenses primarily due to lower employee-related costs;

•	a decrease of $17 million in operating expenses primarily due to a decrease in fuel consumption expense driven by a decrease in fuel market prices.

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a decrease of $47 million in revenues primarily due to lower gas parking service related revenues of approximately $19 million as a result of higher basis differentials in 2014 driven by the colder weather, $22 million and $7 million due to the expiration of a transportation rate schedule and lower sales of gas due to lower prices, respectively, on the Transwestern pipeline, and $15 million due to a managed contract roll off on the Trunkline pipeline to facilitate the transfer of one of the pipelines that was taken out of service in advance of being repurposed from natural gas service to crude oil service. These decreases were partially offset by sales of capacity at higher rates of $13 million on the Panhandle and Transwestern pipelines, as well as higher usage rates and volumes on the Transwestern pipeline;

•	an increase of $13 million in operating expenses due to higher employee expenses of approximately $9 million due in part to lower capitalized costs and $3 million of higher ad valorem taxes primarily due to 2014 refunds associated with the settlement of litigation; and

•	the recognition of an $11 million keep-whole payment received from our FEP joint venture, which is included in “Other” in 2014; offset by

•	a decrease of $10 million in selling, general and administration expenses due to reduced franchise taxes of $3.5 million, state tax refund of $1.1 million, favorable insurance, primarily due to a $1.3 million OIL insurance rebate, and reduced corporate overhead allocations of $2.4 million.

•	an increase of $4 million in adjusted EBITDA related to unconsolidated affiliates primarily due to increased earnings from Citrus as a result of the sale of additional capacity.

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•	a decrease of $88 million in non-fee based margins for natural gas and a $200 million decrease in non-fee based margins for crude oil and NGL due to lower natural gas prices and lower crude oil and NGL prices; and

•	an increase of $135 million in operating expenses primarily due to assets recently placed in service, including the Rebel system in West Texas and the King Ranch system in South Texas, as well as the acquisition of Eagle Rock midstream assets in July 2014; partially offset by

•	an increase of $136 million in fee-based revenues primarily due to increased production and increased capacity from assets placed in service in the Marcellus Shale, Eagle Ford Shale, Permian Basin and Cotton Valley;

•	an increase of $120 million in fee-based margin from the acquisitions of the Eagle Rock, PVR, and King Ranch midstream assets;

•	an increase of $80 million in realized derivatives;

•	an increase of $8 million of Adjusted EBITDA related to unconsolidated affiliates due to the addition of the Mi Vida JV asset in the Permian Basin; and

•	a decrease of $10 million in selling, general and administration expenses due to increased capitalized overhead and higher management fees.

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•	an increase of $139 million related to legacy ETP’s NGLs operations, as follows:

•	an increase of $69 million in legacy ETP’s NGL transportation margin primarily due to higher volumes transported out of West Texas and the Eagle Ford producing regions;

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an increase of $42 million in processing and fractionation margin (excluding changes in unrealized gains of $8 million) due to $9 million increase in margin from our fractionators due to the ramp-up of our second 100,000 Bbls/d fractionator at Mont Belvieu, Texas, and the additional volumes from producers in West Texas and the Eagle Ford regions offset by reductions in blending gains due to lower market prices. Additionally, the commissioning of the Mariner South LPG export project during February 2015 contributed an additional $50 million for the twelve months ended December 31, 2015. Margin associated with our off-gas fractionator in Geismar, Louisiana decreased by $17 million for the year ended December 31, 2015 as NGL and olefin market prices decreased significantly for the comparable period;

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an increase of $15 million in storage margin due to a $24 million increase in fee based storage margin for year ended December 31, 2015 from an increase in demand for leased storage capacity as a result of favorable market conditions and a specific contract negotiated in connection with the Mariner South LPG export project. The increase in fee based storage margin was offset by lower non-fee based margin of $8 million for the year ended December 31, 2015 primarily due to lower propane blending gains;

•	an increase of $33 million in other margin (excluding changes in unrealized losses of $26 million) primarily due to the withdrawal and sale of physical storage volumes, primarily propane and butanes; and

•	a decrease of $4 million in selling, general and administrative expenses primarily due to lower employee-related costs; partially offset by

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an increase of $24 million in operating expenses primarily due to a $6 million increase in employee expenses, a $4 million increase in ad valorem taxes, a $3 million increase in utilities expense, a $6 million increase in project costs and materials and supplies expense, and a $5 million increase in overhead expense allocations. The remainder of the increase in operating expenses in the table above is related to Sunoco Logistics’ NGLs and refined products operations, the results of which are discussed separately below;

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an increase of $130 million in Adjusted EBITDA from legacy Sunoco Logistics’ NGLs operations, primarily due to contributions from Mariner NGLs projects which commenced operations in late 2014 and 2013. These projects contributed to improved results related to legacy Sunoco Logistics’ NGLs pipeline and terminal operations of $160 million, including the Nederland and Marcus Hook facilities. These positive impacts were partially offset by lower results from legacy Sunoco Logistics’ NGLs acquisition and marketing activities of $33 million driven largely by narrowed blending margins compared to the prior year period; and

•	an increase of $65 million in Adjusted EBITDA from legacy Sunoco Logistics’ refined products operations, primarily due to higher results from legacy Sunoco Logistics’ refined products pipelines of $33 million driven largely by the commencement of operations on the Allegheny Access project in 2015. Terminalling activities at legacy Sunoco Logistics’ refined products

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•	an increase of $7 million from legacy ETP’s commissioning of a crude pipeline in the fourth quarter of 2014; offset by

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a decrease of $13 million from legacy Sunoco Logistics’ crude oil operations, primarily due to lower results from our crude oil acquisition and marketing activities of $96 million driven by reduced margins which were negatively impacted by contracted crude oil differentials compared to the prior year period. This impact was partially offset by higher results from our crude oil pipelines of $71 million largely attributable to expansion projects placed into service in 2015 and 2014, and higher results from our crude oil terminals of $14 million.

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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 37.8 million Sunoco LP common units;

•	our natural gas marketing and compression operations;

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

•	our investment in Coal Handling, an entity that owns and operates end-user coal handling facilities; and

•	our investment in AmeriGas until August 2014.

•	a decrease of $124 million due to the deconsolidation of Sunoco LP as a result of the sale of Sunoco LP’s general partner interest and incentive distribution rights to ETE effective July 1, 2015;

•	a decrease of $121 million due to unfavorable fuel margins and $9 million due to unfavorable volumes in the retail and wholesale channels;

•	a decrease of $49 million in margins as 2014 benefited from favorable regional market conditions for ethanol;

•	a decrease of $63 million in Adjusted EBITDA related to unconsolidated affiliates, primarily due to a decrease of $56 million related to our investment in AmeriGas driven by a reduction in our investment due to the sale of AmeriGas common units in 2014; and

•	a decrease in Adjusted EBITDA related to discontinued operations of $27 million in the prior period related to a marketing business that was sold effective April 1, 2014; partially offset by

•	the favorable impact of $112 million from the acquisition of Susser in August 2014 until its contribution to Sunoco LP in July 2015 and $43 million from other recent acquisitions.

•	an increase of $21 million related to our contract services operations primarily due to an increase in revenue-generating horsepower; and

•	an increase of $17 million related to our natural resources operations, for which the period reflected only a partial period due to the acquisition of those operations in March 2014.

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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.	OPERATIONS AND BASIS OF PRESENTATION:

•	References to “ETP” refer to the entity named Energy Transfer Partners, L.P. prior to the close of the merger and 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 “Post-Merger 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:

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

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

6.	DEBT OBLIGATIONS:

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(1)	Sunoco Logistics’ $1.0 billion 364-Day Credit Facility, including its $630 million term loan, were classified as long-term debt as of December 31, 2016 as Sunoco Logistics has the 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 Facility) during certain Defaults (as defined in the ETP Credit Facility) and during any Event of Default (as defined in the ETP Credit Facility);

•	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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7.	SERIES A 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.

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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:

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(1)	Includes contingent rentals totaling $26 million and $24 million for the years ended December 31, 2015 and 2014, respectively.

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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.

•	Currently operating Sunoco, Inc. retail sites.

•	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, 2016, Sunoco, Inc. had been named as a PRP at approximately 50 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 10 and 30 years with a mandatory termination date the same as the effective date.

(3)	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, 2016.

(1)	Comprised of approximately 100% equities as of December 31, 2015.

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

(1)	Primarily comprised of approximately 56% equities, 33% fixed income securities and 11% cash as of December 31, 2015.

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14.	RELATED PARTY TRANSACTIONS:

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15.	REPORTABLE SEGMENTS:

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16.	QUARTERLY FINANCIAL DATA (UNAUDITED):

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17.	CONSOLIDATING GUARANTOR FINANCIAL INFORMATION

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