Energy Transfer LP - Annual Report: 2019 (Form 10-K)

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•	natural gas operations, including the following:

•	natural gas midstream and intrastate transportation and storage;

•	interstate natural gas transportation and storage; and

•	crude oil, NGL and refined products transportation, terminalling services and acquisition and marketing activities, as well as NGL storage and fractionation services.

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•	In December 2019, ET completed its acquisition of Tulsa-based SemGroup Corporation in a unit and cash transaction, and during the first quarter of 2020, certain of the operating assets of SemGroup were contributed to ETO. The segment and asset overviews below include the SemGroup assets.

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In December 2019, ET announced a comprehensive commercial tender package which was issued to engineering, procurement and construction contractors to submit final bids for the proposed Lake Charles LNG liquefaction project being developed with Shell US LNG, LLC. The project would modify ETO’s existing LNG import facility located in Lake Charles, Louisiana to add LNG liquefaction capacity of 16.45 million tonnes per annum for expert to global markets. The commercial bids are expected to be received in the second quarter of 2020.

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In connection with the acquisition of SemGroup and to provide shippers with further access to markets along the Gulf Coast through the Houston Ship Channel, ET announced the construction of the Ted Collins pipeline, a 75-mile crude line that will connect Houston Terminal, which was recently acquired in the SemGroup acquisition, to the Nederland terminal. The pipeline is expected to be in service in 2021 and will have an initial capacity of 500 MBbls/d.

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•	approximately 4,515 miles of NGL pipelines;

•	NGL and propane fractionation facilities with an aggregate capacity of 825 MBbls/d;

•	NGL storage facility in Mont Belvieu with a working storage capacity of approximately 50 MMBbls; and

•	other NGL storage assets, located at our Cedar Bayou and Hattiesburg storage facilities, and our Nederland, Marcus Hook and Inkster NGL terminals with an aggregate storage capacity of approximately 13 MMBbls.

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

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•	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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•	Our approximately 7.4% non-operating interest in PES, which owns a refinery in Philadelphia.

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Our 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.

•	Our natural gas compression equipment business which has operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas.

•	Our wholly-owned subsidiary, Dual Drive Technologies, Ltd. (“DDT”), which provides compression services to customers engaged in the transportation of natural gas, including our other segments.

•	Our subsidiaries 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.

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

•	Our 51% ownership interest in SemCAMS, which owns and operates natural gas processing and gathering facilities in Alberta, Canada.

(1)	Includes bi-directional capabilities

•	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

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The Oasis Pipeline is primarily a 36-inch natural gas pipeline. It has bi-directional capabilities with approximately 1.3 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, Beaumont 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, Carthage and Agua Dulce, as well as our Bammel storage facility.

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The ETC Katy Pipeline connects three treating facilities, one of which we own, with our gathering system known as Southeast Texas System. The ETC Katy pipeline serves producers in East and North Central Texas and provided access to the Katy Hub. The ETC Katy 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.

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

•	Old Ocean is a 240-mile intrastate pipeline system that delivers natural gas from Ellis County, Texas to Brazoria County, Texas. The Partnership owns a 50% membership interest in and operates Old Ocean.

•	The Red Bluff Express Pipeline is an approximately 108-mile intrastate pipeline that runs through the heart of the Delaware basin and connects our Orla Plant, as well as third-party plants to the Waha Oasis Header. The Partnership owns a 70% membership interest in and operates Red Bluff Express.

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(1)	Natural gas storage assets are owned by Southwest Gas.

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Florida Gas Transmission Pipeline (“FGT”) has mainline capacity of 3.5 Bcf/d and approximately 5,362 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 approximately 60% of the natural gas consumed in the state. In addition, FGT’s system operates and maintains multiple 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, industrial end-users and local distribution companies. FGT is owned by Citrus, a 50/50 joint venture with KMI.

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Transwestern Pipeline transports natural gas supply from 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. The system has bi-directional capabilities and can access Texas and Midcontinent natural gas market hubs, as well as major western markets in Arizona, Nevada and California.  Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users.

•	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. Panhandle contracts for over 73 Bcf of natural gas storage.

•	Trunkline Gas Company’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. Trunkline has one natural gas storage field located in Louisiana.

•	Tiger Pipeline is a bi-directional system that extends through the heart of the Haynesville Shale and ends near Delhi, Louisiana, interconnecting with multiple interstate pipelines.

•	Fayetteville Express Pipeline originates near Conway County, Arkansas and continues eastward to Panola County, Mississippi with multiple pipeline interconnections along the route.  Fayetteville Express Pipeline is owned by a 50/50 joint venture with KMI.

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

•	Stingray Pipeline is an interstate natural gas pipeline system with related assets located in the western Gulf of Mexico and Johnson Bayou, Louisiana.

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•	Rover Pipeline is a large diameter pipeline with total capacity to transport 3.25 Bcf/d natural gas from processing plants in West Virginia, Eastern Ohio and Western Pennsylvania for delivery to other pipeline interconnects in Ohio and Michigan, where the gas is delivered for distribution to markets across the United States, as well as to Ontario, Canada.

•	Midcontinent Express Pipeline originates near Bennington, Oklahoma and traverses 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, the operator of the system.

•	Gulf States Transmission is 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 ETC Katy Pipeline and is also connected to the Oasis Pipeline. The Southeast Texas System includes two natural gas processing plants (La Grange and Alamo) with aggregate capacity of 410 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. 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 1.4 Bcf/d.

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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, a 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 an NGL pipeline that provides connections to the Mont Belvieu market for NGLs produced from our processing plants. Collectively, the ten natural gas processing facilities (Dubach, Dubberly, Lisbon, Salem, Elm Grove, Minden, Ada, Brookeland, Lincoln Parish and Mt. Olive) have an aggregate capacity of 1.3 Bcf/d.

•	Through the gathering and processing systems described above and their interconnections with RIGS in north Louisiana, as well as other pipelines, 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 700 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 midcontinent 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 eleven processing facilities (Waha, Coyanosa, Red Bluff, Halley, Jal, Keyston, Tippet, Orla, Panther, Rebel and Arrowhead) with an aggregate processing capacity of 2.4 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.

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•	We own a 50% 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 Midcontinent 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 and the STACK in central Oklahoma. These mature basins have continued to provide generally long-lived, predictable production volume. Our Midcontinent assets are extensive systems that gather, compress and dehydrate low-pressure gas. The Midcontinent Systems include sixteen natural gas processing facilities (Mocane, Beaver, Antelope Hills, Woodall, Wheeler, Sunray, Hemphill, Phoenix, Hamlin, Spearman, Red Deer, Lefors, Cargray, Gray, Rose Valley, and Hopeton) with an aggregate capacity of approximately 1.4 Bcf/d.

•	We operate our Midcontinent 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 eleven counties in Pennsylvania, four counties in Ohio, three counties in West Virginia, and gather natural gas from the Marcellus and Utica basins. Our Eastern Region assets include approximately 600 miles of natural gas gathering pipeline, natural gas trunklines, fresh-water pipelines, and nine gathering and processing systems, as well as the 200 MMcf/d Revolution processing plant, which feeds into our Mariner East and Rover pipeline systems.

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

•	We own a 75% membership interest in ORS. On behalf of ORS, we operate its Ohio Utica River System, which consists of 47 miles of 36-inch, 13 miles of 30-inch and 3 miles of 24-inch gathering trunklines, that delivers up to 3.6 Bcf/d to Rockies Express Pipeline, Texas Eastern Transmission, Leach Xpress, Rover and DEO TPL-18.

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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.

(3)	The White Cliffs Pipeline consists of two parallel, 12-inch common carrier pipelines: one crude oil pipeline and one NGL pipeline.

•	The Lone Star Express System is an interstate NGL pipeline consisting of 24-inch and 30-inch long-haul transportation pipeline, with throughput capacity of approximately 500 MBbls/d, that delivers mixed NGLs from processing plants in the

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•	The West Texas Gateway Pipeline transports NGLs produced in the Permian and Delaware Basins and the Eagle Ford Shale to Mont Belvieu, Texas and has a throughput capacity of approximately 240 MBbls/d.

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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, began service in December 2018. The Mariner East pipeline has a throughput capacity of approximately 345 MBbls/d.

•	The Mariner South liquids pipeline delivers export-grade propane and butane products from Lone Star’s Mont Belvieu, Texas storage and fractionation complex to our marine terminal in Nederland, Texas and has a throughput capacity of approximately 200 MBbls/d.

•	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 and has a throughput capacity of approximately 50 MBbls/d.

•	The White Cliffs NGL pipeline, which we have 51% ownership interest in and which was acquired by ET in the SemGroup acquisition and contributed to ETO in January 2020, transports NGLs produced in the DJ Basin to Cushing, where it interconnects with the Southern Hills Pipeline to move NGLs to Mont Belvieu, Texas and has a throughput capacity of approximately 40 MBbls/d.

•	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 approximately 50 MMBbls 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 VI was placed in service in February 2019, Fractionator VII was placed in service in the first quarter of 2020, and Fractionator VIII is currently under construction and is scheduled to be operational by the second quarter of 2021.

•	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 MMBbls of salt dome capacity, providing 100% fee-based cash flows.

•	The Cedar Bayou storage facility is an integrated liquids storage facility with approximately 1.6 MMBbls of tank storage, generating revenues from fixed fee storage contracts, throughput fees, and revenue from blending butane into refined gasoline.

•	The Nederland terminal, in addition to crude oil activities, also provides approximately 1.2 MMBbls 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 MMbbls of NGL storage capacity in underground caverns, 4 MMbbls of above-ground refrigerated storage, and related commercial agreements. The terminal has a total active refined products storage capacity of approximately 1 MMbbls. The facility can receive NGLs and refined products via marine vessel, pipeline, truck and rail, and can deliver via marine vessel,

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The Inkster terminal, located near Detroit, Michigan, consists of multiple salt caverns with a total storage capacity of approximately 860 MBbls 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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The Eastern region refined products pipelines consist of approximately 615 miles of 6-inch to 16-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 180 miles of various diameters refined products pipeline in New Jersey (including 80 miles of the 16-inch diameter Harbor Pipeline).

•	The midcontinent region refined products pipelines primarily consist of approximately 296 miles of 3-inch to 12-inch refined products pipelines in Ohio and approximately 53 miles of 6-inch and 8-inch refined products pipeline in Michigan.

•	The Southwest region refined products pipelines are located in Eastern Texas and consist primarily of approximately 876 miles of 8-inch diameter refined products pipeline.

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The Inland refined products pipeline is approximately 580 miles of pipeline in Ohio, consisting of 72 miles of 12-inch diameter refined products pipeline in Northwest Ohio, 206 miles of 10-inch diameter refined products pipeline in vicinity of Columbus, Ohio, 135 miles of 8-inch diameter refined products pipeline in western Ohio, and 168 miles of 6-inch diameter refined products pipeline in Northeast Ohio.

•	The JC Nolan Pipeline is a joint venture between a wholly-owned subsidiary of the Partnership and a wholly-owned subsidiary of Sunoco LP, which transports diesel fuel from a tank farm in Hebert, Texas to Midland, Texas, and was placed into service in July 2019 and has a throughput capacity of approximately 36 MBbls/d.

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We have approximately 35 refined products terminals with an aggregate storage capacity of approximately 8 MMBbls 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 7 MMBbls, and provides customers with access to the facility via ship, barge and pipeline. The terminal can deliver via ship, 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 Tank Farm has a total refined products storage capacity of approximately 2 MMBbls of refined products storage. The terminal receives and delivers refined products via pipeline and primarily provides terminalling services to support movements on our refined products pipelines.

•	The JC Nolan Terminal, located in Midland, Texas, is a joint venture between a wholly-owned entity of the Partnership and wholly-owned entity of Sunoco LP, which provides diesel fuel storage that was placed into service in August 2019.

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This segment also includes the following joint ventures: 15% membership interest in the Explorer Pipeline Company, a 1,850-mile pipeline which originates from refining centers in Beaumont, Port Arthur, and Houston, Texas and extends to Chicago, Illinois; 31% membership interest in the Wolverine Pipe Line Company, a 1,055-mile pipeline that originates from Chicago, Illinois and extends to Detroit, Grand Haven, and Bay City, Michigan; 17% membership interest in the West Shore Pipe Line Company, a 650-mile pipeline which originates in Chicago, Illinois and extends to Madison and Green Bay, Wisconsin; a 14% membership interest in the Yellowstone Pipe Line Company, a 710-mile pipeline which originates from Billings, Montana and extends to Moses Lake, Washington.

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(1)	Miles of pipeline as reported to PHMSA.

(2)	The White Cliffs Pipeline consists of two parallel, 12-inch common carrier crude oil pipelines: one crude oil pipeline and one NGL pipeline.

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Bakken Pipeline. Dakota Access and ETCO are collectively referred to as the “Bakken Pipeline.” The Bakken Pipeline is a 1,916 mile pipeline with capacity of 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 ETO and Phillips 66, in which ETO 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 consists of 24-inch pipe from Lake Charles, Louisiana to St. James, Louisiana, which went into service in March 2019.

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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 Express 3, Permian Express 4, which became operational in May 2019, Permian Longview and Louisiana Access pipelines, as well as the Longview to Louisiana and Nederland Access 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.

•	White Cliffs Pipeline. White Cliffs Pipeline, which was acquired by ET in the SemGroup acquisition and contributed to ETO in January 2020, owns a12-inch common carrier, crude oil pipeline, with a throughput capacity of 100 MBbls/d, that transports crude oil from Platteville, Colorado to Cushing, Oklahoma.

•	Maurepas Pipeline. The Maurepas Pipeline, which was acquired by ET in the SemGroup acquisition and contributed to ETO in January 2020, consists of three pipelines, with an aggregate throughput capacity of 460 MBbls/d, which service refineries in the Gulf Coast region.

•	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, petrochemicals and bunker oils (used for fueling ships and other marine vessels). The terminal currently has a total storage capacity of approximately 29 MMBbls in approximately 150 above ground storage tanks with individual capacities of up to 660 MBbls.

•	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 1.3 MMBbls 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 MMBbls of crude oil storage, a combined 20 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 MMBbls.

•	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 MMBbls of crude oil storage.

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Houston Terminal. The Houston Terminal, which was acquired by ET in the SemGroup acquisition and contributed to ETO in February 2020, consists of storage tanks located on the Houston Ship Channel with an aggregate storage capacity of 18.2 MMBbls used to store, blend and transport refinery products and refinery feedstocks via pipeline, barge, rail, truck and ship. This facility has five deep-water ship docks on the Houston Ship Channel capable of loading and unloading Suezmax cargo vessels and seven barge docks which can accommodate 23 barges simultaneously, three crude oil pipelines connecting to four refineries and numerous rail and truck loading spots.

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Cushing Facilities. The Cushing Facility, which was acquired by ET in the SemGroup acquisition and contributed to ETO in January 2020, has approximately 7.6 MMBbls crude oil storage, of which 5.6 MMBbls are leased to customer and 2.0 MMBbls are available for crude oil operations, blending and marketing activities. The storage terminal has inbound connections with the White Cliffs Pipeline from Platteville, Colorado, the Great Salt Plains Pipeline from Cherokee, Oklahoma, the Cimarron Pipeline from Boyer, Kansas, and two-way connections with all of the other major storage terminals in Cushing. The Cushing terminal also includes truck unloading facilities.

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•	Sunoco, LLC (“Sunoco LLC”), a Delaware limited liability company, primarily distributes motor fuel in 30 states throughout the East Coast, Midwest, South Central and Southeast regions of the United States. Sunoco LLC also processes transmix and distributes refined product through its terminals in Alabama, Texas, Arkansas and New York;

•	Sunoco Retail LLC (“Sunoco Retail”), a Pennsylvania limited liability company, owns and operates retail stores that sell motor fuel and merchandise primarily in New Jersey;

•	Aloha Petroleum LLC, a Delaware limited liability company, distributes motor fuel and operates terminal facilities on the Hawaiian Islands; and

•	Aloha Petroleum, Ltd. (“Aloha”), a Hawaii corporation, owns and operates retail stores on the Hawaiian Islands.

•	75 company owned and operated retail stores;

•	537 independently operated consignment locations where Sunoco LP sells motor fuel to customers under commission agent arrangements with such operators;

•	6,742 convenience stores and retail fuel outlets operated by independent operators, which are referred to as “dealers” or “distributors,” pursuant to long-term distribution agreements; and

•	2,581 other commercial customers, including unbranded convenience stores, other fuel distributors, school districts and municipalities and other industrial customers.

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(1)	As of December 31, 2019, USAC had 56,500 large horsepower compression units on order for delivery during 2020.

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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;

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•	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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•	interest expense and principal payments on our indebtedness;

•	restrictions on distributions contained in any current or future debt agreements;

•	our general and administrative expenses;

•	expenses of our subsidiaries other than ETO and its subsidiaries, including tax liabilities of our corporate subsidiaries, if any; and

•	reserves our general partner believes prudent for us to maintain for the proper conduct of our business or to provide for future distributions.

•	the amount of natural gas, NGLs, crude oil and refined products transported through ETO’s pipelines;

•	the level of throughput in processing and treating operations;

•	the fees charged and the margins realized by ETO, Sunoco LP and USAC for their services;

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

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

•	the weather in their respective operating areas;

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

•	the level of their respective operating costs and maintenance and integrity capital expenditures;

•	the tax profile on any blocker entities treated as corporations for federal income tax purposes that are owned by any of our subsidiaries;

•	prevailing economic conditions; and

•	the level and results of their respective derivative activities.

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•	the level of capital expenditures they 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;

•	debt service requirements;

•	fluctuations in working capital needs;

•	their ability to borrow under their respective revolving credit facilities;

•	their ability to access capital markets;

•	restrictions on distributions contained in their respective debt agreements; and

•	the amount, if any, of cash reserves established by the board of directors and their respective general partners in their discretion for the proper conduct of their respective businesses.

•	our Unitholders’ current proportionate ownership interest 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 our Common Units may decline.

•	Unitholders’ current proportionate ownership interest in each partnership 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 each partnership’s common units may decline.

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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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•	a significant portion of ETO’s and its subsidiaries’ cash flows 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 to us;

•	covenants contained in ETO’s and its subsidiaries’ existing debt agreements require ETO and its subsidiaries, as applicable, to meet financial tests that may adversely affect their flexibility in planning for and reacting to changes in their respective businesses;

•	ETO’s and its 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;

•	ETO and its subsidiaries may be at a competitive disadvantage relative to similar companies that have less debt;

•	ETO and its subsidiaries may be more vulnerable to adverse economic and industry conditions as a result of their significant debt levels;

•	failure by ETO or its subsidiaries to comply with the various restrictive covenants of the respective debt agreements could negatively impact ETO’s and/or its subsidiaries’ ability to incur additional debt, including their ability to utilize the available capacity under their revolving credit facilities, and to pay distributions to us and their unitholders.

•	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.

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•	economic downturns;

•	deteriorating capital market conditions;

•	declining market prices for crude oil, 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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•	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;

•	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

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•	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.

•	the allocation of shared overhead expenses to ETO, Sunoco LP, USAC and us;

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•	the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and ETO, Sunoco LP and USAC, on the other hand;

•	the determination of the amount of cash to be distributed to ETO’s, Sunoco LP’s and USAC’s partners and the amount of cash to be reserved for the future conduct of ETO’s, Sunoco LP’s and USAC’s businesses;

•	the determination whether to make borrowings under ETO’s, Sunoco LP’s and USAC’s revolving credit facilities to pay distributions to their respective partners;

•	the determination of whether a business opportunity (such as a commercial development opportunity or an acquisition) that we may become aware of independently of ETO, Sunoco LP and USAC is made available for ETO, Sunoco LP and USAC to pursue; and

•	any decision we make in the future to engage in business activities independent of ETO, Sunoco LP and USAC.

•	our general partner is allowed to take into account the interests of parties other than us, including ETO, and its subsidiaries, including Sunoco LP and USAC, and their respective affiliates and any general partners and limited partnerships acquired in the future, in resolving conflicts of interest, which has the effect of limiting its fiduciary duties to us.

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our general partner has limited its liability and reduced its fiduciary duties under the terms of our partnership agreement, while also restricting the remedies available for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing our units, Unitholders consent to various actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law.

•	our general partner determines the amount and timing of our investment transactions, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution.

•	our general partner determines which costs it and its affiliates have incurred are reimbursable by us.

•	our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered, or from entering into additional contractual arrangements with any of these entities on our behalf, so long as the terms of any such payments or additional contractual arrangements are fair and reasonable to us.

•	our general partner controls the enforcement of obligations owed to us by it and its affiliates.

•	our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

•	permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This 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 “good faith” if it reasonably believes that the decisions are in our best interests;

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generally provides that affiliated transactions and resolutions of conflicts of interest not approved by a conflicts committee of the board of directors of our general partner and not involving a vote of Unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or 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 totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us;

•	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; and

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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 any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence.

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•	inability to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;

•	inability to raise financing for such acquisitions on economically acceptable terms; or

•	inability to outbid by competitors, some of which are substantially larger than ETO or its subsidiaries and may have greater financial resources and lower costs of capital.

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

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

•	significantly increase its interest expense or financial leverage if the acquisition is financed with additional debt;

•	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 there is no indemnity or the indemnity is inadequate;

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

•	less effectively manage its 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.

•	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;

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•	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.

•	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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•	price competition;

•	the perception that another company can provide better service; and

•	the availability of alternative supply points, or supply points located closer to the operations of our customers.

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•	inability to identify pipeline construction opportunities with favorable projected financial returns;

•	inability to raise financing for its identified pipeline construction opportunities; or

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

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•	the inability to renew a ground lease for certain of their fuel storage terminals on similar terms or at all;

•	the dependence on third parties to supply their fuel storage terminals;

•	outages at their fuel storage terminals or interrupted operations due to weather-related or other natural causes;

•	the threat that the nation’s terminal infrastructure may be a future target of terrorist organizations;

•	the volatility in the prices of the products stored at their fuel storage terminals and the resulting fluctuations in demand for storage services;

•	the effects of a sustained recession or other adverse economic conditions;

•	the possibility of federal and/or state regulations that may discourage their customers from storing gasoline, diesel fuel, ethanol and jet fuel at their fuel storage terminals or reduce the demand by consumers for petroleum products;

•	competition from other fuel storage terminals that are able to supply their customers with comparable storage capacity at lower prices; and

•	climate change legislation or regulations that restrict emissions of GHGs could result in increased operating and capital costs and reduced demand for our storage services.

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•	perform ongoing assessments of pipeline integrity;

•	identify and characterize applicable threats to pipeline operations 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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•	provide for the proper conduct of its business;

•	comply with applicable law and/or debt instrument or other agreement; and

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

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•	intrastate transportation and storage;

•	interstate transportation and storage;

•	midstream;

•	NGL and refined products transportation and services;

•	crude oil transportation and services;

•	investment in Sunoco LP;

•	investment in USAC; and

•	all other.

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•	an increase of $198 million recognized by the Partnership (excluding Sunoco LP and USAC, which are discussed below) primarily due to increases in ETO’s long-term debt;

•	an increase of $49 million recognized by USAC primarily attributable to higher overall debt balances and higher interest rates on borrowings under the credit agreement. These increases were partially offset by the decrease in borrowings under the credit agreement; and

•	an increase of $29 million recognized by Sunoco LP due to an increase in total long-term debt; offset by

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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.

•	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.

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Adjusted EBITDA related to unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have

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•	an increase of $64 million in transportation fees, excluding the impact of consolidating RIGS beginning April 2018 as discussed below, primarily due to the Red Bluff Express pipeline coming online in May 2018, as well as new contracts;

•	a net increase of $11 million primarily due to the consolidation of RIGS beginning April 2018, resulting in increases in transportation fees, retained fuel revenues and operating expenses of $24 million, $2 million and $6 million, respectively, partially offset by a decrease in Adjusted EBITDA related to unconsolidated affiliates of $9 million; and

•	an increase of $7 million in realized storage margin primarily due to a realized adjustment to the Bammel storage inventory of $25 million in 2018 and higher storage fees, partially offset by a $20 million decrease due to lower physical withdrawals; partially offset by

•	a decrease of $9 million in retained fuel revenues primarily due to lower gas prices; and

•	a decrease of $5 million in realized natural gas sales and other due to lower realized gains from pipeline optimization activity.

•	an increase in margin of $231 million from the Rover pipeline due to higher reservation and usage resulting from additional connections and utilization of additional compression;

•	an increase of $40 million in reservation and usage fees due to improved market conditions allowing us to successfully bring new volumes to the system at improved rates, primarily on our Transwestern, Tiger and Panhandle Eastern systems; and

•	an increase of $6 million from the Sea Robin pipeline due to higher rates resulting from the rate case filed in June 2019, as well as fewer third party supply interruptions on the Sea Robin system; partially offset by

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an increase of $138 million in operating expense primarily due to an increase in ad valorem taxes of $126 million on the Rover pipeline system resulting from placing the final portions of this asset into service in November 2018, an increase of $24 million in transportation expense on Rover due to an increase in transportation volumes, an increase of $5 million in allocated overhead costs and additional operating expense of $4 million for assets acquired in June 2019, partially offset by lower gas imbalance and system gas activity of $15 million and lower storage capacity leased on the Panhandle Eastern system of $8 million;

•	an increase of $9 million in selling, general and administrative expenses primarily due to an increase in insurance expense of $8 million, an increase in employee cost of $4 million, and an increase in allocated overhead costs of $3 million, partially offset by lower Ohio excise tax on our Rover system; and

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•	a decrease of $15 million in adjusted EBITDA related to unconsolidated affiliates primarily resulting from a $20 million decrease due to lower earnings from MEP as a result of lower capacity being re-contracted at lower rates on expiring contracts, partially offset by a $5 million increase from our Citrus joint venture as we brought new volumes to the system in 2019.

•	a decrease of $137 million in non fee-based margin due to lower NGL prices of $131 million and lower gas prices of $58 million, offset by an increase of $52 million in non fee-based margin due to increased throughput volume in North Texas, South Texas and Permian regions;

•	an increase of $86 million in operating expenses due to increases of $33 million in outside services, $29 million in maintenance project costs, $17 million in employee costs and $6 million in office expenses and materials; and

•	an increase of $9 million in selling, general and administrative expenses primarily due to a decrease of $5 million in capitalized overhead and an increase of $4 million in insurance expense; partially offset by

•	an increase of $214 million in fee-based margin due to volume growth in the Northeast, Permian, Ark-La-Tex, North Texas and South Texas regions.

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an increase of $483 million in transportation margin primarily due to a $265 million increase resulting from the initiation of service on our Mariner East 2 pipeline in the fourth quarter of 2018, a $212 million increase resulting from higher throughput volumes received from the Permian region on our Texas NGL pipelines, a $29 million increase due to higher throughput volumes from the Barnett region, a $9 million increase from the Eagle Ford region, and a $9 million increase due to the

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an increase of $153 million in fractionation and refinery services margin primarily due to a $167 million increase resulting from the commissioning of our fifth and sixth fractionators in July 2018 and February 2019, respectively, and higher NGL volumes from the Permian region feeding our Mont Belvieu fractionation facility. This increase was partially offset by a reclassification between our fractionation and storage margins;

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an increase of $136 million in terminal services margin primarily due to a $171 million increase from the initiation of service of our Mariner East 2 pipeline which commenced operations in the fourth quarter of 2018 and a $7 million increase due to increased tank lease revenue from third-party customers. These increases were partially offset by a $16 million decrease in volumes and expense reimbursements from third parties on Mariner East 1, a $16 million decrease due to lower volumes from third party pipeline, truck and rail deliveries into our Marcus Hook terminal, a $5 million decrease due to fewer vessels exported out of our Nederland terminal, and a $4 million decrease due to the closure of a third party refinery during the third quarter of 2019; and

•	an increase of $12 million in storage margin primarily due to a reclassification between our storage and fractionation margins; partially offset by

•	a decrease of $30 million in marketing margin primarily due to capacity lease fees incurred by our marketing affiliate on our Mariner East 2 pipeline, offset by increased gains from our butane blending business due to more favorable market conditions and increased volumes, as well as increased optimization gains from the sale of NGL component products at our Mont Belvieu facility;

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an increase of $52 million in operating expenses primarily due to a $26 million increase in employee and ad valorem tax expenses on our terminals, fractionation, and transportation operations, a $14 million increase in utility costs to operate our pipelines and our fifth and sixth fractionators which commenced July 2018 and February 2019, respectively, and an $8 million increase in maintenance project costs due to the timing of multiple projects on our transportation assets; and

•	an increase of $19 million in general and administrative expenses primarily due to a $10 million increase in allocated overhead costs, a $5 million increase in insurance expenses, a $4 million increase in legal fees, and a $2 million increase in employee costs.

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an increase of $672 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $282 million increase resulting from higher throughput on our Texas crude pipeline system primarily due to increased production from the Permian region and contributions from capacity expansion projects placed into service, a $219 million increase in throughput on our Bakken pipeline, a favorable inventory valuation adjustment of

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•	an increase of $23 million in operating expenses primarily due to a $30 million increase in throughput-related costs on existing assets and a $10 million increase due to the inclusion of expenses acquired in 2019, partially offset by a $14 million decrease in management fees as well as the impact of certain intrasegment transactions discussed above;

•	a decrease of $7 million in Adjusted EBITDA related to unconsolidated affiliates due to lower margin from jet fuel sales by our joint ventures.

•	a decrease in operating costs of $76 million, primarily as a result of the conversion of 207 retail sites to commission agent sites during April 2018. These expenses include other operating expense, general and administrative expense and lease expense; and

•	an increase of $25 million related to Adjusted EBITDA from discontinued operations related to the divestment of 1,030 company-operated fuel sites to 7-Eleven in January 2018; and

•	an increase of $4 million in Adjusted EBITDA related to unconsolidated affiliates due to Sunoco LP’s investment in the JC Nolan joint venture; partially offset by

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a decrease in the gross profit on motor fuel sales of $76 million (excluding the change in inventory fair value adjustments and unrealized gains and losses on commodity risk management activities) primarily due to lower fuel margins, a one-time benefit of approximately $25 million related to a cash settlement with a fuel supplier recorded in 2018 and an $8 million one-time charge related to a reserve for an open contractual dispute recorded in 2019, partially offset by an increase in gallons sold.

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•	our natural gas marketing operations;

•	our wholly-owned natural gas compression operations;

•	a non-controlling interest in PES. Prior to PES’s reorganization in August 2018, ETO’s 33% interest in PES was reflected as an unconsolidated affiliate; subsequent the August 2018 reorganization, ETO holds an approximately 7.4% interest in PES and no longer reflects PES as an affiliate;

•	our investment in coal handling facilities; and

•	our Canadian operations, which were acquired in the SemGroup acquisition in December 2019 and include natural gas gathering and processing assets.

•	an increase of $8 million in gains from park and loan and storage activity;

•	an increase of $11 million in optimized gains on residue gas sales;

•	an increase of $7 million from settled derivatives;

•	an increase of $15 million from a legal settlement;

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•	an increase of $12 million from payments related to the PES bankruptcy;

•	an increase of $6 million from the recognition of deferred revenue related to a bankruptcy;

•	an increase of $3 million from power trading activities;

•	an increase of $3 million from the SemCAMS joint venture for the period subsequent to our acquisition of SemGroup on December 5, 2019, net of an increase in SemGroup corporate expenses; and

•	a decrease of $40 million in merger and acquisition expenses; partially offset by

•	a decrease of $36 million due to the contribution of CDM to USAC in April 2018, subsequent to which CDM is reflected in the Investment in USAC segment;

•	a decrease of $8 million due to lower gas prices and increased power costs; and

•	a decrease of $11 million due to lower revenue from our compressor equipment business.

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•	an increase of $121 million recognized by ETO primarily related to an increase in long-term debt, including additional senior note issuances and borrowings under our revolving credit facilities; and

•	an increase of $78 million due to the acquisition of USAC on April 2, 2018; partially offset by

•	a decrease of $65 million recognized by Sunoco LP primarily due to the repayment in full of its term loan and refinancing of its senior notes at lower rates.

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(1)	The partnership previously owned a 49.99% interest in HPC, which owns RIGS. In April 2018, we acquired the remaining 50.01% interest in HPC. Prior to April 2018, HPC was reflected as an unconsolidated affiliate in our financial statements; beginning in April 2018, RIGS is reflected as a wholly-owned subsidiary in our financial statements.

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

(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.

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•	an increase of $314 million in realized natural gas sales and other due to higher realized gains from pipeline optimization activity;

•	a net increase of $14 million due to the consolidation of RIGS beginning in April 2018, resulting in increases in transportation fees, operating expenses, and selling, general and administrative expenses of $73 million, $16 million and $6 million, respectively, and a decrease of $37 million in Adjusted EBITDA related to unconsolidated affiliates; and

•	an increase of $4 million in transportation fees, excluding the impact of consolidating RIGS as discussed above, primarily due to new contracts and the impact of the Red Bluff Express pipeline coming online in May 2018; partially offset by

•	a decrease of $33 million in realized storage margin primarily due to an adjustment to the Bammel storage inventory, lower storage fees and lower realized derivative gains.

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•	an increase of $359 million associated with the Rover pipeline with increases of $485 million in revenues, $105 million in net operating expenses and $21 million in selling, general and administrative expenses and other; and

•	an aggregate increase of $66 million in revenues, excluding the incremental revenue related to the Rover pipeline discussed above, primarily due to capacity sold at higher rates on the Transwestern and Panhandle pipelines; partially offset by

•	an increase of $11 million in operating expenses, excluding the incremental expenses related to the Rover pipeline discussed above, primarily due to increases in maintenance project costs due to scope and level of activity; and

•	a decrease of $6 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to lower margins on MEP due to lower rates on renewals of expiring long term contracts.

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•	an increase of $98 million in fee-based margin due to growth in the North Texas, Permian and Northeast regions, offset by declines in the Ark-La-Tex and midcontinent/Panhandle regions;

•	an increase of $79 million in non fee-based margin due to increased throughput volume in the North Texas and Permian regions;

•	an increase of $33 million in non fee-based margin due to higher crude oil and NGL prices; and

•	an increase of $5 million in Adjusted EBITDA related to unconsolidated affiliates due to higher earnings from our Aqua, Mi Vida and Ranch joint ventures; partially offset by

•	an increase of $67 million in operating expenses primarily due to increases of $20 million in outside services, $19 million in materials, $8 million in maintenance project costs, $7 million in ad valorem taxes, $6 million in employee costs and $6 million in office expenses; and

•	an increase of $3 million in selling, general and administrative expenses due to higher professional fees.

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an increase in transportation margin of $243 million primarily due to a $216 million increase resulting from increased producer volumes from the Permian region on our Texas NGL pipelines, a $31 million increase due to higher throughput volumes on Mariner West driven by end-user facility constraints in the prior period, a $15 million increase resulting from a reclassification between our transportation and fractionation margins, a $9 million increase due to higher throughput volumes from the Barnett region, a $5 million increase due to higher throughput volumes on Mariner South due to system downtime in the prior period and a $4 million increase in prior period customer credits. These increases were partially offset by a $16 million decrease resulting from lower throughput volumes on Mariner East 1 due to system downtime in 2018, a $14 million decrease due to lower throughput volumes from the Southeast Texas region and a $7 million decrease resulting from the timing of deficiency fee revenue recognition;

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an increase in fractionation and refinery services margin of $96 million primarily due to a $106 million increase resulting from the commissioning of our fifth fractionator in July 2018 and a $7 million increase from blending gains as a result of improved market pricing. These increases were partially offset by a $16 million decrease resulting from a reclassification between our transportation and fractionation margins and a $2 million decrease from higher affiliate storage fees paid;

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an increase in terminal services margin of $70 million due to a $36 million increase resulting from a change in the classification of certain customer reimbursements previously recorded in operating expenses, a $23 million increase at our Nederland terminal due to increased export demand and a $12 million increase due to higher throughput at our Marcus Hook Industrial Complex. These increases were partially offset by lower terminal throughput fees in part due to the sale of one of our terminals in April 2017;

•	an increase in marketing margin of $55 million due to a $48 million increase from our butane blending operations and a $22 million increase in sales of NGLs and other products at our Marcus Hook Industrial Complex due to more favorable market prices. These increases were partially offset by a $15 million decrease from the timing of optimization gains from our Mont Belvieu fractionators; and

•	an increase of $14 million to adjusted EBITDA related to unconsolidated affiliates due to improved contributions from our unconsolidated refined products joint venture interests; partially offset by

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an increase of $126 million in operating expenses primarily due to a $30 million increase in costs to operate our fractionators and a $20 million increase in operating costs on our NGL pipelines as a result of higher throughput and the commissioning of our fifth fractionator in July 2018, a $36 million increase resulting from a change in the classification of certain customer reimbursements previously recorded as a reduction to operating expenses that are now classified as revenue following the adoption of ASC 606 on January 1, 2018, increases of $24 million and $7 million to operating costs at our Marcus Hook and Nederland terminals, respectively, as a result of significantly higher volumes through both terminals in 2018, an $8 million increase to environmental reserves and a $1 million increase to overhead allocations and maintenance repairs performed on our refinery services assets; and

•	an increase of $10 million in selling, general and administrative expenses primarily due to a $6 million increase in overhead costs allocated to the segment, a $2 million increase in legal fees, a $1 million increase in management fees previously recorded in operating expenses and a $1 million increase in employee costs.

•

an increase of $1.07 billion in segment margin (excluding unrealized losses on commodity risk management activities) primarily due to the following: a $586 million increase resulting from placing the Bakken pipeline in service in the second quarter of 2017, a $266 million increase resulting from higher throughput on our Texas crude pipeline system primarily due to increased production from Permian producers; and gains of $355 million due to more favorable basis spreads; partially offset by an unfavorable inventory valuation adjustment of $54 million for the 2018 year as compared to a favorable inventory valuation adjustment of $82 million for the 2017 year; and

•	an increase of $2 million in Adjusted EBITDA related to unconsolidated affiliates due to increased jet fuel sales from our joint ventures; partially offset by

•

an increase of $117 million in operating expenses primarily due to a $67 million increase to throughput related costs on existing assets; a $36 million increase resulting from placing the Bakken pipeline in service in the second quarter of 2017; a $26 million increase resulting from the addition of certain joint venture transportation assets in the second quarter of 2017; and a $5 million increase from ad valorem taxes; partially offset by an $17 million decrease in insurance and environmental related expenses; and

•	an increase of $4 million in selling, general and administrative expenses primarily due to increases associated with placing our Bakken Pipeline in service in the second quarter of 2017.

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•	a decrease of $248 million in Adjusted EBITDA from discontinued operations primarily due to Sunoco LP’s retail divestment in January 2018; partially offset by

•	an increase of $109 million in inventory fair value adjustments due to changes in fuel prices between periods;

•	an increase of $14 million in margin primarily due to an increase in rental income as a result of the increase in commission agent sites in the current year, offset by decreases in the gross profit on motor fuel sales; and

•	a net decrease of $8 million in operating and selling, general and administrative expenses primarily due to decreased rent expense.

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•	our natural gas marketing operations;

•	our wholly-owned natural gas compression operations;

•	a non-controlling interest in PES. Prior to PES’s reorganization in August 2018, ETO’s 33% interest in PES was reflected as an unconsolidated affiliate; subsequent the August 2018 reorganization, ETO holds an approximately 8% interest in PES and no longer reflects PES as an affiliate; and

•	our investment in coal handling facilities.

•	a decrease of $98 million due to the contribution of CDM to USAC in April 2018, subsequent to which CDM is reflected in the Investment in USAC segment;

•	a decrease of $38 million in Adjusted EBITDA related to unconsolidated affiliates from our investment in PES primarily due to our lower ownership in PES subsequent to its reorganization, which resulted in PES no longer being reflected as an affiliate beginning in the third quarter of 2018;

•	a decrease of $4 million due to merger and acquisition expenses related to the Energy Transfer Merger in 2018; and

•	a decrease of $15 million due to a one-time fee received from a joint venture affiliate in 2017; partially offset by

•	an increase of $7 million due to lower transport fees resulting from the expiration of a capacity commitment on Trunkline pipeline;

•	an increase of $6 million due to a decrease in losses from mark-to-market of physical system gas; and

•	an increase of $7 million due to increased margin from ETO’s compression equipment business.

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(1)	Includes capital expenditures related to ETO’s proportionate ownership of the Bakken, Rover, and Bayou Bridge pipeline projects and our proportionate ownership of the Orbit Gulf Coast NGL export project.

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•	maintenance capital expenditures, which are capital expenditures made to maintain the operating capacity of its assets and extend their useful lives, to replace partially or fully depreciated assets, or other capital expenditures that are incurred in maintaining its existing business and related operating income; and

•	expansion capital expenditures, which are capital expenditures made to expand the operating capacity or operating income capacity of assets, including by acquisition of compression units or through modification of existing compression units to increase their capacity, or to replace certain partially or fully depreciated assets that were not currently generating operating income.

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(1)	Amounts related to Sunoco LP’s capital expenditures include capital expenditures related to discontinued operations.

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•	$1.14 billion aggregate principal amount of 7.50% senior notes due 2020;

•	$995 million aggregate principal amount of 4.25% senior notes due 2023;

•	$1.13 billion aggregate principal amount of 5.875% senior notes due 2024; and

•	$956 million aggregate principal amount of 5.50% senior notes due 2027.

•	$750 million aggregate principal amount of 4.50% senior notes due 2024;

•	$1.50 billion aggregate principal amount of 5.25% senior notes due 2029; and

•	$1.75 billion aggregate principal amount of 6.25% senior notes due 2049.

•	ETO’s $400 million aggregate principal amount of 9.70% senior notes due March 15, 2019;

•	ETO’s $450 million aggregate principal amount of 9.00% senior notes due April 15, 2019; and

•	Panhandle’s $150 million aggregate principal amount of 8.125% senior notes due June 1, 2019.

•	$650 million aggregate principal amount of 3.625% senior notes due 2022;

•	$1.00 billion aggregate principal amount of 3.90% senior notes due 2024; and

•	$850 million aggregate principal amount of 4.625% senior notes due 2029.

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•	incur indebtedness;

•	grant liens;

•	enter into mergers;

•	dispose of assets;

•	make certain investments;

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

•	make certain loans or investments;

•	incur additional indebtedness or guarantee other indebtedness;

•	merge or consolidate;

•	sell our assets; or

•	make certain acquisitions.

•	a minimum EBITDA to interest coverage ratio of 2.5 to 1.0, determined as of the last day of each fiscal quarter; and

•

a maximum funded debt to EBITDA ratio, determined as of the last day of each fiscal quarter, for the annualized trailing three months of (i) 5.5 to 1 through the end of the fiscal quarter ending December 31, 2019 and (ii) 5.0 to 1.0 thereafter, in each case subject to a provision for increases to such thresholds by 0.50 in connection with certain future acquisitions for the six consecutive month period following the period in which any such acquisition occurs.

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(1)

Interest payments on long-term debt are based on the principal amount of debt obligations as of December 31, 2019. With respect to variable rate debt, the interest payments were estimated using the interest rate as of December 31, 2019. 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.

(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, 2019 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)	Includes minimum guaranteed payments under service concession arrangements with New Jersey Turnpike Authority and New York Thruway Authority.

(4)

Expected contributions to fund our pension and postretirement benefit plans were included in “Other” above. Environmental liabilities, AROs, 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.

(5)	Excludes net non-current deferred tax liabilities of $3.21 billion due to uncertainty of the timing of future cash flows for such liabilities.

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(1)

Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received ET Series A Convertible Preferred Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per unit. See Note 8 to the Partnership’s consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”

(1)	Include distributions declared by Energy Transfer LP for periods subsequent to the Energy Transfer Merger.

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(1)	Net of Class I unit distributions

(2)	Distributions reflect prorated distributions for the year ended December 31, 2018.

*	Represent prorated initial distributions. Prorated initial distributions on the recently issued ETO Series F Preferred Units and ETO Series G Preferred Units will be payable in May 2020.

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A $12 million impairment was recorded related to the goodwill associated with the Partnership’s Southwest Gas operations within the interstate segment primarily due to decreases in projected future revenues and cash flows. Additionally, the Partnership recorded a $9 million impairment related to the goodwill associated with the Partnership’s North Central operations within the midstream segment primarily due to changes in assumptions related to projected future revenues and cash flows.

•	Sunoco LP recognized a $47 million write-down on assets held for sale related to its ethanol plant in Fulton, New York.

•	USAC also recognized a $6 million fixed asset impairment related to certain idle compressor assets.

•

a $378 million impairment was recorded related to the goodwill associated with the Partnership’s Northeast operations within the midstream segment primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. These changes in assumptions reflect delays in the construction of third-party takeaway capacity in the Northeast. Additionally, the Partnership recorded asset impairments of $4 million related to our midstream operations and asset impairments $9 million related to our crude operations idle leased assets.

•	Sunoco LP also recognized a $30 million impairment charge on its contractual rights primarily due to decreases in projected future revenues and cash flows from the date the intangible assets were originally recorded.

•	USAC also recognized a $9 million fixed asset impairment related to certain idle compressor assets.

•

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.

•

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 cash flows from the related reporting units, which reduction reflected the impacts discussed in “Results of Operations” above, along with the impacts of re-contracting assumptions related to future periods.

•

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 ETO. 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.

•	For 2017, Sunoco LP also recognized impairments of $404 million, of which $119 million was allocated to continuing operations, as discussed further below.

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•	the ability of our subsidiaries to make cash distributions to us, which is dependent on their results of operations, cash flows and financial condition;

•	the actual amount of cash distributions by our subsidiaries to us;

•	the volumes transported on our subsidiaries’ pipelines and gathering systems;

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

•	the fees our subsidiaries charge and the margins they realize for their 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 subsidiaries’ 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;

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•	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 subsidiaries pipelines and facilities;

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

•	the nonpayment or nonperformance by our subsidiaries’ customers;

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

•	risks associated with the construction of new pipelines and treating and processing facilities or additions to our subsidiaries’ 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 subsidiaries’ 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 our subsidiaries own less than a controlling interests, including risks related to management actions at such entities that our subsidiaries 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)	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.

(3)	The July 2020 interest rate swaps were terminated in January 2020.

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

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

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

•	periodically evaluate the terms and administration of ET’s long-term incentive plans to assure that they are structured and administered in a manner consistent with ET’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 and CFO or executive officer compensation; and

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

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

•	Thomas E. Long, Chief Financial Officer;

•	Marshall S. (Mackie) McCrea, III, President and Chief Commercial Officer;

•	Matthew S. Ramsey, Chief Operating Officer; and

•	Thomas P. Mason, Executive Vice President, General Counsel and President — LNG.

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•	reward executives with an industry-competitive total compensation package of 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/phantom unit awards under the equity incentive plan(s);

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

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

•	401(k) plan employer contributions.

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(1)

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 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.

(2)

ET maintains the Bonus Plan which provides for discretionary bonuses. Awards of discretionary bonuses are tied to achievement of targeted performance objectives and described in the Compensation Discussion and Analysis. The discretionary cash bonus amounts earned by the named executive officers for 2019 reflect cash bonuses approved by the ET Compensation Committee in February 2020 that are expected to be paid on or before March 15, 2020.

(3)

The amounts reflected for 2019 in this column include (i) matching contributions to the ET 401(k) Plan made on behalf of the named executive officers of $14,000 each for Messrs. Long, McCrea, Ramsey and Mason, (ii) health savings account contributions made on behalf of the named executive officers of $2,000 each for Messrs. Long and McCrea, and (iii) the dollar value of life insurance premiums paid for the benefit of the named executive officers. 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 “Equity Awards” column of the Summary Compensation Table at the time that the unit awards and distribution equivalent rights were originally granted. For 2019, distribution payments in connection with distribution equivalent rights totaled $796,382 for Mr. Long, $2,178,361 for Mr. McCrea, $857,108 for Mr. Ramsey, and $756,879 for Mr. Mason.

(4)	Mr. Warren has voluntarily determined that his salary will 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.

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(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)	Certain of these outstanding awards represent Energy Transfer Partners, L.P. awards that converted into ET awards upon the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. in October 2018. Furthermore, some of those converted awards had previously been converted in connection with the merger of Energy Transfer Partners, L.P. and Sunoco Logistics in April 2017.

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(2)

ET unit awards outstanding vest at a rate of 60% in December 2022 and 40% in December 2024 for awards granted in December 2019. Such awards may be settled at the election of the ET Compensation Committee in (i) common units of ET (subject to the approval of the ET Incentive Plans prior to the first vesting date by a majority of ET’s unitholders pursuant to the rules of the New York Stock Exchange); (ii) cash equal to the Fair Market Value (as such term is defined in the ET Incentive Plans) of the ET common units that would otherwise be delivered pursuant to the terms of each named executive officers grant agreement; or (iii) other securities or property in an amount equal to the Fair Market Value of ET common units that would otherwise be delivered pursuant to the terms of the grant agreement, or a combination thereof as determined by the ET Compensation Committee in its discretion.

•	at a rate of 60% in December 2021 and 40% in December 2023 for awards granted in October and December 2018;

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

•	100% in December 2021 for the remaining outstanding portion of awards granted in December 2016; and

•	100% in December 2020 for the remaining outstanding portion of awards granted in December 2015.

(3)	Market value was computed as the number of unvested awards as of December 31, 2019 multiplied by the closing price of respective common units of ET and Sunoco LP.

(1)	Amounts presented represent the value realized upon vesting of these awards, which is calculated as the number of units vested multiplied by the applicable closing market price of applicable common units upon the vesting date.

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1.

It was determined that, as of December 31, 2019, the applicable employee populations consisted of 8,256 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 2018 or 2019 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 and, for 2019, updated the compensation of the “median employee” as reflected in our payroll records as reported on form W-2 for 2019.

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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 2019 resulting in an annual compensation of $124,622. 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 $10,989) and the employee’s 401(k) matching contribution and profit sharing contribution (estimated at $6,040 per employee, includes $3,775 per employee on average matching contribution and $2,265 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 2019 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 ET common units as of the grant date.

(3)	Mr. Washburne was appointed as a director of our General Partner on April 16, 2019.

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*	Less than 1%

(1)	The address for Mr. Davis is 5950 Sherry Lane, Dallas, Texas 75225. The address for all other listed beneficial owners is 8111 Westchester Drive, Suite 600, Dallas, Texas 75225.

(2)

Beneficial ownership for the purposes of this table is defined by Rule 13d-3 under the Exchange Act of 1934. 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 days. The nature of beneficial ownership for all listed persons is direct with sole investment and disposition power unless otherwise noted. The beneficial ownership of each listed person is based on 2,689,897,793 Common Units outstanding in the aggregate as of February 14, 2020.

(3)	Includes 102,693,765 Common Units held by Kelcy Warren Partners, L.P. and 10,244,429 Common Units held by Kelcy Warren Partners II, L.P., the general partners of which are owned by Mr. Warren. Also includes 96,043,757 Common Units

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(4)

Includes 51,701 Common Units held by Avatar Holdings LLC, 1,941,721 Common Units held by Avatar BW, Ltd., 28,203,003 Common Units held by Avatar ETC Stock Holdings LLC, 3,557,757 Common Units held by Avatar Investments LP, 121,117 Common Units held by Avatar Stock Holdings, LP and 1,112,069 Common Units held by RCD Stock Holdings, LLC, all of which entities are owned or controlled by Mr. Davis. Also includes 15,987,283 Common Units held by a remainder trust for Mr. Davis’ spouse and 9,536,054 Common Units held by two trusts for the benefit of Mr. Davis’ grandchildren, for which Mr. Davis serves as trustee. Mr. Davis shares voting and dispositive power with his wife with respect to Common Units held directly. Also includes 328,383 Common Units attributable to ET Company Ltd. Mr. Davis is a former executive officer and director of ETO and is currently a director of the general partner of ET, LE GP, LLC.

(5)	Includes 17,445,608 Common Units held by McReynolds Energy Partners L.P. and 12,142,593 Common Units held by McReynolds Equity Partners L.P., the general partners of which are owned by Mr. McReynolds. Mr. McReynolds disclaims beneficial ownership of Common Units owned by such limited partnerships other than to the extent of his interest in such entities.

(6)	Includes 1,544,558 held by Steven R. Anderson Revocable Trust, for which Mr. Anderson serves as trustee.

(7)	Includes 6,660 Units held by two trusts for the benefit of Mr. Grimm’s children, for which Mr. Grimm serves as trustee.

(8)	Includes 2,090 held by Mr. Washburne’s wife.

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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 2018 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;

•	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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•	Compared the actual current results of the relevant reporting unit to the expected performance of that reporting unit based on prior period financial forecasts, as applicable.

•	Utilized an internal valuation specialist to evaluate:

◦	The methodologies used and whether they were acceptable for the underlying assets or operations and being applied correctly by performing independent calculations,

◦	The appropriateness of the discount rates by recalculating the weighted average costs of capital, and

◦	The qualifications of the third party valuation specialists engaged by the Partnership based on their credentials and experience.

•	Tested the reasonableness of the projected growth rate and forecasted costs by comparing such items to historical operating results of the relevant reporting unit and by assessing the likelihood or capability of the reporting unit to undertake activities or initiatives underpinning significant drivers of growth in the forecasted period.

•	Utilized an internal valuation specialist to evaluate:

◦	The methodologies used and whether they were acceptable for the underlying assets or operations and being applied correctly by performing an independent calculation,

◦	The appropriateness of the replacement cost of property plant, and equipment, by performing an independent calculation and inspecting the estimated remaining years of service for the underlying assets based on the original acquisition dates and condition of assets,

◦	The appropriateness of the discount rate by recalculating the weighted average costs of capital, and

◦	The qualifications of the third party valuation specialist engaged by the Partnership based on their credentials and experience.

•	Tested the revenue growth rates and forecasted costs of SemGroup by comparing such items to the historical operating results of the acquired entity and by assessing the likelihood or capability of the acquired entity to undertake activities or initiatives underpinning significant drivers of growth in the forecasted period.

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•	Utilized an external actuarial specialist to evaluate:

◦	The methodologies used and whether they were acceptable for the underlying operations,

◦	The qualifications of the third party actuary specialist engaged by the Partnership based on their credentials and experience.

•	Evaluated the appropriateness of the discount rate used by comparing it to the historical rate of return from the captive insurance company’s investment portfolio used to fund the underlying liabilities, and

•	Evaluated the life-to-date payments, reserves, and payment patterns by agreeing the historical claims and payment amounts to the underlying claims or general ledger.

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1.	OPERATIONS AND BASIS OF PRESENTATION:

•	the IDRs in Energy Transfer Partners, L.P. were converted into 1,168,205,710 common units;

•	the general partner interest in ETO was converted to a non-economic general partner interest and ETO issued 18,448,341 ETO common units to ETP GP;

•	ET contributed its 2,263,158 Sunoco LP common units to ETO in exchange for 2,874,275 ETO common units and 100 percent of the limited liability company interests in Sunoco GP LLC, the sole general partner of Sunoco LP, and all of the IDRs in Sunoco LP, to ETO in exchange for 42,812,389 ETO common units;

•	ET contributed its 12,466,912 common units representing limited partner interests in USAC and 100 percent of the limited liability company interests in USA Compression GP, LLC, the general partner of USAC, to ETO in exchange for 16,134,903 ETO common units; and

•	ET contributed its 100 percent limited liability company interest in Lake Charles LNG and a 60 percent limited liability company interest in each of Energy Transfer LNG Export, LLC, ET Crude Oil Terminals, LLC and ETC Illinois LLC (collectively, “Lake Charles LNG and Other”) to ETO in exchange for 37,557,815 ETO common units.

•	activities of the Parent Company; and

•	certain operations and investments that are not separately reflected as reportable segments.

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•	the Parent Company;

•	our controlled subsidiary, Energy Transfer Operating, L.P.; and

•	Energy Transfer Partners GP, L.P. (“ETP GP”), the general partner of ETO, and Energy Transfer Partners, L.L.C. (“ETP LLC”), the general partner of ETP GP.

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

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(1)	Due to changes in fuel prices, Sunoco LP recorded a write-down on the value of its fuel inventory of $85 million as of December 31, 2018.

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3.	ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:

(1)	None of the goodwill is expected to be deductible for tax purposes. Goodwill recognized from the business combination primarily relates to the value attributed to additional growth opportunities, synergies and operating leverage within SemGroup’s operations.

(2)	Long-term debt at December 5, 2019 includes SemGroup senior notes with an aggregate principal amount of $1.375 billion and SemGroup subsidiary debt of $593 million, all of which were redeemed in total in December 2019, subsequent to the close of the SemGroup Transaction, utilizing proceeds from an intercompany promissory note from ETO.

(3)	Total consideration includes (i) cash paid to SemGroup shareholders, (ii) fair value of ET Common Units issued in the acquisition and (iii) cash paid to redeem SemGroup’s preferred shares.

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(4)	Cash received represents cash and cash equivalents held by SemGroup as of the acquisition date.

•	2,263,158 common units representing limited partner interests in Sunoco LP to ETO in exchange for 2,874,275 ETO common units;

•	100 percent of the limited liability company interests in Sunoco GP LLC, the sole general partner of Sunoco LP, and all of the IDRs in Sunoco LP, to ETO in exchange for 42,812,389 ETO common units;

•	12,466,912 common units representing limited partner interests in USAC and 100 percent of the limited liability company interests in USA Compression GP, LLC, the general partner of USAC, to ETO in exchange for 16,134,903 ETO common units; and

•	a 100 percent limited liability company interest in Lake Charles LNG and a 60 percent limited liability company interest in each of Energy Transfer LNG Export, LLC, ET Crude Oil Terminals, LLC and ETC Illinois LLC to ETO in exchange for 37,557,815 ETO common units.

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(1)	None of the goodwill is expected to be deductible for tax purposes. Goodwill recognized from the business combination primarily relates to the value attributed to additional growth opportunities, synergies and operating leverage within USAC’s operations.

(2)	Cash received represents cash and cash equivalents held by USAC as of the acquisition date.

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4.	ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES:

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(1)	Selected income data related to HPC for the year ended December 31, 2018 reflects HPC’s results for January 1, 2018 through March 31, 2018. HPC was fully consolidated beginning April 1, 2018 as discussed above.

5.	NET INCOME PER LIMITED PARTNER UNIT:

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6.	DEBT OBLIGATIONS:

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(1)	As of December 31, 2019, these notes were classified as long-term as management had the intent and ability to refinance the borrowings on a long-term basis. The notes were redeemed in January 2020.

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•	Maximum Leverage Ratio – Consolidated Funded Debt (as defined therein) of the Parent Company to Consolidated EBITDA (as defined therein) of the Parent Company of not more than 6.0 to 1, with a permitted increase to 7 to 1 during a specified acquisition period following the close of a specified acquisition; and

•	Consolidated EBITDA (as defined therein) to interest expense of not less than 1.5 to 1.

•	incur indebtedness;

•	grant liens;

•	enter into mergers;

•	dispose of assets;

•	make certain investments;

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

•	make certain loans or investments;

•	incur additional indebtedness or guarantee other indebtedness;

•	merge or consolidate;

•	sell our assets; or

•	make certain acquisitions.

•	a minimum EBITDA to interest coverage ratio of 2.5 to 1.0, determined as of the last day of each fiscal quarter; and

•

a maximum funded debt to EBITDA ratio, determined as of the last day of each fiscal quarter, for the annualized trailing three months of (i) 5.5 to 1 through the end of the fiscal quarter ending December 31, 2019 and (ii) 5.0 to 1.0 thereafter, in each case subject to a provision for increases to such thresholds by 0.50 in connection with certain future acquisitions for the six consecutive month period following the period in which any such acquisition occurs.

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7.	REDEEMABLE NONCONTROLLING INTERESTS:

8.	EQUITY:

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(1)

Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received ET Series A Convertible Preferred Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per unit. See additional information below.

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*	Represent prorated initial distributions. Prorated initial distributions on the recently issued ETO Series F Preferred Units and ETO Series G Preferred Units will be payable in May 2020.

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9.	NON-CASH 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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•	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 be contractually 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 that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that Sunoco no longer operates, closed and/or sold refineries and other formerly owned sites.

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•

Sunoco 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, 2019, Sunoco had been named as a PRP at approximately 40 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco is usually one of a number of companies identified as a PRP at a site. Sunoco has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.

12.	REVENUE:

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•	fuel distribution and marketing;

•	all other;

•	contract operations;

•	retail parts and services; and

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•	In-Kind POP: We retain our POP percentage (non-cash consideration) and also any additional cash fees in exchange for providing the services. We recognize revenue for the non-cash consideration and cash fees at the time the services are performed.

•	Mixed POP: We purchase NGLs from the producer and retain a portion of the residue gas as non-cash consideration for services provided. We may also receive cash fees for such services. Under Topic 606, these agreements were determined

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Right to invoice: The Partnership elected to utilize an output method to recognize revenue that is based on the amount to which the Partnership has a right to invoice a customer for services performed to date, if that amount corresponds directly with the value provided to the customer for the related performance or its obligation completed to date. As such, the Partnership recognized revenue in the amount to which it had the right to invoice customers.

•	Significant financing component: The Partnership elected not to adjust the promised amount of consideration for the effects of significant financing component if the Partnership expects, at contract inception, that the period between the transfer of a promised good or service to a customer and when the customer pays for that good or service will be one year or less.

•	Unearned variable consideration: The Partnership elected to only disclose the unearned fixed consideration associated with unsatisfied performance obligations related to our various customer contracts which contain both fixed and variable components.

•

Incremental costs of obtaining a contract: The Partnership generally expenses sales commissions when incurred because the amortization period would have been less than one year. We record these costs within general and administrative expenses. The Partnership elected to expense the incremental costs of obtaining a contract when the amortization period for such contracts would have been one year or less.

•	Shipping and handling costs: The Partnership elected to account for shipping and handling activities that occur after the customer has obtained control of a good as fulfillment activities (i.e., an expense) rather than as a promised service.

•	Measurement of transaction price: The Partnership has elected to exclude from the measurement of transaction price all taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction and collected by the Partnership from a customer (i.e., sales tax, value added tax, etc.).

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•	Variable consideration of wholly unsatisfied performance obligations: The Partnership has elected to exclude the estimate of variable consideration to the allocation of wholly unsatisfied performance obligations.

13.	LEASE ACCOUNTING:

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14.	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.

(3)	The July 2020 interest rate swaps were terminated in January 2020.

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15.	RETIREMENT BENEFITS:

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(1)	Comprised of approximately 100% equities as of December 31, 2019.

(1)	Comprised of approximately 100% equities as of December 31, 2018.

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(1)	Primarily comprised of approximately 59% equities, 40% fixed income securities and 1% cash as of December 31, 2019.

(1)	Primarily comprised of approximately 53% equities, 46% fixed income securities and 1% cash as of December 31, 2018.

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16.	RELATED PARTY TRANSACTIONS:

17.	REPORTABLE SEGMENTS:

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(1)	Excluding acquisitions, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis).

18.	QUARTERLY FINANCIAL DATA (UNAUDITED):

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