EX-99.1 3 etp12-31x2016xrecastex991.htm EXHIBIT 99.1 Document

TABLE OF CONTENTS


i


Forward-Looking Statements
Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Partners, L.P. (the “Partnership,” or “ETP”) in periodic press releases and some oral statements of the Partnership’s officials during presentations about the Partnership, include forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Partnership and its General Partner believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such assumptions, expectations, or projections will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Partnership’s actual results may vary materially from those anticipated, projected or expected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Item 1A. Risk Factors” included in this annual report.
Definitions
The following is a list of certain acronyms and terms generally used in the energy industry and throughout this document:
 
/d
 
per day
 
 
 
 
 
AmeriGas
 
AmeriGas Partners, L.P.
 
 
 
 
 
AOCI
 
accumulated other comprehensive income (loss)
 
 
 
 
 
Aqua – PVR
 
Aqua – PVR Water Services, LLC
 
 
 
 
 
AROs
 
asset retirement obligations
 
 
 
 
 
Bbls
 
barrels
 
 
 
 
 
Bcf
 
billion cubic feet
 
 
 
 
 
BG
 
BG Group plc
 
 
 
 
 
Btu
 
British thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy used
 
 
 
 
 
Capacity
 
capacity of a pipeline, processing plant or storage facility refers to the maximum capacity under normal operating conditions and, with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may reduce the throughput capacity from specified capacity levels
 
 
 
 
 
Citrus
 
Citrus, LLC
 
 
 
 
 
Coal Handling
 
Coal Handling Solutions LLC, Kingsport Handling LLC, and Kingsport Services LLC, now known as Materials Handling Solutions LLC
 
 
 
 
 
CrossCountry
 
CrossCountry Energy, LLC
 
 
 
 
 
DOE
 
U.S. Department of Energy
 
 
 
 
 
DOT
 
U.S. Department of Transportation
 
 
 
 
 
Eagle Rock
 
Eagle Rock Energy Partners, L.P.
 
 
 
 
 
ELG
 
Edwards Lime Gathering LLC
 
 
 
 
 
EPA
 
U.S. Environmental Protection Agency
 
 
 
 
 
ETC FEP
 
ETC Fayetteville Express Pipeline, LLC
 
 
 
 
 
ETC MEP
 
ETC Midcontinent Express Pipeline, L.L.C.
 
 
 
 
 
ETC OLP
 
La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company
 
 
 
 


ii


 
ETC Tiger
 
ETC Tiger Pipeline, LLC
 
 
 
 
 
ETE
 
Energy Transfer Equity, L.P., a publicly traded partnership and the owner of ETP LLC
 
 
 
 
 
ETE Holdings
 
ETE Common Holdings, LLC, a wholly-owned subsidiary of ETE
 
 
 
 
 
ET Interstate
 
Energy Transfer Interstate Holdings, LLC
 
 
 
 
 
ET Rover
 
ET Rover Pipeline LLC
 
 
 
 
 
ETP Credit Facility
 
ETP’s $3.75 billion revolving credit facility
 
 
 
 
 
ETP GP
 
Energy Transfer Partners GP, L.P., the general partner of ETP
 
 
 
 
 
ETP Holdco
 
ETP Holdco Corporation
 
 
 
 
 
ETP LLC
 
Energy Transfer Partners, L.L.C., the general partner of ETP GP
 
 
 
 
 
Exchange Act
 
Securities Exchange Act of 1934
 
 
 
 
 
FEP
 
Fayetteville Express Pipeline LLC
 
 
 
 
 
FERC
 
Federal Energy Regulatory Commission
 
 
 
 
 
FGT
 
Florida Gas Transmission Company, LLC
 
 
 
 
 
GAAP
 
accounting principles generally accepted in the United States of America
 
 
 
 
 
Gulf States
 
Gulf States Transmission LLC
 
 
 
 
 
HPC
 
RIGS Haynesville Partnership Co. and its wholly-owned subsidiary, Regency Intrastate Gas LP
 
 
 
 
 
HOLP
 
Heritage Operating, L.P.
 
 
 
 
 
Hoover Energy
 
Hoover Energy Partners, LP
 
 
 
 
 
IDRs
 
incentive distribution rights
 
 
 
 
 
KMI
 
Kinder Morgan Inc.
 
 
 
 
 
Lake Charles LNG
 
Lake Charles LNG Company, LLC (previously named Trunkline LNG Company, LLC), a subsidiary of ETE
 
 
 
 
 
LCL
 
Lake Charles LNG Export Company, LLC
 
 
 
 
 
LIBOR
 
London Interbank Offered Rate
 
 
 
 
 
LNG
 
liquefied natural gas
 
 
 
 
 
Lone Star
 
Lone Star NGL LLC
 
 
 
 
 
LPG
 
liquefied petroleum gas
 
 
 
 
 
MACS
 
Mid-Atlantic Convenience Stores, LLC
 
 
 
 
 
MEP
 
Midcontinent Express Pipeline LLC
 
 
 
 
 
Mi Vida JV
 
Mi Vida JV LLC
 
 
 
 
 
MMBtu
 
million British thermal units
 
 
 
 
 
MMcf
 
million cubic feet
 
 
 
 
 
MTBE
 
methyl tertiary butyl ether
 
 
 
 
 
NGL
 
natural gas liquid, such as propane, butane and natural gasoline
 
 
 
 
 
NYMEX
 
New York Mercantile Exchange
 
 
 
 
 
NYSE
 
New York Stock Exchange
 
 
 
 
 
ORS
 
Ohio River System LLC
 
 
 
 


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OSHA
 
federal Occupational Safety and Health Act
 
 
 
 
 
OTC
 
over-the-counter
 
 
 
 
 
Panhandle
 
Panhandle Eastern Pipe Line Company, LP and its subsidiaries
 
 
 
 
 
PCBs
 
polychlorinated biphenyls
 
 
 
 
 
PennTex
 
PennTex Midstream Partners, LP
 
 
 
 
 
PES
 
Philadelphia Energy Solutions
 
 
 
 
 
PHMSA
 
Pipeline Hazardous Materials Safety Administration
 
 
 
 
 
Preferred Units
 
ETP Series A cumulative convertible preferred units
 
 
 
 
 
PVR
 
PVR Partners, L.P.
 
 
 
 
 
Ranch JV
 
Ranch Westex JV LLC
 
 
 
 
 
Regency
 
Regency Energy Partners LP
 
 
 
 
 
Retail Holdings
 
ETP Retail Holdings, LLC, a joint venture between subsidiaries of ETC OLP and Sunoco, Inc.
 
 
 
 
 
RIGS
 
Regency Intrastate Gas System
 
 
 
 
 
Sea Robin
 
Sea Robin Pipeline Company, LLC, a subsidiary of Panhandle
 
 
 
 
 
SEC
 
Securities and Exchange Commission
 
 
 
 
 
Southern Union
 
Southern Union Company
 
 
 
 
 
Southwest Gas
 
Pan Gas Storage, LLC
 
 
 
 
 
Sunoco GP
 
Sunoco GP LLC, the general partner of Sunoco LP
 
 
 
 
 
Sunoco Logistics
 
Sunoco Logistics Partners L.P.
 
 
 
 
 
Sunoco LP
 
Sunoco LP (previously named Susser Petroleum Partners, LP)
 
 
 
 
 
Sunoco Partners
 
Sunoco Partners LLC, the general partner of Sunoco Logistics
 
 
 
 
 
Susser
 
Susser Holdings Corporation
 
 
 
 
 
Transwestern
 
Transwestern Pipeline Company, LLC
 
 
 
 
 
TRRC
 
Texas Railroad Commission
 
 
 
 
 
Trunkline
 
Trunkline Gas Company, LLC, a subsidiary of Panhandle
Adjusted EBITDA is a term used throughout this document, which we define as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Adjusted EBITDA reflects amounts for less than wholly-owned subsidiaries based on 100% of the subsidiaries’ results of operations and for unconsolidated affiliates based on the Partnership’s proportionate ownership.


iv


PART I
ITEM 1.  BUSINESS
Overview
See information previously included in our Form 10-K filed on February 24, 2017 and Form 8-K filed on May 8, 2017.
Segment Overview
See Note 15 to our consolidated financial statements for additional financial information about our segments.
Intrastate Transportation and Storage Segment
Natural gas transportation pipelines receive natural gas from other mainline transportation pipelines, storage facilities and gathering systems and deliver the natural gas to industrial end-users, storage facilities, utilities and other pipelines. Through our intrastate transportation and storage segment, we own and operate approximately 7,900 miles of natural gas transportation pipelines with approximately 15.2 Bcf/d of transportation capacity and three natural gas storage facilities located in the state of Texas. We also own a 49.99% general partner interest in RIGS, a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets.
Through ETC OLP, we own the largest intrastate pipeline system in the United States with interconnects to Texas markets and to major consumption areas throughout the United States. Our intrastate transportation and storage segment focuses on the transportation of natural gas to major markets from various prolific natural gas producing areas through connections with other pipeline systems as well as through our Oasis pipeline, our East Texas pipeline, our natural gas pipeline and storage assets that are referred to as the ET Fuel System, and our HPL System, which are described below.
Our intrastate transportation and storage segment’s results are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly.
We also generate revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and marketing companies on our HPL System. Generally, we purchase natural gas from either the market (including purchases from our marketing operations) or from producers at the wellhead. To the extent the natural gas comes from producers, it is primarily purchased at a discount to a specified market price and typically resold to customers based on an index price. In addition, our intrastate transportation and storage segment generates revenues from fees charged for storing customers’ working natural gas in our storage facilities and from managing natural gas for our own account.
Interstate Transportation and Storage Segment
Natural gas transportation pipelines receive natural gas from other mainline transportation pipelines, storage facilities and gathering systems and deliver the natural gas to industrial end-users, storage facilities, utilities and other pipelines. Through our interstate transportation and storage segment, we directly own and operate approximately 11,800 miles of interstate natural gas pipelines with approximately 10.3 Bcf/d of transportation capacity and have a 50% interest in the joint venture that owns the 185-mile Fayetteville Express pipeline and the 500-mile Midcontinent Express pipeline. ETP also owns a 50% interest in Citrus, which owns 100% of FGT, an approximately 5,325 mile pipeline system that extends from South Texas through the Gulf Coast to south Florida.
Our interstate transportation and storage segment includes Panhandle, which owns and operates a large natural gas open-access interstate pipeline network.  The pipeline network, consisting of the Panhandle, Trunkline and Sea Robin transmission systems, serves customers in the Midwest, Gulf Coast and Midcontinent United States with a comprehensive array of transportation and storage services.  In connection with its natural gas pipeline transmission and storage systems, Panhandle has five natural gas storage fields located in Illinois, Kansas, Louisiana, Michigan and Oklahoma.  Southwest Gas operates four of these fields and Trunkline operates one.
We also own a 50% interest in the MEP pipeline system, which is operated by KMI, and has the capability to transport up to 1.8 Bcf/d of natural gas.


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Gulf States is a small interstate pipeline that uses cost-based rates and terms and conditions of service for shippers wishing to secure capacity for interstate transportation service. Rates charged are largely governed by long-term negotiated rate agreements.
We are currently in the process of converting a portion of the Trunkline gas pipeline to crude oil transportation.
The results from our interstate transportation and storage segment are primarily derived from the fees we earn from natural gas transportation and storage services.
Midstream Segment
The midstream natural gas industry is the link between the exploration and production of natural gas and the delivery of its components to end-use markets. The midstream industry consists of natural gas gathering, compression, treating, processing, storage, and transportation, and is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells and the proximity of storage facilities to production areas and end-use markets.
The natural gas gathering process begins with the drilling of wells into gas-bearing rock formations. Once a well has been completed, the well is connected to a gathering system. Gathering systems generally consist of a network of small diameter pipelines and, if necessary, compression systems, that collects natural gas from points near producing wells and transports it to larger pipelines for further transportation.
Gathering systems are operated at design pressures that will maximize the total throughput from all connected wells. Specifically, lower pressure gathering systems allow wells, which produce at progressively lower field pressures as they age, to remain connected to gathering systems and to continue to produce for longer periods of time. As the pressure of a well declines, it becomes increasingly difficult to deliver the remaining production in the ground against a higher pressure that exists in the connecting gathering system. Field compression is typically used to lower the pressure of a gathering system. If field compression is not installed, then the remaining production in the ground will not be produced because it cannot overcome the higher gathering system pressure. In contrast, if field compression is installed, then a well can continue delivering production that otherwise might not be produced.
Natural gas has a varied composition depending on the field, the formation and the reservoir from which it is produced. Natural gas from certain formations is higher in carbon dioxide, hydrogen sulfide or certain other contaminants. Treating plants remove carbon dioxide and hydrogen sulfide from natural gas to ensure that it meets pipeline quality specifications.
Some natural gas produced by a well does not meet the pipeline quality specifications established by downstream pipelines or is not suitable for commercial use and must be processed to remove the mixed NGL stream. In addition, some natural gas produced by a well, while not required to be processed, can be processed to take advantage of favorable margins for NGLs extracted from the gas stream. Natural gas processing involves the separation of natural gas into pipeline quality natural gas, or residue gas, and a mixed NGL stream.
Through our midstream segment, we own and operate natural gas and NGL gathering pipelines, natural gas processing plants, natural gas treating facilities and natural gas conditioning facilities with an aggregate processing, treating and conditioning capacity of approximately 12.3 Bcf/d. Our midstream segment focuses on the gathering, compression, treating, blending, and processing, and our operations are currently concentrated in major producing basins and shales, including the Austin Chalk trend and Eagle Ford Shale in South and Southeast Texas, the Permian Basin in West Texas and New Mexico, the Barnett Shale and Woodford Shale in North Texas, the Bossier Sands in East Texas, the Marcellus Shale in West Virginia and Pennsylvania, the Haynesville Shale in East Texas and Louisiana, and the Cotton Valley Shale in Louisiana. Many of our midstream assets are integrated with our intrastate transportation and storage assets.
Our midstream segment also includes a 60% interest in ELG, which operates natural gas gathering, oil pipeline, and oil stabilization facilities in South Texas, a 33.33% membership interest in Ranch Westex JV LLC, which processes natural gas delivered from the NGLs-rich shale formations in West Texas, a 75% membership interest in ORS, which operates a natural gas gathering system in the Utica shale in Ohio, and a 50% interest in Mi Vida JV, which operates a cryogenic processing plant and related facilities in West Texas, a 51% membership interest in Aqua – PVR, which transports and supplies fresh water to natural gas producers in the Marcellus shale in Pennsylvania, and a 50% interest in Sweeny Gathering LP, which operates a natural gas gathering facility in South Texas.
Our midstream segment results are derived primarily from margins we earn for natural gas volumes that are gathered, transported, purchased and sold through our pipeline systems and the natural gas and NGL volumes processed at our processing and treating facilities.


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NGL and Refined Products Transportation and Services Segment
Our NGL operations transports, stores and executes acquisition and marketing activities utilizing a complementary network of pipelines, storage and blending facilities, and strategic off-take locations that provide access to multiple NGL markets.
Liquids transportation pipelines transport mixed NGLs and other hydrocarbons from natural gas processing facilities to fractionation plants and storage facilities. NGL storage facilities are used for the storage of mixed NGLs, NGL products and petrochemical products owned by third parties in storage tanks and underground wells, which allow for the injection and withdrawal of such products at various times of the year to meet demand cycles. NGL fractionators separate mixed NGL streams into purity products, such as ethane, propane, normal butane, isobutane and natural gasoline.
Our NGL and refined products transportation and services segment includes approximately 2,300 miles of NGL pipelines, five NGL and propane fractionation facilities with an aggregate capacity of 545,000 Bbls/d and NGL storage facilities with aggregate working storage capacity of approximately 53 million Bbls. Four of our NGL and propane fractionation facilities and 50 million Bbls of our NGL storage capacity are located at Mont Belvieu, Texas, one NGL fractionation facility is located in Geismar, Louisiana, and the segment has 3 million Bbls of salt dome storage capacity near Hattiesburg, Mississippi. The NGL pipelines primarily transport NGLs from the Permian and Delaware basins and the Barnett and Eagle Ford Shales to Mont Belvieu. In addition, we own and operate the 82-mile Rio Bravo crude oil pipeline.
Terminalling services are facilitated by approximately 5 million barrels of NGLs storage capacity, including approximately 1 million barrels of storage at our Nederland, Texas terminal facility and 3 million barrels at our Marcus Hook, Pennsylvania terminal facility (the “Marcus Hook Industrial Complex”). These operations also carry out our NGLs blending activities, including utilizing our patented butane blending technology.
Liquids transportation revenue is principally generated from fees charged to customers under dedicated contracts or take-or-pay contracts. Under a dedicated contract, the customer agrees to deliver the total output from particular processing plants that are connected to the NGL pipeline. Take-or-pay contracts have minimum throughput commitments requiring the customer to pay regardless of whether a fixed volume is transported. Transportation fees are market-based, negotiated with customers and competitive with regional regulated pipelines.
NGL fractionation revenue is principally generated from fees charged to customers under take-or-pay contracts. Take-or-pay contracts have minimum payment obligations for throughput commitments requiring the customer to pay regardless of whether a fixed volume is fractionated from raw make into purity NGL products. Fractionation fees are market-based, negotiated with customers and competitive with other fractionators along the Gulf Coast.
NGL storage revenues are derived from base storage fees and throughput fees. Base storage fees are firm take-or-pay contracts on the volume of capacity reserved, regardless of the capacity actually used. Throughput fees are charged for providing ancillary services, including receipt and delivery and custody transfer fees.
This segment also includes revenues earned from the marketing of NGLs and processing and fractionating refinery off-gas. Marketing of NGLs primarily generates margin from selling ratable NGLs to end users and from optimizing storage assets. Processing and fractionation of refinery off-gas margin is generated from a percentage-of-proceeds of O-grade product sales and income sharing contracts, which are subject to market pricing of olefins and NGLs.

Our refined products operations provide transportation and terminalling services, through the use of approximately 1,800 miles of refined products pipelines and approximately 40 active refined products marketing terminals. Our marketing terminals are located primarily in the northeast, midwest and southwest United States, with approximately 8 million barrels of refined products storage capacity. Our refined products operations include our Eagle Point facility in New Jersey, which has approximately 6 million barrels of refined products storage capacity. The operations also include our equity ownership interests in four refined products pipeline companies. The operations also perform terminalling activities at our Marcus Hook Industrial Complex. Our refined products operations utilize its integrated pipeline and terminalling assets, as well as acquisition and marketing activities, to service refined products markets in several regions in the United States.
Crude Oil Transportation and Services Segment
Our crude oil operations provide transportation, terminalling and acquisition and marketing services to crude oil markets throughout the southwest, midwest and northeastern United States. Included within the operations are approximately 6,100 miles of crude oil trunk and gathering pipelines in the southwest and midwest United States and equity ownership interests in two crude oil pipelines. Our crude oil terminalling services operates with an aggregate storage capacity of approximately 33 million barrels, including approximately 26 million barrels at our Gulf Coast terminal in Nederland, Texas and approximately 3 million barrels at its Fort Mifflin terminal complex in Pennsylvania. Our crude oil acquisition and marketing activities utilize our pipeline and


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terminal assets, our proprietary fleet crude oil tractor trailers and truck unloading facilities, as well as third-party assets, to service crude oil markets principally in the mid-continent United States.
All Other Segment
Segments below the quantitative thresholds are classified as “All other.” These include the following:
We own an equity method investment in limited partnership units of Sunoco LP consisting of 43.5 million units, representing 44.3% of Sunoco LP’s total outstanding common units.
Our wholly-owned subsidiary, Sunoco, Inc., owns an approximate 33% non-operating interest in PES, a refining joint venture with The Carlyle Group, L.P. (“The Carlyle Group”), which owns a refinery in Philadelphia.
We conduct marketing operations in which we market the natural gas that flows through our gathering and intrastate transportation assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other suppliers and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices of natural gas, less the costs of transportation. For the off-system gas, we purchase gas or act as an agent for small independent producers that may not have marketing operations.
We own all of the outstanding equity interests of a natural gas compression equipment business with operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas.
We own 100% of the membership interests of Energy Transfer Group, L.L.C. (“ETG”), which owns all of the partnership interests of Energy Transfer Technologies, Ltd. (“ETT”). ETT provides compression services to customers engaged in the transportation of natural gas, including our other segments.
We own a 40% interest in the parent of LCL, which is developing a LNG liquefaction project, as described further under “Asset Overview – All Other” below.
We own and operate a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems. We also own and operate a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management.
We are involved in the management of coal and natural resources properties and the related collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. These operations also include Coal Handling, which owns and operates end-user coal handling facilities.
We also own PEI Power Corp. and PEI Power II, which own and operate a facility in Pennsylvania that generates a total of 75 megawatts of electrical power.
Asset Overview
The descriptions below include summaries of significant assets within the Partnership’s reportable segments. Amounts, such as capacities, volumes and miles included in the descriptions below are approximate and are based on information currently available; such amounts are subject to change based on future events or additional information.
Intrastate Transportation and Storage
The following details our pipelines and storage facilities in the intrastate transportation and storage segment:
Description of Assets
 
Ownership Interest
(%)
 
Miles of Natural Gas Pipeline
 
Pipeline Throughput Capacity
(Bcf/d)
 
Working Storage Capacity
(Bcf/d)
ET Fuel System
 
100
%
 
2,780

 
5.2

 
11.2

Oasis Pipeline
 
100
%
 
750

 
2.3

 

HPL System
 
100
%
 
3,920

 
5.3

 
52.5

East Texas Pipeline
 
100
%
 
460

 
2.4

 

RIGS Haynesville Partnership Co.
 
49.99
%
 
450

 
2.1

 



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The following information describes our principal intrastate transportation and storage assets:
The ET Fuel System serves some of the most prolific production areas in the United States and is comprised of intrastate natural gas pipeline and related natural gas storage facilities. The ET Fuel System has many interconnections with pipelines providing direct access to power plants, other intrastate and interstate pipelines, and has bi-directional capabilities. It is strategically located near high-growth production areas and provides access to the Waha Hub near Midland, Texas, the Katy Hub near Houston, Texas and the Carthage Hub in East Texas, the three major natural gas trading centers in Texas.
The ET Fuel System also includes our Bethel natural gas storage facility, with a working capacity of 6.0 Bcf, an average withdrawal capacity of 300 MMcf/d and an injection capacity of 75 MMcf/d, and our Bryson natural gas storage facility, with a working capacity of 5.2 Bcf, an average withdrawal capacity of 120 MMcf/d and an average injection capacity of 96 MMcf/d. Storage capacity on the ET Fuel System is contracted to third parties under fee-based arrangements that extend through 2023.
In addition, the ET Fuel System is integrated with our Godley processing plant which gives us the ability to bypass the plant when processing margins are unfavorable by blending the untreated natural gas from the North Texas System with natural gas on the ET Fuel System while continuing to meet pipeline quality specifications.
The Oasis Pipeline is primarily a 36-inch natural gas pipeline. It has bi-directional capabilities with approximately 1.2 Bcf/d of throughput capacity moving west-to-east and greater than 750 MMcf/d of throughput capacity moving east-to-west. The Oasis pipeline connects to the Waha and Katy market hubs and has many interconnections with other pipelines, power plants, processing facilities, municipalities and producers.
The Oasis pipeline is integrated with our Southeast Texas System and is an important component to maximizing our Southeast Texas System’s profitability. The Oasis pipeline enhances the Southeast Texas System by (i) providing access for natural gas on the Southeast Texas System to other third-party supply and market points and interconnecting pipelines and (ii) allowing us to bypass our processing plants and treating facilities on the Southeast Texas System when processing margins are unfavorable by blending untreated natural gas from the Southeast Texas System with gas on the Oasis pipeline while continuing to meet pipeline quality specifications.
The HPL System is an extensive network of intrastate natural gas pipelines, an underground Bammel storage reservoir and related transportation assets. The system has access to multiple sources of historically significant natural gas supply reserves from South Texas, the Gulf Coast of Texas, East Texas and the western Gulf of Mexico, and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City and other cities located along the Gulf Coast of Texas. The HPL System is well situated to gather and transport gas in many of the major gas producing areas in Texas including a strong presence in the key Houston Ship Channel and Katy Hub markets, allowing us to play an important role in the Texas natural gas markets. The HPL System also offers its shippers off-system opportunities due to its numerous interconnections with other pipeline systems, its direct access to multiple market hubs at Katy, the Houston Ship Channel and Agua Dulce, as well as our Bammel storage facility.
The Bammel storage facility has a total working gas capacity of approximately 52.5 Bcf, a peak withdrawal rate of 1.3 Bcf/d and a peak injection rate of 0.6 Bcf/d. The Bammel storage facility is located near the Houston Ship Channel market area and the Katy Hub, and is ideally suited to provide a physical backup for on-system and off-system customers. As of December 31, 2016, we had approximately 10.8 Bcf committed under fee-based arrangements with third parties and approximately 36.9 Bcf stored in the facility for our own account.
The East Texas Pipeline connects three treating facilities, one of which we own, with our Southeast Texas System. The East Texas pipeline serves producers in East and North Central Texas and provided access to the Katy Hub. The East Texas pipeline expansions include the 36-inch East Texas extension to connect our Reed compressor station in Freestone County to our Grimes County compressor station, the 36-inch Katy expansion connecting Grimes to the Katy Hub, and the 42-inch Southeast Bossier pipeline connecting our Cleburne to Carthage pipeline to the HPL System.
RIGS is a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets. The Partnership owns a 49.99% general partner interest in RIGS.


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Interstate Transportation and Storage
The following details our pipelines in the interstate transportation and storage segment:
Description of Assets
 
Ownership Interest
(%)
 
Miles of Natural Gas Pipeline
 
Pipeline Throughput Capacity
(Bcf/d)
 
Working Gas Capacity
(Bcf/d)
Florida Gas Transmission Pipeline
 
50
%
 
5,325

 
3.1

 

Transwestern Pipeline
 
100
%
 
2,600

 
2.1

 

Panhandle Eastern Pipe Line
 
100
%
 
6,000

 
2.8

 
83.9

Trunkline Gas Pipeline
 
100
%
 
2,000

 
0.9

 
13.0

Tiger Pipeline
 
100
%
 
195

 
2.4

 

Fayetteville Express Pipeline
 
50
%
 
185

 
2.0

 

Sea Robin Pipeline
 
100
%
 
1,000

 
2.0

 

Midcontinent Express Pipeline
 
50
%
 
500

 
1.8

 

Gulf States
 
100
%
 
10

 
0.1

 

The following information describes our principal interstate transportation and storage assets:
The Florida Gas Transmission Pipeline (“FGT”) is an open-access interstate pipeline system with a mainline capacity of 3.1 Bcf/d and approximately 5,325 miles of pipelines extending from south Texas through the Gulf Coast region of the United States to south Florida. The FGT system receives natural gas from various onshore and offshore natural gas producing basins. FGT is the principal transporter of natural gas to the Florida energy market, delivering over 66% of the natural gas consumed in the state. In addition, FGT’s system operates and maintains over 81 interconnects with major interstate and intrastate natural gas pipelines, which provide FGT’s customers access to diverse natural gas producing regions. FGT’s customers include electric utilities, independent power producers, industrials and local distribution companies. FGT is owned by Citrus, a 50/50 joint venture with KMI.
The Transwestern Pipeline is an open-access interstate natural gas pipeline extending from the gas producing regions of West Texas, eastern and northwestern New Mexico, and southern Colorado primarily to pipeline interconnects off the east end of its system and to pipeline interconnects at the California border. The Transwestern Pipeline has bi-directional capabilities and access to three significant gas basins: the Permian Basin in West Texas and eastern New Mexico; the San Juan Basin in northwestern New Mexico and southern Colorado; and the Anadarko Basin in the Texas and Oklahoma panhandles. Natural gas sources from the San Juan Basin and surrounding producing areas can be delivered eastward to Texas intrastate and mid-continent connecting pipelines and natural gas market hubs as well as westward to markets in Arizona, Nevada and California. Transwestern’s Phoenix Lateral Pipeline, with a throughput capacity of 660 MMcf/d, connects the Phoenix area to the Transwestern mainline. Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users.
The Panhandle Eastern Pipe Line’s transmission system consists of four large diameter pipelines with bi-directional capabilities, extending approximately 1,300 miles from producing areas in the Anadarko Basin of Texas, Oklahoma and Kansas through Missouri, Illinois, Indiana, Ohio and into Michigan.
The Trunkline Gas Pipeline’s transmission system consists of one large diameter pipeline with bi-directional capabilities, extending approximately 1,400 miles from the Gulf Coast areas of Texas and Louisiana through Arkansas, Mississippi, Tennessee, Kentucky, Illinois, Indiana and Michigan.
The Tiger Pipeline is an approximately 195-mile interstate natural gas pipeline with bi-directional capabilities, that connects to our dual 42-inch pipeline system near Carthage, Texas, extends through the heart of the Haynesville Shale and ends near Delhi, Louisiana, with interconnects to at least seven interstate pipelines at various points in Louisiana.
The Fayetteville Express Pipeline is an approximately 185-mile interstate natural gas pipeline that originates near Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. The Fayetteville Express Pipeline is owned by a 50/50 joint venture with KMI.
The Sea Robin Pipeline’s transmission system consists of two offshore Louisiana natural gas supply systems extending approximately 120 miles into the Gulf of Mexico.


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The Midcontinent Express Pipeline is an approximately 500-mile interstate pipeline stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipeline System in Butler, Alabama. The Midcontinent Express Pipeline is owned by a 50/50 joint venture with KMI.
Gulf States owns a 10-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.
Midstream
The following details our assets in the midstream segment:
Description of Assets
 
Net Gas Processing Capacity
(MMcf/d)
 
Net Gas Treating Capacity
(MMcf/d)
South Texas Region:
 
 
 
 
Southeast Texas System
 
410

 
510

Eagle Ford System
 
1,920

 
930

Ark-La-Tex Region
 
1,025

 
1,186

North Central Texas Region
 
740

 
1,120

Permian Region
 
1,743

 
1,580

Mid-Continent Region
 
885

 
20

Eastern Region
 

 
70

The following information describes our principal midstream assets:
South Texas Region:
The Southeast Texas System is an integrated system that gathers, compresses, treats, processes, dehydrates and transports natural gas from the Austin Chalk trend and Eagle Ford shale formation. The Southeast Texas System is a large natural gas gathering system covering thirteen counties between Austin and Houston. This system is connected to the Katy Hub through the East Texas Pipeline and is also connected to the Oasis Pipeline. The Southeast Texas System includes two natural gas processing plant (La Grange and Alamo) with aggregate capacity of 410 MMcf/d and natural gas treating facilities with aggregate capacity of 510 MMcf/d. The La Grange and Alamo processing plants are natural gas processing plants that process the rich gas that flows through our gathering system to produce residue gas and NGLs. Residue gas is delivered into our intrastate pipelines and NGLs are delivered into our NGL pipelines to Lone Star.
Our treating facilities remove carbon dioxide and hydrogen sulfide from natural gas gathered into our system before the natural gas is introduced to transportation pipelines to ensure that the gas meets pipeline quality specifications.
The Eagle Ford Gathering System consists of 30-inch and 42-inch natural gas gathering pipelines with over 1.4 Bcf/d of capacity originating in Dimmitt County, Texas, and extending to both our King Ranch gas plant in Kleberg County, Texas and Jackson plant in Jackson County, Texas. The Eagle Ford Gathering System includes four processing plants (Chisholm, Kenedy, Jackson and King Ranch) with aggregate capacity of 1,920 MMcf/d and one natural gas treating facility with capacity of 930 MMcf/d. Our Chisholm, Kenedy, Jackson and King Ranch processing plants are connected to our intrastate transportation pipeline systems for deliveries of residue gas and are also connected with our NGL pipelines for delivery of NGLs to Lone Star.
Ark-La-Tex Region:
Our Northern Louisiana assets are comprised of several gathering systems in the Haynesville Shale with access to multiple markets through interconnects with several pipelines, including our Tiger Pipeline. Our Northern Louisiana assets include the Bistineau, Creedence, and Tristate Systems, which collectively include three natural gas treating facilities, with aggregate capacity of 1,186 MMcf/d.
Our PennTex Midstream System is primarily located in Lincoln Parish, Louisiana, and consists of the Lincoln Parish plant, a 200 MMcf/d design-capacity cryogenic natural gas processing plant located near Arcadia, Louisiana, the Mt. Olive plant, a 200 MMcf/d design-capacity cryogenic natural gas processing plant located near Ruston, Louisiana, with on-site liquids handling facilities for inlet gas; a 35-mile rich gas gathering system that provides producers with access to our processing plants and third-party processing capacity; a 15-mile residue gas pipeline that provides market access for natural gas from our processing plants, including connections with pipelines that provide access to the Perryville Hub and other markets in the


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Gulf Coast region; and a 40-mile NGL pipeline that provides connections to the Mont Belvieu market for NGLs produced from our processing plants.
The Ark-La-Tex assets gather, compress, treat and dehydrate natural gas in several parishes in north and west Louisiana and several counties in East Texas. These assets also include cryogenic natural gas processing facilities, a refrigeration plant, a conditioning plant, amine treating plants, and an interstate NGL pipeline. Collectively, the eight natural gas processing facilities (Dubach, Dubberly, Lisbon, Salem, Elm Grove, Minden, Ada and Brookeland) have an aggregate capacity of 1,025 MMcf/d.
Through the gathering and processing systems described above and their interconnections with RIGS in north Louisiana, we offer producers wellhead-to-market services, including natural gas gathering, compression, processing, treating and transportation.
North Central Texas Region:
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 740 MMcf/d and aggregate treating capacity of 1,120 MMcf/d. The Godley plant is integrated with the ET Fuel System.
Permian Region:
The Permian Basin Gathering System offers wellhead-to-market services to producers in eleven counties in West Texas, as well as two counties in New Mexico which surround the Waha Hub, one of Texas’s developing NGL-rich natural gas market areas. As a result of the proximity of our system to the Waha Hub, the Waha Gathering System has a variety of market outlets for the natural gas that we gather and process, including several major interstate and intrastate pipelines serving California, the mid-continent region of the United States and Texas natural gas markets. The NGL market outlets includes Lone Star’s liquids pipelines. The Permian Basin Gathering System includes ten processing facilities (Waha, Coyanosa, Red Bluff, Halley, Jal, Keyston, Tippet, Orla, Panther and Rebel) with an aggregate processing capacity of 1,418 MMcf/d, treating capacity of 1,580 MMcf/d, and one natural gas conditioning facility with aggregate capacity of 200 MMcf/d.
We own a 50% membership interest in Mi Vida JV, a joint venture which owns a 200 MMcf/d cryogenic processing plant in West Texas. We operate the plant and related facilities on behalf of Mi Vida JV.
We own a 33.33% membership interest in Ranch JV, which processes natural gas delivered from the NGL-rich Bone Spring and Avalon Shale formations in West Texas. The joint venture owns a 25 MMcf/d refrigeration plant and a 125 MMcf/d cryogenic processing plant.
Mid-Continent Region:
The Mid-Continent Systems are located in two large natural gas producing regions in the United States, the Hugoton Basin in southwest Kansas, and the Anadarko Basin in western Oklahoma and the Texas Panhandle. These mature basins have continued to provide generally long-lived, predictable production volume. Our Mid-Continent assets are extensive systems that gather, compress and dehydrate low-pressure gas. The Mid-Continent Systems include fourteen natural gas processing facilities (Mocane, Beaver, Antelope Hills, Woodall, Wheeler, Sunray, Hemphill, Phoenix, Hamlin, Spearman, Red Deer, Lefors, Cargray and Gray) with an aggregate capacity of 885 MMcf/d and one natural gas treating facility with aggregate capacity of 20 MMcf/d.
We operate our Mid-Continent Systems at low pressures to maximize the total throughput volumes from the connected wells. Wellhead pressures are therefore adequate to allow for flow of natural gas into the gathering lines without the cost of wellhead compression.
We also own the Hugoton Gathering System that has 1,900 miles of pipeline extending over nine counties in Kansas and Oklahoma. This system is operated by a third party.
Eastern Region:
The Eastern Region assets are located in nine counties in Pennsylvania, three counties in Ohio, three counties in West Virginia, and gather natural gas from the Marcellus and Utica basins. Our Eastern Region assets include approximately 500 miles of natural gas gathering pipeline, natural gas trunklines, fresh-water pipelines, and nine gathering and processing systems. The fresh water pipeline system and Ohio gathering assets are held by jointly-owned entities.


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We also own a 51% membership interest in Aqua – PVR, a joint venture that transports and supplies fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania.
We and Traverse ORS LLC, a subsidiary of Traverse Midstream Partners LLC, own a 75% and 25% membership interest, respectively, in the ORS joint venture. On behalf of ORS, we operate its Ohio Utica River System (the “ORS System”), which consists of 47 miles of 36-inch and 13 miles of 30-inch gathering trunklines that delivers up to 2.1 Bcf/d to Rockies Express Pipeline (“REX”), Texas Eastern Transmission, and others.
NGL and Refined Products Transportation and Services
The following details our assets in the NGL and refined products transportation and services segment:
Description of Assets
 
Miles of Liquids Pipeline
 
Pipeline Throughput Capacity
(Bbls/d)
 
NGL Fractionation / Processing Capacity
(Bbls/d)
 
Working Storage Capacity
(Bbls)
Liquids Pipelines:
 
 
 
 
 
 
 
 
Lone Star Express
 
532

 
507,000

 

 

West Texas Gateway Pipeline
 
570

 
240,000

 

 

Legacy Sunoco Logistics NGL pipelines
 
900

 
**(2)

 
 
 
 
Legacy Sunoco Logistics refined products pipelines
 
1,800

 
**(2)

 
 
 
 
Other NGL Pipelines
 
356

 
691,000

 

 

Liquids Fractionation and Services Facilities:
 
 
 
 
 
 
 
 
Mont Belvieu Facilities
 
185

 
42,000

 
520,000

 
50,000,000

Sea Robin Processing Plant1
 

 

 
26,000

 

Refinery Services1
 
100

 

 
25,000

 

Hattiesburg Storage Facilities
 

 

 

 
3,000,000

NGLs Terminals:
 
 
 
 
 
 
 
 
Nederland
 

 

 

 
1,000,000

Marcus Hook Industrial Complex
 

 

 

 
3,000,000

Inkster
 

 

 

 
1,000,000

Refined Products Terminals (2)
 
 
 
 
 
 
 
 
(1) 
Additionally, the Sea Robin Processing Plant and Refinery Services have residue capacities of 850 MMcf/d and 54 MMcf/d, respectively.
(2) 
See description of the legacy Sunoco Logistics assets below.
The following information describes our principal NGL and refined products transportation and services assets:
The Lone Star Express System is an intrastate NGL pipeline consisting of 24-inch and 30-inch long-haul transportation pipeline that delivers mixed NGLs from processing plants in the Permian Basin, the Barnett Shale, and from East Texas to the Mont Belvieu NGL storage facility.
The West Texas Gateway Pipeline transports NGLs produced in the Permian and Delaware Basins and the Eagle Ford Shale to Mont Belvieu, Texas.
Legacy Sunoco Logistics NGL pipelines, including:
The Mariner East pipeline transports NGLs from the Marcellus and Utica Shales areas in Western Pennsylvania, West Virginia and Eastern Ohio to destinations in Pennsylvania, including our Marcus Hook Industrial Complex on the Delaware River, where they are processed, stored and distributed to local, domestic and waterborne markets. The first phase of the project, referred to as Mariner East 1, consisted of interstate and intrastate propane and ethane service and commenced operations in the fourth quarter of 2014 and the first quarter of 2016, respectively. The second phase of the project, referred to as Mariner East 2, will expand the total takeaway capacity to 345,000 Bbls/d for interstate and intrastate propane, ethane and butane service, and is expected to commence operations in the third quarter of 2017.


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The Mariner South pipeline is part of a joint project with Lone Star to deliver export-grade propane and butane products from Lone Star’s Mont Belvieu, Texas storage and fractionation complex to Sunoco Logistics’ marine terminal in Nederland, Texas. The pipeline has a capacity of approximately 200,000 Bbls/d and can be scaled depending on shipper interest.
The Mariner West pipeline provides transportation of ethane products from the Marcellus shale processing and fractionating areas in Houston, Texas and Pennsylvania to Marysville, Michigan and the Canadian border. Mariner West commenced operations in the fourth quarter 2013, with capacity to transport approximately 50,000 Bbls/d of NGLs and other products.
Legacy Sunoco Logistics refined products pipelines include approximately 1,800 miles of refined products pipelines in several regions of the United States. The pipelines primarily provide transportation in the northeast, midwest, and southwest United States markets. These operations include Sunoco Logistics’ controlling financial interest in Inland Corporation (“Inland”). The mix of products delivered varies seasonally, with gasoline demand peaking during the summer months, and demand for heating oil and other distillate fuels peaking in the winter. In addition, weather conditions in the areas served by the refined products pipelines affect both the demand for, and the mix of, the refined products delivered through the pipelines, although historically, any overall impact on the total volume shipped has been short-term. The products transported in these pipelines include multiple grades of gasoline, and middle distillates, such as heating oil, diesel and jet fuel. Rates for shipments on these product pipelines are regulated by the FERC and other state regulatory agencies, as applicable.
Other NGL pipelines include the 127-mile Justice pipeline with capacity of 375,000 Bbls/d, the 45-mile Freedom pipeline with a capacity of 56,000 Bbls/d, the 15-mile Spirit pipeline with a capacity of 20,000 Bbls/d, the 82-mile Rio Bravo crude oil pipeline with a capacity of 100,000 Bbls/d and a 50% interest in the 87-mile Liberty pipeline with a capacity of 140,000 Bbls/d.
Our Mont Belvieu storage facility is an integrated liquids storage facility with over 50 million Bbls of salt dome capacity providing 100% fee-based cash flows. The Mont Belvieu storage facility has access to multiple NGL and refined product pipelines, the Houston Ship Channel trading hub, and numerous chemical plants, refineries and fractionators.
Our Mont Belvieu fractionators handle NGLs delivered from several sources, including the Lone Star Express pipeline and the Justice pipeline.
Sea Robin is a rich gas processing plant located on the Sea Robin Pipeline in southern Louisiana. The plant, which is connected to nine interstate and four intrastate residue pipelines, as well as various deep-water production fields.
Refinery Services consists of a refinery off-gas processing and O-grade NGL fractionation complex located along the Mississippi River refinery corridor in southern Louisiana that cryogenically processes refinery off-gas and fractionates the O-grade NGL stream into its higher value components. The O-grade fractionator, located in Geismar, Louisiana, is connected by approximately 100 miles of pipeline to the Chalmette processing plant, which has a processing capacity of 54 MMcf/d.
The Hattiesburg storage facility is an integrated liquids storage facility with approximately 3 million Bbls of salt dome capacity, providing 100% fee-based cash flows.
The Nederland terminal, in addition to crude oil activities, also provides approximately 1 million barrels of storage and distribution services for NGLs in connection with the Mariner South pipeline, which provides transportation of propane and butane products from the Mont Belvieu region to the Nederland terminal, where such products can be delivered via ship.
The Marcus Hook Industrial Complex includes terminalling and storage assets, with a capacity of approximately 3 million barrels of NGL storage capacity in underground caverns, and related commercial agreements. The facility can receive NGLs via marine vessel, pipeline, truck and rail, and can deliver via marine vessel, pipeline and truck. In addition to providing NGLs storage and terminalling services to both affiliates and third-party customers, the Marcus Hook Industrial Complex currently serves as an off-take outlet for the Mariner East 1 pipeline, and will provide similar off-take capabilities for the Mariner East 2 pipeline when it commences operations.
The Inkster terminal, located near Detroit, Michigan, consists of multiple salt caverns with a total storage capacity of approximately 1 million barrels of NGLs. We use the Inkster terminal's storage in connection with the Toledo North pipeline system and for the storage of NGLs from local producers and a refinery in Western Ohio. The terminal can receive and ship by pipeline in both directions and has a truck loading and unloading rack.
We have approximately 40 refined products terminals with an aggregate storage capacity of approximately 8 million barrels that facilitate the movement of refined products to or from storage or transportation systems, such as a pipeline, to other transportation systems, such as trucks or other pipelines. Each facility typically consists of multiple storage tanks and is equipped with automated truck loading equipment that is operational 24 hours a day.


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In addition to crude oil service, the Eagle Point terminal can accommodate three marine vessels (ships or barges) to receive and deliver refined products to outbound ships and barges. The tank farm has a total active refined products storage capacity of approximately 6 million barrels, and provides customers with access to the facility via barge and pipeline. The terminal can deliver via barge, truck or pipeline, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.
The Marcus Hook Industrial Complex can receive refined products via marine vessel, pipeline, truck and rail, and can deliver via marine vessel, pipeline and truck. The terminal has a total active refined products storage capacity of approximately 2 million barrels.
The Marcus Hook Tank Farm has a total refined products storage capacity of approximately 2 million barrels of refined products storage. The tank farm historically served Sunoco Inc.'s Marcus Hook refinery and generated revenue from the related throughput and storage. In 2012, the main processing units at the refinery were idled in connection with Sunoco Inc.'s exit from its refining business. The terminal continues to receive and deliver refined products via pipeline and now primarily provides terminalling services to support movements on Sunoco Logistics’ refined products pipelines.
Crude Oil Transportation and Services
The following details our assets in the crude oil transportation and services segment:
Our crude oil operations consist of an integrated set of pipeline, terminalling, and acquisition and marketing assets that service the movement of crude oil from producers to end-user markets.
Crude Oil Pipelines
Our crude oil pipelines consist of approximately 6,100 miles of crude oil trunk and gathering pipelines in the southwest and midwest United States, including wholly-owned interests in West Texas Gulf and Permian Express Terminal LLC (“PET”), and a controlling financial interest in Mid-Valley Pipeline Company ("Mid-Valley"). Additionally, we have equity ownership interests in two crude oil pipelines. Our crude oil pipelines provide access to several trading hubs, including the largest trading hub for crude oil in the United States located in Cushing, Oklahoma, and other trading hubs located in Midland, Colorado City and Longview, Texas. Our crude oil pipelines also deliver to and connect with other pipelines that deliver crude oil to a number of refineries.
Southwest United States Pipelines. The Southwest pipelines include crude oil trunk pipelines and crude oil gathering pipelines in Texas and Oklahoma. This includes the Permian Express 2 pipeline project which provides takeaway capacity from the Permian Basin, with origins in multiple locations in Western Texas: Midland, Garden City and Colorado City. Our fourth quarter 2016 acquisition of a West Texas crude oil system from Vitol Inc. and the remaining ownership interest in PET facilitates connection of its Permian Express 2 pipeline to terminal assets in Midland and Garden City, Texas.
In the third quarter 2016, we commenced operations on the Delaware Basin Extension and Permian Longview and Louisiana Extension pipeline projects. The Delaware Basin Extension pipeline project provides shippers with new takeaway capacity from the rapidly growing Delaware Basin area in New Mexico and West Texas to Midland, Texas. The project has initial capacity to transport approximately 100,000 Bbls/d. The Permian Longview and Louisiana Extension pipeline project provides takeaway capacity for approximately 100,000 Bbls/d additional out of the Permian Basin at Midland, Texas to be transported to the Longview, Texas area as well as destinations in Louisiana utilizing a combination of our proprietary crude oil system as well as third-party pipelines.
We own and operate crude oil pipeline and gathering systems in Oklahoma. We have the ability to deliver substantially all of the crude oil gathered on our Oklahoma system to Cushing. We are one of the largest purchasers of crude oil from producers in the state, and its crude oil acquisition and marketing activities business is the primary shipper on its Oklahoma crude oil system.
Midwest United States Pipelines. We own a controlling financial interest in the Mid-Valley pipeline system which originates in Longview, Texas and passes through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky and Ohio, and terminates in Samaria, Michigan. This pipeline provides crude oil to a number of refineries, primarily in the midwest United States.
In addition, we own a crude oil pipeline that runs from Marysville, Michigan to Toledo, Ohio, and a truck injection point for local production at Marysville. This pipeline receives crude oil from the Enbridge pipeline system for delivery to refineries located in Toledo, Ohio and to Marathon Petroleum Corporation’s Samaria, Michigan tank farm, which supplies its refinery in Detroit, Michigan.


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Crude Oil Terminals
Nederland. The Nederland terminal, located on the Sabine-Neches waterway between Beaumont and Port Arthur, Texas, is a large marine terminal providing storage and distribution services for refiners and other large transporters of crude oil and NGLs. The terminal receives, stores, and distributes crude oil, NGLs, feedstocks, lubricants, petrochemicals, and bunker oils (used for fueling ships and other marine vessels), and also blends lubricants. The terminal currently has a total storage capacity of approximately 26 million barrels in approximately 150 above ground storage tanks with individual capacities of up to 660,000 Bbls.
The Nederland terminal can receive crude oil at each of its five ship docks and four barge berths. The five ship docks are capable of receiving over 2 million Bbls/d of crude oil. In addition to Sunoco Logistics’ crude oil pipelines, the terminal can also receive crude oil through a number of other pipelines, including the DOE. The DOE pipelines connect the terminal to the United States Strategic Petroleum Reserve’s West Hackberry caverns at Hackberry, Louisiana and Big Hill near Winnie, Texas, which have an aggregate storage capacity of approximately 395 million barrels.
The Nederland Terminal can deliver crude oil and other petroleum products via pipeline, barge and ship. The terminal has two ship docks and three barge berths that are capable of delivering crude oils for international transport. In total, the terminal is capable of delivering over 2 million Bbls/d of crude oil to our crude oil pipelines or a number of third-party pipelines including the DOE. The Nederland terminal generates crude oil revenues primarily by providing term or spot storage services and throughput capabilities to a number of customers.
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.
The Fort Mifflin terminal contains two ship docks with freshwater drafts and a total storage capacity of approximately 570,000 Bbls. Crude oil and some refined products enter the Fort Mifflin terminal primarily from marine vessels on the Delaware River. One Fort Mifflin dock is designed to handle crude oil from very large crude carrier-class tankers and smaller crude oil vessels. The other dock can accommodate only smaller crude oil vessels.
The Hog Island wharf is located next to the Fort Mifflin terminal on the Delaware River and receives crude oil via two ship docks, one of which can accommodate crude oil tankers and smaller crude oil vessels, and the other of which can accommodate some smaller crude oil vessels.
The Darby Creek tank farm is a primary crude oil storage terminal for the Philadelphia refinery, which is operated by PES under a joint venture with Sunoco, Inc. This facility has a total storage capacity of approximately 3 million barrels. Darby Creek receives crude oil from the Fort Mifflin terminal and Hog Island wharf via Sunoco Logistics’ pipelines. The tank farm then stores the crude oil and transports it to the PES refinery via Sunoco Logistics’ pipelines.
Eagle Point. The Eagle Point terminal is located in Westville, New Jersey and consists of docks, truck loading facilities and a tank farm. The docks are located on the Delaware River and can accommodate three marine vessels (ships or barges) to receive and deliver crude oil, intermediate products and refined products to outbound ships and barges. The tank farm has a total active storage capacity of approximately 1 million barrels and can receive crude oil via barge and rail and deliver via barge, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.
Midland. The Midland terminal is located in Midland, Texas and was acquired in November 2016 from Vitol. The facility includes approximately 2 million barrels of crude oil storage, a combined 14 lanes of truck loading and unloading, and will provide access to the Permian Express 2 transportation system.
Crude Oil Acquisition and Marketing
Our crude oil acquisition and marketing activities include the gathering, purchasing, marketing and selling of crude oil primarily in the mid-continent United States. The operations are conducted using our assets, which include approximately 370 crude oil transport trucks and approximately 150 crude oil truck unloading facilities, as well as third-party truck, rail and marine assets. Specifically, the crude oil acquisition and marketing activities include:
purchasing crude oil at both the wellhead from producers, and in bulk from aggregators at major pipeline interconnections and trading locations;
storing inventory during contango market conditions (when the price of crude oil for future delivery is higher than current prices);


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buying and selling crude oil of different grades, at different locations in order to maximize value;
transporting crude oil using the pipelines, terminals and trucks or, when necessary or cost effective, pipelines, terminals or trucks owned and operated by third parties; and
marketing crude oil to major integrated oil companies, independent refiners and resellers through various types of sale and exchange transactions.
In November 2016, Sunoco Logistics purchased a crude oil acquisition and marketing business from Vitol, with operations based in the Permian Basin, Texas. Included in the acquisition was a significant acreage dedication from an investment-grade Permian producer.
All Other
The following details our assets in the all other segment.
Equity Method Investments
Sunoco LP. We have an equity method investment in limited partnership units of Sunoco LP consisting of 43.5 million units, representing 44.3% of Sunoco LP’s total outstanding common units.
PES. We have a non-controlling interest in PES, comprising 33% of PES’ outstanding common units.
Contract Services Operations
We own and operate a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management. Our contract treating services are primarily located in Texas, Louisiana and Arkansas.
Compression
We own all of the outstanding equity interests of a natural gas compression equipment business with operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas.
We own 100% of the membership interests of ETG, which owns all of the partnership interests of ETT. ETT provides compression services to customers engaged in the transportation of natural gas, including our other segments.
Natural Resources Operations
Our Natural Resources operations primarily involve the management and leasing of coal properties and the subsequent collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage fees. As of December 31, 2016, we owned or controlled approximately 772 million tons of proven and probable coal reserves in central and northern Appalachia, properties in eastern Kentucky, Tennessee, southwestern Virginia and southern West Virginia, and in the Illinois Basin, properties in southern Illinois, Indiana, and western Kentucky and as the operator of end-user coal handling facilities. Our subsidiary, Materials Handling Solutions, LLC, owns and operates facilities for industrial customers on a fee basis. During 2014, our coal reserves located in the San Juan basin were depleted and our associated coal royalties revenues ceased.
Liquefaction Project
LCL, an entity whose parent is owned 60% by ETE and 40% by ETP, is in the process of developing the liquefaction project in conjunction with BG pursuant to a project development agreement entered into in September 2013. Pursuant to this agreement, each of LCL and BG are obligated to pay 50% of the development expenses for the liquefaction project, subject to reimbursement by the other party if such party withdraws from the project prior to both parties making an affirmative FID to become irrevocably obligated to fully develop the project, subject to certain exceptions. The liquefaction project is expected to consist of three LNG trains with a combined design nameplate outlet capacity of 16.2 metric tonnes per annum. Once completed, the liquefaction project will enable LCL to liquefy domestically produced natural gas and export it as LNG. By adding the new liquefaction facility and integrating with the existing LNG regasification/import facility, the enhanced facility will become a bi-directional facility capable of exporting and importing LNG. BG is the sole customer for the existing regasification facility and is obligated to pay reservation fees for 100% of the regasification capacity regardless of whether it actually utilizes such capacity pursuant to a regasification services agreement that terminates in 2030. The liquefaction project will be constructed on 440 acres of land, of which 80 acres are owned by Lake Charles LNG and the remaining acres are to be leased by LCL under a long-term lease from the Lake Charles Harbor and Terminal District.


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As currently provided in the Project Development Agreement, the construction of the liquefaction project is subject to each of LCL and BG making an affirmative FID to proceed with the project, which decision is in the sole discretion of each party. In the event an affirmative FID is made by both parties, LCL and BG will enter into several agreements related to the project, including a liquefaction services agreement pursuant to which BG will pay LCL for liquefaction services on a tolling basis for a minimum 25-year term with evergreen extension options for 20 years. In addition, a subsidiary of BG, a highly experienced owner and operator of LNG facilities, would oversee construction of the liquefaction facility and, upon completion of construction, manage the operations of the liquefaction facility on behalf of LCL. In the event that each of LCL and BG elect to make an affirmative FID, construction of the liquefaction project would commence promptly thereafter, and the first train would be expected to be placed in service about four years later.
The export of LNG produced by the liquefaction project from the U.S. will be undertaken under long-term export authorizations issued by the DOE to Lake Charles Exports, LLC (“LCE”), which is currently a jointly owned subsidiary of BG and ETP and following FID, will be 100% owned by BG. In July 2011, LCE obtained a DOE authorization to export LNG to countries with which the U.S. has or will have Free Trade Agreements (“FTA”) for trade in natural gas (the “FTA Authorization”). In August 2013, LCE obtained a conditional DOE authorization to export LNG to countries that do not have an FTA for trade in natural gas (the “Non-FTA Authorization”). The FTA Authorization and Non-FTA Authorization have 25- and 20-year terms, respectively. In January 2013, LCL filed for a secondary, non-cumulative FTA and Non-FTA Authorization to be held by LCL. FTA Authorization was granted in March 2013 and the Non-FTA Authorization was granted in July 2016.
We have received our wetlands permits from the U.S. Army Corps of Engineers (“USACE”) to perform wetlands mitigation work and to perform modification and dredging work for the temporary and permanent dock facilities at the Lake Charles LNG facilities.
Business Strategy
See information previously included in our Form 10-K filed on February 24, 2017 and Form 8-K filed on May 8, 2017.
Environmental Matters
See information previously included in our Form 10-K filed on February 24, 2017 and Form 8-K filed on May 8, 2017.
Employees
See information previously included in our Form 10-K filed on February 24, 2017 and Form 8-K filed on May 8, 2017.
SEC Reporting
We file or furnish annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any related amendments and supplements thereto with the SEC. From time to time, we may also file registration and related statements pertaining to equity or debt offerings. You may read and copy any materials we file or furnish with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information regarding the Public Reference Room by calling the SEC at 1-800-732-0330. In addition, the SEC maintains an Internet website at http://www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.
We provide electronic access, free of charge, to our periodic and current reports, and amendments to these reports, on our internet website located at http://www.energytransfer.com. These reports are available on our website as soon as reasonably practicable after we electronically file such materials with the SEC. Information contained on our website is not part of this report.


14


PART II
ITEM 6.  SELECTED FINANCIAL DATA
The selected financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical consolidated financial statements and the accompanying notes thereto included elsewhere in this report. The amounts in the table below, except per unit data, are in millions.
 
Years Ended December 31,
 
2016
 
2015
 
2014
 
2013
 
2012
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Total revenues
$
21,827

 
$
34,292

 
$
55,475

 
$
48,335

 
$
16,964

Operating income
1,802

 
2,259

 
2,443

 
1,619

 
1,425

Income from continuing operations
624

 
1,521

 
1,235

 
713

 
1,754

Basic income (loss) from continuing operations per Common Unit
(1.37
)
 
(0.06
)
 
1.05

 
(0.15
)
 
3.29

Diluted income (loss) from continuing operations per Common Unit
(1.37
)
 
(0.07
)
 
1.05

 
(0.15
)
 
3.27

Cash distributions per unit
2.81

 
2.77

 
2.57

 
2.41

 
2.39

Balance Sheet Data (at period end):
 
 
 
 
 
 
 
 
 
Total assets
70,191

 
65,173

 
62,518

 
49,900

 
48,394

Long-term debt, less current maturities
31,741

 
28,553

 
24,831

 
19,761

 
17,599

Total equity
26,527

 
27,031

 
25,311

 
18,694

 
19,982

Other Financial Data:
 
 
 
 
 
 
 
 
 
Capital expenditures:
 
 
 
 
 
 
 
 
 
Maintenance (accrual basis)
368

 
485

 
444

 
391

 
347

Growth (accrual basis)
5,442

 
7,682

 
5,050

 
2,936

 
3,186

Cash paid for acquisitions
1,227

 
804

 
2,367

 
1,737

 
1,364


ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
(Tabular dollar and unit amounts, except per unit data, are in millions)
The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with our historical consolidated financial statements and accompanying notes thereto included in “Item 8. Financial Statements and Supplementary Data” of this report. This discussion includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Item 1A. Risk Factors” included in this report.
References to “we,” “us,” “our,” the “Partnership” and “ETP” shall mean Energy Transfer Partners, L.P. and its subsidiaries.
Overview
The primary activities and operating subsidiaries through which we conduct those activities are as follows:
Natural gas operations, including the following:
natural gas midstream and intrastate transportation and storage; and
interstate natural gas transportation and storage through ET Interstate and Panhandle. ET Interstate is the parent company of Transwestern, ETC FEP, ETC Tiger, CrossCountry, ETC MEP and ET Rover. Panhandle is the parent company of the Trunkline and Sea Robin transmission systems.
Liquids operations, including NGL transportation, storage and fractionation services and refined products transportation.
Crude oil transportation, terminalling services and acquisition and marketing activities.


15


Recent Developments
See information previously included in our Form 10-K filed on February 24, 2017 and Form 8-K filed on May 8, 2017.
General
Our primary objective is to increase the level of our distributable cash flow to our Unitholders over time by pursuing a business strategy that is currently focused on growing our businesses through, among other things, pursuing certain construction and expansion opportunities relating to our existing infrastructure and acquiring certain strategic operations and businesses or assets as demonstrated by our recent acquisitions and organic growth projects. The actual amounts of cash that we will have available for distribution will primarily depend on the amount of cash we generate from our operations.
During the past several years, we have been successful in completing several transactions that have significantly increased our distributable cash flow. We have also made, and are continuing to make, significant investments in internal growth projects, primarily the construction of pipelines, gathering systems and natural gas treating and processing plants, which we believe will provide additional distributable cash flow to our Partnership for years to come. Lastly, we have established and executed on cost control measures to drive cost savings across our operations to generate additional distributable cash flow.
Our principal operations as of December 31, 2016 included the following segments:
Intrastate transportation and storage – Revenue is principally generated from fees charged to customers to reserve firm capacity on or move gas through our pipelines on an interruptible basis. Our interruptible or short-term business is generally impacted by basis differentials between delivery points on our system and the price of natural gas. The basis differentials that primarily impact our interruptible business are primarily among receipt points between West Texas to East Texas or segments thereof. When narrow or flat spreads exist, our open capacity may be underutilized and go unsold. Conversely, when basis differentials widen, our interruptible volumes and fees generally increase. The fee structure normally consists of a monetary fee and fuel retention. Excess fuel retained after consumption, if any, is typically sold at market prices. In addition to transport fees, we generate revenue from purchasing natural gas and transporting it across our system. The natural gas is then sold to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies. The HPL System purchases natural gas at the wellhead for transport and selling. Other pipelines with access to West Texas supply, such as Oasis and ET Fuel, may also purchase gas at the wellhead and other supply sources for transport across our system to be sold at market on the east side of our system. This activity allows our intrastate transportation and storage segment to capture the current basis differentials between delivery points on our system or to capture basis differentials that were previously locked in through hedges. Firm capacity long-term contracts are typically not subject to price differentials between shipping locations.
We also generate fee-based revenue from our natural gas storage facilities by contracting with third parties for their use of our storage capacity. From time to time, we inject and hold natural gas in our Bammel storage facility to take advantage of contango markets, a term used to describe a pricing environment when the price of natural gas is higher in the future than the current spot price. We use financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. Our earnings from natural gas storage we purchase, store and sell are subject to the current market prices (spot price in relation to forward price) at the time the storage gas is hedged. At the inception of the hedge, we lock in a margin by purchasing gas in the spot market and entering into a financial derivative to lock in the forward sale price. If we designate the related financial derivative as a fair value hedge for accounting purposes, we value the hedged natural gas inventory at current spot market prices whereas the financial derivative is valued using forward natural gas prices. As a result of fair value hedge accounting, we have elected to exclude the spot forward premium from the measurement of effectiveness and changes in the spread between forward natural gas prices and spot market prices result in unrealized gains or losses until the underlying physical gas is withdrawn and the related financial derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. If the spread narrows between spot and forward prices, we will record unrealized gains or lower unrealized losses. If the spread widens prior to withdrawal of the gas, we will record unrealized losses or lower unrealized gains.
As noted above, any excess retained fuel is sold at market prices. To mitigate commodity price exposure, we may use financial derivatives to hedge prices on a portion of natural gas volumes retained. For certain contracts that qualify for hedge accounting, we designate them as cash flow hedges of the forecasted sale of gas. The change in value, to the extent the contracts are effective, remains in accumulated other comprehensive income until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.
In addition, we use financial derivatives to lock in price differentials between market hubs connected to our assets on a portion of our intrastate transportation system’s unreserved capacity. Gains and losses on these financial derivatives are dependent on price differentials at market locations, primarily points in West Texas and East Texas. We account for these derivatives


16


using mark-to-market accounting, and the change in the value of these derivatives is recorded in earnings. During the fourth quarter of 2011, we began using derivatives for trading purposes.
Interstate transportation and storage – The majority of our interstate transportation and storage revenues are generated through firm reservation charges that are based on the amount of firm capacity reserved for our firm shippers regardless of usage. Tiger, FEP, Transwestern, Panhandle, MEP and Gulf States shippers have made long-term commitments to pay reservation charges for the firm capacity reserved for their use.  In addition to reservation revenues, additional revenue sources include interruptible transportation charges as well as usage rates and overrun rates paid by firm shippers based on their actual capacity usage.
Midstream – Revenue is principally dependent upon the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipelines as well as the level of natural gas and NGL prices.
In addition to fee-based contracts for gathering, treating and processing, we also have percent-of-proceeds and keep-whole contracts, which are subject to market pricing. For percent-of-proceeds contracts, we retain a portion of the natural gas and NGLs processed, or a portion of the proceeds of the sales of those commodities, as a fee. When natural gas and NGL prices increase, the value of the portion we retain as a fee increases. Conversely, when prices of natural gas and NGLs decrease, so does the value of the portion we retain as a fee. For wellhead (keep-whole) contracts, we retain the difference between the price of NGLs and the cost of the gas to process the NGLs. In periods of high NGL prices relative to natural gas, our margins increase. During periods of low NGL prices relative to natural gas, our margins decrease or could become negative. Our processing contracts and wellhead purchases in rich natural gas areas provide that we earn and take title to specified volumes of NGLs, which we also refer to as equity NGLs. Equity NGLs in our midstream segment are derived from performing a service in a percent-of-proceeds contract or produced under a keep-whole arrangement.
In addition to NGL price risk, our processing activity is also subject to price risk from natural gas because, in order to process the gas, in some cases we must purchase it. Therefore, lower gas prices generally result in higher processing margins.
NGL and refined products transportation and services – Liquids transportation revenue is principally generated from fees charged to customers under dedicated contracts or take-or-pay contracts. Under a dedicated contract, the customer agrees to deliver the total output from particular processing plants that are connected to the NGL pipeline. Take-or-pay contracts have minimum throughput commitments requiring the customer to pay regardless of whether a fixed volume is transported. Transportation fees are market-based, negotiated with customers and competitive with regional regulated pipelines.
NGL storage revenues are derived from base storage fees and throughput fees. Base storage fees are based on the volume of capacity reserved, regardless of the capacity actually used. Throughput fees are charged for providing ancillary services, including receipt and delivery, custody transfer, rail/truck loading and unloading fees. Storage contracts may be for dedicated storage or fungible storage. Dedicated storage enables a customer to reserve an entire storage cavern, which allows the customer to inject and withdraw proprietary and often unique products. Fungible storage allows a customer to store specified quantities of NGL products that are commingled in a storage cavern with other customers’ products of the same type and grade. NGL storage contracts may be entered into on a firm or interruptible basis. Under a firm basis contract, the customer obtains the right to store products in the storage caverns throughout the term of the contract; whereas, under an interruptible basis contract, the customer receives only limited assurance regarding the availability of capacity in the storage caverns. Revenues are also generated by charging fees for terminalling services for NGLs and refined products and by acquiring and marketing NGLs and refined products. Generally, NGL and refined products purchases are entered into in contemplation of or simultaneously with corresponding sale transactions involving physical deliveries, which enables us to secure a profit on the transaction at the time of purchase.
Our refined products terminals derive revenues from terminalling fees paid by customers. A fee is charged for receiving products into the terminal and delivering them to trucks, barges, or pipelines. In addition to terminalling fees, our refined products terminals generate revenues by charging customers fees for blending services, including certain ethanol and biodiesel blending, injecting additives, and filtering jet fuel. Our refined products pipelines provide supply to the majority of our refined products terminals, with third-party pipelines and barges supplying the remainder.
Our refined products acquisition and marketing activities include the acquisition, marketing and selling of bulk refined products such as gasoline products and distillates. These activities utilize our refined products pipeline and terminal assets, as well as third-party assets and facilities. The operating results of our refined products acquisition and marketing activities are dependent on our ability to execute sales in excess of the aggregate cost, and therefore we structure our acquisition and marketing operations to optimize the sources and timing of purchases and minimize the transportation and storage costs. In order to manage exposure to volatility in refined products prices, our policy is to (i) only purchase products for which sales contracts have been executed or for which ready markets exist, (ii) structure sales contracts so that price fluctuations do not materially impact the margins earned, and (iii) not acquire and hold physical inventory, futures contracts or other derivative instruments for the purpose of speculating on commodity price changes. However, we do utilize a hedge program involving swaps, futures


17


and other derivative instruments to mitigate the risk associated with unfavorable market movements in the price of refined products. These derivative contracts act as a hedging mechanism against the volatility of prices.
This segment also includes revenues earned from processing and fractionating refinery off-gas. Under these contracts we receive an O-grade stream from cryogenic processing plants located at refineries and fractionate the products into their pure components. We deliver purity products to customers through pipelines and across a truck rack located at the fractionation complex. In addition to revenues for fractionating the O-grade stream, we have percentage-of-proceeds and income sharing contracts, which are subject to market pricing of olefins and NGLs. For percentage-of-proceeds contracts, we retain a portion of the purity NGLs and olefins processed, or a portion of the proceeds from the sales of those commodities, as a fee. When NGLs and olefin prices increase, the value of the portion we retain as a fee increases. Conversely, when NGLs and olefin prices decrease, so does the value of the portion we retain as a fee. Under our income sharing contracts, we pay the producer the equivalent energy value for their liquids, similar to a traditional keep-whole processing agreement, and then share in the residual income created by the difference between NGLs and olefin prices as compared to natural gas prices. As NGLs and olefins prices increase in relation to natural gas prices, the value of the percent we retain as a fee increases. Conversely, when NGLs and olefins prices decrease as compared to natural gas prices, so does the value of the percent we retain as a fee.
Crude oil transportation and services – Revenues are generated by charging tariffs for transporting crude oil through our pipelines as well as by charging fees for terminalling services for at our facilities. Revenues are also generated by acquiring and marketing crude oil. Generally, crude oil purchases are entered into in contemplation of or simultaneously with corresponding sale transactions involving physical deliveries, which enables us to secure a profit on the transaction at the time of purchase.
Trends and Outlook
See information previously included in our Form 10-K filed on February 24, 2017 and Form 8-K filed on May 8, 2017.
Results of Operations
We report Segment Adjusted EBITDA as a measure of segment performance. We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership.
When presented on a consolidated basis, Adjusted EBITDA is a non-GAAP measure. Although we include Segment Adjusted EBITDA in this report, we have not included an analysis of the consolidated measure, Adjusted EBITDA. We have included a total of Segment Adjusted EBITDA for all segments, which is reconciled to the GAAP measure of net income in the consolidated results sections that follow.


18


Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015
Consolidated Results
 
Years Ended December 31,
 
 
 
2016
 
2015
 
Change
Segment Adjusted EBITDA:
 
 
 
 
 
Intrastate transportation and storage
$
613

 
$
543

 
$
70

Interstate transportation and storage
1,117

 
1,155

 
(38
)
Midstream
1,133

 
1,237

 
(104
)
NGL and refined products transportation and services
1,483

 
1,225

 
258

Crude oil transportation and services
719

 
671

 
48

All other
540

 
883

 
(343
)
Total
5,605

 
5,714

 
(109
)
Depreciation, depletion and amortization
(1,986
)
 
(1,929
)
 
(57
)
Interest expense, net
(1,317
)
 
(1,291
)
 
(26
)
Gains on acquisitions
83

 

 
83

Impairment losses
(813
)
 
(339
)
 
(474
)
Losses on interest rate derivatives
(12
)
 
(18
)
 
6

Non-cash unit-based compensation expense
(80
)
 
(79
)
 
(1
)
Unrealized losses on commodity risk management activities
(131
)
 
(65
)
 
(66
)
Inventory valuation adjustments
170

 
(104
)
 
274

Losses on extinguishments of debt

 
(43
)
 
43

Adjusted EBITDA related to unconsolidated affiliates
(946
)
 
(937
)
 
(9
)
Equity in earnings of unconsolidated affiliates
59

 
469

 
(410
)
Impairment of investment in an unconsolidated affiliate
(308
)
 

 
(308
)
Other, net
114

 
20

 
94

Income before income tax benefit
438

 
1,398

 
(960
)
Income tax benefit
186

 
123

 
63

Net income
$
624

 
$
1,521

 
$
(897
)
See the detailed discussion of Segment Adjusted EBITDA below.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased primarily due to increases from assets recently placed in service, partially offset by a decrease of $191 million related to the deconsolidation of Sunoco, LLC and the legacy Sunoco, Inc. retail business.
Gains on Acquisitions. Gains on acquisitions include gains of $83 million in connection with recent acquisitions during 2016, including $41 million related to Sunoco Logistics’ acquisition of the remaining interest in SunVit.
Impairment Losses. In 2016, we recorded goodwill impairments of $638 million in the interstate transportation and storage segment and $32 million in the midstream segment. These goodwill impairments were primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve. In addition, impairment losses for 2016 also include a $133 million impairment to property, plant and equipment in the interstate transportation and storage segment due to a decrease in projected future cash flows as well as a $10 million impairment to property, plant and equipment in the midstream segment. In 2015, we recorded goodwill impairments of (i) $99 million related to Transwestern due primarily to the market declines in current and expected future commodity prices in the fourth quarter of 2015, (ii) $106 million related to Lone Star Refinery Services due primarily to changes in assumptions related to potential future revenues as well as the market declines in current and expected future commodity prices, (iii) $110 million of fixed asset impairments related to Lone Star NGL Refinery Services primarily due to the economic obsolescence identified as a result of low utilization and expected decrease in future cash flows, and (iv) $24 million of intangible asset impairments related to Lone Star NGL Refinery Services primarily due to the economic obsolescence identified as a result of expected decrease in future cash flows.


19


Losses on Interest Rate Derivatives. Our interest rate derivatives are not designated as hedges for accounting purposes; therefore, changes in fair value are recorded in earnings each period. Losses on interest rate derivatives during the years ended December 31, 2016 and 2015 resulted from decreases in forward interest rates, which caused our forward-starting swaps to decrease in value.
Unrealized Losses on Commodity Risk Management Activities. See discussion of the unrealized gains (losses) on commodity risk management activities included in “Segment Operating Results” below.
Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recorded for the inventory associated with Sunoco Logistics’ crude oil, NGLs and refined products inventories as a result of commodity price changes between periods.
Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. See additional information in “Supplemental Information on Unconsolidated Affiliates” and “Segment Operation Results” below.
Impairment of Investment in an Unconsolidated Affiliate. In 2016, the Partnership impaired its investment in MEP and recorded a non-cash impairment loss of $308 million based on commercial discussions with current and potential shippers on MEP regarding the outlook for long-term transportation contract rates.
Other, net. Other, net in 2016 and 2015 primarily includes amortization of regulatory assets and other income and expense amounts.
Income Tax Benefit. For the years ended December 31, 2016 and 2015, the Partnership recorded an income tax benefit due to pre-tax losses at its corporate subsidiaries. The year ended December 31, 2015 also reflected a benefit of $24 million of net state tax benefit attributable to statutory state rate changes resulting from the Regency Merger and sale of Susser to Sunoco LP, as well as a favorable impact of $11 million due to a reduction in the statutory Texas franchise tax rate which was enacted by the Texas legislature during the second quarter of 2015.


20


Supplemental Information on Unconsolidated Affiliates
The following table presents financial information related to unconsolidated affiliates:
 
Years Ended December 31,
 
 
 
2016
 
2015
 
Change
Equity in earnings (losses) of unconsolidated affiliates:
 
 
 
 
 
Citrus
$
102

 
$
97

 
$
5

FEP
51

 
55

 
(4
)
PES
(26
)
 
52

 
(78
)
MEP
40

 
45

 
(5
)
HPC
31

 
32

 
(1
)
AmeriGas
14

 
(3
)
 
17

Sunoco, LLC

 
(10
)
 
10

Sunoco LP(1)
(211
)
 
202

 
(413
)
Other
58

 
(1
)
 
59

Total equity in earnings of unconsolidated affiliates
$
59

 
$
469

 
$
(410
)
 
 
 
 
 
 
Adjusted EBITDA related to unconsolidated affiliates(2):
 
 
 
 
 
Citrus
$
329

 
$
315

 
$
14

FEP
75

 
75

 

PES
10

 
86

 
(76
)
MEP
90

 
96

 
(6
)
HPC
61

 
61

 

Sunoco, LLC

 
91

 
(91
)
Sunoco LP
271

 
137

 
134

Other
110

 
76

 
34

Total Adjusted EBITDA related to unconsolidated affiliates
$
946

 
$
937

 
$
9

 
 
 
 
 
 
Distributions received from unconsolidated affiliates:
 
 
 
 
 
Citrus
$
144

 
$
182

 
$
(38
)
FEP
65

 
69

 
(4
)
PES

 
78

 
(78
)
MEP
74

 
80

 
(6
)
HPC
51

 
52

 
(1
)
AmeriGas
12

 
11

 
1

Sunoco LP
138

 
39

 
99

Other
57

 
53

 
4

Total distributions received from unconsolidated affiliates
$
541

 
$
564

 
$
(23
)
(1) 
For the year ended December 31, 2016, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by Sunoco LP, which reduced the Partnership’s equity in earnings by $277 million.
(2) 
These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.
Segment Operating Results
Our reportable segments are discussed below. “All other” includes our compression operations, our investment in AmeriGas, our approximate 33% non-operating interest in PES, our investment in Coal Handling and our natural gas marketing operations.


21


Additionally, due to the transfer of the general partner interest of Sunoco LP from ETP to ETE in 2015 and completion of the dropdown of remaining Retail Marketing interests from ETP to Sunoco LP in March 2016, the Partnership’s retail marketing segment has been deconsolidated, and the segment results now reflect an equity method investment in limited partnership units of Sunoco LP. As of December 31, 2016, the Partnership’s interest in Sunoco LP common units consisted of 43.5 million units, representing 44.3% of Sunoco LP’s total outstanding common units, and is reflected in the all other segment.
We evaluate segment performance based on Segment Adjusted EBITDA, which we believe is an important performance measure of the core profitability of our operations. This measure represents the basis of our internal financial reporting and is one of the performance measures used by senior management in deciding how to allocate capital resources among business segments.
The tables below identify the components of Segment Adjusted EBITDA, which is calculated as follows:
Segment margin, operating expenses, and selling, general and administrative expenses. These amounts represent the amounts included in our consolidated financial statements that are attributable to each segment.
Unrealized gains or losses on commodity risk management activities and inventory valuation adjustments. These are the unrealized amounts that are included in cost of products sold to calculate segment margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized losses are added back and the unrealized gains are subtracted to calculate the segment measure.
Non-cash compensation expense. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate the segment measure.
Adjusted EBITDA related to unconsolidated affiliates. These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates. Amounts reflected are calculated consistently with our definition of Adjusted EBITDA.
In the following analysis of segment operating results, a measure of segment margin is reported for segments with sales revenues. Segment Margin is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment Margin is similar to the GAAP measure of gross margin, except that Segment Margin excludes charges for depreciation, depletion and amortization.
In addition, for certain segments, the sections below include information on the components of Segment Margin by sales type, which components are included in order to provide additional disaggregated information to facilitate the analysis of Segment Margin and Segment Adjusted EBITDA. For example, these components include transportation margin, storage margin, and other margin. These components of Segment Margin are calculated consistent with the calculation of Segment Margin; therefore, these components also exclude charges for depreciation, depletion and amortization.
For additional information regarding our business segments, see “Item 1. Business” and Notes 1 and 15 to our consolidated financial statements.


22


Following is a reconciliation of Segment Margin to operating income, as reported in the Partnership’s consolidated statements of operations:
 
Years Ended December 31,
 
2016
 
2015
Segment Margin by segment:
 
 
 
Intrastate transportation and storage
$
716

 
$
696

Interstate transportation and storage
969

 
1,025

Midstream
1,798

 
1,792

NGL and refined products transportation and services
1,944

 
1,660

Crude oil transportation and services
1,156

 
821

All other
330

 
1,745

Intersegment eliminations
(480
)
 
(476
)
Total Segment Margin
6,433

 
7,263

 
 
 
 
Less:
 
 
 
Operating expenses
1,484

 
2,261

Depreciation, depletion and amortization
1,986

 
1,929

Selling, general and administrative
348

 
475

Impairment losses
813

 
339

Operating income
$
1,802

 
$
2,259


Intrastate Transportation and Storage
 
Years Ended December 31,
 
 
 
2016
 
2015
 
Change
Natural gas transported (MMBtu/d)
8,257,611

 
8,426,818

 
(169,207
)
Revenues
$
2,613

 
$
2,250

 
$
363

Cost of products sold
1,897

 
1,554

 
343

Segment margin
716

 
696

 
20

Unrealized (gains) losses on commodity risk management activities
19

 
(26
)
 
45

Operating expenses, excluding non-cash compensation expense
(162
)
 
(163
)
 
1

Selling, general and administrative expenses, excluding non-cash compensation expense
(22
)
 
(25
)
 
3

Adjusted EBITDA related to unconsolidated affiliates
61

 
61

 

Other
1

 

 
1

Segment Adjusted EBITDA
$
613

 
$
543

 
$
70

Volumes.  For the year ended December 31, 2016 compared to the prior year, transported volumes decreased primarily due to lower production volumes in the Barnett Shale region, partially offset by increased volumes related to significant new long-term transportation contracts, as well as the addition of a new short-haul transport pipeline delivering volumes into our Houston Pipeline system.


23


Segment Margin.  The components of our intrastate transportation and storage segment margin were as follows:
 
Years Ended December 31,
 
 
 
2016
 
2015
 
Change
Transportation fees
$
505

 
$
502

 
$
3

Natural gas sales and other
113

 
96

 
17

Retained fuel revenues
48

 
57

 
(9
)
Storage margin, including fees
50

 
41

 
9

Total segment margin
$
716

 
$
696

 
$
20

Segment Adjusted EBITDA. For the year ended December 31, 2016 compared to the prior year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impacts of the following:
an increase of $3 million in transportation fees, despite lower throughput volumes, due to fees from renegotiated and newly initiated fixed fee contracts primarily on our Houston Pipeline system;
an increase of $34 million in natural gas sales (excluding changes in unrealized losses of $17 million) primarily due to higher realized gains from the buying and selling of gas along our system;
a decrease of $9 million from the sale of retained fuel, primarily due to lower market prices and lower volumes. The average spot price at the Houston Ship Channel location decreased 5% for the year ended December 31, 2016 compared to the prior year;
an increase of $37 million in storage margin (excluding net changes in unrealized amounts of $28 million related to fair value inventory adjustments and unrealized gains and losses on derivatives), as discussed below; and
a decrease of $3 million in general and administrative expenses primarily due to lower legal fees and insurance costs, as well as allocations between segments.
Storage margin was comprised of the following:
 
Years Ended December 31,
 
 
 
2016
 
2015
 
Change
Withdrawals from storage natural gas inventory (MMBtu)
38,905,000

 
15,782,500

 
23,122,500

Realized margin on natural gas inventory transactions
$
36

 
$
(2
)
 
$
38

Fair value inventory adjustments
76

 
4

 
72

Unrealized (gains) losses on derivatives
(87
)
 
12

 
(99
)
Margin recognized on natural gas inventory, including related derivatives
25

 
14

 
11

Revenues from fee-based storage
25

 
27

 
(2
)
Total storage margin
$
50

 
$
41

 
$
9

The changes in storage margin were primarily driven by the timing of withdrawals and sales of natural gas from our Bammel storage cavern, as well as the timing of settlement of related derivative hedging contracts.


24


Interstate Transportation and Storage
 
Years Ended December 31,
 
 
 
2016
 
2015
 
Change
Natural gas transported (MMBtu/d)
5,475,948

 
6,074,282

 
(598,334
)
Natural gas sold (MMBtu/d)
18,842

 
17,340

 
1,502

Revenues
$
969

 
$
1,025

 
$
(56
)
Operating expenses, excluding non-cash compensation, amortization and accretion expenses
(302
)
 
(304
)
 
2

Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses
(47
)
 
(52
)
 
5

Adjusted EBITDA related to unconsolidated affiliates
494

 
486

 
8

Other
3

 

 
3

Segment Adjusted EBITDA
$
1,117

 
$
1,155

 
$
(38
)
Volumes. For the year ended December 31, 2016 compared to the prior year, transported volumes decreased 423,564 MMBtu/d on the Trunkline pipeline due to the transfer of one of the pipelines at Trunkline which was repurposed from natural gas service to crude oil service and lower utilization resulting from lower customer demand. Transported volumes decreased 82,018 MMBtu/d on the Transwestern pipe line due to milder weather in the West and decreased 76,373 MMBtu/d on the Sea Robin pipeline due to reduced supply as a result of producer system maintenance and overall lower production.
Segment Adjusted EBITDA. For the year ended December 31, 2016 compared to the prior year, Segment Adjusted EBITDA related to our interstate transportation and storage segment decreased due to the net impacts of the following:
a decrease of $26 million in revenues due to contract restructuring on the Tiger pipeline, a decrease of $17 million due to lower reservation revenues on the Panhandle and Trunkline pipelines from capacity sold at lower rates and lower sales of capacity in the Phoenix and San Juan areas on the Transwestern pipeline, a decrease of $14 million due to the transfer of one of the Trunkline pipelines which was repurposed from natural gas service to crude oil service, a decrease of $11 million due to the expiration of a transportation rate schedule on the Transwestern pipeline, and a decrease of $10 million on the Sea Robin pipeline due to declines in production and third-party maintenance. These decreases were partially offset by higher reservation revenues on the Transwestern pipeline of $18 million, primarily from a growth project, and higher parking revenues of $9 million, primarily on the Panhandle and Trunkline pipelines; partially offset by
an increase of $8 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to higher margins from sales of additional capacity on Citrus of $6 million and lower operating expenses of $5 million, offset by lower margins on the Midcontinent Express pipeline of $4 million due to a customer bankruptcy;
a decrease of $2 million in operating expenses primarily due to lower maintenance project costs of $5 million and lower allocated costs of $3 million. These decreases were partially offset by an increase of $7 million in ad valorem tax expense due to higher current year assessments of $2 million and a prior period credit and settlement of ad valorem taxes in 2015 of $5 million;
a decrease of $5 million in selling, general and administrative expenses primarily due to $5 million in lower allocated costs; and
an increase of $3 million in other primarily due to the tax gross-up associated with reimbursable projects on the Transwestern and Panhandle pipelines.


25


Midstream
 
Years Ended December 31,
 
 
 
2016
 
2015
 
Change
Gathered volumes (MMBtu/d)
9,813,660

 
9,981,212

 
(167,552
)
NGLs produced (Bbls/d)
437,730

 
406,149

 
31,581

Equity NGLs (Bbls/d)
31,131

 
28,493

 
2,638

Revenues
$
5,179

 
$
5,056

 
$
123

Cost of products sold
3,381

 
3,264

 
117

Segment margin
1,798

 
1,792

 
6

Unrealized losses on commodity risk management activities
15

 
82

 
(67
)
Operating expenses, excluding non-cash compensation expense
(621
)
 
(616
)
 
(5
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(84
)
 
(44
)
 
(40
)
Adjusted EBITDA related to unconsolidated affiliates
24

 
20

 
4

Other
1

 
3

 
(2
)
Segment Adjusted EBITDA
$
1,133

 
$
1,237

 
$
(104
)
Volumes. Gathered volumes decreased during the year ended December 31, 2016 compared to the prior year primarily due to declines in the South Texas, North Texas, and Mid-Continent/Panhandle regions, partially offset by increases in the Permian region and the impact of recent acquisitions, including PennTex. NGL production increased due to increased gathering and processing capacities in the Permian region, partially offset by declines in the South Texas, North Texas, and Mid-Continent/Panhandle regions.
Segment Margin.  The components of our midstream segment margin were as follows:
 
Years Ended December 31,
 
 
 
2016
 
2015
 
Change
Gathering and processing fee-based revenues
$
1,554

 
$
1,570

 
$
(16
)
Non fee-based contracts and processing
244

 
222

 
22

Total segment margin
$
1,798

 
$
1,792

 
$
6

Segment Adjusted EBITDA. For the year ended December 31, 2016 compared to the prior year, Segment Adjusted EBITDA related to our midstream segment decreased due to the net impacts of the following:
a decrease of $16 million in fee-based margin due to volume declines in the South Texas, North Texas, and Mid-Continent/Panhandle regions, partially offset by increased gathering and processing volumes in the Permian region and the impact of recent acquisitions, including PennTex and the King Ranch assets;
an increase of $40 million in general and administrative expenses primarily due to costs associated with the acquisition of PennTex and changes in capitalized overhead and accruals;
an increase of $5 million in operating expenses primarily due to the King Ranch acquisition in the second quarter of 2015 and assets recently placed in service in the Permian and Eagle Ford regions; and
a decrease of $92 million (excluding unrealized gains of $67 million) in non fee-based margin due to lower benefit from settled derivatives used to hedge commodity margins; partially offset by
an increase of $44 million in non fee-based margin due to volume increases in the Permian region, partially offset by volume declines in the South Texas, North Texas, and Mid-Continent/Panhandle regions; and
an increase of $3 million in non fee-based margin due to higher crude oil and NGL prices, partially offset by lower natural gas prices.




26


NGL and Refined Products Transportation and Services
 
Years Ended December 31,
 
 
 
2016
 
2015
 
Change
Revenues
$
6,535

 
$
5,118

 
$
1,417

Cost of products sold
4,591

 
3,458

 
1,133

Segment margin
1,944

 
1,660

 
284

Unrealized losses on commodity risk management activities
69

 
10

 
59

Operating expenses, excluding non-cash compensation expense
(520
)
 
(469
)
 
(51
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(56
)
 
(55
)
 
(1
)
Inventory valuation adjustments
(22
)
 
12

 
(34
)
Adjusted EBITDA related to unconsolidated affiliates
67

 
67

 

Other
1

 

 
1

Segment Adjusted EBITDA
$
1,483

 
$
1,225

 
$
258

Segment Adjusted EBITDA. For the year ended December 31, 2016 compared to the prior year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impacts of the following:
an increase of $209 million related to legacy ETP’s NGLs operations, as follows:
an increase of $36 million in storage margin primarily due to increased volumes from our Mont Belvieu fractionators. Throughput volumes, on which we earn a fee in our storage assets, increased 34% resulting in an increase of $18 million year over year. We also realized an increase of $8 million due to increased demand for our leased storage capacity as a result of more favorable market conditions. Finally, we realized increased terminal fees and pipeline lease fees of $8 million, as well as increased blending gains of $2 million resulting from higher volumes during the 2016 period;
an increase of $80 million in legacy ETP’s NGL transportation fees due to higher NGL transport volumes from all producing regions, with the Permian region being the most significant among them; and
an increase of $107 million in legacy ETP’s NGL processing and fractionation margin (excluding an increase in unrealized losses of $11 million) primarily due to higher NGL volumes from all producing regions, as detailed in our transport fees explanation above. We placed approximately 118,000bbls/d of fractionation capacity in-service in 2016, allowing our Mont Belvieu fractionators to handle the significant increase in volumes from year to year. Additional barrels fractionated and an associated increase in blending gains at our fractionators resulted in a margin increase of $101 million. We delivered approximately 26% more barrels to our Mariner South LPG export terminal in the 2016 period, which resulted in an increase of $22 million in cargo loading fees and blending fees year over year. These gains were offset by an increase in storage fees paid of $2 million, and a decrease in margin from our refinery services segment of $3 million; partially offset by
a decrease of $24 million in other margin due to the timing of the withdrawal and sale of NGL component product inventory; and
an increase of $20 million in legacy ETP’s operating expenses primarily due to increased costs associated with our third fractionator at Mont Belvieu and higher ad valorem expenses, partially offset by lower project related expenses. The remainder of the increase in operating expenses in the table above is related to legacy Sunoco Logistics’ NGLs and refined products operations, the results of which are discussed separately below;
an increase of $65 million in Adjusted EBITDA from legacy Sunoco Logistics’ refined products operations driven primarily by improved operating results from refined products pipelines of $32 million, which benefited from higher volumes on Allegheny Access pipeline, and higher results from refined products acquisition and marketing activities of $21 million. Improved contributions from refined product joint venture interests of $6 million and higher earnings attributable to refined products terminals of $5 million also contributed to the increase; partially offset by
a decrease in Adjusted EBITDA from legacy Sunoco Logistics’ NGLs operations of $16 million, largely attributable to lower operating results from our NGLs acquisition and marketing activities of $106 million due to lower volumes and margins compared to the prior year. These factors were largely offset by increased volumes and fees from our Mariner NGLs projects of $90 million, which includes our NGLs pipelines and Marcus Hook and Nederland facilities.


27


Crude Oil Transportation and Services
 
Years Ended December 31,
 
 
 
2016
 
2015
 
Change
Revenue
$
7,896

 
$
9,267

 
$
(1,371
)
Cost of products sold
6,740

 
8,446

 
(1,706
)
Segment margin
1,156

 
821

 
335

Unrealized losses on commodity risk management activities
2

 

 
2

Operating expenses, excluding non-cash compensation expense
(247
)
 
(245
)
 
(2
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(58
)
 
(53
)
 
(5
)
Inventory valuation adjustments
(148
)
 
150

 
(298
)
Adjusted EBITDA related to unconsolidated affiliates
14

 
(2
)
 
16

Segment Adjusted EBITDA
$
719

 
$
671

 
$
48

Segment Adjusted EBITDA. For the year ended December 31, 2016 compared to the prior year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impacts of the following:
an increase of $20 million in crude transport fees, primarily resulting from placing in-service the first phase of the Bayou Bridge pipeline in April 2016, and from placing crude gathering assets in West Texas in-service during the 2016 period; and
an increase of $31 million from legacy Sunoco Logistics’ crude oil operations, primarily due to improved results from our crude oil pipelines of $155 million which benefited from the expansion capital projects which commenced operations in 2016 and 2015, and the fourth quarter 2016 acquisition from Vitol, including the remaining interest in SunVit. Higher results from our crude oil terminals of $31 million, largely related to Nederland facility, and improved contributions from crude oil joint venture interests of $16 million also contributed to the increase. These positive factors were largely offset by a decrease in operating results from our crude oil acquisition and marketing activities of $166 million, which includes transportation and storage fees related to our crude oil pipelines and terminal facilities, due to lower crude oil differentials and decreased volumes compared to the prior year.

All Other
 
Years Ended December 31,
 
 
 
2016
 
2015
 
Change
Revenue
$
3,272

 
$
15,774

 
$
(12,502
)
Cost of products sold
2,942

 
14,029

 
(11,087
)
Segment margin
330

 
1,745

 
(1,415
)
Unrealized (gains) losses on commodity risk management activities
26

 
(1
)
 
27

Operating expenses, excluding non-cash compensation expense
(79
)
 
(896
)
 
817

Selling, general and administrative expenses, excluding non-cash compensation expense
(86
)
 
(254
)
 
168

Adjusted EBITDA related to unconsolidated affiliates
286

 
313

 
(27
)
Inventory valuation adjustments

 
(58
)
 
58

Other
95

 
95

 

Elimination
(32
)
 
(61
)
 
29

Segment Adjusted EBITDA
$
540

 
$
883

 
$
(343
)
Amounts reflected in our all other segment primarily include:
our retail marketing operations prior to the transfer of the general partner interest of Sunoco LP from ETP to ETE in 2015 and completion of the dropdown of remaining Retail Marketing interests from ETP to Sunoco LP in March 2016;


28


our equity method investment in limited partnership units of Sunoco LP consisting of 43.5 million units, representing 44.3% of Sunoco LP’s total outstanding common units;
our natural gas marketing and compression operations;
a non-controlling interest in PES, comprising 33% of PES’ outstanding common units; and
our investment in Coal Handling, an entity that owns and operates end-user coal handling facilities.
Segment Adjusted EBITDA. For the year ended December 31, 2016 compared to the prior year, Segment Adjusted EBITDA decreased due to the net impact of the following:
a decrease of $308 million due to the transfer and contribution of our retail marketing assets to Sunoco LP. The consolidated results of Sunoco LP are reflected in the results for All Other above through June 2015. Effective July 1, 2015, Sunoco LP was deconsolidated, and the results for All Other reflect Adjusted EBITDA related to unconsolidated affiliates for our limited partner interests in Sunoco LP. The impact of the deconsolidation of Sunoco LP reduced segment margin, operating expenses and selling, general and administrative expenses; the impact to Segment Adjusted EBITDA is offset by the incremental Adjusted EBITDA related to unconsolidated affiliates from our equity method investment in Sunoco LP subsequent to the deconsolidation; and
a decrease of $76 million in Adjusted EBITDA related to our investment in PES.
ETP provides management services for ETE for which ETE has agreed to pay management fees to ETP of $95 million per year for the years ending December 31, 2016 and 2015. These fees were reflected in “Other” in the “All other” segment and for the years ended December 31, 2016 and 2015 were reflected as an offset to operating expenses of $32 million and selling, general and administrative expenses of $63 million in the consolidated statements of operations.


29


Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014
Consolidated Results
 
Years Ended December 31,
 
 
 
2015
 
2014
 
Change
Segment Adjusted EBITDA:
 
 
 
 
 
Intrastate transportation and storage
$
543

 
$
559

 
$
(16
)
Interstate transportation and storage
1,155

 
1,212

 
(57
)
Midstream
1,237

 
1,318

 
(81
)
NGL and refined products transportation and services
1,225

 
891

 
334

Crude oil transportation and services
671

 
671

 

All other
883

 
1,059

 
(176
)
Total
5,714

 
5,710

 
4

Depreciation, depletion and amortization
(1,929
)
 
(1,669
)
 
(260
)
Interest expense, net
(1,291
)
 
(1,165
)
 
(126
)
Gain on sale of AmeriGas common units

 
177

 
(177
)
Impairment losses
(339
)
 
(370
)
 
31

Losses on interest rate derivatives
(18
)
 
(157
)
 
139

Non-cash compensation expense
(79
)
 
(68
)
 
(11
)
Unrealized gains (losses) on commodity risk management activities
(65
)
 
112

 
(177
)
Inventory valuation adjustments
(104
)
 
(473
)
 
369

Losses on extinguishments of debt
(43
)
 
(25
)
 
(18
)
Adjusted EBITDA related to discontinued operations

 
(27
)
 
27

Adjusted EBITDA related to unconsolidated affiliates
(937
)
 
(748
)
 
(189
)
Equity in earnings of unconsolidated affiliates
469

 
332

 
137

Other, net
20

 
(36
)
 
56

Income from continuing operations before income tax (expense) benefit
1,398

 
1,593

 
(195
)
Income tax (expense) benefit from continuing operations
123

 
(358
)
 
481

Income from continuing operations
1,521

 
1,235

 
286

Income from discontinued operations

 
64

 
(64
)
Net income
$
1,521

 
$
1,299

 
$
222

See the detailed discussion of Segment Adjusted EBITDA below.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased primarily due to additional depreciation from assets recently placed in service and recent acquisitions, including Regency’s acquisitions in 2014.
Gain on Sale of AmeriGas Common Units. During the year ended December 31, 2014 we sold 18.9 million the AmeriGas common units that were originally received in connection with the contribution of our propane business to AmeriGas in January 2012. We recorded a gain based on the sale proceeds in excess of the carrying amount of the units sold. As of December 31, 2015, the Partnership’s remaining interest in AmeriGas common units consisted of 3.1 million units held by a wholly-owned captive insurance company.
Impairment Losses. In 2015, we recorded goodwill impairments of (i) $99 million related to Transwestern due primarily to the market declines in current and expected future commodity prices in the fourth quarter of 2015, (ii) $106 million related to Lone Star Refinery Services due primarily to changes in assumptions related to potential future revenues as well as the market declines in current and expected future commodity prices, (iii) $110 million of fixed asset impairments related to Lone Star NGL Refinery Services primarily due to the economic obsolescence identified as a result of low utilization and expected decrease in future cash flows, and (iv) $24 million of intangible asset impairments related to Lone Star NGL Refinery Services primarily due to the economic obsolescence identified as a result of expected decrease in future cash flows. In 2014, a $370 million goodwill impairment was recorded related to the Permian Basin gathering and processing operations. The decline in estimated fair value of that reporting


30


unit was primarily driven by a significant decline in commodity prices in the fourth quarter of 2014, and the resulting impact to future commodity prices as well as increases in future estimated operations and maintenance expenses.
Losses on Interest Rate Derivatives. Our interest rate derivatives are not designated as hedges for accounting purposes; therefore, changes in fair value are recorded in earnings each period. Losses on interest rate derivatives during the years ended December 31, 2015 and 2014 resulted from decreases in forward interest rates, which caused our forward-starting swaps to decrease in value.
Unrealized Gains (Losses) on Commodity Risk Management Activities. See discussion of the unrealized gains (losses) on commodity risk management activities included in “Segment Operating Results” below.
Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recorded for the inventory associated with Sunoco Logistics’ crude oil, NGLs and refined products inventories as a result of commodity price changes between periods.
Adjusted EBITDA Related to Discontinued Operations. In 2014, amounts were related to a marketing business that was sold effective April 1, 2014.
Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. See additional information in “Supplemental Information on Unconsolidated Affiliates” and “Segment Operation Results” below.
Other, net. Other, net in 2015 and 2014 primarily includes amortization of regulatory assets and other income and expense amounts.
Income Tax (Expense) Benefit from Continuing Operations. For the year ended December 31, 2015, the Partnership’s effective income tax rate decreased from the prior year primarily due to lower earnings among the Partnership’s consolidated corporate subsidiaries.  The year ended December 31, 2015 also reflected a benefit of $24 million of net state tax benefit attributable to statutory state rate changes resulting from the Regency Merger and sale of Susser to Sunoco LP, as well as a favorable impact of $11 million due to a reduction in the statutory Texas franchise tax rate which was enacted by the Texas legislature during the second quarter of 2015. For the year ended December 31, 2014, the Partnership’s income tax expense from continuing operations included unfavorable income tax adjustments of $87 million related to the Lake Charles LNG Transaction, which was treated as a sale for tax purposes.


31


Supplemental Information on Unconsolidated Affiliates
The following table presents financial information related to unconsolidated affiliates:
 
Years Ended December 31,
 
 
 
2015
 
2014
 
Change
Equity in earnings (losses) of unconsolidated affiliates:
 
 
 
 
 
Citrus
$
97

 
$
96

 
$
1

FEP
55

 
55

 

PES
52

 
59

 
(7
)
MEP
45

 
45

 

HPC
32

 
28

 
4

AmeriGas
(3
)
 
21

 
(24
)
Sunoco, LLC
(10
)
 

 
(10
)
Sunoco LP
202

 

 
202

Other
(1
)
 
28

 
(29
)
Total equity in earnings of unconsolidated affiliates
$
469

 
$
332

 
$
137

 
 
 
 
 
 
Adjusted EBITDA related to unconsolidated affiliates(1):
 
 
 
 
 
Citrus
$
315

 
$
305

 
$
10

FEP
75

 
75

 

PES
86

 
86

 

MEP
96

 
102

 
(6
)
HPC
61

 
53

 
8

AmeriGas

 
56

 
(56
)
Sunoco, LLC
91

 

 
91

Sunoco LP
137

 

 
137

Other
76

 
71

 
5

Total Adjusted EBITDA related to unconsolidated affiliates
$
937

 
$
748

 
$
189

 
 
 
 
 
 
Distributions received from unconsolidated affiliates:
 
 
 
 
 
Citrus
$
182

 
$
168

 
$
14

FEP
69

 
70

 
(1
)
PES
78

 

 
78

MEP
80

 
73

 
7

HPC
52

 
48

 
4

AmeriGas
11

 
28

 
(17
)
Sunoco LP
39