EX-99.1 4 ex991-ete12x31x201610k.htm EXHIBIT 99.1
Table of Contents
TABLE OF CONTENTS

PART I
|  | PAGE
ITEM 1. | BUSINESS | 1
PART II
ITEM 6. | SELECTED FINANCIAL DATA | 19
ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | 19
ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA | 44

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Forward-Looking Statements
Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Equity, L.P. (the “Partnership” or “ETE”) 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,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “continue,” “could,” “believe,” “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, estimated, projected, forecasted, expressed or expected 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 1.A Risk Factors” included in the Partnership’s Annual Report on Form 10-K that was filed on February 24, 2017.
Definitions
The following is a list of certain acronyms and terms generally used in the energy industry and throughout this document:

/d |  | per day
Aloha |  | Aloha Petroleum, Ltd
AmeriGas |  | AmeriGas Partners, L.P.
AOCI |  | accumulated other comprehensive income (loss)
AROs |  | asset retirement obligations
Bbls |  | barrels
Bcf |  | billion cubic feet
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 content
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 which owns 100% of FGT
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
ETG |  | Energy Transfer Group, L.L.C.
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

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ETP |  | Energy Transfer Partners, L.P.
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
ETP Preferred Units |  | ETP’s Series A Convertible Preferred Units,
Exchange Act |  | Securities Exchange Act of 1934
FDOT/FTE |  | Florida Department of Transportation, Florida’s Turnpike Enterprise
FEP |  | Fayetteville Express Pipeline LLC
FERC |  | Federal Energy Regulatory Commission
FGT |  | Florida Gas Transmission Company, LLC, which owns a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula
GAAP |  | accounting principles generally accepted in the United States of America
General Partner |  | LE GP, LLC, the general partner of ETE
HPC |  | RIGS Haynesville Partnership Co. and its wholly-owned subsidiary, Regency Intrastate Gas LP
HOLP |  | Heritage Operating, L.P.
Hoover |  | Hoover Energy Partners, LP
IDRs |  | incentive distribution rights
KMI |  | Kinder Morgan Inc.
Lake Charles LNG |  | Lake Charles LNG Company, LLC
LCL |  | Lake Charles LNG Export Company, LLC
LIBOR |  | London Interbank Offered Rate
LNG |  | liquefied natural gas
LNG Holdings |  | Lake Charles LNG Holdings, LLC
LPG |  | liquefied petroleum gas
Lone Star |  | Lone Star NGL LLC
MACS |  | Mid-Atlantic Convenience Stores, LLC
MEP |  | Midcontinent Express Pipeline LLC
MLP Merger |  | The merger of Sunoco Logistics with and into ETP, with ETP surviving the merger as a wholly owned subsidiary of Sunoco Logistics
MMBtu |  | million British thermal units
MMcf |  | million cubic feet
MTBE |  | methyl tertiary butyl ether
NGA |  | Natural Gas Act of 1938
NGPA |  | Natural Gas Policy Act of 1978
NGL |  | natural gas liquid, such as propane, butane and natural gasoline
NYMEX |  | New York Mercantile Exchange
NYSE |  | New York Stock Exchange
OSHA |  | Federal Occupational Safety and Health Act
OTC |  | over-the-counter

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Panhandle |  | Panhandle Eastern Pipe Line Company, LP and its subsidiaries
PCBs |  | polychlorinated biphenyls
PEPL |  | Panhandle Eastern Pipe Line Company, LP
PennTex |  | PennTex Midstream Partners, LP
PES |  | Philadelphia Energy Solutions
PHMSA |  | Pipeline Hazardous Materials Safety Administration
PropCo |  | Susser Petroleum Property Company LLC
PVR |  | PVR Partners, L.P.
RIGS |  | Regency Intrastate Gas System
RGS |  | Regency Gas Services, a wholly-owned subsidiary of Regency
Ranch JV |  | Ranch Westex JV LLC
Regency |  | Regency Energy Partners LP
Regency Preferred Units |  | Regency’s Series A Convertible Preferred Units, the Preferred Units of a Subsidiary
Retail Holdings |  | ETP Retail Holdings LLC, an indirect wholly-owned subsidiary of ETP
Sea Robin |  | Sea Robin Pipeline Company, LLC
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
TCEQ |  | Texas Commission on Environmental Quality
Transwestern |  | Transwestern Pipeline Company, LLC
TRRC |  | Texas Railroad Commission
Trunkline |  | Trunkline Gas Company, LLC, a subsidiary of Panhandle
WMB |  | The Williams Companies, Inc.
WPZ |  | Williams Partners, L.P.
WTI |  | West Texas Intermediate Crude

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.
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PART I
ITEM 1. BUSINESS
Overview
See information previously included in our Form 10-K filed on February 24, 2017.
Organizational Structure
See information previously included in our Form 10-K filed on February 24, 2017.
Significant Achievements in 2016 and Beyond
See information previously included in our Form 10-K filed on February 24, 2017.
Business Strategy
See information previously included in our Form 10-K filed on February 24, 2017.
Segment Overview
Our reportable segments are as follows:
•Investment in ETP, including the consolidated operations of ETP;

• | Investment in Sunoco LP, including the consolidated operations of Sunoco LP;

• | Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and

• | Corporate and Other, including the activities of the Parent Company.

The businesses within these segments are described below. See Note 15 to our consolidated financial statements for additional financial information about our reportable segments.
Investment in ETP
ETP’s operations include the following:
Intrastate Transportation and Storage Operations
ETP’s 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 its intrastate transportation and storage operations, ETP owns and operates 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. ETP also owns 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, ETP owns the largest intrastate pipeline system in the United States with interconnects to Texas markets and to major consumption areas throughout the United States. ETP’s intrastate transportation and storage operations focus 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 its Oasis pipeline, its East Texas pipeline, its natural gas pipeline and storage assets that are referred to as the ET Fuel System, and its HPL System, which are described below.
ETP’s intrastate transportation and storage operations results are determined primarily by the amount of capacity its customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, 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.
ETP also generates 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 the HPL System. In addition, ETP’s intrastate transportation and storage operations generate revenues from fees charged for storing customers’ working natural gas in ETP’s storage facilities and from managing natural gas for its own account.
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Interstate Transportation and Storage Operations
ETP’s 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 its interstate transportation and storage operations, ETP directly owns and operates approximatel y 11,800 miles of interstate natural gas pipelines with approximately 10.3 Bcf/d of transportation capacity and has 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.
ETP’s interstate transportation and storage operations include 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.
ETP also owns 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.
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.
ETP is currently in the process of converting a portion of the Trunkline gas pipeline to crude oil transportation.
The results from ETP’s interstate transportation and storage operations are primarily derived from the fees ETP earns from natural gas transportation and storage services.
Midstream Operations
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 its midstream operations, ETP owns and operates 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. ETP’s midstream operations focus on the gathering, compression, treating, blending, and processing, of natural gas and its operations are currently concentrated in major producing basins and shales, including the Austin Chalk trend
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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, and the Haynesville Shale in East Texas and Louisiana. Many of ETP’s midstream assets are integrated with its intrastate transportation and storage assets.
ETP’s midstream operations also include 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.
The results from ETP’s midstream operations are primarily derived from margins ETP earns for natural gas volumes that are gathered, transported, purchased and sold through ETP’s pipeline systems and the natural gas and NGL volumes processed at its processing and treating facilities.
NGL and Refined Products Transportation and Services Segment
ETP’s 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.
ETP’s 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 ETP’s NGL and propane fractionation facilities and 50 million Bbls of ETP’s 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, ETP owns and operates 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 ETP’s Nederland, Texas terminal facility and 3 million barrels at ETP’s Marcus Hook, Pennsylvania terminal facility (the “Marcus Hook Industrial Complex”). These operations also carry out ETP’s NGLs blending activities, including utilizing ETP’s 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.
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ETP’s 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. ETP’s marketing terminals are located primarily in the northeast, midwest and southwest United States, with approximately 8 million barrels of refined products storage capacity. ETP’s refined products operations include its Eagle Point facility in New Jersey, which has approximately 6 million barrels of refined products storage capacity. The operations also include ETP’s equity ownership interests in four refined products pipeline companies. The operations also perform terminalling activities at ETP’s Marcus Hook Industrial Complex. ETP’s 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
ETP’s 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. ETP’s crude oil terminalling services operates with an aggregate storage capacity of approximately 33 million barrels, including approximately 26 million barrels at ETP’s Gulf Coast terminal in Nederland, Texas and approximately 3 million barrels at ETP’s Fort Mifflin terminal complex in Pennsylvania. ETP’s crude oil acquisition and marketing activities utilize its pipeline and terminal assets, its 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.
ETP’s Other Operations and Investments
ETP’s other operations and investments include the following:

• | ETP owns an equity method investment in limited partner units of Sunoco LP consisting of 43.5 million units, representing 44.3% of Sunoco LP’s total outstanding common units.

• | ETP’s 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.

• | ETP conducts marketing operations in which it markets the natural gas that flows through its gathering and intrastate transportation assets, referred to as on-system gas. ETP also attracts other customers by marketing volumes of natural gas that do not move through its assets, referred to as off-system gas. For both on-system and off-system gas, ETP purchases natural gas from natural gas producers and other suppliers and sells 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, ETP purchases gas or acts as an agent for small independent producers that may not have marketing operations.

• | ETP owns 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.

• | ETP owns 100% of the membership interests of 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 ETP’s other operations.

• | ETP owns a 40% interest in the parent of LCL, which is developing a LNG liquefaction project.

• | ETP owns and operates a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems. ETP also owns and operates a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management.

• | ETP is involved in the management of coal and natural resources properties and the related collection of royalties. ETP also earns 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.

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

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Investment in Sunoco LP
Sunoco LP is engaged in the retail sale of motor fuels and merchandise through its company-operated convenience stores and retail fuel sites, as well as the wholesale distribution of motor fuels to convenience stores, independent dealers, commercial customers and distributors.
Wholesale Operations
Sunoco LP is a wholesale distributor of motor fuels and other petroleum products which Sunoco LP supplies to its retail operations, to third-party dealers and distributors, to independent operators of consignment locations and other consumers of motor fuel. Also included in the wholesale operations are transmix processing plants and refined products terminals. Transmix is the mixture of various refined products (primarily gasoline and diesel) created in the supply chain (primarily in pipelines and terminals) when various products interface with each other. Transmix processing plants separate this mixture and return it to salable products of gasoline and diesel.
Sunoco LP is the exclusive wholesale supplier of the iconic Sunoco branded motor fuel, supplying an extensive distribution network of approximately 5,335 Sunoco-branded company and third-party operated locations throughout the East Coast, Midwest and Southeast regions of the United States, including approximately 235 company operated Sunoco-branded locations in Texas. Sunoco LP believes it is one of the largest independent motor fuel distributors by gallons in Texas and one of the largest distributors of Chevron, Exxon, and Valero branded motor fuel in the United States. In addition to distributing motor fuels, Sunoco LP also distributes other petroleum products such as propane and lubricating oil, and Sunoco LP receives rental income from real estate that it leases or subleases.
Sunoco LP purchases motor fuel primarily from independent refiners and major oil companies and distribute it across more than 30 states throughout the East Coast, Midwest and Southeast regions of the United States, as well as Hawaii to approximately:

• | 1,345 company-operated convenience stores and fuel outlets;

• | 165 independently operated consignment locations where we sell motor fuel under consignment arrangements to retail customers;

• | 5,550 convenience stores and retail fuel outlets operated by independent operators, which are referred to as “dealers” or “distributors,” pursuant to long-term distribution agreements; and

• | 2,130 other commercial customers, including unbranded convenience stores, other fuel distributors, school districts and municipalities and other industrial customers.

Retail Operations
As of December 31, 2016, Sunoco LP’s retail operations operated approximately 1,345 convenience stores and retail fuel outlets. Our retail convenience stores operate under several brands, including Sunoco’s proprietary brands Stripes, APlus, and Aloha Island Mart, and offer a broad selection of food, beverages, snacks, grocery and non-food merchandise, motor fuel and other services. We have company operated sites in more than 20 states, with a significant presence in Texas, Pennsylvania, New York, Florida, Virginia and Hawaii.
As of December 31, 2016, Sunoco LP operated approximately 740 Stripes convenience stores in Texas, New Mexico, Oklahoma and Louisiana. Each store offers a customized merchandise mix based on local customer demand and preferences. Sunoco LP has built approximately 255 large-format convenience stores from January 2000 through December 31, 2016. Sunoco LP has implemented our proprietary, in-house Laredo Taco Company restaurant concept in approximately 470 Stripes convenience stores and intend to implement it in all newly constructed Stripes convenience stores. Sunoco LP also owns and operates ATM and proprietary money order systems in most Stripes stores and provide other services such as lottery, prepaid telephone cards, wireless services and car washes.
As of December 31, 2016, Sunoco LP operated approximately 445 retail convenience stores and fuel outlets, primarily under Sunoco’s proprietary and iconic Sunoco fuel brand, and principally located in Pennsylvania, New York and Florida, including approximately 400 APlus convenience stores. Sunoco Retail's convenience stores offer a broad selection of food, beverages, snacks, grocery, and non-food merchandise, as well as motor fuel and other services such as ATM's, money orders, lottery, prepaid telephone cards, and wireless services.
As of December 31, 2016, Sunoco LP operated approximately 160 MACS and Aloha convenience stores and fuel outlets in Virginia, Maryland, Tennessee, Georgia, and Hawaii offering merchandise, food service, motor fuel and other services. As of December 31, 2016, MACS operated approximately 110 company-operated retail convenience stores and Aloha operated approximately 50 Aloha, Shell, and Mahalo branded fuel stations.
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Investment in Lake Charles LNG
Lake Charles LNG provides terminal services for shippers by receiving LNG at the facility for storage and delivering such LNG to shippers, either in liquid state or gaseous state after regasification. Lake Charles LNG derives all of its revenue from a series of long term contracts with a wholly-owned subsidiary of BG Group plc (“BG”).
Lake Charles LNG is currently developing a natural gas liquefaction facility with BG for the export of LNG. In December 2015, Lake Charles LNG received authorization from the FERC to site, construct, and operate facilities for the liquefaction and export of natural gas. On February 15, 2016, Royal Dutch Shell plc completed its acquisition of BG. Shell announced in the second quarter of 2016 that they will delay making a final investment decision (“FID”) for the Lake Charles LNG project and Shell has not advised LCL of any change in the status of the project. In the event that each of LCL and Shell elect to make an affirmative FID, construction of the project would be expected to commence promptly thereafter and first LNG exports would commence about four years later.
Asset Overview
Investment in ETP
The descriptions below include summaries of significant assets within ETP’s operations. 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.
The following details the assets in ETP’s operations:
Intrastate Transportation and Storage
The following details pipelines and storage facilities in ETP’s intrastate transportation and storage operations:

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 | % |  | 3,900 |  |  | 5.3 |  |  | 52.5 |
East Texas Pipeline |  | 100 | % |  | 460 |  |  | 2.4 |  |  | — |
RIGS Haynesville Partnership Co. |  | 49.99 | % |  | 450 |  |  | 2.1 |  |  | — |

The following information describes ETP’s 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 ETP’s 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 ETP’s Godley processing plant which gives ETP 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.

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The Oasis pipeline is integrated with ETP’s 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, ETP had approximately 10.8 Bcf committed under fee-based arrangements with third parties and approximately 36.9 Bcf stored in the facility for ETP’s own account.

• | The East Texas Pipeline connects three treating facilities, one of which ETP owns, 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.

Interstate Transportation and Storage

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 ETP’s 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 between ETP and KMI.

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

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

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

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

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

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

• | The 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 ETP’s assets in its midstream operations:

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 ETP’s 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

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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 ETP’s gathering system to produce residue gas and NGLs. Residue gas is delivered into our intrastate pipelines and NGLs are delivered into ETP’s NGL pipelines to Lone Star.
ETP’s treating facilities remove carbon dioxide and hydrogen sulfide from natural gas gathered into ETP’s 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 ETP’s 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. ETP’s Chisholm, Kenedy, Jackson and King Ranch processing plants are connected to its intrastate transportation pipeline systems for deliveries of residue gas and are also connected with ETP’s NGL pipelines for delivery of NGLs to Lone Star.

Ark-La-Tex Region:

• | ETP’s 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. ETP’s 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.

• | ETP’s 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 ETP’s processing plants and third-party processing capacity; a 15-mile residue gas pipeline that provides market access for natural gas from our processing plants, including connections with pipelines that provide access to the Perryville Hub and other markets in the Gulf Coast region; and a 40-mile NGL pipeline that provides connections to the Mont Belvieu market for NGLs produced from ETP’s 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, ETP offers 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. ETP’s North Central Texas assets include its 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 ETP gathers and processes, 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.
ETP owns a 50% membership interest in Mi Vida JV, a joint venture which owns a 200 MMcf/d cryogenic processing plant in West Texas. ETP operates the plant and related facilities on behalf of Mi Vida JV.
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ETP owns 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.
ETP operates 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.
ETP also owns 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. ETP’s 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.
ETP also owns 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.
ETP 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, ETP operates ORS’s Ohio Utica River System (the “ORS System”), which consists of 47 miles of 36-inch and 13 miles of 30-inch gathering trunklines that delivers up to 2.1 Bcf/d to Rockies Express Pipeline (“REX”), Texas Eastern Transmission, and others.
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NGL and Refined Products Transportation and Services
The following details ETP’s assets in its 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 Plant 1 |  | — |  |  | — |  |  | 26,000 |  |  | — |
Refinery Services 1 |  | 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 ETP’s 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 ETP’s 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.

◦ | 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

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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.

• | ETP’s 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.

• | ETP’s 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.

• | 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.

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• | 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 ETP’s assets in its crude oil transportation and services segment:
ETP’s 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
ETP’s 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. ETP’s 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. ETP’s 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. ETP’s 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 ETP’s 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 ETP’s 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.
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.

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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 ETP’s 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
ETP’s 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 ETP’s 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);

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

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

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

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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
Equity Method Investments

• | Sunoco LP. ETP has 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. ETP has a non-controlling interest in PES, comprising 33% of PES’ outstanding common units.

Contract Services Operations
ETP owns and operates a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management. ETP’s contract treating services are primarily located in Texas, Louisiana and Arkansas.
Compression
ETP owns 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.
ETP owns 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 ETP’s other operations.
Natural Resources Operations
ETP’s Natural Resources operations primarily involve the management and leasing of coal properties and the subsequent collection of royalties. ETP also earns 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, ETP 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. ETP’s subsidiary, Materials Handling Solutions, LLC, owns and operates facilities for industrial customers on a fee basis. During 2014, ETP’s coal reserves located in the San Juan basin were depleted and ETP’s 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 and scheduled to expire at the end of February 2017, subject to the partner right to mutually extend the term. 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.
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
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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.
ETP has received 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.
Investment in Sunoco LP
The following details the assets of Sunoco LP:
Wholesale Subsidiaries

• | Susser Petroleum Operating Company LLC, a Delaware limited liability company, distributes motor fuel, propane and lubricating oils to Stripes’ retail locations, consignment locations, and third party customers in Texas, New Mexico, Oklahoma, Louisiana, and Kansas.

• | Sunoco LLC, a Delaware limited liability company, primarily distributes motor fuel across more than 26 states throughout the East Coast, Midwest, and Southeast regions of the United States. Sunoco LLC also processes transmix and distributes refined product through its terminals in Alabama and the Greater Dallas, TX metroplex.

• | Southside Oil, LLC (“Southside”), a Virginia limited liability company, distributes motor fuel primarily in Virginia, Maryland, Tennessee, and Georgia.

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

Retail Subsidiaries

• | Susser Petroleum Property Company LLC , a Delaware limited liability company, primarily owns and leases convenience store properties.

• | Susser Holdings Corporation, a Delaware corporation, sells motor fuel and merchandise in Texas, New Mexico, and Oklahoma through Stripes-branded convenience stores.

• | Sunoco Retail, a Pennsylvania limited liability company, owns and operates convenience stores that sell motor fuel and merchandise primarily in Pennsylvania, New York, and Florida.

• | MACS Retail LLC, a Virginia limited liability company, owns and operates convenience stores in Virginia, Maryland, and Tennessee.

• | Aloha Petroleum, Ltd., a Hawaii corporation, owns and operates convenience stores on the Hawaiian Islands.

As of December 31, 2016, Sunoco LP’s retail operations operated approximately 1,345 convenience stores and retail fuel outlets. Sunoco LP’s retail convenience stores operate under several brands, including our proprietary brands Stripes, APlus, and Aloha Island Mart, and offer a broad selection of food, beverages, snacks, grocery and non-food merchandise, motor fuel and other services. Sunoco LP has company operated sites in more than 20 states, with a significant presence in Texas, Pennsylvania, New York, Florida, Virginia and Hawaii.
As of December 31, 2016, Sunoco LP operated 740 Stripes convenience stores in Texas, New Mexico and Oklahoma. Each store offers a customized merchandise mix based on local customer demand and preferences. To further differentiate its merchandise offering, Stripes has developed numerous proprietary offerings and private label items unique to Stripes stores, including Laredo Taco Company® restaurants, Café de la Casa® custom blended coffee, Slush Monkey® frozen carbonated beverages, Quake® energy drink, Smokin’ Barrel® beef jerky and meat snacks, Monkey Loco® candies, Monkey Juice® and Royal® brand cigarettes. Stripes has built approximately 255 large-format convenience stores from January 2000 through December 31, 2016 and expects to construct and open 5 to 10 stores during 2017. Stripes has implemented its proprietary, in-house Laredo Taco Company restaurant concepts in over 470 Stripes convenience stores and intends to implement it in all newly constructed Stripes convenience stores.
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Stripes also owns and operates ATM and proprietary money order systems in most of its stores and also provides other services such as lottery, prepaid telephone cards, wireless services and car washes.
As of December 31, 2016, Sunoco LP operated approximately 445 retail convenience stores and fuel outlets, primarily under Sunoco’s proprietary and iconic Sunoco fuel brand, and principally located in Pennsylvania, New York and Florida, including approximately 400 APlus convenience stores. Sunoco Retail's convenience stores offer a broad selection of food, beverages, snacks, grocery, and non-food merchandise, as well as motor fuel and other services such as ATM's, money orders, lottery, prepaid telephone cards, and wireless services.
As of December 31, 2016, Sunoco LP operated approximately 160 MACS and Aloha convenience stores and fuel outlets in Virginia, Maryland, Tennessee, Georgia, and Hawaii offering merchandise, food service, motor fuel and other services. As of December 31, 2016, MACS operated 110 company-operated retail convenience stores and Aloha operated 50 Aloha, Shell, and Mahalo branded fuel stations.
On April 6, 2017, Sunoco LP entered into a definitive asset purchase agreement for the sale of a portfolio of approximately 1,112 Sunoco LP operated retail fuel outlets in 19 geographic regions, together with ancillary businesses and related assets, including the proprietary Laredo Taco Company brand, to 7-Eleven, Inc. (“7-Eleven”) for an aggregate purchase price of $3.3 billion (the “7-Eleven Transaction”). The closing of the transaction contemplated by the asset purchase agreement is expected to occur in the fourth quarter of 2017.
With the assistance of a third-party brokerage firm, Sunoco LP began marketing efforts with respect to approximately 208 sites under the Stripes brand (“Stripes Sites”) located in certain West Texas, Oklahoma and New Mexico markets, which were not included in the 7-Eleven purchase agreement. There can be no assurance of Sunoco LP’s success in selling the remaining company-operated retail assets, nor the price or terms of such sale, and even if a sale is consummated, Sunoco LP may remain contingently responsible for certain risks and obligations related to the divested retail assets. On January 18, 2017, with the assistance of a third-party brokerage firm, Sunoco LP launched a portfolio optimization plan to market and sell 97 real estate assets located in Florida, Louisiana, Massachusetts, Michigan, New Hampshire, New Jersey, New Mexico, New York, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, Texas and Virginia. The properties will be sold through a sealed-bid sale. Of the 97 properties, 16 have been sold and an additional 20 are under contract to be sold. 31 are being sold to 7-Eleven and 9 are being sold in another transaction. The remaining 21 continue to be marketed by the third-party brokerage firm.
Investment in Lake Charles LNG
Regasification Facility
Lake Charles LNG, a wholly-owned subsidiary of ETE, owns a LNG import terminal and regasification facility located on Louisiana’s Gulf Coast near Lake Charles, Louisiana. The import terminal has approximately 9.0 Bcf of above ground LNG storage capacity and the regasification facility has a run rate send out capacity of 1.8 Bcf/day.
Liquefaction Project
LCL, an entity 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 and scheduled to expire at the end of February 2017, subject to the parties’ right to mutually extend the term. 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 is expected to 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.
Ac 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
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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 will make an affirmative FID in 2017, construction of the liquefaction project would commence immediately thereafter in order to place the first and second LNG trains in service in 2022 and the third train in service in early 2023.
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 we expect the DOE to issue the Non-FTA Authorization to LCL in due course.
In addition, 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.
Environmental Matters
See information previously included in our Form 10-K filed on February 24, 2017.
Employees
See information previously included in our Form 10-K filed on February 24, 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.
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PART II
ITEM 6. SELECTED FINANCIAL DATA
The selected historical 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 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 | $ | 30,102 |  |  | $ | 34,204 |  |  | $ | 52,639 |  |  | $ | 48,335 |  |  | $ | 16,964 |
Operating income | 1,910 |  |  | 2,250 |  |  | 2,372 |  |  | 1,551 |  |  | 1,360 |
Income from continuing operations | 520 |  |  | 1,012 |  |  | 994 |  |  | 282 |  |  | 1,383 |
Income (loss) from discontinued operations | (479 | ) |  | 81 |  |  | 130 |  |  | 33 |  |  | (109 | )
Net income | 41 |  |  | 1,093 |  |  | 1,124 |  |  | 315 |  |  | 1,274 |
Basic income from continuing operations per limited partner unit | 0.95 |  |  | 1.11 |  |  | 0.57 |  |  | 0.17 |  |  | 0.29 |
Diluted income from continuing operations per limited partner unit | 0.93 |  |  | 1.11 |  |  | 0.57 |  |  | 0.17 |  |  | 0.29 |
Basic income from discontinued operations per limited partner unit | (0.01 | ) |  | — |  |  | 0.01 |  |  | 0.01 |  |  | 0.01 |
Diluted income from discontinued operations per limited partner unit | (0.01 | ) |  | — |  |  | 0.01 |  |  | 0.01 |  |  | 0.01 |
Cash distribution per unit | 1.14 |  |  | 1.08 |  |  | 0.80 |  |  | 0.67 |  |  | 0.63 |
Balance Sheet Data (at period end): |  |  |  |  |  |  |  |  |
Assets held for sale | 4,549 |  |  | 4,647 |  |  | 4,316 |  |  | — |  |  | 1,169 |
Total assets(1) | 79,011 |  |  | 71,189 |  |  | 64,279 |  |  | 50,330 |  |  | 48,904 |
Liabilities associated with assets held for sale | 68 |  |  | 67 |  |  | 71 |  |  | — |  |  | 227 |
Long-term debt, less current maturities | 42,608 |  |  | 36,837 |  |  | 29,477 |  |  | 22,562 |  |  | 21,440 |
Total equity | 22,517 |  |  | 23,598 |  |  | 22,314 |  |  | 16,279 |  |  | 16,350 |

(1) | Includes assets held for sale

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)
Energy Transfer Equity, L.P. is a Delaware limited partnership whose common units are publicly traded on the NYSE under the ticker symbol “ETE.” ETE was formed in September 2002 and completed its initial public offering in February 2006.
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” of the Partnership’s Annual Report on Form 10-K filed February 24, 2017.
Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP, ETP GP, ETP LLC, Panhandle (or Southern Union prior to its merger into Panhandle in January 2014), Sunoco Logistics, Sunoco LP, Lake Charles LNG and ETP Holdco. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.
OVERVIEW
Energy Transfer Equity, L.P. directly and indirectly owns equity interests in ETP and Sunoco LP, both publicly traded master limited partnerships engaged in diversified energy-related services.
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The historical common units for ETP presented have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger, defined in Note 1 to our consolidated financial statements
At December 31, 2016, our interests in ETP and Sunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as approximately 3.9 million ETP common units, approximately 81.0 million ETP Class H units and approximately 2.3 million Sunoco LP common units.
Additionally, ETE owns 100 ETP Class I Units, the distributions from which offset a portion of IDR subsidies ETE has previously provided to ETP.
The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Sunoco LP, both of which are publicly traded master limited partnerships engaged in diversified energy-related services, and the Partnership’s ownership of Lake Charles LNG. The Parent Company’s primary cash requirements are for distributions to its partners, general and administrative expenses, debt service requirements and at ETE’s election, capital contributions to ETP and Sunoco LP in respect of ETE’s general partner interests in ETP and Sunoco LP. The Parent Company-only assets and liabilities are not available to satisfy the debts and other obligations of subsidiaries.
In order to fully understand the financial condition and results of operations of the Parent Company on a stand-alone basis, we have included discussions of Parent Company matters apart from those of our consolidated group.
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 subsidiaries’ natural gas and liquids businesses through, among other things, pursuing certain construction and expansion opportunities relating to our subsidiaries’ existing infrastructure and acquiring certain strategic operations and businesses or assets. The actual amounts of cash that we will have available for distribution will primarily depend on the amount of cash our subsidiaries generate from their operations.
Our reportable segments are as follows:

• | Investment in ETP, including the consolidated operations of ETP;

• | Investment in Sunoco LP, including the consolidated operations of Sunoco LP;

• | Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and

• | Corporate and Other, including the following:

• | activities of the Parent Company; and

• | the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

Each of the respective general partners of ETP and Sunoco LP have separate operating management and boards of directors. We control ETP and Sunoco LP through our ownership of their respective general partners.
Recent Developments
See information previously included in our Form 10-K filed on February 24, 2017.
On April 6, 2017, Sunoco LP entered into a definitive asset purchase agreement for the sale of a portfolio of approximately 1,112 Sunoco LP operated retail fuel outlets in 19 geographic regions, together with ancillary businesses and related assets, including the Laredo Taco Company, to 7-Eleven, Inc. for an aggregate purchase price of $3.3 billion (the “7-Eleven Transaction”). The closing of the transaction contemplated by the asset purchase agreement is expected to occur in the fourth quarter of 2017. With the assistance of a third-party brokerage firm, Sunoco LP began marketing efforts with respect to approximately 208 Stripes Sites located in certain West Texas, Oklahoma and New Mexico markets which were not included in the 7-Eleven purchase agreement. There can be no assurance of Sunoco LP’s success in selling the remaining company-operated retail assets, nor the price or terms of such sale, and even if a sale is consummated, Sunoco LP may remain contingently responsible for certain risks and obligations related to the divested retail assets. On January 18, 2017, with the assistance of a third-party brokerage firm, Sunoco LP launched a portfolio optimization plan to market and sell 97 real estate assets located in Florida, Louisiana, Massachusetts, Michigan, New Hampshire, New Jersey, New Mexico, New York, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, Texas and Virginia. The properties will be sold through a sealed-bid sale. Of the 97 properties, 16 have been sold and an additional 20 are under contract to be sold. 31 are being sold to 7-Eleven and 9 are being sold in another transaction. The remaining 21 continue to be marketed by the third-party brokerage firm.
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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.
Segment Adjusted EBITDA, as reported for each segment in the table below, is analyzed for each segment in the section below titled “Segment Operating Results.” Total Segment Adjusted EBITDA, as presented below, is equal to the consolidated measure of Adjusted EBITDA, which is a non-GAAP measure used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating results of the Partnership’s fundamental business activities and should not be considered in isolation or as a substitution for net income, income from operations, cash flows from operating activities or other GAAP measures. Our definition of total or consolidated Adjusted EBITDA is consistent with the definition of Segment Adjusted EBITDA above.
Based on the following changes in our reportable segments, we have adjusted the presentation of our segment results for the prior years to be consistent with the current year presentation. We previously presented reportable segments for our investments in ETP and Regency. ETP completed its acquisition of Regency in April 2015; therefore, the Investment in ETP segment amounts have been retrospectively adjusted to reflect ETP’s consolidation of Regency for the periods presented. The Investment in Regency is no longer presented as a separate reportable segment.
The Investment in Sunoco LP segment reflects the results of Sunoco LP beginning August 29, 2014, the date that ETP originally obtained control of Sunoco LP. ETE’s consolidated results reflect the elimination of MACS, Sunoco, LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco, LLC (through December 2015) and a continuing investment in Sunoco LP, the equity in earnings from which are also eliminated in ETE’s consolidated financial statements.
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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: |  |  |  |  |
Investment in ETP | $ | 5,605 |  |  | $ | 5,714 |  |  | $ | (109 | )
Investment in Sunoco LP | 665 |  |  | 719 |  |  | (54 | )
Investment in Lake Charles LNG | 179 |  |  | 196 |  |  | (17 | )
Corporate and other | (170 | ) |  | (104 | ) |  | (66 | )
Adjustments and eliminations | (272 | ) |  | (590 | ) |  | 318 |
Total | 6,007 |  |  | 5,935 |  |  | 72 |
Depreciation, depletion and amortization | (2,166 | ) |  | (1,904 | ) |  | (262 | )
Interest expense, net of interest capitalized | (1,803 | ) |  | (1,621 | ) |  | (182 | )
Gains on acquisitions | 83 |  |  | — |  |  | 83 |
Impairment losses | (970 | ) |  | (339 | ) |  | (631 | )
Losses on interest rate derivatives | (12 | ) |  | (18 | ) |  | 6 |
Non-cash compensation expense | (70 | ) |  | (91 | ) |  | 21 |
Unrealized losses on commodity risk management activities | (136 | ) |  | (65 | ) |  | (71 | )
Inventory valuation adjustments | 267 |  |  | (229 | ) |  | 496 |
Losses on extinguishments of debt | — |  |  | (43 | ) |  | 43 |
Impairment of investment in affiliate | (308 | ) |  | — |  |  | (308 | )
Equity in earnings of unconsolidated affiliates | 270 |  |  | 276 |  |  | (6 | )
Adjusted EBITDA related to unconsolidated affiliates | (675 | ) |  | (713 | ) |  | 38 |
Adjusted EBITDA related to discontinued operations | (293 | ) |  | (345 | ) |  | 52 |
Other, net | 78 |  |  | 21 |  |  | 57 |
Income from continuing operations before income tax benefit | 272 |  |  | 864 |  |  | (592 | )
Income tax benefit from continuing operations | (248 | ) |  | (148 | ) |  | (100 | )
Income from continuing operations | 520 |  |  | 1,012 |  |  | (492 | )
Income (loss) from discontinued operations, net of income taxes | (479 | ) |  | 81 |  |  | (560 | )
Net income | $ | 41 |  |  | $ | 1,093 |  |  | $ | (1,052 | )

See the detailed discussion of Segment Adjusted EBITDA in the Segment Operating Results section below.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased primarily due to additional depreciation and amortization from assets recently placed in service.
Interest Expense, Net of Interest Capitalized. Interest expense increased primarily due to the following:

• | an increase of $101 million of expense recognized by Sunoco LP primarily due to increased term loan borrowings, the issuance of senior notes and an increase in borrowings under the Sunoco LP revolving credit facility;

• | an increase of $33 million of expense recognized by the Parent Company primarily related to the May 2015 issuance of $1 billion aggregate principal amount of its 5.5% senior notes; and

• | an increase of $53 million of expense recognized by ETP (excluding interest expense related to Sunoco LP for the period prior to ETP’s deconsolidation of Sunoco LP on July 1, 2015) primarily due to recent debt issuances by ETP and its consolidated subsidiaries.

Gains on acquisitions. The Partnership recorded 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.
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Impairment Losses. In 2016, ETP recorded goodwill impairments of $638 million related to its interstate transportation and storage operations and $32 million related to its midstream operations. 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. Sunoco LP recognized goodwill impairments of $642 million, of which $156 million was allocated to continuing operations, primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. In addition, impairment losses for 2016 also include a $133 million impairment to property, plant and equipment in ETP’s interstate transportation and storage operations due to a decrease in projected future cash flows as well as a $10 million impairment to property, plant and equipment in ETP’s midstream operations. In 2015, ETP recorded 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.
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 year 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 the discussion of segment results below.
Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recorded for the inventory associated with Sunoco LP and ETP’s NGL and refined products and transportation services operations as a result of commodity price changes between periods.
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.
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.
Adjusted EBITDA Related to Discontinued Operations. Amounts were related to the operations of Sunoco LP’s retail business that is classified as held for sale.
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.
Segment Operating Results
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.
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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: |  |  |
Investment in ETP | $ | 6,433 |  |  | $ | 7,263 |
Investment in Sunoco LP | 837 |  |  | 636 |
Investment in Lake Charles LNG | 196 |  |  | 216 |
Adjustments and eliminations | — |  |  | (1,346 | )
Total Segment Margin | 7,466 |  |  | 6,769 |
Less: |  |  |
Operating expenses | 1,727 |  |  | 1,728 |
Depreciation, depletion and amortization | 2,166 |  |  | 1,904 |
Selling, general and administrative | 693 |  |  | 548 |
Impairment losses | 970 |  |  | 339 |
Operating income | $ | 1,910 |  |  | $ | 2,250 |

Investment in ETP

| Years Ended December 31, |  |
| 2016 |  | 2015 |  | Change
Revenues | $ | 21,827 |  |  | $ | 34,292 |  |  | $ | (12,465 | )
Cost of products sold | 15,394 |  |  | 27,029 |  |  | (11,635 | )
Segment margin | 6,433 |  |  | 7,263 |  |  | (830 | )
Unrealized losses on commodity risk management activities | 131 |  |  | 65 |  |  | 66 |
Operating expenses, excluding non-cash compensation expense | (1,485 | ) |  | (2,265 | ) |  | 780 |
Selling, general and administrative expenses, excluding non-cash compensation expense | (351 | ) |  | (468 | ) |  | 117 |
Inventory valuation adjustments | (170 | ) |  | 104 |  |  | (274 | )
Adjusted EBITDA related to unconsolidated affiliates | 946 |  |  | 937 |  |  | 9 |
Other, net | 101 |  |  | 78 |  |  | 23 |
Segment Adjusted EBITDA | $ | 5,605 |  |  | $ | 5,714 |  |  | $ | (109 | )

Segment Adjusted EBITDA. For the year ended December 31, 2016 compared to the prior year, Segment Adjusted EBITDA related to the Investment in ETP decreased primarily as a result of the following:

• | a decrease of $343 million in ETP’s all other operations caused by deconsolidation of the retail marketing operations as a result of the dropdown from ETP to Sunoco LP;

• | a decrease of $104 million in ETP’s midstream operations due to decreases in gathered volumes 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; and

• | a decrease $38 million in ETP’s interstate transportation and storage operations caused by a $56 million decrease in revenues primarily caused by contract restructuring on the Tiger pipeline, lower reservation revenues on the Panhandle and Trunkline pipelines, lower sales of capacity in the Phoenix and San Juan areas on the Transwestern pipeline, the transfer of one of the Trunkline pipelines which was repurposed from natural gas service to crude oil service, the expiration of a transportation rate schedule on the Transwestern pipeline, and declines in production and third-party maintenance on the Sea Robin pipeline, partially offset by higher reservation revenues on the Transwestern pipeline and higher parking revenues on the Panhandle and Trunkline pipelines; partially offset by

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• | an increase of $258 million in ETP’s NGL and refined products and transportation services operations primarily resulting from:

• | an increase of $209 million related to legacy ETP’s NGL operations resulting from a $36 million increase in storage margin from Mont Belvieu fractionators, $18 million from increased throughput volumes, $8 million due to increased demand on leased storage capacity, $80 million from Legacy ETP NGL transportation fees due to higher transport volumes over all regions, $107 million increase in Legacy ETP NGL processing and fractionation margin due to higher NGL volumes from all producing regions, partially offset by a $24 million decrease in margin due to the timing of the withdrawal and sale of NGL component product inventory and an increase of $20 million in legacy ETP operating expenses;

• | an increase of $65 million from legacy Sunoco Logistics’ refined products operations driven primarily by improved operating results from refined products pipelines of $32 million and higher results from refined products acquisition and marketing activities of $21 million; offset by,

• | a decrease of $16 million from legacy Sunoco Logistics NGL operations primarily attributable to lower operating results from NGL acquisition and marketing activities due to lower volumes and margins offset by increased volumes and fees from Mariner NGL projects.

• | an increase of $48 million from ETP’s crude oil and transportation services operations, primarily due to an increase of $20 million in crude transport fees primarily from placing in-service the first phase of Bayou Bridge pipeline in April 2016 and $31 million from legacy Sunoco Logistics’ crude oil operations primarily due to improved results from ETP’s crude oil pipelines from the expansion capital projects which commenced operations in 2016 and 2015.

• | an increase of $70 million from ETP’s intrastate transportation and storage operations, caused by an increase of $20 million in segment margin related to higher storage margin and higher natural gas sales as well as increases in unrealized losses on commodity risk management activities of $45 million.

Adjusted EBITDA Related to Unconsolidated Affiliates. ETP’s Adjusted EBITDA related to unconsolidated affiliates for the years ended December 31, 2016 and 2015 consisted of the following:

| Years Ended December 31, |  |
| 2016 |  | 2015 |  | Change
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 |

These amounts represent ETP’s proportionate share of the Adjusted EBITDA of its unconsolidated affiliates and are based on ETP’s equity in earnings or losses of its unconsolidated affiliates adjusted for its proportionate share of the unconsolidated affiliates’ interest, depreciation, amortization, non-cash items and taxes.
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Investment in Sunoco LP

| Years Ended December 31, |  |
| 2016 |  | 2015 |  | Change
Revenues | $ | 8,296 |  |  | $ | 10,538 |  |  | $ | (2,242 | )
Cost of products sold | 7,459 |  |  | 9,902 |  |  | (2,443 | )
Segment margin | 837 |  |  | 636 |  |  | 201 |
Unrealized losses on commodity risk management activities | 5 |  |  | 2 |  |  | 3 |
Operating expenses, excluding non-cash compensation expense | (230 | ) |  | (223 | ) |  | (7 | )
Selling, general and administrative, excluding non-cash compensation expense | (142 | ) |  | (118 | ) |  | (24 | )
Inventory fair value adjustments | (98 | ) |  | 78 |  |  | (176 | )
Adjusted EBITDA from discontinued operations | 293 |  |  | 345 |  |  | (52 | )
Other, net | — |  |  | (1 | ) |  | 1 |
Segment Adjusted EBITDA | $ | 665 |  |  | $ | 719 |  |  | $ | (54 | )

The Investment in Sunoco LP segment reflects the results of Sunoco LP beginning August 29, 2014, the date that ETP originally obtained control of Sunoco LP. Sunoco LP obtained control of MACS in October 2014, Sunoco, LLC in April 2015, Susser in July 2015, and Sunoco Retail LLC in March 2016. Because these entities were under common control, Sunoco LP recast its financial statements to retrospectively consolidate each of the entities beginning September 1, 2014. The segment results above are presented on the same basis as Sunoco LP’s standalone financial statements; therefore, the segment results above also include MACS, Sunoco, LLC, Susser and Sunoco Retail LLC beginning September 1, 2014. MACS, Sunoco, LLC, Susser and Sunoco Retail LLC were also consolidated by ETP until October 2014, April 2015, July 2015 and March 2016, respectively; therefore, the results from those entities are reflected in both the Investment in ETP and the Investment in Sunoco LP segments for the respective periods in 2014 and 2015. ETE’s consolidated results reflect the elimination of MACS, Sunoco, LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco, LLC (through December 2015) and a continuing investment in Sunoco LP, the equity in earnings from which are also eliminated in ETE’s consolidated financial statements.
Segment Adjusted EBITDA. For the year ended December 31, 2016 compared to the prior year, Segment Adjusted EBITDA related to the Investment in Sunoco LP decreased primarily as a result of the following:

• | a change of $176 million in the fair value adjustment to inventory resulting from changes in fuels prices during the year ended December 31, 2016;

• | a decrease of $52 million related to Sunoco LP’s retail operations that have been classified as discontinued operations;

• | an increase of $24 million in general and administrative expenses primarily due to $18 million for the transition of employees from Houston, Texas, Corpus Christi, Texas and Philadelphia, Pennsylvania to Dallas, Texas, with the remaining increase due to higher professional fees and other administrative expenses; partially offset by

• | an increase of $201 million in segment margin primarily caused by an increase in wholesale motor fuel gross profit of $206 million due to a 28.9%, or $0.55, decrease in the cost per wholesale motor fuel gallon, an increase in merchandise gross profit of $36 million due to the increase in the number of retail sites, and an increase in rental and other gross profit of $17 million due to increased other retail income, offset by a decrease in the gross profit on retail motor fuel of $24 million due to an 11.8%, or $0.28, decrease in the price per retail motor fuel gallon;

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Investment in Lake Charles LNG

| Years Ended December 31, |  |
| 2016 |  | 2015 |  | Change
Revenues | $ | 197 |  |  | $ | 216 |  |  | $ | (19 | )
Operating expenses, excluding non-cash compensation expense | (16 | ) |  | (17 | ) |  | 1 |
Selling, general and administrative, excluding non-cash compensation expense | (2 | ) |  | (3 | ) |  | 1 |
Segment Adjusted EBITDA | $ | 179 |  |  | $ | 196 |  |  | $ | (17 | )

Lake Charles LNG derives all of its revenue from a contract with a non-affiliated gas marketer.
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: |  |  |  |  |
Investment in ETP | $ | 5,714 |  |  | $ | 5,710 |  |  | $ | 4 |
Investment in Sunoco LP | 719 |  |  | 332 |  |  | 387 |
Investment in Lake Charles LNG | 196 |  |  | 195 |  |  | 1 |
Corporate and other | (104 | ) |  | (97 | ) |  | (7 | )
Adjustments and eliminations | (590 | ) |  | (300 | ) |  | (290 | )
Total | 5,935 |  |  | 5,840 |  |  | 95 |
Depreciation, depletion and amortization | (1,904 | ) |  | (1,669 | ) |  | (235 | )
Interest expense, net of interest capitalized | (1,621 | ) |  | (1,368 | ) |  | (253 | )
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 | (91 | ) |  | (82 | ) |  | (9 | )
Unrealized gains (losses) on commodity risk management activities | (65 | ) |  | 116 |  |  | (181 | )
Inventory valuation adjustments | (229 | ) |  | (445 | ) |  | 216 |
Losses on extinguishments of debt | (43 | ) |  | (25 | ) |  | (18 | )
Equity in earnings of unconsolidated affiliates | 276 |  |  | 332 |  |  | (56 | )
Adjusted EBITDA related to unconsolidated affiliates | (713 | ) |  | (748 | ) |  | 35 |
Adjusted EBITDA related to discontinued operations | (345 | ) |  | (208 | ) |  | (137 | )
Other, net | 21 |  |  | (74 | ) |  | 95 |
Income from continuing operations before income tax expense (benefit) | 864 |  |  | 1,319 |  |  | (455 | )
Income tax expense (benefit) from continuing operations | (148 | ) |  | 325 |  |  | (473 | )
Income from continuing operations | 1,012 |  |  | 994 |  |  | 18 |
Income from discontinued operations | 81 |  |  | 130 |  |  | (49 | )
Net income | $ | 1,093 |  |  | $ | 1,124 |  |  | $ | (31 | )

See the detailed discussion of Segment Adjusted EBITDA in the Segment Operating Results section below.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased primarily as a result of acquisitions and growth projects, including an increase of $260 million primarily due to assets recently placed in service and recent acquisitions from ETP.
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Interest Expense, Net of Interest Capitalized. Interest expense increased primarily due to the following:

• | an increase of $126 million related to ETP primarily due to ETP’s issuance of senior notes.

• | an increase of $38 million of expense recognized by Sunoco LP primarily due to the recognition of a partial period in 2014.

• | an increase of $89 million of expense recognized by the Parent Company primarily related to recent issuances of senior notes.

Gain on Sale of AmeriGas Common Units. During the year ended December 31, 2014, ETP sold 18.9 million of the AmeriGas common units that were originally received in connection with the contribution of its propane business to AmeriGas in January 2012. ETP recorded a gain based on the sale proceeds in excess of the carrying amount of the units sold. As of December 31, 2015, ETP’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, ETP 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 at ETP related to the Permian Basin gathering and processing operations. The decline in estimated fair value of that reporting 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 year 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 the discussion of segment results below.
Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recorded for the inventory associated with Sunoco LP, ETP’s NGL and refined products and transportation services operations as a result of commodity price changes between periods.
Adjusted EBITDA Related to Discontinued Operations. Amounts were related to the operations of Sunoco LP’s retail business that is classified as held for sale.
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. Income tax expense is based on the earnings of our taxable subsidiaries. For the year ended December 31, 2015, the Partnership’s income tax expense 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.
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Segment Operating Results
Following is a reconciliation of Segment Margin to operating income, as reported in the Partnership’s consolidated statements of operations:

| Years Ended December 31,
| 2015 |  | 2014
Segment Margin by segment: |  |  |
Investment in ETP | $ | 7,263 |  |  | $ | 7,061 |
Investment in Sunoco LP | 636 |  |  | 77 |
Investment in Lake Charles LNG | 216 |  |  | 216 |
Adjustments and eliminations | (1,346 | ) |  | (576 | )
Total Segment Margin | 6,769 |  |  | 6,778 |
Less: |  |  |
Operating expenses | 1,728 |  |  | 1,811 |
Depreciation, depletion and amortization | 1,904 |  |  | 1,669 |
Selling, general and administrative | 548 |  |  | 556 |
Impairment losses | 339 |  |  | 370 |
Operating income | $ | 2,250 |  |  | $ | 2,372 |

Investment in ETP

| Years Ended December 31, |  |
| 2015 |  | 2014 |  | Change
Revenues | $ | 34,292 |  |  | $ | 55,475 |  |  | $ | (21,183 | )
Cost of products sold | 27,029 |  |  | 48,414 |  |  | (21,385 | )
Segment margin | 7,263 |  |  | 7,061 |  |  | 202 |
Unrealized (gains) losses on commodity risk management activities | 65 |  |  | (112 | ) |  | 177 |
Operating expenses, excluding non-cash compensation expense | (2,265 | ) |  | (2,065 | ) |  | (200 | )
Selling, general and administrative expenses, excluding non-cash compensation expense | (468 | ) |  | (508 | ) |  | 40 |
Inventory valuation adjustments | 104 |  |  | 473 |  |  | (369 | )
Adjusted EBITDA related to discontinued operations | — |  |  | 27 |  |  | (27 | )
Adjusted EBITDA related to unconsolidated affiliates | 937 |  |  | 748 |  |  | 189 |
Other, net | 78 |  |  | 86 |  |  | (8 | )
Segment Adjusted EBITDA | $ | 5,714 |  |  | $ | 5,710 |  |  | $ | 4 |

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Segment Adjusted EBITDA. For the year ended December 31, 2015 compared to the prior year, Segment Adjusted EBITDA related to the Investment in ETP increased primarily as a result of the following:

• | an increase of $334 million in ETP’s NGL and refined products and transportation services operations primarily resulting from:

• | an increase of $139 million related to legacy ETP’s NGL operations resulting from an increase of $69 million in legacy ETP NGL transportation margin due to high volumes out of West Texas and Eagle Ford producing areas, increase of $42 million in processing and fractionation margin due to ramp-up of fractionators, an increase of $15 million in storage due to increased fee-based storage, an increase of $33 million in other margin due to the withdrawal and sale of physical storage volumes, a decrease of $4 million in selling, general and administrative expenses, partially offset by an increase in operating expenses of $24 million.

• | an increase of $65 million from legacy Sunoco Logistics’ refined products operations driven primarily by improved operating results from refined products pipelines of $33 million and higher results from refined products acquisition and marketing activities of $6 million, higher contributions from legacy Sunoco Logistics’ joint venture interests of $10 million, and increased terminalling activities of $15 million; and

• | an increase of $130 million from legacy Sunoco Logistics NGL operations primarily attributable to lower operating results from NGL acquisition and marketing activities due to lower volumes and margins offset by increased volumes and fees from Mariner NGL projects.

• | decrease of $81 million in ETP’s midstream operations, primarily due to a decrease of $88 million in non-fee based margins for natural gas and a $200 million decrease in non-fee based margins for crude oil and NGL due to lower natural gas prices and lower crude oil and NGL prices as well as an increase of $135 million in operating expenses primarily due to assets recently placed in service, including Rebel system in West Texas and King Ranch system in South Texas as well as the acquisition of Eagle Rock midstream assets in July 2014, partially offset by an increase of $120 million in fee-based margin from the acquisitions of the Eagle Rock, PVR, and King Ranch midstream assets;

• | a decrease of $57 million in ETP’s interstate transportation and storage operations, primarily due to lower revenues of $47 million as a result of higher basis differentials in 2014 driven by colder weather, lower revenues of $22 million and $7 million due to the expiration of a transportation rate schedule and lower sales of gas due to lower prices, respectively, on the Transwestern pipeline, and $15 million due to a managed contract roll off to facilitate the transfer of a line from Trunkline to an affiliate for its conversion from natural gas to crude oil service. These decreases were partially offset by sales of capacity at higher rates of $13 million on the Panhandle and Transwestern pipelines, as well as higher usage rates and volumes on the Transwestern pipeline;

• | a decrease of $16 million in ETP’s intrastate transportation and storage operations, primarily due to a decrease of $17 million in storage margin;

• | a decrease of $176 million in ETP’s other operations due to:

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

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

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

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

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

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

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

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

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, 2015 and 2014. These fees were reflected in “Other” in the “All other” segment and for the years ended December 31, 2015 and 2014 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.
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. ETP’s Adjusted EBITDA related to unconsolidated affiliates for the years ended December 31, 2015 and 2014 consisted of the following:

| Years Ended December 31, |  |
| 2015 |  | 2014 |  | Change
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 |

These amounts represent ETP’s proportionate share of the Adjusted EBITDA of its unconsolidated affiliates and are based on ETP’s equity in earnings or losses of its unconsolidated affiliates adjusted for its proportionate share of the unconsolidated affiliates’ interest, depreciation, amortization, non-cash items and taxes.
Investment in Sunoco LP

| Years Ended December 31, |  |
| 2015 |  | 2014 |  | Change
Revenues | $ | 10,538 |  |  | $ | 4,291 |  |  | $ | 6,247 |
Cost of products sold | 9,902 |  |  | 4,214 |  |  | 5,688 |
Segment margin | 636 |  |  | 77 |  |  | 559 |
Unrealized losses (gains) on commodity risk management activities | 2 |  |  | (1 | ) |  | 3 |
Operating expenses, excluding non-cash compensation expense | (223 | ) |  | (71 | ) |  | (152 | )
Selling, general and administrative, excluding non-cash compensation expense | (118 | ) |  | (31 | ) |  | (87 | )
Inventory fair value adjustments | 78 |  |  | 177 |  |  | (99 | )
Adjusted EBITDA from discontinued operations | 345 |  |  | 181 |  |  | 164 |
Other, net | (1 | ) |  | — |  |  | (1 | )
Segment Adjusted EBITDA | $ | 719 |  |  | $ | 332 |  |  | $ | 387 |

The Investment in Sunoco LP segment reflects the results of Sunoco LP beginning August 29, 2014, the date that ETP originally obtained control of Sunoco LP. Sunoco LP obtained control of MACS in October 2014, Sunoco, LLC in April 2015, Susser in July 2015, and Sunoco Retail LLC in March 2016. Because these entities were under common control, Sunoco LP recast its financial statements to retrospectively consolidate each of the entities beginning September 1, 2014. The segment results above are presented on the same basis as Sunoco LP’s standalone financial statements; therefore, the segment results above also include MACS, Sunoco, LLC, Susser and Sunoco Retail LLC beginning September 1, 2014. MACS, Sunoco, LLC, Susser and Sunoco Retail LLC were also consolidated by ETP until October 2014, April 2015, July 2015 and March 2016, respectively; therefore,
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the results from those entities are reflected in both the Investment in ETP and the Investment in Sunoco LP segments for the respective periods in 2014 and 2015. ETE’s consolidated results reflect the elimination of MACS, Sunoco, LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco, LLC (through December 2015) and a continuing investment in Sunoco LP, the equity in earnings from which are also eliminated in ETE’s consolidated financial statements.
Segment Adjusted EBITDA. The increase in Segment Adjusted EBITDA for the year ended December 31, 2015 is primarily due to the presentation of only a partial period of results for Sunoco LP in 2014, as discussed above.
Investment in Lake Charles LNG

| Years Ended December 31, |  |
| 2015 |  | 2014 |  | Change
Revenues | $ | 216 |  |  | $ | 216 |  |  | $ | — |
Operating expenses, excluding non-cash compensation expense | (17 | ) |  | (17 | ) |  | — |
Selling, general and administrative, excluding non-cash compensation expense | (3 | ) |  | (4 | ) |  | 1 |
Segment Adjusted EBITDA | $ | 196 |  |  | $ | 195 |  |  | $ | 1 |

Lake Charles LNG derives all of its revenue from a contract with a non-affiliated gas marketer.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
Our cash flows may change in the future due to a number of factors, some of which we cannot control. These factors include regulatory changes, the price of our subsidiaries’ products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of our acquisitions, and other factors.
Operating Activities
Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in “Results of Operations” above), excluding the impacts of non-cash items and changes in operating assets and liabilities. Non-cash items include recurring non-cash expenses, such as depreciation, depletion and amortization expense and non-cash compensation expense. The increase in depreciation, depletion and amortization expense during the periods presented primarily resulted from construction and acquisition of assets, while changes in non-cash unit-based compensation expense resulted from changes in the number of units granted and changes in the grant date fair value estimated for such grants. Cash flows from operating activities also differ from earnings as a result of non-cash charges that may not be recurring, such as impairment charges and allowance for equity funds used during construction. The allowance for equity funds used during construction increases in periods when ETP has a significant amount of interstate pipeline construction in progress. Changes in operating assets and liabilities between periods result from factors such as the changes in the value of price risk management assets and liabilities, timing of accounts receivable collection, payments on accounts payable, the timing of purchases and sales of inventories, and the timing of advances and deposits received from customers.
Following is a summary of operating activities by period:
Year Ended December 31, 2016
Cash provided by operating activities in 2016 was $3.27 billion and net income was $41 million. The difference between net income and cash provided by operating activities in 2016 primarily consisted of net non-cash items totaling $2.45 billion, loss from discontinued operations of $479 million and changes in operating assets and liabilities of $36 million. The non-cash activity in 2016 consisted primarily of depreciation, depletion and amortization of $2.17 billion, impairment losses of $1.28 billion, deferred income tax benefit of $225 million, inventory valuation adjustments of $267 million and non-cash compensation expense of $70 million.
Year Ended December 31, 2015
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Cash provided by operating activities in 2015 was $2.91 billion and net income was $1.09 billion. The difference between net income and cash provided by operating activities in 2015 primarily consisted of net non-cash items totaling $2.52 billion and changes in operating assets and liabilities of $1.03 billion. The non-cash activity in 2015 consisted primarily of depreciation, depletion and amortization of $1.90 billion, impairment losses of $339 million, deferred income tax expense of $221 million, inventory valuation adjustments of $229 million, losses on extinguishments of debt of $43 million and non-cash compensation expense of $91 million.
Year Ended December 31, 2014
Cash provided by operating activities in 2014 was $2.89 billion and net income was $1.12 billion. The difference between net income and cash provided by operating activities in 2014 consisted of net non-cash items totaling $1.94 billion and changes in operating assets and liabilities of $338 million. The non-cash activity in 2014 consisted primarily of depreciation, depletion and amortization of $1.67 billion, impairment losses of $370 million, inventory valuation adjustments of $445 million, losses on extinguishments of debt of $25 million and non-cash compensation expense of $82 million, partially offset by the gain on the sale of AmeriGas common units of $177 million and a deferred income tax benefit of $4 million.
Investing Activities
Cash flows from investing activities primarily consist of cash amounts paid for acquisitions, capital expenditures, and cash contributions to our joint ventures. Changes in capital expenditures between periods primarily result from increases or decreases in growth capital expenditures to fund their respective construction and expansion projects.
Following is a summary of investing activities by period:
Year Ended December 31, 2016
Cash used in investing activities in 2016 of $8.93 billion was comprised primarily of capital expenditures of $7.72 billion (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs). ETP invested $5.44 billion for growth capital expenditures and $368 million for maintenance capital expenditures during 2016. We paid net cash for acquisitions of $1.40 billion, including the acquisition of a noncontrolling interest.
Year Ended December 31, 2015
Cash used in investing activities in 2015 of $9.68 billion was comprised primarily of capital expenditures of $9.02 billion (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs). ETP invested $7.68 billion for growth capital expenditures and $485 million for maintenance capital expenditures during 2015. We paid net cash for acquisitions of $906 million, including the acquisition of a noncontrolling interest.
Year Ended December 31, 2014
Cash used in investing activities in 2014 of $6.87 billion was comprised primarily of capital expenditures of $5.37 billion (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs). ETP invested $5.05 billion for growth capital expenditures and $444 million for maintenance capital expenditures during 2014. Regency invested $1.20 billion for growth capital expenditures and $98 million for maintenance capital expenditures during 2014. We paid cash for acquisitions of $2.37 billion and received $814 million in cash received from the sale of AmeriGas common units.
Financing Activities
Changes in cash flows from financing activities between periods primarily result from changes in the levels of borrowings and equity issuances, which are primarily used to fund acquisitions and growth capital expenditures. Distributions increase between the periods based on increases in the number of common units outstanding or increases in the distribution rate.
Following is a summary of financing activities by period:
Year Ended December 31, 2016
Cash provided by financing activities was $5.93 billion in 2016. We had a consolidated increase in our debt level of $6.71 billion, primarily due to the issuance of Parent Company and subsidiary senior notes, as well as increases in our revolving credit facilities during 2015. Our subsidiaries also received $2.56 billion in proceeds from common unit offerings, including $1.10 billion from the issuance of ETP Common Units and $1.46 billion from the issuance of other subsidiary common units. We paid distributions to partners of $1.02 billion, and our subsidiaries paid $2.77 billion on limited partner interests other than those held by the Parent Company.
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Year Ended December 31, 2015
Cash provided by financing activities was $6.79 billion in 2015. We had a consolidated increase in our debt level of $6.63 billion, primarily due to the issuance of Parent Company and subsidiary senior notes, as well as increases in our revolving credit facilities during 2015. Our subsidiaries also received $3.89 billion in proceeds from common unit offerings, including $1.43 billion from the issuance of ETP Common Units and $2.46 billion from the issuance of other subsidiary common units. We paid distributions to partners of $1.09 billion, and our subsidiaries paid $2.34 billion on limited partner interests other than those held by the Parent Company. We also paid $1.06 billion to repurchase common units during the year ended December 31, 2015.
Year Ended December 31, 2014
Cash provided by financing activities was $3.88 billion in 2014. We had a consolidated increase in our debt level of $4.49 billion, primarily due to Regency’s issuance of senior notes and assumption and debt, and Sunoco Logistics’ issuance of $2.00 billion in aggregate principal amount of senior notes in April 2014 and November 2014 (see Note 6 to our consolidated financial statements) and an increase of the Parent Company’s debt of $1.88 billion. Our subsidiaries also received $3.06 billion in proceeds from common unit offerings, including $1.38 billion from the issuance of ETP Common Units, $428 million from the issuance of Regency Common Units and $1.25 billion from the issuance of other subsidiary common units. We paid distributions to partners of $821 million, and our subsidiaries paid $1.91 billion on limited partner interests other than those held by the Parent Company. We also paid $1.00 billion to repurchase common units during the year ended December 31, 2014.
Discontinued Operations
Following is a summary of activities related to discontinued operations by period:
Year Ended December 31, 2016
Cash used in discontinued operations was $384 million for the year ended December 31, 2016 resulting from cash provided by operating activities of $146 million, cash used in investing activities of $535 million and changes in cash included in current assets held for sale of $5 million.
Year Ended December 31, 2015
Cash used in discontinued operations was $262 million for the year ended December 31, 2015 resulting from cash provided by operating activities of $162 million, cash used in investing activities of $410 million and changes in cash included in current assets held for sale of $14 million.
Year Ended December 31, 2014
Cash provided by discontinued operations was $363 million for the year ended December 31, 2014 resulting from cash provided by operating activities of $290 million, cash provided by investing activities of $74 million and changes in cash included in current assets held for sale of $1 million.
Description of Indebtedness
See information previously included in our Form 10-K filed on February 24, 2017.
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Contractual Obligations
The following table summarizes our long-term debt and other contractual obligations as of December 31, 2016:

|  | Payments Due by Period
Contractual Obligations |  | Total |  | Less Than 1 Year |  | 1-3 Years |  | 3-5 Years |  | More Than 5 Years
Long-term debt |  | $ | 43,958 |  |  | $ | 1,817 |  |  | $ | 12,013 |  |  | $ | 7,666 |  |  | $ | 22,462 |
Interest on long-term debt(1) |  | 22,063 |  |  | 2,086 |  |  | 3,805 |  |  | 2,879 |  |  | 13,293 |
Payments on derivatives |  | 194 |  |  | 120 |  |  | 74 |  |  | — |  |  | — |
Purchase commitments(2) |  | 6,799 |  |  | 4,444 |  |  | 929 |  |  | 621 |  |  | 805 |
Transportation, natural gas storage and fractionation contracts |  | 44 |  |  | 24 |  |  | 20 |  |  | — |  |  | — |
Operating lease obligations |  | 528 |  |  | 82 |  |  | 122 |  |  | 105 |  |  | 219 |
Other(3) |  | 46 |  |  | 8 |  |  | 15 |  |  | 15 |  |  | 8 |
Total(4) |  | $ | 73,632 |  |  | $ | 8,581 |  |  | $ | 16,978 |  |  | $ | 11,286 |  |  | $ | 36,787 |

(1) | Interest payments on long-term debt are based on the principal amount of debt obligations as of December 31, 2016. With respect to variable rate debt, the interest payments were estimated using the interest rate as of December 31, 2016. To the extent interest rates change, our contractual obligation for interest payments will change. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” of the Partnership’s Annual Report on Form 10-K filed February 24, 2017 for further discussion.

(2) | We define a purchase commitment as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on us that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions. We have long and short-term product purchase obligations for refined product and energy commodities with third-party suppliers. These purchase obligations are entered into at either variable or fixed prices. The purchase prices that we are obligated to pay under variable price contracts approximate market prices at the time we take delivery of the volumes. Our estimated future variable price contract payment obligations are based on the December 31, 2016 market price of the applicable commodity applied to future volume commitments. Actual future payment obligations may vary depending on market prices at the time of delivery. The purchase prices that we are obligated to pay under fixed price contracts are established at the inception of the contract. Our estimated future fixed price contract payment obligations are based on the contracted fixed price under each commodity contract. Obligations shown in the table represent estimated payment obligations under these contracts for the periods indicated.

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

(4) | Excludes net non-current deferred tax liabilities of $5.11 billion due to uncertainty of the timing of future cash flows for such liabilities.

Cash Distributions
See information previously included in our Form 10-K filed on February 24, 2017.
New Accounting Standards
See information previously included in our Form 10-K filed on February 24, 2017.
Estimates and Critical Accounting Policies
The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules, and we believe the proper implementation and consistent application of the accounting rules are critical. Our critical accounting policies are discussed below. For further details on our accounting policies, see Note 2 to our consolidated financial statements.
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Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the operating results estimated for the year ended December 31, 2016 represent the actual results in all material respects.
Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation, depletion and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.
Revenue Recognition. Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale. Revenues from service labor, transportation, treating, compression and gas processing, are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available.
The results of ETP’s intrastate transportation and storage and interstate transportation operations are determined primarily by the amount of capacity ETP’s customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, ETP 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. Excess fuel retained after consumption is typically valued at market prices.
ETP’s intrastate transportation and storage operations also generate revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, ETP purchases natural gas from the market, including purchases from the midstream marketing operations, and from producers at the wellhead.
In addition, ETP’s intrastate transportation and storage operations generate revenues and margin from fees charged for storing customers’ working natural gas in our storage facilities. ETP also engages in natural gas storage transactions in which ETP seeks to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. ETP purchases physical natural gas and then sells financial contracts at a price sufficient to cover ETP’s carrying costs and provide for a gross profit margin. ETP expects margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, ETP cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.
Results from ETP’s midstream operations are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through ETP’s pipeline and gathering systems and the level of natural gas and NGL prices. ETP generates midstream revenues and segment margins principally under fee-based or other arrangements in which ETP receives a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through ETP’s systems and is not directly dependent on commodity prices.
ETP also utilizes other types of arrangements in ETP’s midstream operations, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price, and (iii) keep-whole arrangements where ETP gathers natural gas from the producer, processes the natural gas and sells the resulting NGLs to third parties at market prices. In many cases, ETP provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of ETP’s contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. ETP’s contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.
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ETP conducts marketing activities in which ETP markets the natural gas that flows through ETP’s assets, referred to as on-system gas. ETP also attracts other customers by marketing volumes of natural gas that do not move through ETP’s assets, referred to as off-system gas. For both on-system and off-system gas, ETP purchases natural gas from natural gas producers and other supply points and sells 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.
ETP has a risk management policy that provides for oversight over ETP’s marketing activities. These activities are monitored independently by ETP’s risk management function and must take place within predefined limits and authorizations. As a result of ETP’s use of derivative financial instruments that may not qualify for hedge accounting, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. ETP attempts to manage this volatility through the use of daily position and profit and loss reports provided to senior management and predefined limits and authorizations set forth in ETP’s risk management policy.
ETP injects and holds natural gas in our Bammel storage facility to take advantage of contango markets, when the price of natural gas is higher in the future than the current spot price. ETP uses financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, ETP locks in a margin by purchasing gas in the spot market or off peak season and entering a financial contract to lock in the sale price. If ETP designates the related financial contract as a fair value hedge for accounting purposes, ETP values the hedged natural gas inventory at current spot market prices along with the financial derivative ETP uses to hedge it. Changes in the spread between the forward natural gas prices designated as fair value hedges and the physical inventory spot prices result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated 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. Unrealized margins represent the unrealized gains or losses from our derivative instruments using mark-to-market accounting, with changes in the fair value of our derivatives being recorded directly in earnings. These margins fluctuate based upon changes in the spreads between the physical spot prices and forward natural gas prices. If the spread narrows between the physical and financial prices, ETP will record unrealized gains or lower unrealized losses. If the spread widens, ETP will record unrealized losses or lower unrealized gains. Typically, as ETP enters the winter months, the spread converges so that ETP recognizes in earnings the original locked in spread, either through mark-to-market or the physical withdrawal of natural gas.
ETP’s NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third-party pipeline, which is when title and risk of loss pass to the customer.
In ETP’s natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized.
Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.
Retail marketing operations sell gasoline and diesel in addition to a broad mix of merchandise such as groceries, fast foods and beverages at its convenience stores. A portion of our gasoline and diesel sales are to wholesale customers on a consignment basis, in which we retain title to inventory, control access to and sale of fuel inventory, and recognize revenue at the time the fuel is sold to the ultimate customer. We typically own the fuel dispensing equipment and underground storage tanks at consignment sites, and in some cases we own the entire site and have entered into an operating lease whit the wholesale customer operating the site. In addition, our retail outlets derive other income from lottery ticket sales, money orders, prepaid phone cards and wireless services, ATM transactions, car washes, movie rental and other ancillary product and service offerings. Some of Sunoco, Inc.’s retail outlets provide a variety of car care services. Revenues related to the sale of products are recognized when title passes, while service revenues are recorded on a net commission basis and are recognized when services are provided. Title passage generally occurs when products are shipped or delivered in accordance with the terms of the respective sales agreements. In addition, revenues are not recognized until sales prices are fixed or determinable and collectability is reasonably assured.
Regulatory Assets and Liabilities. Certain of our subsidiaries are subject to regulation by certain state and federal authorities and have accounting policies that conform to FASB Accounting Standards Codification (“ASC”) Topic 980, Regulated Operations, which is in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application
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of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.
Accounting for Derivative Instruments and Hedging Activities. ETP utilizes various exchange-traded and over-the-counter commodity financial instrument contracts to limit their exposure to margin fluctuations in natural gas, NGL and refined products. These contracts consist primarily of commodity futures and swaps. In addition, prior to ETP’s contribution of its retail propane activities to AmeriGas, ETP used derivatives to limit its exposure to propane market prices.
If ETP designates a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, the change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.
If ETP designates a hedging relationship as a fair value hedge, they record the changes in fair value of the hedged asset or liability in cost of products sold in the consolidated statement of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statement of operations.
ETP utilizes published settlement prices for exchange-traded contracts, quotes provided by brokers, and estimates of market prices based on daily contract activity to estimate the fair value of these contracts. Changes in the methods used to determine the fair value of these contracts could have a material effect on our results of operations. We do not anticipate future changes in the methods used to determine the fair value of these derivative contracts. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk,” of the Partnership’s Annual Report on Form 10-K filed February 24, 2017 for further discussion regarding our derivative activities.
Fair Value of Financial Instruments. We have commodity derivatives, interest rate derivatives and embedded derivatives in the ETP Preferred Units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. Derivatives related to the embedded derivatives in our preferred units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered level 3. See further information on our fair value assets and liabilities in Note 2 of our consolidated financial statements.
Impairment of Long-Lived Assets and Goodwill. Long-lived assets are required to be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Goodwill and intangibles with indefinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. An impairment loss should be recognized only if the carrying amount of the asset/goodwill is not recoverable and exceeds its fair value.
In order to test for recoverability when performing a quantitative impairment test, we must make estimates of projected cash flows related to the asset, which include, but are not limited to, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and future expenditures necessary to maintain the asset’s existing service potential. In order to determine fair
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value, we make certain estimates and assumptions, including, among other things, changes in general economic conditions in regions in which our markets are located, the availability and prices of natural gas, our ability to negotiate favorable sales agreements, the risks that natural gas exploration and production activities will not occur or be successful, our dependence on certain significant customers and producers of natural gas, and competition from other companies, including major energy producers. While we believe we have made reasonable assumptions to calculate the fair value, if future results are not consistent with our estimates, we could be exposed to future impairment losses that could be material to our results of operations.
The Partnership determined the fair value of its reporting units using a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determined fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determined the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimated a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.
One key assumption for the measurement of goodwill impairment is management’s estimate of future cash flows and EBITDA. These estimates are based on the annual budget for the upcoming year and forecasted amounts for multiple subsequent years. The annual budget process is typically completed near the annual goodwill impairment testing date, and management uses the most recent information for the annual impairment tests. The forecast is also subjected to a comprehensive update annually in conjunction with the annual budget process and is revised periodically to reflect new information and/or revised expectations. The estimates of future cash flows and EBITDA are subjective in nature and are subject to impacts from the business risks described in “Item 1A. Risk Factors” of the Partnership’s Annual Report on Form 10-K filed February 24, 2017. Therefore, the actual results could differ significantly from the amounts used for goodwill impairment testing, and significant changes in fair value estimates could occur in a given period.
For Energy Transfer Partners, L.P., the goodwill impairments recorded during the years ended December 31, 2016 and 2015 represented all of the goodwill within the respective reporting units. For Sunoco LP, the impairment of $642 million during the year ended December 31, 2016 represented a portion of the goodwill within Sunoco LP’s retail reporting unit. In the discounted cash flow model used to measure the goodwill impairment in Sunoco LP’s retail reporting unit, the key assumptions were developed as follows:

• | The estimated future cash flows were based on management’s forecasted cash flows and reflected long-term growth that management believed was reasonable.

• | The discount rate applied to the estimated cash flows was based on an assumed weighted average cost of capital calculated using information on the capital structures of six peer companies.

The key assumptions in the guideline company model used to measure the goodwill impairment in Sunoco LP’s retail reporting unit were developed as follows:

• | A multiple was applied to expected EBITDA for 2017, with the multiple based on consideration of the reporting unit’s growth, size, profitability, geographic diversity, and risk profile compared with those of the same peer group that was used in the calculation of the discount rate discussed in the discounted cash flow model assumptions above.

• | The model also reflected a control premium, which was estimated at an equity level based on observed transaction premiums and based on the hypothetical capital structure for the industry, as well as considering the specific attributes of the reporting unit.

Property, Plant and Equipment. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, ETP capitalizes certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition
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or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in the consolidated statement of operations. Depreciation of property, plant and equipment is provided using the straight-line method based on their estimated useful lives ranging from 1 to 99 years. Changes in the estimated useful lives of the assets could have a material effect on our results of operation. We do not anticipate future changes in the estimated useful lives of our property, plant and equipment.
Asset Retirement Obligations. We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.
An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably estimate the settlement dates.
Except for certain amounts recorded by Panhandle and Sunoco Logistics discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 2016 and 2015, in most cases because the settlement dates were indeterminable. Although a number of other onshore assets in Panhandle’s system are subject to agreements or regulations that give rise to an ARO upon Panhandle’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Sunoco, Inc. has legal asset retirement obligations for several other assets at its previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, Sunoco, Inc. is legally or contractually required to abandon in place or remove the asset. Sunoco Logistics believes it may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time.
Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future. We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.
Long-lived assets related to AROs aggregated $14 million and $18 million, and were reflected as property, plant and equipment on our balance sheet as of December 31, 2016 and 2015, respectively. In addition, the Partnership had $13 million and $6 million legally restricted funds for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2016 and 2015, respectively.
Pensions and Other Postretirement Benefit Plans. We are required to measure plan assets and benefit obligations as of its fiscal year-end balance sheet date. We recognize the changes in the funded status of our defined benefit postretirement plans through AOCI or are reflected as a regulatory asset or regulatory liability for regulated subsidiaries.
The calculation of the net periodic benefit cost and benefit obligation requires the use of a number of assumptions. Changes in these assumptions can have a significant effect on the amounts reported in the financial statements. The Partnership believes that the two most critical assumptions are the assumed discount rate and the expected rate of return on plan assets.
The discount rate is established by using a hypothetical portfolio of high-quality debt instruments that would provide the necessary cash flows to pay the benefits when due. Net periodic benefit cost and benefit obligation increases and equity correspondingly decreases as the discount rate is reduced.
The expected rate of return on plan assets is based on long-term expectations given current investment objectives and historical results. Net periodic benefit cost increases as the expected rate of return on plan assets is correspondingly reduced.
Legal Matters. We are subject to litigation and regulatory proceedings as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from claims, orders, judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. We expense legal costs as incurred, and all recorded legal liabilities are revised as required as better information becomes available to us. The factors we consider when recording an accrual for contingencies
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include, among others: (i) the opinions and views of our legal counsel; (ii) our previous experience; and (iii) the decision of our management as to how we intend to respond to the complaints.
For more information on our litigation and contingencies, see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” in this report.
Environmental Remediation Activities. The Partnership’s accrual for environmental remediation activities reflects anticipated work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. The accrual for known claims is undiscounted and is based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. It is often extremely difficult to develop reasonable estimates of future site remediation costs due to changing regulations, changing technologies and their associated costs, and changes in the economic environment. Engineering studies, historical experience and other factors are used to identify and evaluate remediation alternatives and their related costs in determining the estimated accruals for environmental remediation activities.
Losses attributable to unasserted claims are generally reflected in the accruals on an undiscounted basis, to the extent they are probable of occurrence and reasonably estimable. ETP has established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, ETP accrues losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.
In general, each remediation site/issue is evaluated individually based upon information available for the site/issue and no pooling or statistical analysis is used to evaluate an aggregate risk for a group of similar items (e.g., service station sites) in determining the amount of probable loss accrual to be recorded. ETP’s estimates of environmental remediation costs also frequently involve evaluation of a range of estimates. In many cases, it is difficult to determine that one point in the range of loss estimates is more likely than any other. In these situations, existing accounting guidance requires that the minimum of the range be accrued. Accordingly, the low end of the range often represents the amount of loss which has been recorded.
In addition to the probable and estimable losses which have been recorded, management believes it is reasonably possible (i.e., less than probable but greater than remote) that additional environmental remediation losses will be incurred. At December 31, 2016, the aggregate of the estimated maximum additional reasonably possible losses, which relate to numerous individual sites, totaled approximately $5 million. This estimate of reasonably possible losses comprises estimates for remediation activities at current logistics and retail assets and, in many cases, reflects the upper end of the loss ranges which are described above. Such estimates include potentially higher contractor costs for expected remediation activities, the potential need to use more costly or comprehensive remediation methods and longer operating and monitoring periods, among other things.
Total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the nature of operations at each site, the technology available and needed to meet the various existing legal requirements, the nature and terms of cost-sharing arrangements with other potentially responsible parties, the availability of insurance coverage, the nature and extent of future environmental laws and regulations, inflation rates, terms of consent agreements or remediation permits with regulatory agencies and the determination of the Partnership’s liability at the sites, if any, in light of the number, participation level and financial viability of the other parties. The recognition of additional losses, if and when they were to occur, would likely extend over many years. Management believes that the Partnership’s exposure to adverse developments with respect to any individual site is not expected to be material. However, if changes in environmental laws or regulations occur or the assumptions used to estimate losses at multiple sites are adjusted, such changes could impact multiple facilities, formerly owned facilities and third-party sites at the same time. As a result, from time to time, significant charges against income for environmental remediation may occur; however, management does not believe that any such charges would have a material adverse impact on the Partnership’s consolidated financial position.
Deferred Income Taxes. ETE recognizes benefits in earnings and related deferred tax assets for net operating loss carryforwards (“NOLs”) and tax credit carryforwards. If necessary, a charge to earnings and a related valuation allowance are recorded to reduce deferred tax assets to an amount that is more likely than not to be realized by the Partnership in the future. Deferred income tax assets attributable to state and federal NOLs and federal tax alternative minimum tax credit carryforwards totaling $472 million have been included in ETE’s consolidated balance sheet as of December 31, 2016. All of the deferred income tax assets attributable to state and federal NOL benefits expire before 2036 as more fully described below. The state NOL carryforward benefits of $127 million (net of federal benefit) begin to expire in 2017 with a substantial portion expiring between 2029 and 2036. The federal NOLs of $835 million ($292 million in benefits) will expire in 2032 and 2035. Federal tax alternative minimum tax credit carryforwards of $52 million remained at December 31, 2016. We have determined that a valuation allowance totaling $118
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million (net of federal income tax effects) is required for the state NOLs at December 31, 2016 primarily due to significant restrictions on their use in the Commonwealth of Pennsylvania. In making the assessment of the future realization of the deferred tax assets, we rely on future reversals of existing taxable temporary differences, tax planning strategies and forecasted taxable income based on historical and projected future operating results. The potential need for valuation allowances is regularly reviewed by management. If it is more likely than not that the recorded asset will not be realized, additional valuation allowances which increase income tax expense may be recognized in the period such determination is made. Likewise, if it is more likely than not that additional deferred tax assets will be realized, an adjustment to the deferred tax asset will increase income in the period such determination is made.
Forward-Looking Statements
This annual report contains various forward-looking statements and information that are based on our beliefs and those of our General Partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. When used in this annual report, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “could,” “believe,” “may,” “will” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our General Partner believe that the expectations on which such forward-looking statements are reasonable, neither we nor our General Partner can give assurances that such expectations 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, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are:

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

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

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

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

• | the fees our subsidiaries charge and the margins they realize for their gathering, treating, processing, storage and transportation services;

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

• | energy prices generally;

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

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

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

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

• | actions taken by foreign oil and gas producing nations;

• | the political and economic stability of petroleum producing nations;

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

• | availability of local, intrastate and interstate transportation systems;

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

• | availability and marketing of competitive fuels;

• | the impact of energy conservation efforts;

• | energy efficiencies and technological trends;

• | governmental regulation and taxation;

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

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

• | competition from other midstream companies and interstate pipeline companies;

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• | loss of key personnel;

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

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

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

• | the nonpayment or nonperformance by our subsidiaries’ customers;

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

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

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

• | a deterioration of the credit and capital markets;

• | risks associated with our significant level of stand-alone and consolidated debt and the incurrence or assumption of additional debt in connection with our proposed acquisition of WMB;

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

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

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

• | the costs and effects of legal and administrative proceedings.

You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risks described under “Item 1A. Risk Factors” in the Partnership’s Annual Report on Form 10-K filed February 24, 2017. Any forward-looking statement made by us in this report is based only on information currently available to us and speaks only as of the date on which it is made. We undertake no obligation to publicly update any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of new information, future developments or otherwise.
Inflation
Interest rates on existing and future credit facilities and future debt offerings could be significantly higher than current levels, causing our financing costs to increase accordingly. Although increased financing costs could limit our ability to raise funds in the capital markets, we expect to remain competitive with respect to acquisitions and capital projects since our competitors would face similar circumstances.
Inflation in the United States has been relatively low in recent years and has not had a material effect on our results of operations. It may in the future, however, increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. Our operating revenues and costs are influenced to a greater extent by commodity price changes. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along a portion of increased costs to our customers in the form of higher fees.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
Energy Transfer Equity, L.P. and Subsidiaries

| Page
Report of Independent Registered Public Accounting Firm | 45
Consolidated Balance Sheets | 46
Consolidated Statements of Operations | 48
Consolidated Statements of Comprehensive Income | 49
Consolidated Statements of Equity | 50
Consolidated Statements of Cash Flows | 52
Notes to Consolidated Financial Statements | 54

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Partners
Energy Transfer Equity, L.P.
We have audited the accompanying consolidated balance sheets of Energy Transfer Equity, L.P. (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2016 and 2015, and the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Energy Transfer Equity, L.P. and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership’s internal control over financial reporting as of December 31, 2016, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 24, 2017 (not separately included herein) expressed an unqualified opinion thereon.
We draw attention to Note 1 to the consolidated financial statements which describes the retrospective adjustments of certain unit and per unit amounts, to Note 3 to the consolidated financial statements which describes the retrospective adjustments to the consolidated financial statements for discontinued operations, and to Note 15 to the consolidated financial statements which has been retrospectively adjusted for amounts included in reportable segments.
/s/ GRANT THORNTON LLP
Dallas, Texas
February 24, 2017 (except for certain unit and per unit amounts as discussed in Note 1, for the discontinued operations discussed in Note 3 and the effects thereof, and for amounts included in reportable segments in Note 15, which are as of October 2, 2017)
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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)

| December 31,
| 2016 |  | 2015
ASSETS |  |  |
Current assets: |  |  |
Cash and cash equivalents | $ | 463 |  |  | $ | 581 |
Accounts receivable, net | 3,557 |  |  | 2,400 |
Accounts receivable from related companies | 47 |  |  | 119 |
Inventories | 2,103 |  |  | 1,465 |
Derivative assets | 21 |  |  | 46 |
Other current assets | 503 |  |  | 593 |
Current assets held for sale | 291 |  |  | 206 |
Total current assets | 6,985 |  |  | 5,410 |
Property, plant and equipment | 61,158 |  |  | 52,851 |
Accumulated depreciation and depletion | (7,905 | ) |  | (6,067 | )
| 53,253 |  |  | 46,784 |
Advances to and investments in unconsolidated affiliates | 3,040 |  |  | 3,462 |
Other non-current assets, net | 816 |  |  | 711 |
Intangible assets, net | 5,489 |  |  | 4,896 |
Goodwill | 5,170 |  |  | 5,485 |
Non-current assets held for sale | 4,258 |  |  | 4,441 |
Total assets | $ | 79,011 |  |  | $ | 71,189 |

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)

| December 31,
| 2016 |  | 2015
LIABILITIES AND EQUITY |  |  |
Current liabilities: |  |  |
Accounts payable | $ | 3,502 |  |  | $ | 2,274 |
Accounts payable to related companies | 42 |  |  | 28 |
Derivative liabilities | 172 |  |  | 69 |
Accrued and other current liabilities | 2,367 |  |  | 2,408 |
Current maturities of long-term debt | 1,194 |  |  | 131 |
Total current liabilities | 7,277 |  |  | 4,910 |
Long-term debt, less current maturities | 42,608 |  |  | 36,837 |
Long-term notes payable - related companies | 250 |  |  | — |
Deferred income taxes | 5,112 |  |  | 4,590 |
Non-current derivative liabilities | 76 |  |  | 137 |
Other non-current liabilities | 1,055 |  |  | 1,002 |
Liabilities associated with assets held for sale | 68 |  |  | 67 |
Commitments and contingencies |  |  |  |  |
Preferred units of subsidiary (Note 7) | 33 |  |  | 33 |
Redeemable noncontrolling interests | 15 |  |  | 15 |
Equity: |  |  |
General Partner | (3 | ) |  | (2 | )
Limited Partners: |  |  |
Common Unitholders (1,046,947,157 and 1,044,767,336 units authorized, issued and outstanding as of December 31, 2016 and 2015, respectively) | (1,871 | ) |  | (952 | )
Class D Units (2,156,000 units authorized, issued and outstanding as of December 31, 2015) | — |  |  | 22 |
Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2016) | 180 |  |  | — |
Total partners’ deficit | (1,694 | ) |  | (932 | )
Noncontrolling interest | 24,211 |  |  | 24,530 |
Total equity | 22,517 |  |  | 23,598 |
Total liabilities and equity | $ | 79,011 |  |  | $ | 71,189 |

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per unit data)

| Years Ended December 31,
| 2016 |  | 2015 |  | 2014
REVENUES: |  |  |  |  |
Natural gas sales | $ | 3,619 |  |  | $ | 3,671 |  |  | $ | 5,386 |
NGL sales | 4,841 |  |  | 3,935 |  |  | 5,845 |
Crude sales | 6,766 |  |  | 8,378 |  |  | 16,416 |
Gathering, transportation and other fees | 4,172 |  |  | 4,200 |  |  | 3,733 |
Refined product sales | 8,896 |  |  | 9,933 |  |  | 17,068 |
Other | 1,808 |  |  | 4,087 |  |  | 4,191 |
Total revenues | 30,102 |  |  | 34,204 |  |  | 52,639 |
COSTS AND EXPENSES: |  |  |  |  |
Cost of products sold | 22,636 |  |  | 27,435 |  |  | 45,861 |
Operating expenses | 1,727 |  |  | 1,728 |  |  | 1,811 |
Depreciation, depletion and amortization | 2,166 |  |  | 1,904 |  |  | 1,669 |
Selling, general and administrative | 693 |  |  | 548 |  |  | 556 |
Impairment losses | 970 |  |  | 339 |  |  | 370 |
Total costs and expenses | 28,192 |  |  | 31,954 |  |  | 50,267 |
OPERATING INCOME | 1,910 |  |  | 2,250 |  |  | 2,372 |
OTHER INCOME (EXPENSE): |  |  |  |  |
Interest expense, net | (1,803 | ) |  | (1,621 | ) |  | (1,368 | )
Equity in earnings from unconsolidated affiliates | 270 |  |  | 276 |  |  | 332 |
Impairment of investment in an unconsolidated affiliate | (308 | ) |  | — |  |  | — |
Gains on acquisitions | 83 |  |  | — |  |  | — |
Gain on sale of AmeriGas common units | — |  |  | — |  |  | 177 |
Losses on extinguishments of debt | — |  |  | (43 | ) |  | (25 | )
Losses on interest rate derivatives | (12 | ) |  | (18 | ) |  | (157 | )
Other, net | 132 |  |  | 20 |  |  | (12 | )
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT) | 272 |  |  | 864 |  |  | 1,319 |
Income tax expense (benefit) from continuing operations | (248 | ) |  | (148 | ) |  | 325 |
INCOME FROM CONTINUING OPERATIONS | 520 |  |  | 1,012 |  |  | 994 |
Income (loss) from discontinued operations, net of income taxes | (479 | ) |  | 81 |  |  | 130 |
NET INCOME | 41 |  |  | 1,093 |  |  | 1,124 |
Less: Net income (loss) attributable to noncontrolling interest | (954 | ) |  | (96 | ) |  | 491 |
NET INCOME ATTRIBUTABLE TO PARTNERS | 995 |  |  | 1,189 |  |  | 633 |
General Partner’s interest in net income | 3 |  |  | 3 |  |  | 2 |
Convertible Unitholders’ interest in income | 9 |  |  | — |  |  | — |
Class D Unitholder’s interest in net income | — |  |  | 3 |  |  | 2 |
Limited Partners’ interest in net income | $ | 983 |  |  | $ | 1,183 |  |  | $ | 629 |
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT: |  |  |  |  |
Basic | $ | 0.95 |  |  | $ | 1.11 |  |  | $ | 0.57 |
Diluted | $ | 0.93 |  |  | $ | 1.11 |  |  | $ | 0.57 |
NET INCOME PER LIMITED PARTNER UNIT: |  |  |  |  |
Basic | $ | 0.94 |  |  | $ | 1.11 |  |  | $ | 0.58 |
Diluted | $ | 0.92 |  |  | $ | 1.11 |  |  | $ | 0.58 |

The accompanying notes are an integral part of these consolidated financial statements.
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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)

| Years Ended December 31,
| 2016 |  | 2015 |  | 2014
Net income | $ | 41 |  |  | $ | 1,093 |  |  | $ | 1,124 |
Other comprehensive income (loss), net of tax: |  |  |  |  |
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges | — |  |  | — |  |  | 3 |
Change in value of available-for-sale securities | 2 |  |  | (3 | ) |  | 1 |
Actuarial gain (loss) relating to pension and other postretirement benefits | (1 | ) |  | 65 |  |  | (113 | )
Foreign currency translation adjustment | (1 | ) |  | (1 | ) |  | (2 | )
Change in other comprehensive income from unconsolidated affiliates | 4 |  |  | (1 | ) |  | (6 | )
| 4 |  |  | 60 |  |  | (117 | )
Comprehensive income | 45 |  |  | 1,153 |  |  | 1,007 |
Less: Comprehensive income (loss) attributable to noncontrolling interest | (950 | ) |  | (41 | ) |  | 388 |
Comprehensive income attributable to partners | $ | 995 |  |  | $ | 1,194 |  |  | $ | 619 |

The accompanying notes are an integral part of these consolidated financial statements.
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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
(Dollars in millions)

| General Partner |  | Common Unitholders |  | Class D Units |  | Series A Convertible Preferred Units |  | Accumulated Other Comprehensive Income (Loss) |  | Non- controlling Interest |  | Total
Balance, December 31, 2013 | $ | (3 | ) |  | $ | 1,066 |  |  | $ | 6 |  |  | $ | — |  |  | $ | 9 |  |  | $ | 15,201 |  |  | $ | 16,279 |
Distributions to partners | (2 | ) |  | (817 | ) |  | (2 | ) |  | — |  |  | — |  |  | — |  |  | (821 | )
Distributions to noncontrolling interest | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (1,905 | ) |  | (1,905 | )
Subsidiary units issued for cash | — |  |  | 148 |  |  | 2 |  |  | — |  |  | — |  |  | 2,907 |  |  | 3,057 |
Subsidiary units issued in certain acquisitions | — |  |  | 211 |  |  | — |  |  | — |  |  | — |  |  | 5,604 |  |  | 5,815 |
Subsidiary units redeemed in Lake Charles LNG Transaction | 2 |  |  | 480 |  |  | — |  |  | — |  |  | — |  |  | (482 | ) |  | — |
Purchase of additional Regency Units | — |  |  | (99 | ) |  | — |  |  | — |  |  | — |  |  | 99 |  |  | — |
Subsidiary acquisition of a noncontrolling interest | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (319 | ) |  | (319 | )
Non-cash compensation expense, net of units tendered by employees for tax withholdings | — |  |  | — |  |  | 14 |  |  | — |  |  | — |  |  | 51 |  |  | 65 |
Capital contributions received from noncontrolling interest | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 139 |  |  | 139 |
Other, net | — |  |  | 30 |  |  | — |  |  | — |  |  | — |  |  | (33 | ) |  | (3 | )
Units repurchased under buyback program | — |  |  | (1,000 | ) |  | — |  |  | — |  |  | — |  |  | — |  |  | (1,000 | )
Other comprehensive loss, net of tax | — |  |  | — |  |  | — |  |  | — |  |  | (14 | ) |  | (103 | ) |  | (117 | )
Net income | 2 |  |  | 629 |  |  | 2 |  |  | — |  |  | — |  |  | 491 |  |  | 1,124 |
Balance, December 31, 2014 | (1 | ) |  | 648 |  |  | 22 |  |  | — |  |  | (5 | ) |  | 21,650 |  |  | 22,314 |
Distributions to partners | (3 | ) |  | (1,084 | ) |  | (3 | ) |  | — |  |  | — |  |  | — |  |  | (1,090 | )
Distributions to noncontrolling interest | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (2,335 | ) |  | (2,335 | )
Subsidiary units issued | (1 | ) |  | (524 | ) |  | (1 | ) |  | — |  |  | — |  |  | 4,415 |  |  | 3,889 |
Conversion of Class D Units to ETE Common Units | — |  |  | 7 |  |  | (7 | ) |  | — |  |  | — |  |  | — |  |  | — |
Non-cash compensation expense, net of units tendered by employees for tax withholdings | — |  |  | — |  |  | 8 |  |  | — |  |  | — |  |  | 62 |  |  | 70 |
Capital contributions received from noncontrolling interest | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 875 |  |  | 875 |
Units repurchased under buyback program | — |  |  | (1,064 | ) |  | — |  |  | — |  |  | — |  |  | — |  |  | (1,064 | )
Acquisition and disposition of noncontrolling interest | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (65 | ) |  | (65 | )
Other comprehensive income, net of tax | — |  |  | — |  |  | — |  |  | — |  |  | 5 |  |  | 55 |  |  | 60 |
Other, net | — |  |  | (118 | ) |  | — |  |  | — |  |  | — |  |  | (31 | ) |  | (149 | )
Net income (loss) | 3 |  |  | 1,183 |  |  | 3 |  |  | — |  |  | — |  |  | (96 | ) |  | 1,093 |
Balance, December 31, 2015 | (2 | ) |  | (952 | ) |  | 22 |  |  | — |  |  | — |  |  | 24,530 |  |  | 23,598 |
Distributions to partners | (3 | ) |  | (1,019 | ) |  | — |  |  | — |  |  | — |  |  | — |  |  | (1,022 | )
Distributions to noncontrolling interest | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (2,795 | ) |  | (2,795 | )
Distributions reinvested | — |  |  | (173 | ) |  | — |  |  | 173 |  |  | — |  |  | — |  |  | — |
Subsidiary units issued for cash | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 2,559 |  |  | 2,559 |
Subsidiary units issued for acquisition | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 307 |  |  | 307 |
Issuance of common units | — |  |  | 39 |  |  |  |  |  | (2 | ) |  | — |  |  | — |  |  | 37 |
Non-cash compensation expense, net of units tendered by employees for tax withholdings | — |  |  | — |  |  | (22 | ) |  | — |  |  | — |  |  | 74 |  |  | 52 |

The accompanying notes are an integral part of these consolidated financial statements.
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Capital contributions received from noncontrolling interest | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 236 |  |  | 236 |
Acquisition and disposition of noncontrolling interest | — |  |  | (779 | ) |  | — |  |  | — |  |  | — |  |  | — |  |  | (779 | )
PennTex Acquisition | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 236 |  |  | 236 |
Other comprehensive income, net of tax | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 4 |  |  | 4 |
Other, net | (1 | ) |  | 30 |  |  | — |  |  | — |  |  | — |  |  | 14 |  |  | 43 |
Net income (loss) | 3 |  |  | 983 |  |  | — |  |  | 9 |  |  | — |  |  | (954 | ) |  | 41 |
Balance, December 31, 2016 | $ | (3 | ) |  | $ | (1,871 | ) |  | $ | — |  |  | $ | 180 |  |  | $ | — |  |  | $ | 24,211 |  |  | $ | 22,517 |

The accompanying notes are an integral part of these consolidated financial statements.
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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)

| Years Ended December 31,
| 2016 |  | 2015 |  | 2014
OPERATING ACTIVITIES: |  |  |  |  |
Net income | $ | 41 |  |  | $ | 1,093 |  |  | $ | 1,124 |
Reconciliation of net income to net cash provided by operating activities: |  |  |  |  |
Loss (income) from discontinued operations | 479 |  |  | (81 | ) |  | (130 | )
Depreciation, depletion and amortization | 2,166 |  |  | 1,904 |  |  | 1,669 |
Deferred income taxes | (225 | ) |  | 221 |  |  | (4 | )
Amortization included in interest expense | 3 |  |  | (21 | ) |  | (51 | )
Unit-based compensation expense | 70 |  |  | 91 |  |  | 82 |
Impairment losses | 970 |  |  | 339 |  |  | 370 |
Gains on acquisitions | (83 | ) |  | — |  |  | — |
Gain on sale of AmeriGas common units | — |  |  | — |  |  | (177 | )
Losses on extinguishments of debt | — |  |  | 43 |  |  | 25 |
Impairment of investment in an unconsolidated affiliate | 308 |  |  | — |  |  | — |
(Gains) losses on disposal of assets | 2 |  |  | (6 | ) |  | — |
Equity in earnings of unconsolidated affiliates | (270 | ) |  | (276 | ) |  | (332 | )
Distributions from unconsolidated affiliates | 268 |  |  | 409 |  |  | 291 |
Inventory valuation adjustments | (267 | ) |  | 229 |  |  | 445 |
Other non-cash | (229 | ) |  | (8 | ) |  | (89 | )
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | 36 |  |  | (1,032 | ) |  | (338 | )
Net cash provided by operating activities | 3,269 |  |  | 2,905 |  |  | 2,885 |
INVESTING ACTIVITIES: |  |  |  |  |
Proceeds from sale of noncontrolling interest | — |  |  | 64 |  |  | — |
Proceeds from the sale of AmeriGas common units | — |  |  | — |  |  | 814 |
Cash paid for acquisitions, net of cash received | (1,398 | ) |  | (777 | ) |  | (2,367 | )
Cash paid for acquisition of a noncontrolling interest | — |  |  | (129 | ) |  | — |
Capital expenditures, excluding allowance for equity funds used during construction | (7,719 | ) |  | (9,021 | ) |  | (5,369 | )
Contributions in aid of construction costs | 71 |  |  | 80 |  |  | 45 |
Contributions to unconsolidated affiliates | (68 | ) |  | (45 | ) |  | (334 | )
Distributions from unconsolidated affiliates in excess of cumulative earnings | 135 |  |  | 128 |  |  | 136 |
Proceeds from the sale of other assets | 35 |  |  | 14 |  |  | 54 |
Change in restricted cash | 14 |  |  | 19 |  |  | 172 |
Other | — |  |  | (16 | ) |  | (19 | )
Net cash used in investing activities | (8,930 | ) |  | (9,683 | ) |  | (6,868 | )
FINANCING ACTIVITIES: |  |  |  |  |
Proceeds from borrowings | 25,785 |  |  | 26,455 |  |  | 18,375 |
Repayments of long-term debt | (19,076 | ) |  | (19,828 | ) |  | (13,886 | )
Cash received from affiliate notes | 5,317 |  |  | — |  |  | — |
Cash paid on affiliate notes | (5,051 | ) |  | — |  |  | — |
Subsidiary units issued for cash | 2,559 |  |  | 3,889 |  |  | 3,057 |
Distributions to partners | (1,022 | ) |  | (1,090 | ) |  | (821 | )
Distributions to noncontrolling interests | (2,766 | ) |  | (2,335 | ) |  | (1,905 | )
Debt issuance costs | (52 | ) |  | (75 | ) |  | (77 | )
Capital contributions from noncontrolling interest | 236 |  |  | 841 |  |  | 139 |
Units repurchased under buyback program | — |  |  | (1,064 | ) |  | (1,000 | )
Other, net | (3 | ) |  | (8 | ) |  | (5 | )
Net cash provided by financing activities | 5,927 |  |  | 6,785 |  |  | 3,877 |
DISCONTINUED OPERATIONS |  |  |  |  |
Operating activities | 146 |  |  | 162 |  |  | 290 |
Investing activities | (535 | ) |  | (410 | ) |  | 74 |
Changes in cash included in current assets held for sale | 5 |  |  | (14 | ) |  | (1 | )

The accompanying notes are an integral part of these consolidated financial statements.
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Net increase (decrease) in cash and cash equivalents of discontinued operations | (384 | ) |  | (262 | ) |  | 363 |
Increase (decrease) in cash and cash equivalents | (118 | ) |  | (255 | ) |  | 257 |
Cash and cash equivalents, beginning of period | 581 |  |  | 836 |  |  | 579 |
Cash and cash equivalents, end of period | $ | 463 |  |  | $ | 581 |  |  | $ | 836 |

The accompanying notes are an integral part of these consolidated financial statements.
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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular dollar and unit amounts, except per unit data, are in millions)

1. | OPERATIONS AND ORGANIZATION:

Financial Statement Presentation
The consolidated financial statements of Energy Transfer Equity, L.P. (the “Partnership,” “we” or “ETE”) presented herein for the years ended December 31, 2016, 2015, and 2014, have been prepared in accordance with GAAP and pursuant to the rules and regulations of the SEC. We consolidate all majority-owned subsidiaries and limited partnerships, which we control as the general partner or owner of the general partner. All significant intercompany transactions and accounts are eliminated in consolidation.
Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP, ETP GP, ETP LLC, ETE Common Holdings, LLC, Panhandle (or Southern Union prior to its merger into Panhandle in January 2014), Sunoco Logistics, Sunoco LP and ETP Holdco. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.
As discussed in Note 8, in January 2014 and July 2015, the Partnership completed two-for-one splits of ETE Common Units. All references to unit and per unit amounts in the consolidated financial statements and in these notes to the consolidated financial statements have been adjusted to reflect the effects of the unit splits for all periods presented.
The historical common units for ETP presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger, defined below.
At December 31, 2016, our interests in ETP and Sunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as 3.9 million ETP common units, 81.0 million ETP Class H units and 2.3 million Sunoco LP common units held by us or our wholly-owned subsidiaries. We also own 0.1% of Sunoco Partners LLC, the entity that owns the general partner interest and IDRs of Sunoco Logistics, while ETP owns the remaining 99.9% of Sunoco Partners LLC. Additionally, ETE owns 100 ETP Class I Units, the distributions from which offset a portion of IDR subsidies ETE has previously provided to ETP.
In April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed a merger transaction (the “Sunoco Logistics Merger”) in which Sunoco Logistics acquired Energy Transfer Partners, L.P. in a unit-for-unit transaction. Prior to the Sunoco Logistics Merger, Sunoco Logistics was a consolidated subsidiary of Energy Transfer Partners, L.P. Under the terms of the transaction, the unitholders received 1.5 common units of Sunoco Logistics for each Energy Transfer Partners, L.P. common unit they owned. Under the terms of the merger agreement, Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE. Based on the number of Energy Transfer Partners, L.P. common units outstanding at the closing of the merger, Sunoco Logistics issued approximately 832 million Sunoco Logistics common units to Energy Transfer Partners, L.P. unitholders. In connection with the merger, the Energy Transfer Partners, L.P. Class H units were cancelled. The outstanding Energy Transfer Partners, L.P. Class E units, Class G units, Class I units and Class K units at the effective time of the merger were converted into an equal number of newly created classes of Sunoco Logistics units, with the same rights, preferences, privileges, duties and obligations as such classes of Energy Transfer Partners, L.P. units had immediately prior to the closing of the merger. Additionally, the outstanding Sunoco Logistics common units and Sunoco Logistics Class B units owned by Energy Transfer Partners, L.P. at the effective time of the merger were cancelled.
Prior to the Sunoco Logistics Merger, ETE owned 18.4 million Energy Transfer Partners, L.P. common units (representing 3.3% of the total outstanding common units), 81 million Energy Transfer Partners, L.P. Class H units and 100 Energy Transfer Partners, L.P. Class I units. In connection with the Sunoco Logistics Merger, the Class H units were cancelled, and ETE now owns 27.5 million ETP common units (representing 2.5% of the total outstanding common units) and 100 ETP Class I units. The ETP Class I units have the same rights, privileges, duties and obligations as those historically associated with the Class I units prior to the Sunoco Logistics Merger.
At the time of the Sunoco Logistics Merger, Energy Transfer Partners, L.P. changed its name from “Energy Transfer Partners, L.P.” to “Energy Transfer, LP” and Sunoco Logistics Partners L.P. changed its name to “Energy Transfer Partners, L.P.” Energy Transfer, LP is a wholly-owned subsidiary of Energy Transfer Partners, L.P. For purposes of maintaining clarity, the following references are used herein:

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

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

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

The consolidated financial statements of ETE presented herein include the results of operations of:

• | the Parent Company;

• | our controlled subsidiaries, ETP and Sunoco LP;

• | consolidated subsidiaries of our controlled subsidiaries and our wholly-owned subsidiaries that own general partner interests and IDR interests in ETP and Sunoco LP; and

• | our wholly-owned subsidiary, Lake Charles LNG.

Our subsidiaries also own varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, we apply proportionate consolidation for our interests in these entities.
Certain prior period amounts have been reclassified to conform to the 2016 presentation. These reclassifications had no impact on net income or total equity.
Business Operations
The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Sunoco LP. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to understand the financial condition of the Parent Company on a stand-alone basis, see Note 17 for stand-alone financial information apart from that of the consolidated partnership information included herein.
ETP is a publicly traded partnership whose operations comprise the following:

• | the gathering and processing, compression, treating and transportation of natural gas, focusing on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring, and Avalon shales;

• | intrastate transportation and storage natural gas operations that own and operate natural gas pipeline systems that are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia;

• | interstate pipelines that are owned and operated, either directly or through equity method investments, that transport natural gas to various markets in the United States; and

• | a controlling interest in Sunoco Logistics, a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of crude oil, NGL and refined products pipelines.

Sunoco LP is a publicly traded partnership engaged in retail sale of motor fuels and merchandise through its company-operated convenience stores and retail fuel sites, as well as the wholesale distribution of motor fuels to convenience stores, independent dealers, commercial customers and distributors.
Lake Charles LNG operates a LNG import terminal, which has approximately 9.0 Bcf of above ground LNG storage capacity and re-gasification facilities on Louisiana’s Gulf Coast near Lake Charles, Louisiana. Lake Charles LNG is engaged in interstate commerce and is subject to the rules, regulations and accounting requirements of the FERC.
Our financial statements reflect the following reportable business segments:
•Investment in ETP, including the consolidated operations of ETP;
•Investment in Sunoco LP, including the consolidated operations of Sunoco LP;
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•Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and
•Corporate and Other including the following:
•activities of the Parent Company; and

• | the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

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

Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.
Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation, amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.
New Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.
In August 2015, the FASB deferred the effective date of ASU 2014-09, which is now effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The guidance permits two methods of adoption: retrospectively to each prior reporting period presented (full retrospective method), or retrospectively with the cumulative effect of initially applying the guidance recognized at the date of initial application (the cumulative catchup transition method). The Partnership expects to adopt ASU 2014-09 in the first quarter of 2018 and will apply the cumulative catchup transition method.
We are in the process of evaluating our revenue contracts by segment and fee type to determine the potential impact of adopting the new standards. At this point in our evaluation process, we have determined that the timing and/or amount of revenue that we recognize on certain contracts may be impacted by the adoption of the new standard; however, we are still in the process of quantifying these impacts and cannot say whether or not they would be material to our financial statements. In addition, we are in the process of implementing appropriate changes to our business processes, systems and controls to support recognition and disclosure under the new standard. We continue to monitor additional authoritative or interpretive guidance related to the new standard as it becomes available, as well as comparing our conclusions on specific interpretative issues to other peers in our industry, to the extent that such information is available to us.
In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.
In October 2016, the FASB issued Accounting Standards Update No. 2016-16, Income Taxes (Topic 740): Intra-entity Transfers of Assets Other Than Inventory (“ASU 2016-16”), which requires that entities recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The amendments in this update do not change GAAP for the pre-tax effects of an intra-entity asset transfer under Topic 810, Consolidation, or for an intra-entity transfer of
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inventory. ASU 2016-16 is effective for fiscal years beginning after December 15, 2017, and interim periods within those annual periods. Early adoption is permitted. The Partnership is currently evaluating the impact that adoption of this standard will have on the consolidated financial statements and related disclosures.
On January 1, 2017, the Partnership adopted Accounting Standards Update No. 2016-09, Stock Compensation (Topic 718) (“ASU 2016-09”). The objective of the update is to reduce complexity in accounting standards. The areas for simplification in this update involve several aspects of the accounting for employee share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The adoption of this standard did not have an impact on the Partnership’s consolidated financial statements and related disclosures.
On January 1, 2017, the Partnership adopted Accounting Standards Update No. 2016-17, Consolidation (Topic 810): Interests Held Through Related Parties That Are Under Common Control (“ASU 2016-17”), which amends the consolidation guidance on how a reporting entity that is the single decision maker of a variable interest entity (VIE) should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. Under the amendments, a single decision maker is required to include indirect interests on a proportionate basis consistent with indirect interests held through other related parties. Adoption of this standard did not have an impact on the Partnership’s consolidated financial statements and related disclosures.
In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment”. The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit's carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance does not amend the optional qualitative assessment of goodwill impairment. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. We expect that our adoption of this standard will change our approach for testing goodwill for impairment; however, this standard requires prospective application and therefore will only impact periods subsequent to adoption.
Revenue Recognition
Our segments are engaged in multiple revenue-generating activities. To the extent that those activities are similar among our segments, revenue recognition policies are similar. Below is a description of revenue recognition policies for significant revenue-generating activities within our segments.
Investment in ETP
Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available.
The results of ETP’s intrastate transportation and storage and interstate transportation and storage operations are determined primarily by the amount of capacity customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, 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. Fuel retained for a fee is typically valued at market prices.
ETP’s intrastate transportation and storage operations also generate revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, ETP purchases natural gas from the market, including purchases from ETP’s marketing operations, and from producers at the wellhead.
In addition, ETP’s intrastate transportation and storage operations generate revenues and margin from fees charged for storing customers’ working natural gas in ETP’s storage facilities. ETP also engages in natural gas storage transactions in which ETP seeks to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. ETP purchases physical natural gas and then sells financial contracts at a price sufficient to cover ETP’s carrying costs and provide for a gross profit margin. ETP expects margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, ETP cannot assure that management’s expectations will be fully realized in the
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future and in what time period, due to various factors including weather, availability of natural gas in regions in which ETP operate, competitive factors in the energy industry, and other issues.
Results from ETP’s midstream operations are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through ETP’s pipeline and gathering systems and the level of natural gas and NGL prices. ETP generates midstream revenues and segment margins principally under fee-based or other arrangements in which ETP receives a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through ETP’s systems and is not directly dependent on commodity prices.
ETP also utilizes other types of arrangements in ETP’s midstream operations, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which ETP gathers and processes natural gas on behalf of producers, sells the resulting residue gas and NGL volumes at market prices and remits to producers an agreed upon percentage of the proceeds based on an index price, (iii) keep-whole arrangements where ETP gathers natural gas from the producer, processes the natural gas and sells the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing ETP’s plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing objectives. In many cases, ETP provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of ETP’s contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. ETP’s contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.
NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third-party pipeline, which is when title and risk of loss pass to the customer.
In ETP’s natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized.
ETP conducts marketing activities in which ETP markets the natural gas that flows through ETP’s assets, referred to as on-system gas. ETP also attracts other customers by marketing volumes of natural gas that do not move through ETP’s assets, referred to as off-system gas. For both on-system and off-system gas, ETP purchases natural gas from natural gas producers and other supply points and sells 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.
Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.
Investment in Sunoco LP
Revenues from Sunoco LP’s two primary product categories, motor fuel and merchandise, are recognized either at the time fuel is delivered to the customer or at the time of sale. Revenue recognition on consignment sales differ from this and are discussed in greater detail below. Shipment and delivery of motor fuel generally occurs on the same day. Sunoco LP charges its wholesale customers for third-party transportation costs, which are recorded net in cost of sales. Through PropCo, Sunoco LP’s wholly owned corporate subsidiary, Sunoco LP may sell motor fuel to wholesale customers on a consignment basis, in which Sunoco LP retains title to inventory, control access to and sale of fuel inventory, and recognize revenue at the time the fuel is sold to the ultimate customer. Sunoco LP derives other income from rental income, propane and lubricating oils and other ancillary product and service offerings. Sunoco LP derives other income from lottery ticket sales, money orders, prepaid phone cards and wireless services, ATM transactions, car washes, movie rentals and other ancillary product and service offerings. Sunoco LP records revenue on a net commission basis when the product is sold and/or services are rendered. Rental income from operating leases is recognized on a straight line basis over the term of the lease.
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Investment in Lake Charles LNG
Lake Charles LNG’s revenues from storage and re-gasification of natural gas are based on capacity reservation charges and, to a lesser extent, commodity usage charges. Reservation revenues are based on contracted rates and capacity reserved by the customers and recognized monthly. Revenues from commodity usage charges are also recognized monthly and represent the recovery of electric power charges at Lake Charles LNG’s terminal.
Regulatory Accounting – Regulatory Assets and Liabilities
ETP’s interstate transportation and storage operations are subject to regulation by certain state and federal authorities and certain subsidiaries in those operations have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of ETP’s regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, ETP ceases to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.
Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the NGA and NGPA, it does not currently apply regulatory accounting policies in accounting for its operations. Panhandle does not apply regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.
Cash, Cash Equivalents and Supplemental Cash Flow Information
Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.
We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.
The net change in operating assets and liabilities (net of effects of acquisitions, dispositions and deconsolidation) included in cash flows from operating activities was comprised as follows:

| Years Ended December 31,
| 2016 |  | 2015 |  | 2014
Accounts receivable | $ | (1,126 | ) |  | $ | 856 |  |  | $ | 600 |
Accounts receivable from related companies | 42 |  |  | (5 | ) |  | 30 |
Inventories | (345 | ) |  | (410 | ) |  | 52 |
Other current assets | 149 |  |  | (225 | ) |  | 151 |
Other non-current assets, net | (148 | ) |  | 250 |  |  | (6 | )
Accounts payable | 1,214 |  |  | (1,043 | ) |  | (893 | )
Accounts payable to related companies | (64 | ) |  | 400 |  |  | 5 |
Exchanges payable | — |  |  | — |  |  | — |
Accrued and other current liabilities | 89 |  |  | (697 | ) |  | (158 | )
Other non-current liabilities | 158 |  |  | (233 | ) |  | (138 | )
Derivative assets and liabilities, net | 67 |  |  | 75 |  |  | 19 |
Net change in operating assets and liabilities, net of effects of acquisitions | $ | 36 |  |  | $ | (1,032 | ) |  | $ | (338 | )

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Non-cash investing and financing activities and supplemental cash flow information were as follows:

| Years Ended December 31,
| 2016 |  | 2015 |  | 2014
NON-CASH INVESTING ACTIVITIES: |  |  |  |  |
Accrued capital expenditures | $ | 930 |  |  | $ | 910 |  |  | $ | 643 |
Net gains (losses) from subsidiary common unit transactions | 16 |  |  | (526 | ) |  | 744 |
NON-CASH FINANCING ACTIVITIES: |  |  |  |  |
Issuance of Common Units in connection with the PennTex Acquisition | 307 |  |  | — |  |  | — |
Contribution of property, plant and equipment from noncontrolling interest | — |  |  | 34 |  |  | — |
Subsidiary issuances of common units in connection with PVR, Hoover and Eagle Rock Midstream acquisitions | — |  |  | — |  |  | 4,281 |
Subsidiary issuances of common units in connection with the Susser Merger | — |  |  | — |  |  | 908 |
Long-term debt assumed in PVR Acquisition | — |  |  | — |  |  | 1,887 |
Long-term debt exchanged in Eagle Rock Midstream Acquisition | — |  |  | — |  |  | 499 |
SUPPLEMENTAL CASH FLOW INFORMATION: |  |  |  |  |
Cash paid for interest, net of interest capitalized | 1,922 |  |  | 1,800 |  |  | 1,416 |
Cash paid for (refund of) income taxes | (229 | ) |  | 72 |  |  | 345 |

Accounts Receivable
Our subsidiaries assess the credit risk of their customers and take steps to mitigate risk as necessary. Management reviews accounts receivable and an allowance for doubtful accounts is determined based on the overall creditworthiness of customers, historical write-off experience, general and specific economic trends, and identification of specific customers with payment issues.
Inventories
Inventories consist principally of natural gas held in storage, crude oil, refined products and spare parts. Natural gas held in storage is valued at the lower of cost or market utilizing the weighted-average cost method. The cost of crude oil and refined products is determined using the last-in, first out method. The cost of spare parts is determined by the first-in, first-out method.
Inventories consisted of the following:

| December 31,
| 2016 |  | 2015
Natural gas and NGLs | $ | 699 |  |  | $ | 415 |
Crude oil | 683 |  |  | 424 |
Refined products | 483 |  |  | 378 |
Spare parts and other | 238 |  |  | 248 |
Total inventories | $ | 2,103 |  |  | $ | 1,465 |

During the year ended December 31, 2015, the Partnership’s income from continuing operations included a write-down of $229 million on its crude oil, refined products and NGL inventories as a result of declines in the market price of these products. The write-down was calculated based upon current replacement costs.
ETP utilizes commodity derivatives to manage price volatility associated with certain of its natural gas inventory and designates certain of these derivatives as fair value hedges for accounting purposes. Changes in fair value of the designated hedged inventory have been recorded in inventory on our consolidated balance sheets and in cost of products sold in our consolidated statements of operations.
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Other Current Assets
Other current assets consisted of the following:

| December 31,
| 2016 |  | 2015
Deposits paid to vendors | $ | 74 |  |  | $ | 74 |
Income taxes receivable | 128 |  |  | 326 |
Prepaid expenses and other | 301 |  |  | 193 |
Total other current assets | $ | 503 |  |  | $ | 593 |

Property, Plant and Equipment
Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Natural gas and NGLs used to maintain pipeline minimum pressures is capitalized and classified as property, plant and equipment. Additionally, our subsidiaries capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. For the Lake Charles LNG project, a portion of the management fees are capitalized. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations.
Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value.
In 2016, ETP recorded a $133 million fixed asset impairment related to the interstate transportation and storage operations primarily due to expected decreases in future cash flows driven by declines in commodity prices as well as a $10 million impairment to property, plant and equipment in ETP’s midstream operations. In 2015, we recorded $110 million fixed asset impairments related to ETP’s NGL and refined products transportation and services operations primarily due to an expected decrease in future cash flows. No other fixed asset impairments were identified or recorded for our reporting units during the periods presented.
Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facilities when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.
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Components and useful lives of property, plant and equipment were as follows:

| December 31,
| 2016 |  | 2015
Land and improvements | $ | 1,160 |  |  | $ | 1,008 |
Buildings and improvements (1 to 45 years) | 2,197 |  |  | 1,629 |
Pipelines and equipment (5 to 83 years) | 35,593 |  |  | 32,677 |
Natural gas and NGL storage facilities (5 to 46 years) | 1,515 |  |  | 390 |
Bulk storage, equipment and facilities (2 to 83 years) | 3,677 |  |  | 2,853 |
Tanks and other equipment (5 to 40 years) | 1,286 |  |  | 1,488 |
Retail equipment (2 to 99 years) | 427 |  |  | 436 |
Vehicles (1 to 25 years) | 241 |  |  | 220 |
Right of way (20 to 83 years) | 3,374 |  |  | 2,573 |
Natural resources | 434 |  |  | 484 |
Other (1 to 40 years) | 1,031 |  |  | 1,296 |
Construction work-in-process | 10,223 |  |  | 7,797 |
| 61,158 |  |  | 52,851 |
Less – Accumulated depreciation and depletion | (7,905 | ) |  | (6,067 | )
Property, plant and equipment, net | $ | 53,253 |  |  | $ | 46,784 |

We recognized the following amounts for the periods presented:

| Years Ended December 31,
| 2016 |  | 2015 |  | 2014
Depreciation and depletion expense | $ | 1,904 |  |  | $ | 1,616 |  |  | $ | 1,409 |
Capitalized interest, excluding AFUDC | 200 |  |  | 163 |  |  | 101 |

Advances to and Investments in Affiliates
Certain of our subsidiaries own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies.
Other Non-Current Assets, net
Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following:

| December 31,
| 2016 |  | 2015
Unamortized financing costs(1) | $ | 13 |  |  | $ | 29 |
Regulatory assets | 86 |  |  | 90 |
Deferred charges | 217 |  |  | 198 |
Restricted funds | 190 |  |  | 192 |
Other | 310 |  |  | 202 |
Total other non-current assets, net | $ | 816 |  |  | $ | 711 |

(1)Includes unamortized financing costs related to the Partnership’s revolving credit facilities.
Restricted funds primarily consisted of restricted cash held in our wholly-owned captive insurance companies.
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Intangible Assets
Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized.
Components and useful lives of intangible assets were as follows:

| December 31, 2016 |  | December 31, 2015
| Gross Carrying Amount |  | Accumulated Amortization |  | Gross Carrying Amount |  | Accumulated Amortization
Amortizable intangible assets: |  |  |  |  |  |  |
Customer relationships, contracts and agreements (3 to 46 years) | $ | 6,050 |  |  | $ | (971 | ) |  | $ | 5,199 |  |  | $ | (712 | )
Trade names (15 years) | 352 |  |  | (22 | ) |  | 66 |  |  | (18 | )
Patents (9 years) | 25 |  |  | (21 | ) |  | 48 |  |  | (16 | )
Other (1 to 15 years) | 42 |  |  | (9 | ) |  | 14 |  |  | — |
Total amortizable intangible assets | 6,469 |  |  | (1,023 | ) |  | 5,327 |  |  | (746 | )
Non-amortizable intangible assets: |  |  |  |  |  |  |
Trademarks | — |  |  | — |  |  | 281 |  |  | — |
Contractual rights | 43 |  |  | — |  |  | 34 |  |  | — |
Liquor licenses | — |  |  | — |  |  | — |  |  | — |
Total intangible assets | $ | 6,512 |  |  | $ | (1,023 | ) |  | $ | 5,642 |  |  | $ | (746 | )

Aggregate amortization expense of intangibles assets was as follows:

| Years Ended December 31,
| 2016 |  | 2015 |  | 2014
Reported in depreciation, depletion and amortization | $ | 262 |  |  | $ | 288 |  |  | $ | 212 |

Estimated aggregate amortization expense of intangible assets for the next five years was as follows:

Years Ending December 31: |
2017 | $ | 279 |
2018 | 277 |
2019 | 273 |
2020 | 268 |
2021 | 251 |

We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate.
In 2015, we recorded $24 million of intangible asset impairments related to ETP’s NGL and refined products transportation and services operations primarily due to an expected decrease in future cash flows.
Goodwill
Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the fourth quarter.
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Changes in the carrying amount of goodwill were as follows:

| Investment in ETP |  | Investment in Sunoco LP |  | Investment in Lake Charles LNG |  | Corporate, Other and Eliminations |  | Total
Balance, December 31, 2014 | $ | 7,642 |  |  | $ | 1,149 |  |  | $ | 184 |  |  | $ | (3,104 | ) |  | $ | 5,871 |
Goodwill acquired | — |  |  | 23 |  |  | — |  |  | — |  |  | 23 |
Sunoco LP Exchange | (2,018 | ) |  | — |  |  | — |  |  | 2,018 |  |  | — |
Goodwill impairment | (205 | ) |  | — |  |  | — |  |  | — |  |  | (205 | )
Other | 9 |  |  | (49 | ) |  | — |  |  | (164 | ) |  | (204 | )
Balance, December 31, 2015 | 5,428 |  |  | 1,123 |  |  | 184 |  |  | (1,250 | ) |  | 5,485 |
Goodwill acquired | 428 |  |  | 81 |  |  | — |  |  | — |  |  | 509 |
Contribution of retail business | (1,289 | ) |  | — |  |  | — |  |  | 1,289 |  |  | — |
Goodwill impairment | (670 | ) |  | (156 | ) |  | — |  |  | — |  |  | (826 | )
Other | — |  |  | 2 |  |  | — |  |  | — |  |  | 2 |
Balance, December 31, 2016 | $ | 3,897 |  |  | $ | 1,050 |  |  | $ | 184 |  |  | $ | 39 |  |  | $ | 5,170 |

Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized.
During the fourth quarter of 2016, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $638 million the interstate transportation and storage operations and $32 million in the midstream operations 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. Sunoco LP recognized goodwill impairments of $642 million, of which $156 million was allocated to continuing operations, primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded.
During the fourth quarter of 2015, ETP performed goodwill impairment tests on its reporting units and recognized goodwill impairments of: (i) $99 million in the Transwestern reporting unit due primarily to the market declines in current and expected future commodity prices in the fourth quarter of 2015, and (ii) $106 million in the Lone Star Refinery Services reporting unit due primarily to changes in assumptions related to potential future revenues decrease as well as the market declines in current and expected future commodity prices.
The Partnership determined the fair value of our reporting units using a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determined fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determined the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimated a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.
Asset Retirement Obligations
We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.
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An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably estimate the settlement dates.
Except for certain amounts recorded by Panhandle and Sunoco Logistics discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 2016 and 2015, in most cases because the settlement dates were indeterminable. Although a number of other onshore assets in Panhandle’s system are subject to agreements or regulations that give rise to an ARO upon Panhandle’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Sunoco, Inc. has legal asset retirement obligations for several other assets at its previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, Sunoco, Inc. is legally or contractually required to abandon in place or remove the asset. Sunoco Logistics believes it may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time.
As of December 31, 2016 and 2015, other non-current liabilities in ETP’s consolidated balance sheets included AROs of $170 million and $212 million, respectively.
Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future. We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.
Long-lived assets related to AROs aggregated $14 million and $18 million, and were reflected as property, plant and equipment on our balance sheet as of December 31, 2016 and 2015, respectively. In addition, the Partnership had $13 million and $6 million legally restricted funds for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2016 and 2015, respectively.
Accrued and Other Current Liabilities
Accrued and other current liabilities consisted of the following:

| December 31,
| 2016 |  | 2015
Interest payable | $ | 545 |  |  | $ | 519 |
Customer advances and deposits | 72 |  |  | 114 |
Accrued capital expenditures | 769 |  |  | 743 |
Accrued wages and benefits | 254 |  |  | 218 |
Taxes payable other than income taxes | 201 |  |  | 76 |
Exchanges payable | 208 |  |  | 106 |
Other | 318 |  |  | 632 |
Total accrued and other current liabilities | $ | 2,367 |  |  | $ | 2,408 |

Deposits or advances are received from customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit.
Redeemable Noncontrolling Interests
The noncontrolling interest holders in one of Sunoco Logistics’ consolidated subsidiaries have the option to sell their interests to Sunoco Logistics. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interest on the consolidated balance sheet.
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Environmental Remediation
We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued.
Fair Value of Financial Instruments
The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value.
Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of December 31, 2016 was $45.05 billion and $43.80 billion, respectively. As of December 31, 2015, the aggregate fair value and carrying amount of our consolidated debt obligations was $33.22 billion and $36.97 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.
We have commodity derivatives, interest rate derivatives and embedded derivatives in the ETP Preferred Units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. Derivatives related to the embedded derivatives in our preferred units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered Level 3. During the year ended December 31, 2016, no transfers were made between any levels within the fair value hierarchy.
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The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2016 and 2015 based on inputs used to derive their fair values:

| Fair Value Measurements at December 31, 2016
| Fair Value Total |  | Level 1 |  | Level 2 |  | Level 3
Assets: |  |  |  |  |  |  |
Commodity derivatives: |  |  |  |  |  |  |
Natural Gas: |  |  |  |  |  |  |
Basis Swaps IFERC/NYMEX | $ | 14 |  |  | $ | 14 |  |  | $ | — |  |  | $ | — |
Swing Swaps IFERC | 2 |  |  | — |  |  | 2 |  |  | — |
Fixed Swaps/Futures | 96 |  |  | 96 |  |  | — |  |  | — |
Forward Physical Swaps | 1 |  |  | — |  |  | 1 |  |  | — |
Power: |  |  |  |  |  |  |
Forwards | 4 |  |  | — |  |  | 4 |  |  | — |
Futures | 1 |  |  | 1 |  |  | — |  |  | — |
Options — Calls | 1 |  |  | 1 |  |  | — |  |  | — |
Natural Gas Liquids — Forwards/Swaps | 233 |  |  | 233 |  |  | — |  |  | — |
Refined Products – Futures | 2 |  |  | 2 |  |  | — |  |  | — |
Crude – Futures | 9 |  |  | 9 |  |  | — |  |  | — |
Total commodity derivatives | 363 |  |  | 356 |  |  | 7 |  |  | — |
Total assets | $ | 363 |  |  | $ | 356 |  |  | $ | 7 |  |  | $ | — |
Liabilities: |  |  |  |  |  |  |
Interest rate derivatives | $ | (193 | ) |  | $ | — |  |  | $ | (193 | ) |  | $ | — |
Embedded derivatives in the ETP Preferred Units | (1 | ) |  | — |  |  | — |  |  | (1 | )
Commodity derivatives: |  |  |  |  |  |  |
Natural Gas: |  |  |  |  |  |  |
Basis Swaps IFERC/NYMEX | (11 | ) |  | (11 | ) |  | — |  |  | — |
Swing Swaps IFERC | (3 | ) |  | — |  |  | (3 | ) |  | — |
Fixed Swaps/Futures | (149 | ) |  | (149 | ) |  | — |  |  | — |
Power: |  |  |  |  |  |  |
Forwards | (5 | ) |  |  |  |  | (5 | ) |  | — |
Futures | (1 | ) |  | (1 | ) |  | — |  |  | — |
Natural Gas Liquids — Forwards/Swaps | (273 | ) |  | (273 | ) |  | — |  |  | — |
Refined Products – Futures | (23 | ) |  | (23 | ) |  | — |  |  | — |
Crude — Futures | (13 | ) |  | (13 | ) |  | — |  |  | — |
Total commodity derivatives | (478 | ) |  | (470 | ) |  | (8 | ) |  | — |
Total liabilities | $ | (672 | ) |  | $ | (470 | ) |  | $ | (201 | ) |  | $ | (1 | )

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| Fair Value Measurements at December 31, 2015
| Fair Value Total |  | Level 1 |  | Level 2 |  | Level 3
Assets: |  |  |  |  |  |  |
Commodity derivatives: |  |  |  |  |  |  |
Natural Gas: |  |  |  |  |  |  |
Basis Swaps IFERC/NYMEX | $ | 16 |  |  | $ | 16 |  |  | $ | — |  |  | $ | — |
Swing Swaps IFERC | 10 |  |  | 2 |  |  | 8 |  |  | — |
Fixed Swaps/Futures | 274 |  |  | 274 |  |  | — |  |  | — |
Forward Physical Contracts | 4 |  |  | — |  |  | 4 |  |  | — |
Power: |  |  |  |  |  |  |
Forwards | 22 |  |  | — |  |  | 22 |  |  | — |
Futures | 3 |  |  | 3 |  |  | — |  |  | — |
Options — Calls | 1 |  |  | 1 |  |  | — |  |  | — |
Options — Puts | 1 |  |  | 1 |  |  | — |  |  | — |
Natural Gas Liquids — Forwards/Swaps | 99 |  |  | 99 |  |  | — |  |  | — |
Refined Products – Futures | 15 |  |  | 15 |  |  | — |  |  | — |
Crude – Futures | 9 |  |  | 9 |  |  | — |  |  | — |
Total commodity derivatives | 454 |  |  | 420 |  |  | 34 |  |  | — |
Total assets | $ | 454 |  |  | $ | 420 |  |  | $ | 34 |  |  | $ | — |
Liabilities: |  |  |  |  |  |  |
Interest rate derivatives | $ | (171 | ) |  | $ | — |  |  | $ | (171 | ) |  | $ | — |
Embedded derivatives in the ETP Preferred Units | (5 | ) |  | — |  |  | — |  |  | (5 | )
Commodity derivatives: |  |  |  |  |  |  |
Natural Gas: |  |  |  |  |  |  |
Basis Swaps IFERC/NYMEX | (16 | ) |  | (16 | ) |  | — |  |  | — |
Swing Swaps IFERC | (12 | ) |  | (2 | ) |  | (10 | ) |  | — |
Fixed Swaps/Futures | (203 | ) |  | (203 | ) |  | — |  |  | — |
Power: |  |  |  |  |  |  |
Forwards | (22 | ) |  | — |  |  | (22 | ) |  | — |
Futures | (2 | ) |  | (2 | ) |  | — |  |  | — |
Options — Puts | (1 | ) |  | (1 | ) |  | — |  |  | — |
Natural Gas Liquids — Forwards/Swaps | (89 | ) |  | (89 | ) |  | — |  |  | — |
Refined Products – Futures | (6 | ) |  | (6 | ) |  | — |  |  | — |
Crude — Futures | (5 | ) |  | (5 | ) |  | — |  |  | — |
Total commodity derivatives | (356 | ) |  | (324 | ) |  | (32 | ) |  | — |
Total liabilities | $ | (532 | ) |  | $ | (324 | ) |  | $ | (203 | ) |  | $ | (5 | )

The following table presents the material unobservable inputs used to estimate the fair value of ETP’s Preferred Units and the embedded derivatives in ETP’s Preferred Units:

| Unobservable Input |  | December 31, 2016
Embedded derivatives in the ETP Preferred Units | Credit Spread |  | 5.12 | %
| Volatility |  | 31.73 | %

Changes in the remaining term of the Preferred Units, U.S. Treasury yields and valuations in related instruments would cause a change in the yield to value the Preferred Units. Changes in ETP’s cost of equity and U.S. Treasury yields would cause a change in the credit spread used to value the embedded derivatives in the ETP Preferred Units. Changes in ETP’s historical unit price volatility would cause a change in the volatility used to value the embedded derivatives.
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The following table presents a reconciliation of the beginning and ending balances for our Level 3 financial instruments measured at fair value on a recurring basis using significant unobservable inputs for the year ended December 31, 2016.

Balance, December 31, 2015 | $ | (5 | )
Net unrealized gains included in other income (expense) | 4 |
Balance, December 31, 2016 | $ | (1 | )

Contributions in Aid of Construction Cost
On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received, and any CIAC which exceeds our total project costs, is recognized as other income in the period in which it is realized.
Shipping and Handling Costs
Shipping and handling costs are included in cost of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are included in operating expenses.
Costs and Expenses
Costs of products sold include actual cost of fuel sold, adjusted for the effects of hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel.
We record the collection of taxes to be remitted to governmental authorities on a net basis except for our retail marketing operations in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income (loss). Excise taxes collected by our retail marketing operations, including discontinued operations, were $3.48 billion, $3.05 billion and $2.46 billion for the years ended December 31, 2016, 2015 and 2014, respectively.
Issuances of Subsidiary Units
We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon our subsidiaries’ issuance of common units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interest is adjusted as a change in partners’ capital.
Income Taxes
ETE is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and state income tax purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities, in addition to the allocation requirements related to taxable income under our Third Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”).
As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and IRS pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, we would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2016, 2015, and 2014, our qualifying income met the statutory requirement.
The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local income taxes. These corporate subsidiaries include ETP Holdco, Oasis Pipeline Company, Susser Petroleum Property Company, Aloha Petroleum and Susser Holding Corporation. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method.
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Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.
The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes.
Accounting for Derivative Instruments and Hedging Activities
For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third-party prices, readily available market information, broker quotes and appropriate valuation techniques.
At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period.
If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in the consolidated statement of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statement of operations.
Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged.
If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, a change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.
We previously have managed a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on interest rate derivatives” in the consolidated statements of operations.
Unit-Based Compensation
For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of our common units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of our common units as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets.
Pensions and Other Postretirement Benefit Plans
Employers are required to recognize in their balance sheets the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation
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(the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans). Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Employers must recognize the change in the funded status of the plan in the year in which the change occurs within AOCI in equity or, for entities applying regulatory accounting, as a regulatory asset or regulatory liability.
Allocation of Income
For purposes of maintaining partner capital accounts, our Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests.

3. | ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:

2017 Transactions
Sunoco LP Convenience Store Sale
On April 6, 2017, Sunoco LP entered into a definitive asset purchase agreement for the sale of a portfolio of approximately 1,112 Sunoco LP operated retail fuel outlets in 19 geographic regions, together with ancillary businesses and related assets, including the proprietary Laredo Taco Company brand, to 7-Eleven, Inc. (“7-Eleven”) for an aggregate purchase price of $3.3 billion (the “7-Eleven Transaction”). The closing of the transaction contemplated by the asset purchase agreement is expected to occur in the fourth quarter of 2017.
With the assistance of a third-party brokerage firm, Sunoco LP began marketing efforts with respect to approximately 208 sites under the Stripes brand (“Stripes Sites”) located in certain West Texas, Oklahoma and New Mexico markets, which were not included in the 7-Eleven purchase agreement. There can be no assurance of Sunoco LP’s success in selling the remaining company-operated retail assets, nor the price or terms of such sale, and even if a sale is consummated, Sunoco LP may remain contingently responsible for certain risks and obligations related to the divested retail assets. On January 18, 2017, with the assistance of a third-party brokerage firm, Sunoco LP launched a portfolio optimization plan to market and sell 97 real estate assets located in Florida, Louisiana, Massachusetts, Michigan, New Hampshire, New Jersey, New Mexico, New York, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, Texas and Virginia. The properties will be sold through a sealed-bid sale. Of the 97 properties, 16 have been sold and an additional 20 are under contract to be sold. 31 are being sold to 7-Eleven and 9 are being sold in another transaction. The remaining 21 continue to be marketed by the third-party brokerage firm.
The Partnership has concluded that it meets the accounting requirements for reporting results of operations and cash flows of Sunoco LP’s continental United States retail convenience stores as discontinued operations and the related assets and liabilities as held for sale.
The following tables present the aggregate carrying amounts of assets and liabilities classified as held for sale in the consolidated balance sheet:

|  | December 31, 2016 |  | December 31, 2015
Carrying amount of assets classified as held for sale: |  |  |  |
Cash and cash equivalents |  | $ | 20 |  |  | $ | 25 |
Inventories |  | 188 |  |  | 171 |
Other current assets |  | 83 |  |  | 10 |
Property, plant and equipment, net |  | 2,185 |  |  | 1,899 |
Goodwill |  | 1,568 |  |  | 1,988 |
Intangible assets, net |  | 503 |  |  | 535 |
Other non-current assets, net |  | 2 |  |  | 19 |
Total assets classified as held for sale in the Consolidated Balance Sheet |  | $ | 4,549 |  |  | $ | 4,647 |
Carrying amount of liabilities classified as held for sale: |  |  |  |
Other non-current liabilities |  | 68 |  |  | 67 |
Total liabilities classified as held for sale in the Consolidated Balance Sheet |  | $ | 68 |  |  | $ | 67 |

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The results of operations associated with discontinued operations are presented in the following table:

| Years Ended December 31,
| 2016 |  | 2015 |  | 2014
REVENUES | $ | 7,402 |  |  | $ | 7,922 |  |  | $ | 3,052 |
COSTS AND EXPENSES |  |  |  |  |
Cost of products sold | 6,020 |  |  | 6,574 |  |  | 2,553 |
Operating expenses | 1,486 |  |  | 933 |  |  | 291 |
Depreciation and amortization | 193 |  |  | 175 |  |  | 55 |
Selling, general and administrative | 114 |  |  | 91 |  |  | 55 |
Total costs and expenses | 7,813 |  |  | 7,773 |  |  | 2,954 |
OPERATING INCOME | (411 | ) |  | 149 |  |  | 98 |
Interest expense, net | 29 |  |  | 22 |  |  | 1 |
Other, net | 8 |  |  | (2 | ) |  | (1 | )
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE | (448 | ) |  | 129 |  |  | 98 |
Income tax expense | 31 |  |  | 48 |  |  | 32 |
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES | $ | (479 | ) |  | $ | 81 |  |  | $ | 66 |
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE ATTRIBUTABLE TO ETE | $ | (12 | ) |  | $ | 1 |  |  | $ | 3 |

2016 Transactions
WMB Merger
On June 24, 2016, the Delaware Court of Chancery issued an opinion finding that ETE was contractually entitled to terminate its Merger Agreement with WMB in the event Latham & Watkins LLP (“Latham”) were unable to deliver a required tax opinion on or prior to June 28, 2016. Latham advised ETE that it was unable to deliver the tax opinion as of June 28, 2016. Consistent with its rights and obligations under the merger agreement, ETE subsequently provided written notice terminating the merger agreement due to the failure of conditions under the merger agreement, including Latham’s inability to deliver the tax opinion, as well as the other bases detailed in ETE’s filings in the Delaware lawsuit referenced above. WMB has appealed the decision by the Delaware Court of Chancery to the Delaware Supreme Court.
PennTex Acquisition
On November 1, 2016, ETP acquired certain interests in PennTex from various parties for total consideration of approximately $627 million in ETP units and cash. Through this transaction, ETP acquired a controlling financial interest in PennTex, whose assets complement ETP’s existing midstream footprint in northern Louisiana.
Summary of Assets Acquired and Liabilities Assumed
We accounted for the PennTex acquisition using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date.
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The total purchase price was allocated as follows:

|  | At November 1, 2016
Total current assets |  | $ | 34 |
Property, plant and equipment |  | 393 |
Goodwill(1) |  | 177 |
Intangible assets |  | 446 |
|  | 1,050 |
Total current liabilities |  | 6 |
Long-term debt, less current maturities |  | 164 |
Other non-current liabilities |  | 17 |
Noncontrolling interest |  | 236 |
|  | 423 |
Total consideration |  | 627 |
Cash received |  | 21 |
Total consideration, net of cash received |  | $ | 606 |

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

The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
Sunoco Logistics’ Vitol Acquisition
In November 2016, Sunoco Logistics completed an acquisition from Vitol, Inc. (“Vitol”) of an integrated crude oil business in West Texas for $760 million plus working capital. The acquisition provides Sunoco Logistics with an approximately 2 million barrel crude oil terminal in Midland, Texas, a crude oil gathering and mainline pipeline system in the Midland Basin, including a significant acreage dedication from an investment-grade Permian producer, and crude oil inventories related to Vitol's crude oil purchasing and marketing business in West Texas. The acquisition also included the purchase of a 50% interest in SunVit Pipeline LLC ("SunVit"), which increased Sunoco Logistics' overall ownership of SunVit to 100%. The $769 million purchase price, net of cash received, consisted primarily of net working capital of $13 million largely attributable to inventory and receivables; property, plant and equipment of $286 million primarily related to pipeline and terminalling assets; intangible assets of $313 million attributable to customer relationships; and goodwill of $251 million.
Sunoco Logistics’ Permian Express Partners
In February 2017, Sunoco Logistics formed Permian Express Partners LLC ("PEP"), a strategic joint venture, with ExxonMobil Corp. Sunoco Logistics contributed its Permian Express 1, Permian Express 2 and Permian Longview and Louisiana Access pipelines. ExxonMobil Corp. contributed its Longview to Louisiana and Pegasus pipelines; Hawkins gathering system; an idle pipeline in southern Oklahoma; and its Patoka, Illinois terminal. Sunoco Logistics’ ownership percentage is approximately 85%. Upon commencement of operations on the Bakken Pipeline, Sunoco Logistics will contribute its investment in the project, with a corresponding increase in its ownership percentage in PEP. Sunoco Logistics maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP will be reflected as a consolidated subsidiary of Sunoco Logistics. ExxonMobil Corp.’s interest will be reflected as noncontrolling interest in Sunoco Logistics’ consolidated balance sheet.
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Bakken Equity Sale
On August 2, 2016, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 60% membership interest and Sunoco Logistics indirectly owns a 40% membership interest, agreed to sell a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by Marathon Petroleum Corporation and Enbridge Energy Partners, L.P. for $2.00 billion in cash. This transaction closed in February 2017. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access, LLC (“Dakota Access”) and Energy Transfer Crude Oil Company, LLC (“ETCO”). The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP will continue to consolidate Dakota Access and ETCO subsequent to this transaction. Upon closing, ETP and Sunoco Logistics collectively own a 38.25% interest in the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects (collectively, the "Bakken Pipeline"), and MarEn Bakken Company owns 36.75% and Phillips 66 owns 25.00% in the Bakken Pipeline.
Bakken Financing
In August 2016, ETP, Sunoco Logistics and Phillips 66 announced the completion of the project-level financing of the Bakken Pipeline. The $2.50 billion credit facility is anticipated to provide substantially all of the remaining capital necessary to complete the projects. As of December 31, 2016, $1.10 billion was outstanding under this credit facility.
Bayou Bridge
In April 2016, Bayou Bridge Pipeline, LLC (“Bayou Bridge”), a joint venture among ETP, Sunoco Logistics and Phillips 66 Partners LP, began commercial operations on the 30-inch segment of the pipeline from Nederland, Texas to Lake Charles, Louisiana. ETP and Sunoco Logistics each hold a 30% interest in the entity and Sunoco Logistics is the operator of the system.
Sunoco Retail to Sunoco LP
In March 2016, ETP contributed to Sunoco LP its remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business for $2.23 billion. Sunoco LP paid $2.20 billion in cash, including a working capital adjustment and issued 5.7 million Sunoco LP common units to Retail Holdings, a wholly-owned subsidiary of the Partnership. The transaction was effective January 1, 2016.
Sunoco LP Acquisitions
In August 2016, Sunoco LP acquired the fuels business from Emerge Energy Services LP for $171 million, including tax deductible goodwill of $78 million and intangible assets of $23 million. Additionally, during 2016, Sunoco LP made other acquisitions primarily consisting of convenience stores, totaling $114 million plus the value of inventory on hand at closing and increasing goodwill by $61 million.
In October 2016, Sunoco LP completed the acquisition of a convenience store, wholesale motor fuel distribution, and commercial fuels distribution business for approximately $55 million plus inventory on hand at closing, subject to closing adjustments.
2015 Transactions
Sunoco LP
In April 2015, Sunoco LP acquired a 31.58% equity interest in Sunoco, LLC from Retail Holdings for $816 million. Sunoco, LLC distributes approximately 5.3 billion gallons of motor fuel per year to customers in the east, midwest and southwest regions of the United States. Sunoco LP paid $775 million in cash and issued $41 million of Sunoco LP common units to Retail Holdings, based on the five-day volume weighted average price of Sunoco LP’s common units as of March 20, 2015.
In July 2015, in exchange for the contribution of 100% of Susser from ETP to Sunoco LP, Sunoco LP paid $970 million in cash and issued to ETP subsidiaries 22 million Sunoco LP Class B units valued at $970 million. The Sunoco Class B units did not receive second quarter 2015 cash distributions from Sunoco LP and converted on a one-for-one basis into Sunoco LP common units on the day immediately following the record date for Sunoco LP’s second quarter 2015 distribution. In addition, (i) a Susser subsidiary exchanged its 79,308 Sunoco LP common units for 79,308 Sunoco LP Class A units, (ii) 10.9 million Sunoco LP subordinated units owned by Susser subsidiaries were converted into 10.9 million Sunoco LP Class A units and (iii) Sunoco LP issued 79,308 Sunoco LP common units and 10.9 million Sunoco LP subordinated units to subsidiaries of ETP. The Sunoco LP Class A units owned by the Susser subsidiaries were contributed to Sunoco LP as part of the transaction. Sunoco LP subsequently contributed its interests in Susser to one of its subsidiaries.
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Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP, and in exchange, ETP repurchased from ETE 31.5 million ETP common units owned by ETE. In connection with ETP’s 2014 acquisition of Susser, ETE agreed to provide ETP a $35 million annual IDR subsidy for 10 years, which terminated upon the closing of ETE’s acquisition of Sunoco GP. In connection with the exchange and repurchase, ETE will provide ETP a $35 million annual IDR subsidy for two years beginning with the quarter ended September 30, 2015.
Bakken Pipeline
In March 2015, ETE transferred 46.2 million ETP common units, ETE’s 45% interest in the Bakken Pipeline project, and $879 million in cash to ETP in exchange for 30.8 million newly issued ETP Class H Units that, when combined with the 50.2 million previously issued ETP Class H Units, generally entitle ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics (the “Bakken Pipeline Transaction”). In connection with this transaction, ETP also issued to ETE 100 ETP Class I Units that provide distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, including the impact from distributions on ETP Class I Units, were reduced by $55 million in 2015 and $30 million in 2016.
In October 2015, Sunoco Logistics completed the previously announced acquisition of a 40% membership interest (the “Bakken Membership Interest”) in Bakken Holdings Company LLC (“Bakken Holdco”). Bakken Holdco, through its wholly-owned subsidiaries, owns a 75% membership interest in each of Dakota Access, LLC and Energy Transfer Crude Oil Company, LLC, which together intend to develop the Bakken Pipeline system to deliver crude oil from the Bakken/Three Forks production area in North Dakota to the Gulf Coast. ETP transferred the Bakken Membership Interest to Sunoco Logistics in exchange for approximately 9.4 million Class B Units representing limited partner interests in Sunoco Logistics and the payment by Sunoco Logistics to ETP of $382 million of cash, which represented reimbursement for its proportionate share of the total cash contributions made in the Bakken Pipeline project as of the date of closing of the exchange transaction.
Regency Merger
On April 30, 2015, a wholly-owned subsidiary of ETP merged with Regency, with Regency surviving as a wholly-owned subsidiary of ETP (the “Regency Merger”). Each Regency common unit and Class F unit was converted into the right to receive 0.6186 common units of ETP. ETP issued 258.3 million ETP common units to Regency unitholders, including 23.3 million units issued to ETP subsidiaries. The 1.9 million outstanding Regency Preferred Units were converted into corresponding new ETP Series A Preferred Units on a one-for-one basis.
In connection with the Regency Merger, ETE agreed to reduce the incentive distributions it receives from ETP by a total of $320 million over a five-year period. The IDR subsidy was $80 million for the year ended December 31, 2015 and will total $60 million per year for the following four years.
ETP has assumed all of the obligations of Regency and Regency Energy Finance Corp., of which ETP was previously a co-obligor or parent guarantor.
2014 Transactions
MACS to Sunoco LP
In October 2014, Sunoco LP acquired MACS from a subsidiary of ETP in a transaction valued at approximately $768 million (the “MACS Transaction”). The transaction included approximately 110 company-operated retail convenience stores and 200 dealer-operated and consignment sites from MACS, which had originally been acquired by ETP in October 2013. The consideration paid by Sunoco LP consisted of approximately 4 million Sunoco LP common units issued to ETP and $556 million in cash, subject to customary closing adjustments. Sunoco LP initially financed the cash portion by utilizing availability under its revolving credit facility. In October 2014 and November 2014, Sunoco LP partially repaid borrowings on its revolving credit facility with aggregate net proceeds of $405 million from a public offering of 9.1 million Sunoco LP common units.
Susser Merger
In August 2014, ETP and Susser completed the merger of an indirect wholly-owned subsidiary of ETP, with and into Susser, with Susser surviving the merger as a subsidiary of ETP for total consideration valued at approximately $1.8 billion (the “Susser Merger”). The total consideration paid in cash was approximately $875 million and the total consideration paid in equity was approximately 23.7 million ETP Common Units. The Susser Merger broadens ETP’s retail geographic footprint and provides synergy opportunities and a platform for future growth.
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In connection with the Susser Merger, ETP acquired an indirect 100% equity interest in Susser and the general partner interest and the incentive distribution rights in Sunoco LP, approximately 11 million Sunoco LP common and subordinated units, and Susser’s existing retail operations, consisting of 630 convenience store locations.
Effective with the closing of the transaction, Susser ceased to be a publicly traded company and its common stock discontinued trading on the NYSE.
Summary of Assets Acquired and Liabilities Assumed
ETP accounted for the Susser Merger using the acquisition method of accounting which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date.
The following table summarizes the assets acquired and liabilities assumed recognized as of the merger date:

|  | Susser
Total current assets |  | $ | 446 |
Property, plant and equipment |  | 1,069 |
Goodwill(1) |  | 1,734 |
Intangible assets |  | 611 |
Other non-current assets |  | 17 |
|  | 3,877 |
Total current liabilities |  | 377 |
Long-term debt, less current maturities |  | 564 |
Deferred income taxes |  | 488 |
Other non-current liabilities |  | 39 |
Noncontrolling interest |  | 626 |
|  | 2,094 |
Total consideration |  | 1,783 |
Cash received |  | 67 |
Total consideration, net of cash received |  | $ | 1,716 |

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

The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
ETP incurred merger related costs related to the Susser Merger of $25 million during the year ended December 31, 2015. Our consolidated statements of operations for the year ended December 31, 2015 reflected revenue and net income related to Susser of $2.32 billion and $105 million, respectively.
No pro forma information has been presented for the Susser Merger, as the impact of this acquisition was not material in relation to our consolidated results of operations.
Regency’s Acquisition of Eagle Rock’s Midstream Business
On July 1, 2014, Regency acquired Eagle Rock’s midstream business (the “Eagle Rock Midstream Acquisition”) for $1.3 billion, including the assumption of $499 million of Eagle Rock’s 8.375% senior notes due 2019. The remainder of the purchase price was funded by $400 million in Regency Common Units sold to a wholly-owned subsidiary of ETE, 8.2 million Regency Common Units issued to Eagle Rock and borrowings under Regency’s revolving credit facility. Our consolidated statement of operations for the year ended December 31, 2014 included revenues and net income attributable to Eagle Rock’s operations of $903 million and $30 million, respectively.
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The total purchase price was allocated as follows:

Assets | At July 1, 2014
Current assets | $ | 120 |
Property, plant and equipment | 1,295 |
Other non-current assets | 4 |
Goodwill | 49 |
Total assets acquired | 1,468 |
Liabilities |
Current liabilities | 116 |
Long-term debt | 499 |
Other non-current liabilities | 12 |
Total liabilities assumed | 627 |
Net assets acquired | $ | 841 |

The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
Regency’s Acquisition of PVR Partners, L.P.
On March 21, 2014, Regency acquired PVR for a total purchase price of $5.7 billion (based on Regency’s closing price of $27.82 per Regency Common Unit on March 21, 2014), including $1.8 billion principal amount of assumed debt (the “PVR Acquisition”). PVR unitholders received (on a per unit basis) 1.02 Regency Common Units and a one-time cash payment of $36 million, which was funded through borrowings under Regency’s revolving credit facility. Our consolidated statement of operations for the year ended December 31, 2014 included revenues and net income attributable to PVR’s operations of $956 million and $166 million, respectively.
Regency completed the evaluation of the assigned fair values to the assets acquired and liabilities assumed. The total purchase price was allocated as follows:

Assets | At March 21, 2014
Current assets | $ | 149 |
Property, plant and equipment | 2,716 |
Investment in unconsolidated affiliates | 62 |
Intangible assets (average useful life of 30 years) | 2,717 |
Goodwill(1) | 370 |
Other non-current assets | 18 |
Total assets acquired | 6,032 |
Liabilities |
Current liabilities | 168 |
Long-term debt | 1,788 |
Premium related to senior notes | 99 |
Non-current liabilities | 30 |
Total liabilities assumed | 2,085 |
Net assets acquired | $ | 3,947 |

(1)None of the goodwill is expected to be deductible for tax purposes.
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
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Lake Charles LNG Transaction
On February 19, 2014, ETP completed the transfer to ETE of Lake Charles LNG, the entity that owns a LNG regasification facility in Lake Charles, Louisiana, in exchange for the redemption by ETP of 28.1 million ETP Common Units held by ETE (the “Lake Charles LNG Transaction”). The transaction was effective as of January 1, 2014, at which time ETP deconsolidated Lake Charles LNG.
In connection with ETE’s acquisition of Lake Charles LNG, ETP agreed to continue to provide management services for ETE through 2015 in relation to both Lake Charles LNG’s regasification facility and the development of a liquefaction project at Lake Charles LNG’s facility, for which ETE has agreed to pay incremental management fees to ETP of $75 million per year for the years ending December 31, 2014 and 2015. ETE also agreed to provide additional subsidies to ETP through the relinquishment of future incentive distributions, as discussed further in Note 8.
Panhandle Merger
On January 10, 2014, Panhandle consummated a merger with Southern Union, the indirect parent of Panhandle at the time of the merger, and PEPL Holdings, a wholly-owned subsidiary of Southern Union and the sole limited partner of Panhandle at the time of the merger, pursuant to which each of Southern Union and PEPL Holdings were merged with and into Panhandle (the “Panhandle Merger”), with Panhandle surviving the Panhandle Merger. In connection with the Panhandle Merger, Panhandle assumed Southern Union’s obligations under its 7.6% senior notes due 2024, 8.25% senior notes due 2029 and the junior subordinated notes due 2066. At the time of the Panhandle Merger, Southern Union did not have material operations of its own, other than its ownership of Panhandle and noncontrolling interests in PEI Power II, LLC, Regency (31.4 million Regency Common Units and 6.3 million Regency Class F Units), and ETP (3.3 million ETP Common Units).

4. | ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES:

The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2016 and 2015, were as follows:

| December 31,
| 2016 |  | 2015
Citrus | $ | 1,729 |  |  | $ | 1,739 |
AmeriGas | 82 |  |  | 80 |
FEP | 101 |  |  | 115 |
MEP | 318 |  |  | 660 |
HPC | 382 |  |  | 402 |
Others | 428 |  |  | 466 |
Total | $ | 3,040 |  |  | $ | 3,462 |

Citrus
ETP owns CrossCountry, which owns a 50% interest in Citrus. The other 50% interest in Citrus is owned by a subsidiary of KMI. Citrus owns 100% of FGT, a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula.
AmeriGas
In 2012, ETP received 29.6 million AmeriGas common units in connection with the contribution of its propane operations. During the year ended December 31, 2014, ETP sold 18.9 million AmeriGas common units for net proceeds of $814 million. As of December 31, 2016, the Partnership’s remaining interest in AmeriGas common units consisted of 3.1 million units held by a wholly-owned captive insurance company and is reflected in the Investment in ETP segment.
FEP
ETP has a 50% interest in FEP which owns an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi.
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MEP
ETP owns a 50% interest in MEP, which owns approximately 500 miles of natural gas pipeline that extends from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama. ETP evaluated its investment in MEP for impairment as of September 30, 2016, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. Based on commercial discussions with current and potential shippers on MEP regarding the outlook for long-term transportation contract rates, the Partnership concluded that the fair value of its investment was other than temporarily impaired, resulting in a non-cash impairment of $308 million during the year ended December 31, 2016.
HPC
ETP owns a 49.99% interest in HPC, which, through its ownership of RIGS, delivers natural gas from Northwest Louisiana to downstream pipelines and markets through a 450-mile intrastate pipeline system.
Summarized Financial Information
The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, including AmeriGas, Citrus, FEP, HPC and MEP (on a 100% basis) for all periods presented:

| December 31,
| 2016 |  | 2015
Current assets | $ | 720 |  |  | $ | 632 |
Property, plant and equipment, net | 9,982 |  |  | 10,213 |
Other assets | 2,618 |  |  | 2,649 |
Total assets | $ | 13,320 |  |  | $ | 13,494 |
Current liabilities | $ | 1,358 |  |  | $ | 841 |
Non-current liabilities | 7,583 |  |  | 7,950 |
Equity | 4,379 |  |  | 4,703 |
Total liabilities and equity | $ | 13,320 |  |  | $ | 13,494 |

| Years Ended December 31,
| 2016 |  | 2015 |  | 2014
Revenue | $ | 3,509 |  |  | $ | 4,026 |  |  | $ | 4,925 |
Operating income | 1,181 |  |  | 1,302 |  |  | 1,071 |
Net income | 602 |  |  | 807 |  |  | 577 |

In addition to the equity method investments described above our subsidiaries have other equity method investments which are not significant to our consolidated financial statements.
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5. | NET INCOME PER LIMITED PARTNER UNIT:

Basic net income per limited partner unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding. Diluted net income per limited partner unit is computed by dividing net income (as adjusted as discussed herein), after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding and the assumed conversion of our Preferred Units, see Note 7. For the diluted earnings per share computation, income allocable to the limited partners is reduced, where applicable, for the decrease in earnings from ETE’s limited partner unit ownership in ETP or Sunoco LP that would have resulted assuming the incremental units related to ETP’s or Sunoco LP’s equity incentive plans, as applicable, had been issued during the respective periods. Such units have been determined based on the treasury stock method.
A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows:

| Years Ended December 31,
| 2016 |  | 2015 |  | 2014
Income from continuing operations | $ | 520 |  |  | $ | 1,012 |  |  | $ | 994 |
Less: Income (loss) from continuing operations attributable to noncontrolling interest | (487 | ) |  | (176 | ) |  | 371 |
Income from continuing operations, net of noncontrolling interest | 1,007 |  |  | 1,188 |  |  | 623 |
Less: General Partner’s interest in income from continuing operations | 3 |  |  | 3 |  |  | 2 |
Less: Convertible Unitholders’ interest in net income from continuing operations | 8 |  |  | — |  |  | — |
Less: Class D Unitholder’s interest in income from continuing operations | — |  |  | 3 |  |  | 2 |
Income from continuing operations available to Limited Partners | $ | 996 |  |  | $ | 1,182 |  |  | $ | 619 |
Basic Income from Continuing Operations per Limited Partner Unit: |  |  |  |  |
Weighted average limited partner units | 1,045.5 |  |  | 1,062.8 |  |  | 1,088.6 |
Basic income from continuing operations per Limited Partner unit | $ | 0.95 |  |  | $ | 1.11 |  |  | $ | 0.57 |
Basic income (loss) from discontinued operations per Limited Partner unit | $ | (0.01 | ) |  | $ | — |  |  | $ | 0.01 |
Diluted Income from Continuing Operations per Limited Partner Unit: |  |  |  |  |
Income from continuing operations available to Limited Partners | $ | 996 |  |  | $ | 1,182 |  |  | $ | 619 |
Dilutive effect of equity-based compensation of subsidiaries, distributions to Class D Unitholder and Convertible Units | 8 |  |  | 3 |  |  | (2 | )
Diluted income from continuing operations available to Limited Partners | 1,004 |  |  | 1,185 |  |  | 617 |
Weighted average limited partner units | 1,045.5 |  |  | 1,062.8 |  |  | 1,088.6 |
Dilutive effect of unconverted unit awards and Convertible Units | 33.1 |  |  | 1.6 |  |  | 2.2 |
Weighted average limited partner units, assuming dilutive effect of unvested unit awards | 1,078.6 |  |  | 1,064.4 |  |  | 1,090.8 |
Diluted income from continuing operations per Limited Partner unit | $ | 0.93 |  |  | $ | 1.11 |  |  | $ | 0.57 |
Diluted income (loss) from discontinued operations per Limited Partner unit | $ | (0.01 | ) |  | $ | — |  |  | $ | 0.01 |

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6. | DEBT OBLIGATIONS:

Our debt obligations consist of the following:

| December 31,
| 2016 |  | 2015
Parent Company Indebtedness: |  |  |
7.50% Senior Notes, due October 15, 2020 | $ | 1,187 |  |  | $ | 1,187 |
5.875% Senior Notes, due January 15, 2024 | 1,150 |  |  | 1,150 |
5.50% Senior Notes due June 1, 2027 | 1,000 |  |  | 1,000 |
ETE Senior Secured Term Loan, due December 2, 2019 | 2,190 |  |  | 2,190 |
ETE Senior Secured Revolving Credit Facility due December 18, 2018 | 875 |  |  | 860 |
Unamortized premiums, discounts and fair value adjustments, net | (15 | ) |  | (17 | )
Deferred debt issuance costs | (30 | ) |  | (38 | )
| 6,357 |  |  | 6,332 |
Subsidiary Indebtedness: |  |  |
ETP Debt |  |  |
6.125% Senior Notes due February 15, 2017 | 400 |  |  | 400 |
2.50% Senior Notes due June 15, 2018 | 650 |  |  | 650 |
6.70% Senior Notes due July 1, 2018 | 600 |  |  | 600 |
9.70% Senior Notes due March 15, 2019 | 400 |  |  | 400 |
9.00% Senior Notes due April 15, 2019 | 450 |  |  | 450 |
5.75% Senior Notes due September 1, 2020 | 400 |  |  | 400 |
4.15% Senior Notes due October 1, 2020 | 1,050 |  |  | 1,050 |
6.50% Senior Notes due July 15, 2021 | 500 |  |  | 500 |
4.65% Senior Notes due June 1, 2021 | 800 |  |  | 800 |
5.20% Senior Notes due February 1, 2022 | 1,000 |  |  | 1,000 |
5.875% Senior Notes due March 1, 2022 | 900 |  |  | 900 |
5.00% Senior Notes due October 1, 2022 | 700 |  |  | 700 |
3.60% Senior Notes due February 1, 2023 | 800 |  |  | 800 |
5.50% Senior Notes due April 15, 2023 | 700 |  |  | 700 |
4.50% Senior Notes due November 1, 2023 | 600 |  |  | 600 |
4.90% Senior Notes due February 1, 2024 | 350 |  |  | 350 |
7.60% Senior Notes due February 1, 2024 | 277 |  |  | 277 |
4.05% Senior Notes due March 15, 2025 | 1,000 |  |  | 1,000 |
4.75% Senior Notes due January 15, 2026 | 1,000 |  |  | 1,000 |
8.25% Senior Notes due November 15, 2029 | 267 |  |  | 267 |
4.90% Senior Notes due March 15, 2035 | 500 |  |  | 500 |
6.625% Senior Notes due October 15, 2036 | 400 |  |  | 400 |
7.50% Senior Notes due July 1, 2038 | 550 |  |  | 550 |
6.05% Senior Notes due June 1, 2041 | 700 |  |  | 700 |
6.50% Senior Notes due February 1, 2042 | 1,000 |  |  | 1,000 |
5.15% Senior Notes due February 1, 2043 | 450 |  |  | 450 |
5.95% Senior Notes due October 1, 2043 | 450 |  |  | 450 |
5.15% Senior Notes due March 15, 2045 | 1,000 |  |  | 1,000 |
6.125% Senior Notes due December 15, 2045 | 1,000 |  |  | 1,000 |
Floating Rate Junior Subordinated Notes due November 1, 2066 | 546 |  |  | 545 |
ETP $3.75 billion Revolving Credit Facility due November 2019 | 2,777 |  |  | 1,362 |
Unamortized premiums, discounts and fair value adjustments, net | (18 | ) |  | (21 | )
Deferred debt issuance costs | (132 | ) |  | (147 | )
| 22,067 |  |  | 20,633 |
Transwestern Debt |  |  |
5.54% Senior Notes due November 17, 2016 | — |  |  | 125 |
5.64% Senior Notes due May 24, 2017 | 82 |  |  | 82 |
5.36% Senior Notes due December 9, 2020 | 175 |  |  | 175 |
5.89% Senior Notes due May 24, 2022 | 150 |  |  | 150 |
5.66% Senior Notes due December 9, 2024 | 175 |  |  | 175 |

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6.16% Senior Notes due May 24, 2037 | 75 |  |  | 75 |
Unamortized premiums, discounts and fair value adjustments, net | — |  |  | (1 | )
Deferred debt issuance costs | (1 | ) |  | (2 | )
| 656 |  |  | 779 |
Panhandle Debt |  |  |
6.20% Senior Notes due November 1, 2017 | 300 |  |  | 300 |
7.00% Senior Notes due June 15, 2018 | 400 |  |  | 400 |
8.125% Senior Notes due June 1, 2019 | 150 |  |  | 150 |
7.60% Senior Notes due February 1, 2024 | 82 |  |  | 82 |
7.00% Senior Notes due July 15, 2029 | 66 |  |  | 66 |
8.25% Senior Notes due November 14, 2029 | 33 |  |  | 33 |
Floating Rate Junior Subordinated Notes due November 1, 2066 | 54 |  |  | 54 |
Unamortized premiums, discounts and fair value adjustments, net | 50 |  |  | 75 |
| 1,135 |  |  | 1,160 |
Sunoco, Inc. Debt |  |  |
5.75% Senior Notes due January 15, 2017 | 400 |  |  | 400 |
9.00% Debentures due November 1, 2024 | 65 |  |  | 65 |
Unamortized premiums, discounts and fair value adjustments, net | 9 |  |  | 20 |
| 474 |  |  | 485 |
Sunoco Logistics Debt |  |  |
6.125% Senior Notes due May 15, 2016 | — |  |  | 175 |
5.50% Senior Notes due February 15, 2020 | 250 |  |  | 250 |
4.40% Senior Notes due April 1, 2021 | 600 |  |  | 600 |
4.65% Senior Notes due February 15, 2022 | 300 |  |  | 300 |
3.45% Senior Notes due January 15, 2023 | 350 |  |  | 350 |
4.25% Senior Notes due April 1, 2024 | 500 |  |  | 500 |
5.95% Senior Notes due December 1, 2025 | 400 |  |  | 400 |
3.90% Senior Notes due July 15, 2026 | 550 |  |  | — |
6.85% Senior Notes due February 15, 2040 | 250 |  |  | 250 |
6.10% Senior Notes due February 15, 2042 | 300 |  |  | 300 |
4.95% Senior Notes due January 15, 2043 | 350 |  |  | 350 |
5.30% Senior Notes due April 1, 2044 | 700 |  |  | 700 |
5.35% Senior Notes due May 15, 2045 | 800 |  |  | 800 |
Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 | 1,292 |  |  | 562 |
Sunoco Logistics $1.0 billion 364-Day Credit Facility due December 2017(1) | 630 |  |  | — |
Unamortized premiums, discounts and fair value adjustments, net | 75 |  |  | 85 |
Deferred debt issuance costs | (34 | ) |  | (32 | )
| 7,313 |  |  | 5,590 |
Bakken Project Debt |  |  |
Bakken Project $2.50 billion Credit Facility due August 2019 | 1,100 |  |  | — |
Deferred debt issuance costs | (13 | ) |  | — |
| 1,087 |  |  | — |
PennTex Debt |  |  |
PennTex $275 million Revolving Credit Facility due December 2019 | 168 |  |  | — |
Sunoco LP Debt |  |  |
5.50% Senior Notes Due August 1, 2020 | 600 |  |  | 600 |
6.375% Senior Notes due April 1, 2023 | 800 |  |  | 800 |
6.25% Senior Notes due April 15, 2021 | 800 |  |  | — |
Sunoco LP $1.50 billion Revolving Credit Facility due September 25, 2019 | 1,000 |  |  | 450 |
Sunoco LP Term Loan due October 1, 2019 | 1,243 |  |  | — |
Lease-related obligations | 118 |  |  | 126 |
Deferred debt issuance costs | (47 | ) |  | (18 | )
| 4,514 |  |  | 1,958 |

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Other | 31 |  |  | 31 |
| 43,802 |  |  | 36,968 |
Less: current maturities | 1,194 |  |  | 131 |
| $ | 42,608 |  |  | $ | 36,837 |

(1) | Sunoco Logistics’ $1.0 billion 364-Day Credit Facility, including its $630 million term loan, were classified as long-term debt as of December 31, 2016 as Sunoco Logistics has the ability and intent to refinance such borrowings on a long-term basis.

The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $156 million in unamortized premiums, fair value adjustments and deferred debt issuance costs, net:

2017 | $ | 1,817 |
2018 | 2,530 |
2019 | 9,483 |
2020 | 4,960 |
2021 | 2,706 |
Thereafter | 22,462 |
Total | $ | 43,958 |

Long-term debt reflected on our consolidated balance sheets includes fair value adjustments related to interest rate swaps, which represent fair value adjustments that had been recorded in connection with fair value hedge accounting prior to the termination of the interest rate swap.
Notes and Debentures
ETE Senior Notes
The ETE Senior Notes are the Parent Company’s senior obligations, ranking equally in right of payment with our other existing and future unsubordinated debt and senior to any of its future subordinated debt. The Parent Company’s obligations under the ETE Senior Notes are secured on a first-priority basis with its obligations under the Revolver Credit Agreement and the ETE Term Loan Facility, by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets, subject to certain exceptions and permitted liens. The ETE Senior Notes are not guaranteed by any of the Parent Company’s subsidiaries.
The covenants related to the ETE Senior Notes include a limitation on liens, a limitation on transactions with affiliates, a restriction on sale-leaseback transactions and limitations on mergers and sales of all or substantially all of the Parent Company’s assets.
As discussed above, the Parent Company’s outstanding senior notes are collateralized by its interests in certain of its subsidiaries. SEC Rule 3-16 of Regulation S-X (“Rule 3-16”) requires a registrant to file financial statements for each of its affiliates whose securities constitute a substantial portion of the collateral for registered securities. The Parent Company’s limited partner interests in ETP constitute substantial portions of the collateral for the Parent Company’s outstanding senior notes; accordingly, financial statements of ETP are required under Rule 3-16 to be included in the Partnership’s Annual Report on Form 10-K and have been included herein.
The Parent Company’s interests in ETP GP and ETE Common Holdings, LLC, (collectively, the “Non-Reporting Entities”) also constitute substantial portions of the collateral for the Parent Company’s outstanding senior notes. Accordingly, the financial statements of the Non-Reporting Entities would be required under Rule 3-16 to be included in the Parent Company’s Annual Report on Form 10-K. None of the Non-Reporting Entities has substantive operations of its own; rather, each of the Non-Reporting Entities holds only direct or indirect interests in ETP and/or the consolidated subsidiaries of ETP. Following is a summary of the interests held by each of the Non-Reporting Entities, as well as a summary of the significant differences between each of the Non-Reporting Entities compared to ETP:

• | ETP GP owns 100% of the general partner interest in ETP. ETP GP does not own limited partner interests in ETP; therefore, the limited partner interests in ETP, which had a carrying value of $18.43 billion and $20.53 billion as of December 31, 2016 and 2015, respectively, would be reflected as noncontrolling interests on ETP GP’s balance sheets. Likewise, ETP’s income (loss) attributable to limited partners (including common unitholders, Class H

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unitholders and Class I unitholders) of $(651) million, $334 million and $823 million for the years ended December 31, 2016, 2015 and 2014, respectively, would be reflected as income attributable to noncontrolling interest in ETP GP’s statements of operations.

• | As of December 31, 2014, ETE Common Holdings, LLC (“ETE Common Holdings”) owned 5.2 million ETP Common Units, representing approximately 1.5% of the total outstanding ETP Common Units, and 50.2 million ETP Class H Units, representing 100% of the total outstanding ETP Class H Units. ETE Common Holdings also owned 30.9 million Regency Common Units, representing approximately 7.5% of the total outstanding Regency Common Units; ETE Common Holdings’ interest in Regency was acquired in 2014. During 2015, all of the units held by ETE Common Holdings were redeemed by ETP. ETE Common Holdings does not own the general partner interests in ETP; therefore, the financial statements of ETE Common Holdings would only reflect equity method investments in ETP. The carrying values of ETE Common Holdings’ investments in ETP was $1.72 billion as of December 31, 2014, and ETE Common Holdings’ equity in earnings from its investments in ETP was $292 million for the year ended December 31, 2014.

ETP’s general partner interest, Common Units and Class H Units are reflected separately in ETP’s financial statements. As a result, the financial statements of the Non-Reporting Entities would substantially duplicate information that is available in the financial statements of ETP. Therefore, the financial statements of the Non-Reporting Entities have been excluded from the Partnership’s Annual Report on Form 10-K.
ETP as Co-Obligor of Sunoco, Inc. Debt
In connection with the Sunoco Merger and ETP Holdco Transaction, ETP became a co-obligor on approximately $965 million of aggregate principal amount of Sunoco, Inc.’s existing senior notes and debentures. The balance of these notes was $465 million as of December 31, 2016, and $400 million matured and was repaid in January 2017.
Panhandle Junior Subordinated Notes
The interest rate on the remaining portion of Panhandle’s junior subordinated notes due 2066 is a variable rate based upon the three-month LIBOR rate plus 3.0175%. The balance of the variable rate portion of the junior subordinated notes was $54 million at an effective interest rate of 3.77% at December 31, 2016.
ETP Senior Notes Offerings
In January 2017, ETP issued $600 million aggregate principal amount of 4.20% senior notes due April 2027 and $900 million aggregate principal amount of 5.30% senior notes due April 2047. ETP used the $1.48 billion net proceeds from the offering to refinance current maturities and to repay borrowings outstanding under the ETP Credit Facility.
The ETP senior notes were registered under the Securities Act of 1933 (as amended). ETP may redeem some or all of the ETP senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the ETP senior notes. The balance is payable upon maturity. Interest on the ETP senior notes is paid semi-annually.
The ETP senior notes are unsecured obligations of ETP and the obligation of ETP to repay the ETP senior notes is not guaranteed by us or any of ETP’s subsidiaries. As a result, the ETP senior notes effectively rank junior to any future indebtedness of ours or our subsidiaries that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETP senior notes effectively rank junior to all indebtedness and other liabilities of our existing and future subsidiaries.
Transwestern Senior Notes
The Transwestern senior notes are redeemable at any time in whole or pro rata in part, subject to a premium or upon a change of control event or an event of default, as defined. The balance is payable upon maturity. Interest is payable semi-annually.
Sunoco Logistics Senior Notes Offerings
In July 2016, Sunoco Logistics issued $550 million aggregate principal amount of 3.90% senior notes due in July 2026. The net proceeds from this offering were used to repay outstanding credit facility borrowings and for general partnership purposes.
Sunoco LP Senior Notes
In April 2016, Sunoco LP issued $800 million aggregate principal amount of 6.25% Senior Notes due 2021. The net proceeds of $789 million were used to repay a portion of the borrowings under its term loan facility.
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Term Loans, Credit Facilities and Commercial Paper
ETE Term Loan Facility
As of December 31, 2016, the Parent Company had outstanding a Senior Secured Term Loan Agreement, dated as of March 5, 2015, both with scheduled maturities on December 2, 2019. In connection with the Parent Company’s entry into a Senior Secured Term loan Agreement on February 2, 2017, as discussed below, the Parent Company terminated both agreements.
On February 2, 2017, the Partnership entered into a Senior Secured Term Loan Agreement (the “Term Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto. The Term Credit Agreement has a scheduled maturity date of February 2, 2024, with an option for the Parent Company to extend the term subject to the terms and conditions set forth therein. The Term Credit Agreement contains an accordion feature, under which the total commitments may be increased, subject to the terms thereof.
Pursuant to the Term Credit Agreement, the Term Lenders have provided senior secured financing in an aggregate principal amount of $2.2 billion (the “Term Loan Facility”). The Parent Company is not required to make any amortization payments with respect to the term loans under the Term Credit Agreement. Under certain circumstances and subject to certain reinvestment rights, the Parent Company is required to prepay the term loan in connection with dispositions of (a) IDRs in (i) prior to the consummation of the MLP Merger, ETP , and (ii) upon and after the consummation of the MLP Merger, Sunoco Logistics ; or (b) equity interests of any person which owns, directly or indirectly, IDRs in (i) prior to the consummation of the MLP Merger, ETP, and (ii) upon and after the consummation of the MLP Merger, Sunoco Logistics, in each case, with a percentage ranging from 50% to 75% of such net proceeds in excess of $50 million.
Under the Term Credit Agreement, the obligations of the Parent Company are secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets including (i) approximately 18.4 million common units representing limited partner interests in ETP and approximately 81.0 million Class H units of ETP owned by the Partnership; and (ii) the Partnership’s 100% equity interest in Energy Transfer Partners, L.L.C. and Energy Transfer Partners GP, L.P., through which the Partnership indirectly holds all of the outstanding general partnership interests and IDRs in, immediately prior to the consummation of the MLP Merger, ETP and, immediately after the consummation of the MLP Merger, Sunoco Logistics. The Term Loan Facility initially is not guaranteed by any of the Partnership’s subsidiaries.
Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The applicable margin for LIBOR rate loans is 2.75% and the applicable margin for base rate loans is 1.75%. Proceeds of the borrowings under the Term Credit Agreement were used to refinance amounts outstanding under the Parent Company’s existing term loan facilities and to pay transaction fees and expenses related to the Term Loan Facility and other transactions incidental thereto.
ETE Revolving Credit Facility
The Parent Company has the Revolver Credit Agreement which has a scheduled maturity date of December 2, 2018, with an option for the Parent Company to extend the term subject to the terms and conditions set forth therein.
Pursuant to the Revolver Credit Agreement, the lenders have committed to provide advances up to an aggregate principal amount of $1.50 billion at any one time outstanding. The Revolver Credit Agreement contains an accordion feature, under which the total commitments may be increased, subject to the terms thereof.
As part of the aggregate commitments under the facility, the Revolver Credit Agreement provides for letters of credit to be issued at the request of the Parent Company in an aggregate amount not to exceed a $150 million sublimit.
Under the Revolver Credit Agreement, the obligations of the Parent Company are secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets. Borrowings under the Revolver Credit Agreement are not guaranteed by any of the Parent Company’s subsidiaries.
Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The issuing fees for all letters of credit are also based on an applicable margin. The applicable margin used in connection with interest rates and fees is based on the then applicable leverage ratio of the Parent Company. The applicable margin for LIBOR rate loans and letter of credit fees ranges from 1.75% to 2.50% and the applicable margin for base rate loans ranges from 0.75% to 1.50%. The Parent Company will also pay a commitment fee based on its leverage ratio on the actual daily unused amount of the aggregate commitments.
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ETP Credit Facility
The ETP Credit Facility allows for borrowings of up to $3.75 billion and matures on November 18, 2019. The indebtedness under the ETP Credit Facility is unsecured, is not guaranteed by any of the Partnership’s subsidiaries and has equal rights to holders of our current and future unsecured debt. The indebtedness under the ETP Credit Facility has the same priority of payment as our other current and future unsecured debt. We use the ETP Credit Facility to provide temporary financing for our growth projects, as well as for general partnership purposes.
As of December 31, 2016, the ETP Credit Facility had $2.78 billion outstanding, and the amount available for future borrowings was $813 million after taking into account letters of credit of $160 million and commercial paper of $777 million. The weighted average interest rate on the total amount outstanding as of December 31, 2016 was 2.20%.
Sunoco Logistics Credit Facilities
Sunoco Logistics maintains a $2.50 billion unsecured revolving credit agreement (the “Sunoco Logistics Credit Facility”), which matures in March 2020. The Sunoco Logistics Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased to $3.25 billion under certain conditions.
The Sunoco Logistics Credit Facility is available to fund Sunoco Logistics’ working capital requirements, to finance acquisitions and capital projects, to pay distributions and for general partnership purposes. The Sunoco Logistics Credit Facility bears interest at LIBOR or the Base Rate, based on Sunoco Logistics’ election for each interest period, plus an applicable margin. The credit facility may be prepaid at any time. As of December 31, 2016, the Sunoco Logistics Credit Facility had $1.29 billion of outstanding borrowings, which included commercial paper of $50 million. The weighted average interest rate on the total amount outstanding as of December 31, 2016 was 1.76%.
In December 2016, Sunoco Logistics entered into an agreement for a 364-day maturity credit facility ("364-Day Credit Facility"), due to mature in December 2017, with a total lending capacity of $1.00 billion, including a $630 million term loan. The terms of the 364-Day Credit Facility are similar to those of the $2.50 billion Sunoco Logistics Credit Facility, including limitations on the creation of indebtedness, liens and financial covenants. The 364-Day Credit Facility is expected to be terminated and repaid in connection with the completion of the ETP and Sunoco Logistics merger.
Bakken Credit Facility
In August 2016, ETP, Sunoco Logistics and Phillips 66 announced the completion of the project-level financing of the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects (collectively, the “Bakken Pipeline”). The $2.50 billion credit facility is anticipated to provide substantially all of the remaining capital necessary to complete the projects and matures in August 2019 (the “Bakken Credit Facility”). As of December 31, 2016, the Bakken Credit Facility had $1.10 billion of outstanding borrowings. The weighted average interest rate on the total amount outstanding as of December 31, 2016 was 2.13%.
PennTex Revolving Credit Facility
On December 19, 2014, PennTex entered into a senior secured revolving credit facility with Royal Bank of Canada, as administrative agent, and a syndicate of lenders that became effective upon the closing of PennTex’s initial public offering and matures in December 2019 (the “PennTex Revolving Credit Facility”). The agreement provides for a $275 million commitment that is expandable up to $400 million under certain conditions. The funds have been used for general purposes, including the funding of capital expenditures. PennTex’s assets have been pledged as collateral for this credit facility.
As of December 31, 2016, PennTex had $106 million of available borrowing capacity under the PennTex Revolving Credit Facility. As of December 31, 2016, the weighted average interest rate on outstanding borrowings was 2.90%.
Sunoco LP Term Loan
In March 2016, Sunoco LP entered into a term loan agreement which provides secured financing in an aggregate principal amount of up to $2.035 billion due 2019. Amounts borrowed under the term loan bear interest at either LIBOR or base rate, based on Sunoco LP’s election for each interest period, plus an applicable margin. The proceeds were used to fund a portion of the ETP dropdown and to pay fees and expenses incurred in connection with the ETP dropdown and the term loan. In December, 2016, Sunoco LP entered into an amendment to the term loan to, among other matters, increase the maximum applicable margin for LIBOR rate loans, increase the maximum ratio of funded debt, and add new obligations to maintain a maximum ratio of secured funded debt to EBITDA of the Sunoco LP. As of December 31, 2016, the balance on the term loan was $1.24 billion. In January 2017, Sunoco LP entered into a limited waiver to its term loan, under which the agents and
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lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest owed under the term loan.
Sunoco LP Credit Facility
Sunoco LP maintains a $1.50 billion revolving credit agreement, which was amended in April 2015 from the initially committed amount of $1.25 billion and matures in September 2019. As of December 31, 2016, the Sunoco LP Credit Facility had $1.00 billion of outstanding borrowings. In January 2017, Sunoco LP entered into a limited waiver to its revolving credit facility, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest owed under the revolving credit facility.
Covenants Related to Our Credit Agreements
Covenants Related to the Parent Company
The Term Loan Facility and ETE Revolving Credit Facility contain customary representations, warranties, covenants and events of default, including a change of control event of default and limitations on incurrence of liens, new lines of business, merger, transactions with affiliates and restrictive agreements.
The Term Loan Facility and ETE Revolving Credit Facility contain financial covenants as follows:

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

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

Covenants Related to ETP
The agreements relating to the ETP senior notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.
The ETP Credit Facility contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things:

• | incur indebtedness;

• | grant liens;

• | enter into mergers;

• | dispose of assets;

• | make certain investments;

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

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

• | engage in transactions with affiliates; and

• | enter into restrictive agreements.

The credit agreement relating to the ETP Credit Facility also contains a financial covenant that provides that the Leverage Ratio, as defined in the ETP Credit Facility, shall not exceed 5.0 to 1 as of the end of each quarter, with a permitted increase to 5.5 to 1 during a Specified Acquisition Period, as defined in the ETP Credit Facility.
The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.
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Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Companies’ ability to incur additional debt and/or our ability to pay distributions.
Covenants Related to Panhandle
Panhandle is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Panhandle’s lending agreements. Financial covenants exist in certain of Panhandle’s debt agreements that require Panhandle to maintain a certain level of net worth, to meet certain debt to total capitalization ratios and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by Panhandle to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if Panhandle did not cure such default within any permitted cure period or if Panhandle did not obtain amendments, consents or waivers from its lenders with respect to such covenants.
Panhandle’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Panhandle’s debt and other financial obligations and that of its subsidiaries.
In addition, Panhandle and/or its subsidiaries are subject to certain additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in Panhandle’s cash management program; and limitations on Panhandle’s ability to prepay debt.
Covenants Related to Sunoco Logistics
The Sunoco Logistics $2.50 billion Credit Facility contains various covenants, including limitations on the creation of indebtedness and liens, and other covenants related to the operation and conduct of the business of Sunoco Logistics and its subsidiaries. The Sunoco Logistics Credit Facility also limits Sunoco Logistics, on a rolling four-quarter basis, to a maximum total Consolidated Funded Indebtedness to Consolidated EBITDA ratio, each as defined in the Sunoco Logistics Credit Facility, of 5.0 to 1, which can generally be increased to 5.5 to 1 during an acquisition period. Sunoco Logistics’ ratio of total Consolidated Funded Indebtedness, excluding net unamortized fair value adjustments, to Consolidated EBITDA was 4.4 to 1 at December 31, 2016, as calculated in accordance with the credit agreements.
Covenants Related to Bakken Credit Facility
The Bakken Credit Facility contains standard and customary covenants for a financing of this type, subject to materiality, knowledge and other qualifications, thresholds, reasonableness and other exceptions. These standard and customary covenants include, but are not limited to:

• | prohibition of certain incremental secured indebtedness;

• | prohibition of certain liens / negative pledge;

• | limitations on uses of loan proceeds;

• | limitations on asset sales and purchases;

• | limitations on permitted business activities;

• | limitations on mergers and acquisitions;

• | limitations on investments;

• | limitations on transactions with affiliates; and

• | maintenance of commercially reasonable insurance coverage.

A restricted payment covenant is also included in the Bakken Credit Facility which requires a minimum historic debt service coverage ratio (“DSCR”) of not less than 1.20 to 1 (the “Minimum Historic DSCR”) with respect each 12-month period following the commercial in-service date of the Dakota Access and ETCO Project in order to make certain restricted payments thereunder.
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Covenants Related to PennTex
The PennTex Revolving Credit Facility contains various covenants and restrictive provisions that, among other things, limit or restrict PennTex’s ability to incur or guarantee additional debt, incur certain liens on assets, dispose of assets, make certain distributions (including distributions from available cash, if a default or event of default under the credit agreement then exists or would result from making such a distribution), change the nature of PennTex’s business, engage in certain mergers or make certain investments and acquisitions, enter into non-arm’s-length transactions with affiliates and designate certain subsidiaries of PennTex as “Unrestricted Subsidiaries” for purposes of the credit agreement. Currently, no subsidiaries have been designated as Unrestricted Subsidiaries. PennTex is required to comply with a minimum consolidated interest coverage ratio of 2.50 x and a maximum consolidated leverage ratio of 4.75 x under the PennTex Revolving Credit Facility.
The borrowed amounts accrue interest at a LIBOR rate or a base rate, based on PennTex’s election for each interest period, plus an applicable margin. The applicable margin used in connection with the interest rates and fees is based on the then applicable Consolidated Total Leverage Ratio (as defined therein). The applicable margin for LIBOR rate loans and letter of credit fees range from 2.00% and 3.25% based on the Consolidated Total Leverage Ratio and the applicable margin for ABR loans ranges from 1.00% to 2.25% based on the Consolidated Total Leverage Ratio. The unused portion of the credit facility is subject to a commitment fee, which is based on the Consolidated Total Leverage Ratio and ranges from 0.35% to 0.50% multiplied by the amount of the unused commitment.
Covenants Related to Sunoco LP
The Sunoco LP Credit Facilities contain various customary representations, warranties, covenants and events of default, including a change of control event of default, as defined therein. The Sunoco LP Credit Facilities require Sunoco LP to maintain a leverage ratio (as defined therein) of not more than (a) as of the last day of each fiscal quarter through December 31, 2017, 6.75 to 1.0, (b) as of March 31, 2018, 6.5 to 1.0, (c) as of June 30, 2018, 6.25 to 1.0, (d) as of September 30, 2018, 6.0 to 1.0, (e) as of December 31, 2018, 5.75 to 1.0 and (f) thereafter, 5.5 to 1.0 (in the case of the quarter ending March 31, 2019 and thereafter, subject to increases to 6.0 to 1.0 in connection with certain specified acquisitions in excess of $50 million, as permitted under the Credit Facilities. Indebtedness under the Credit Facilities is secured by a security interest in, among other things, all of Sunoco LP’s present and future personal property and all of the present and future personal property of its guarantors, the capital stock of its material subsidiaries (or 66% of the capital stock of material foreign subsidiaries), and any intercompany debt. Upon the first achievement by Sunoco LP of an investment grade credit rating, all security interests securing borrowings under the Credit Facilities will be released.
Compliance With Our Covenants
Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities and note agreements could require us or our subsidiaries to pay debt balances prior to scheduled maturity and could negatively impact the subsidiaries ability to incur additional debt and/or our ability to pay distributions.
We and our subsidiaries are required to assess compliance quarterly and were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2016.

7. | REDEEMABLE PREFERRED UNITS:

The ETP Preferred Units are mandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon and are reflected as long-term liabilities in our consolidated balance sheets. The ETP Preferred Units are entitled to a preferential quarterly cash distribution of $0.445 per ETP Preferred Unit if outstanding on the record dates of ETP’s common unit distributions. Holders of the ETP Preferred Units can elect to convert the ETP Preferred Units to ETP Common Units at any time in accordance with ETP’s partnership agreement. The number of ETP common units issuable upon conversion of the ETP Preferred Units is equal to the issue price of $18.30, plus all accrued but unpaid distributions and interest thereon, divided by the conversion price of $44.37. As of December 31, 2016, the ETP Preferred Units were convertible into 1.3 million ETP Common Units.
In January 2017, ETP repurchased all of its 1.9 million outstanding Series A Preferred Units for cash in the aggregate amount of $53 million.
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8. | EQUITY:

Limited Partner Units
Limited partner interests in the Partnership are represented by Common Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. The Partnership’s Common Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for trading on the NYSE. Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the Limited Partners for a vote. In addition, if at any time any person or group (other than the Partnership’s General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Parent Company Quarterly Distributions of Available Cash.”
As of December 31, 2016, there were issued and outstanding 1.05 billion Common Units representing an aggregate 97.71% limited partner interest in the Partnership.
Our Partnership Agreement contains specific provisions for the allocation of net earnings and losses to the partners for purposes of maintaining the partner capital accounts. For any fiscal year that the Partnership has net profits, such net profits are first allocated to the General Partner until the aggregate amount of net profits for the current and all prior fiscal years equals the aggregate amount of net losses allocated to the General Partner for the current and all prior fiscal years. Second, such net profits shall be allocated to the Limited Partners pro rata in accordance with their respective sharing ratios. For any fiscal year in which the Partnership has net losses, such net losses shall be first allocated to the Limited Partners in proportion to their respective adjusted capital account balances, as defined by the Partnership Agreement, (before taking into account such net losses) until their adjusted capital account balances have been reduced to zero. Second, all remaining net losses shall be allocated to the General Partner. The General Partner may distribute to the Limited Partners funds of the Partnership that the General Partner reasonably determines are not needed for the payment of existing or foreseeable Partnership obligations and expenditures.
Common Units
The change in ETE Common Units during the years ended December 31, 2016, 2015 and 2014 was as follows:

| Years Ended December 31,
| 2016 |  | 2015 |  | 2014
Number of Common Units, beginning of period | 1,044.8 |  |  | 1,077.5 |  |  | 1,119.8 |
Conversion of Class D Units to ETE Common Units | — |  |  | 0.9 |  |  | — |
Repurchase of common units under buyback program | — |  |  | (33.6 | ) |  | (42.3 | )
Issuance of common units | 2.1 |  |  | — |  |  | — |
Number of Common Units, end of period | 1,046.9 |  |  | 1,044.8 |  |  | 1,077.5 |

ETE Series A Preferred Units

| Years Ended December 31,
| 2016 |  | 2015 |  | 2014
Number of Series A Convertible Preferred Units, beginning of period | — |  |  | — |  |  | — |
Issuance of Series A Convertible Preferred Units | 329.3 |  |  | — |  |  | — |
Number of Series A Convertible Preferred Units, end of period | 329.3 |  |  | — |  |  | — |

On March 8, 2016, the Partnership completed a private offering of 329.3 million Series A Convertible Preferred Units representing limited partner interests in the Partnership (the “Convertible Units”) to certain common unitholders (“Electing Unitholders”) who elected to participate in a plan to forgo a portion of their future potential cash distributions on common units participating in the plan for a period of up to nine fiscal quarters, commencing with distributions for the fiscal quarter ended March 31, 2016, and reinvest those distributions in the Convertible Units. With respect to each quarter for which the declaration date and record date occurs prior to the closing of the merger, or earlier termination of the merger agreement (the “WMB End Date”), each participating common unit will receive the same cash distribution as all other ETE common units
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up to $0.11 per unit, which represents approximately 40% of the per unit distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Preferred Distribution Amount”), and the holder of such participating common unit will forgo all cash distributions in excess of that amount (other than (i) any non-cash distribution or (ii) any cash distribution that is materially and substantially greater, on a per unit basis, than ETE’s most recent regular quarterly distribution, as determined by the ETE general partner (such distributions in clauses (i) and (ii), “Extraordinary Distributions”)). With respect to each quarter for which the declaration date and record date occurs after the WMB End Date, each participating common unit will forgo all distributions for each such quarter (other than Extraordinary Distributions), and each Convertible Unit will receive the Preferred Distribution Amount payable in cash prior to any distribution on ETE common units (other than Extraordinary Distributions). At the end of the plan period, which is expected to be May 18, 2018, the Convertible Units are expected to automatically convert into common units based on the Conversion Value (as defined and described below) of the Convertible Units and a conversion rate of $6.56.
The conversion value of each Convertible Unit (the “Conversion Value”) on the closing date of the offering is zero. The Conversion Value will increase each quarter in an amount equal to $0.285, which is the per unit amount of the cash distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Conversion Value Cap”), less the cash distribution actually paid with respect to each Convertible Unit for such quarter (or, if prior to the WMB End Date, each participating common unit). Any cash distributions in excess of $0.285 per ETE common unit, and any Extraordinary Distributions, made with respect to any quarter during the plan period will be disregarded for purposes of calculating the Conversion Value. The Conversion Value will be reflected in the carrying amount of the Convertible Units until the conversion into common units at the end of the plan period. The Convertible Units had $180 million carrying value as of December 31, 2016.
ETE issued 329,295,770 Convertible Units to the Electing Unitholders at the closing of the offering, which represents the participation by common unitholders with respect to approximately 31.5% of ETE’s total outstanding common units. ETE’s Chairman, Kelcy L. Warren, participated in the Plan with respect to substantially all of his common units, which represent approximately 18% of ETE’s total outstanding common units, and was issued 187,313,942 Convertible Units. In addition, John McReynolds, a director of our general partner and President of our general partner; and Matthew S. Ramsey, a director of our general partner and the general partner of ETP and Sunoco LP and President of the general partner of ETP, participated in the Plan with respect to substantially all of their common units, and Marshall S. McCrea, III, a director of our general partner and the general partner of ETP and Sunoco Logistics and the Group Chief Operating Officer and Chief Commercial Officer of our general partner, participated in the Plan with respect to a substantial portion of his common units. The common units for which Messrs. McReynolds, Ramsey and McCrea elected to participate in the Plan collectively represent approximately 2.2% of ETE’s total outstanding common units. ETE issued 21,382,155 Convertible Units to Mr. McReynolds, 51,317 Convertible Units to Mr. Ramsey and 1,112,728 Convertible Units to Mr. McCrea. Mr. Ray Davis, who owns an 18.8% membership interest in our general partner, participated in the Plan with respect to substantially all of his ETE common units, which represents approximately 6.9% of ETE’s total outstanding common units, and was issued 72,042,486 Convertible Units. Other than Mr. Davis, no other Electing Unitholder owns a material amount of equity securities of ETE or its affiliates.
ETE January 2017 Private Placement and ETP Unit Purchase
In January 2017, ETE issued 32.2 million common units representing limited partner interests in the Partnership to certain institutional investors in a private transaction for gross proceeds of approximately $580 million, which ETE used to purchase 23.7 million newly issued ETP common units for approximately $568 million.
Common Unit Split
On December 23, 2013, ETE announced that the board of directors of its general partner approved a two-for-one split of the Partnership’s outstanding common units (the “2014 Split”). The 2014 Split was completed on January 27, 2014. The 2014 Split was effected by a distribution of one ETE Common Unit for each common unit outstanding and held by unitholders of record at the close of business on January 13, 2014.
On May 28, 2015, ETE announced that the board of directors its general partner approved a two-for-one split of the Partnership’s outstanding common units (the “2015 Split”). The 2015 Split was completed on July 27, 2015. The 2015 Split was effected by a distribution of one ETE common unit for each common unit outstanding and held by unitholders of record at the close of business on July 15, 2015.
Repurchase Program
In December 2013, the Partnership announced a common unit repurchase program, whereby the Partnership may repurchase up to $1 billion of ETE Common Units in the open market at the Partnership’s discretion, subject to market conditions and
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other factors, and in accordance with applicable regulatory requirements. The Partnership repurchased 42.3 million ETE Common Units under this program through May 23, 2014, and the program was completed.
In February 2015, the Partnership announced a common unit repurchase program, whereby the Partnership may repurchase up to an additional $2 billion of ETE Common Units in the open market at the Partnership’s discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements. The Partnership repurchased 33.6 million ETE Common Units under this program in 2015. No units were repurchased in 2016, and there was $936 million available to use under the program as of December 31, 2016.
Class D Units
On May 1, 2013, Jamie Welch was appointed Group Chief Financial Officer and Head of Corporate Development of LE GP, LLC, the general partner of ETE, effective June 24, 2013. Pursuant to an equity award agreement between Mr. Welch and the Partnership dated April 23, 2013, Mr. Welch received 3,000,000 restricted ETE common units representing limited partner interest. The restricted ETE common units were subject to vesting, based on continued employment with ETE. On December 23, 2013, ETE and Mr. Welch entered into (i) a rescission agreement in order to rescind the original offer letter to the extent it relates to the award of 3,000,000 common units of ETE to Mr. Welch, the original award agreements, and the receipt of cash amounts by Mr. Welch with respect to such awarded units and (ii) a new Class D Unit Agreement between ETE and Mr. Welch providing for the issuance to Mr. Welch of an aggregate of 3,080,000 Class D Units of ETE, which number of Class D Units includes an additional 80,000 Class D Units that were issued to Mr. Welch in connection with other changes to his original offer letter.
Under the terms of the Class D Unit Agreement, as amended, 30% of the Class D Units converted to ETE common units on a one-for-one basis on March 31, 2015, 35% were scheduled to convert to ETE common units on a one-for-one-basis on March 31, 2018, and the remaining 35% were scheduled to convert to ETE common units on a one-for-one basis on March 31, 2020, subject in each case to (i) Mr. Welch being in Good Standing with ETE (as defined in the Class D Unit Agreement) and (ii) there being a sufficient amount of gain available (based on the ETE partnership agreement) to be allocated to the Class D Units being converted so as to cause the capital account of each such unit to equal the capital account of an ETE Common Unit on the conversion date. Per the terms of the Class D Unit Agreement, 924,000 units converted to ETE common units on a one-for-one basis March 31, 2015. In connection with Mr. Welch’s replacement as Group Chief Financial Officer and Head of Business Development of our General Partner and his termination of employment by an affiliate of ETE, any future conversion of the Class D Units is the subject of on-going discussions between ETE and Mr. Welch in connection with his separation from employment. On March 10, 2016, Jamie Welch (“Welch”) filed an original petition against ETE and LE GP, LLC in Texas state court in Dallas. A confidential settlement was reached in August 2016. The court dismissed the matter with prejudice on September 6, 2016.
Sale of Common Units by Subsidiaries
The Parent Company accounts for the difference between the carrying amount of its investment in subsidiaries and the underlying book value arising from issuance of units by subsidiaries (excluding unit issuances to the Parent Company) as a capital transaction. If a subsidiary issues units at a price less than the Parent Company’s carrying value per unit, the Parent Company assesses whether the investment has been impaired, in which case a provision would be reflected in our statement of operations. The Parent Company did not recognize any impairment related to the issuances of subsidiary common units during the periods presented.
Sale of Common Units by ETP
ETP’s Equity Distribution Program
From time to time, ETP has sold ETP Common Units through an equity distribution agreement. Such sales of ETP Common Units are made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between us and the sales agent which is the counterparty to the equity distribution agreement.
In July 2016, ETP entered into an equity distribution agreement with an aggregate offering price up to $1.50 billion. During the year ended December 31, 2016, ETP issued 39.2 million units for $891 million, net of commissions of $8 million. In connection with the merger of ETP and Sunoco Logistics in April 2017, the equity distribution agreement was terminated.
ETP’s Equity Incentive Plan Activity
ETP issues ETP Common Units to employees and directors upon vesting of awards granted under ETP’s equity incentive plans. Upon vesting, participants in the equity incentive plans may elect to have a portion of the ETP Common Units to which they are entitled withheld by ETP to satisfy tax-withholding obligations.
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ETP’s Distribution Reinvestment Program
ETP’s Distribution Reinvestment Plan (the “DRIP”) provides ETP’s Unitholders of record and beneficial owners of ETP Common Units a voluntary means by which they can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional ETP Common Units.
During the years ended December 31, 2016, 2015 and 2014, aggregate distributions of $216 million, $360 million, and $155 million, respectively, were reinvested under the DRIP resulting in the issuance in aggregate of 25.7 million Common Units. In connection with the merger of ETP and Sunoco Logistics in April 2017, the distribution reinvestment plan was terminated.
ETP Class E Units
These ETP Class E Units are entitled to aggregate cash distributions equal to 11.1% of the total amount of cash distributed to all ETP Unitholders, including the ETP Class E Unitholders, up to $1.41 per unit per year, with any excess thereof available for distribution to ETP Unitholders other than the holders of ETP Class E Units in proportion to their respective interests. The ETP Class E Units are treated by ETP as treasury units for accounting purposes because they are owned by a subsidiary of ETP Holdco, Heritage Holdings, Inc. Although no plans are currently in place, management may evaluate whether to retire some or all of the ETP Class E Units at a future date. All of the 8.9 million ETP Class E Units outstanding are held by a subsidiary of ETP and are reported by ETP as treasury units.
ETP Class G Units
In conjunction with the Sunoco Merger, ETP amended its partnership agreement to create ETP Class F Units. The number of ETP Class F Units issued was determined at the closing of the Sunoco Merger and equaled 90.7 million, which included 40 million ETP Class F Units issued in exchange for cash contributed by Sunoco, Inc. to ETP immediately prior to or concurrent with the closing of the Sunoco Merger. The ETP Class F Units generally did not have any voting rights. The ETP Class F Units were entitled to aggregate cash distributions equal to 35% of the total amount of cash generated by ETP and its subsidiaries, other than ETP Holdco, and available for distribution, up to a maximum of $3.75 per ETP Class F Unit per year. In April 2013, all of the outstanding ETP Class F Units were exchanged for ETP Class G Units on a one-for-one basis. The ETP Class G Units have terms that are substantially the same as the ETP Class F Units, with the principal difference between the ETP Class G Units and the ETP Class F Units being that allocations of depreciation and amortization to the ETP Class G Units for tax purposes are based on a predetermined percentage and are not contingent on whether ETP has net income or loss. The ETP Class G Units are held by a subsidiary of ETP and therefore are reflected by ETP as treasury units in its consolidated financial statements.
ETP Class H Units and Class I Units
Pursuant to an Exchange and Redemption Agreement previously entered into between ETP, ETE and ETE Holdings, ETP redeemed and cancelled 50.2 million of its Common Units representing limited partner interests (the “Redeemed Units”) owned by ETE Holdings on October 31, 2013 in exchange for the issuance by ETP to ETE Holdings of a new class of limited partner interest in ETP (the “Class H Units”), which are generally entitled to (i) allocations of profits, losses and other items from ETP corresponding to 90.05% of the profits, losses, and other items allocated to ETP by Sunoco Partners, with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners, (ii) distributions from available cash at ETP for each quarter equal to 90.05% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters. The Class H Units were cancelled in connection with the merger of ETP and Sunoco Logistics in April 2017.
Bakken Pipeline Transaction
In March 2015, ETE transferred 46.2 million ETP common units, ETE’s 45% interest in the Bakken Pipeline project, and $879 million in cash to ETP in exchange for 30.8 million newly issued ETP Class H Units that, when combined with the 50.2 million previously issued ETP Class H Units, generally entitle ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics (the “Bakken Pipeline Transaction”). In connection with this transaction, ETP also issued to ETE 100 ETP Class I Units that provide distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, including the impact from distributions on ETP Class I Units, were reduced by $55 million in 2015 and $30 million in 2016.
In connection with the transaction, ETP issued 100 ETP Class I Units. The ETP Class I Units are generally entitled to: (i) pro rata allocations of gross income or gain until the aggregate amount of such items allocated to the holders of the ETP Class
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I Units for the current taxable period and all previous taxable periods is equal to the cumulative amount of all distributions made to the holders of the ETP Class I Units and (ii) after making cash distributions to ETP Class H Units, any additional available cash deemed to be either operating surplus or capital surplus with respect to any quarter will be distributed to the Class I Units in an amount equal to the excess of the distribution amount set forth in ETP’s Partnership Agreement, as amended, (the “Partnership Agreement”) for such quarter over the cumulative amount of available cash previously distributed commencing with the quarter ending March 31, 2015 until the quarter ending December 31, 2016. The impact of (i) the IDR subsidy adjustments and (ii) the ETP Class I Unit distributions, along with the currently effective IDR subsidies, is included in the table below under “Quarterly Distributions of Available Cash.” Subsequent to the April 2017 merger of ETP and Sunoco Logistics, 100 Class I Units remained outstanding.
Bakken Equity Sale
On August 2, 2016, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 60% membership interest and Sunoco Logistics indirectly owns a 40% membership interest, agreed to sell a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by Marathon Petroleum Corporation and Enbridge Energy Partners, L.P. for $2.00 billion in cash. This transaction closed in February 2017. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access, LLC (“Dakota Access”) and Energy Transfer Crude Oil Company, LLC (“ETCO”). The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP will continue to consolidate Dakota Access and ETCO subsequent to this transaction. Upon closing, ETP and Sunoco Logistics collectively own a 38.25% interest in the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects (collectively, the "Bakken Pipeline"), and MarEn Bakken Company owns 36.75% and Phillips 66 owns 25.00% in the Bakken Pipeline.
Class K Units
On December 29, 2016, ETP issued to certain of its indirect subsidiaries, in exchange for cash contributions and the exchange of outstanding common units representing limited partner interests in ETP, Class K Units, each of which is entitled to a quarterly cash distribution of $0.67275 per Class K Unit prior to ETP making distributions of available cash to any class of units other than the Class H Units and the Class I Units, excluding any cash available distributions or dividends or capital stock sales proceeds received by ETP from ETP Holdco. As of December 31, 2016, a total of 101,525,429 Class K Units were held by indirect subsidiaries of ETP.
Sales of Common Units by Sunoco Logistics
In September and October 2016, a total of 24.2 million common units were issued for net proceeds of $644 million in connection with a public offering and related option exercise. The proceeds from this offering were used to partially fund the acquisition from Vitol.
In March and April 2015, a total of 15.5 million common units were issued in connection with a public offering and related option exercise. Net proceeds of $629 million were used to repay outstanding borrowings under Sunoco Logistics’ $2.50 billion Credit Facility and for general partnership purposes.
In September 2014, Sunoco Logistics completed an overnight public offering of 7.7 million common units for net proceeds of $362 million were used to repay outstanding borrowings under the Sunoco Logistics Credit Facility and for general partnership purposes.
In 2014, Sunoco Logistics entered into equity distribution agreements pursuant to which Sunoco Logistics may sell from time to time common units having aggregate offering prices of up to $1.25 billion. In the fourth quarter of 2015, the aggregate capacity was increased to $2.25 billion. During the year ended December 31, 2016, Sunoco Logistics received proceeds of $744 million, net of commissions of $8 million, from the issuance of 29.1 million common units pursuant to the equity distribution agreement.
Sales of Common Units by Sunoco LP
In October 2016, Sunoco LP entered into an equity distribution agreement pursuant to which Sunoco LP may sell from time to time common units having aggregate offering prices of up to $400 million. Through December 31, 2016, Sunoco LP received net proceeds of $71 million from the issuance of 2.8 million Sunoco LP common units pursuant to such equity distribution agreement. Sunoco LP intends to use the proceeds from any sales for general partnership purposes. As of December 31, 2016, $328 million of Sunoco LP common units remained available to be issued under the currently effective equity distribution agreement. From January 1, 2017 through February 24, 2017, Sunoco LP issued additional 0.4 million units with total net proceeds of $10 million and intends to use the net proceeds from sales for general partnership purposes,
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which may include repaying or refinancing all or a portion of our outstanding indebtedness and funding capital expenditures, acquisitions or working capital.
In March 2016, ETP contributed to Sunoco LP its remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business for $2.23 billion. Sunoco LP paid $2.20 billion in cash, including a working capital adjustment, and issued 5.7 million Sunoco LP common units to Retail Holdings, a wholly-owned subsidiary of ETP.
On March 31, 2016, Sunoco LP sold 2.3 million of Sunoco LP’s common units in a private placement to the Partnership.
In January 2016, Sunoco LP issued 16.4 million Class C units representing limited partner interest consisting of (i) 5.2 million Class C Units issued by Sunoco LP to Aloha Petroleum, Ltd as consideration for the contribution by Aloha to an indirect wholly-owned subsidiary, and (ii) 11.2 million Class C Units that were issued by Sunoco LP to its indirect wholly-owned subsidiaries in exchange for all of the outstanding Class A Units held by such subsidiaries.
In July 2015, Sunoco LP completed an offering of 5.5 million Sunoco LP common units for net proceeds of $213 million. The net proceeds from the offering were used to repay outstanding balances under the Sunoco LP revolving credit facility.
In October 2014 and November 2014, Sunoco LP issued an aggregate total of 9.1 million common units in an underwritten public offering. Aggregate net proceeds of $405 million from the offering were used to repay amounts outstanding under the $1.50 billion Sunoco LP Credit Facility and for general partnership purposes.
Contributions to Subsidiaries
The Parent Company indirectly owns the entire general partner interest in ETP through its ownership of ETP GP, the general partner of ETP. ETP GP has the right, but not the obligation, to contribute a proportionate amount of capital to ETP to maintain its current general partner interest. ETP GP’s interest in ETP’s distributions is reduced if ETP issues additional units and ETP GP does not contribute a proportionate amount of capital to ETP to maintain its General Partner interest.
Parent Company Quarterly Distributions of Available Cash
Our distribution policy is consistent with the terms of our Partnership Agreement, which requires that we distribute all of our available cash quarterly. The Parent Company’s only cash-generating assets currently consist of distributions from ETP and Sunoco LP related to limited and general partner interests, including IDRs, as well as cash generated from our investment in Lake Charles LNG.
Our distributions declared with respect to our common units during the years ended December 31, 2016, 2015, and 2014 were as follows:

Quarter Ended |  | Record Date |  | Payment Date |  | Rate
December 31, 2013 |  | February 7, 2014 |  | February 19, 2014 |  | $ | 0.1731 |
March 31, 2014 |  | May 5, 2014 |  | May 19, 2014 |  | 0.1794 |
June 30, 2014 |  | August 4, 2014 |  | August 19, 2014 |  | 0.1900 |
September 30, 2014 |  | November 3, 2014 |  | November 19, 2014 |  | 0.2075 |
December 31, 2014 |  | February 6, 2015 |  | February 19, 2015 |  | 0.2250 |
March 31, 2015 |  | May 8, 2015 |  | May 19, 2015 |  | 0.2450 |
June 30, 2015 |  | August 6, 2015 |  | August 19, 2015 |  | 0.2650 |
September 30, 2015 |  | November 5, 2015 |  | November 19, 2015 |  | 0.2850 |
December 31, 2015 |  | February 4, 2016 |  | February 19, 2016 |  | 0.2850 |
March 31, 2016 (1) |  | May 6, 2016 |  | May 19, 2016 |  | 0.2850 |
June 30, 2016 (1) |  | August 8, 2016 |  | August 19, 2016 |  | 0.2850 |
September 30, 2016 (1) |  | November 7, 2016 |  | November 18, 2016 |  | 0.2850 |
December 31, 2016 (1) |  | February 7, 2017 |  | February 21, 2017 |  | 0.2850 |

(1) | Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received Convertible Units (on a one-for-one basis for each common unit as to

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which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Convertible Unit. See Note 8, ETE Series A Preferred Units.
Our distributions declared with respect to our Convertible Unit during the year ended December 31, 2016 were as follows:

Quarter Ended |  | Record Date |  | Payment Date |  | Rate
March 31, 2016 |  | May 6, 2016 |  | May 19, 2016 |  | $ | 0.1100 |
June 30, 2016 |  | August 8, 2016 |  | August 19, 2016 |  | 0.1100 |
September 30, 2016 |  | November 7, 2016 |  | November 18, 2016 |  | 0.1100 |
December 31, 2016 |  | February 7, 2017 |  | February 21, 2017 |  | 0.1100 |

ETP’s Quarterly Distributions of Available Cash
ETP’s Partnership Agreement requires that ETP distribute all of its Available Cash to its Unitholders and its General Partner within 45 days following the end of each fiscal quarter, subject to the payment of incentive distributions to the holders of IDRs to the extent that certain target levels of cash distributions are achieved. The term Available Cash generally means, with respect to any fiscal quarter of ETP, all cash on hand at the end of such quarter, plus working capital borrowings after the end of the quarter, less reserves established by its General Partner in its sole discretion to provide for the proper conduct of ETP’s business, to comply with applicable laws or any debt instrument or other agreement, or to provide funds for future distributions to partners with respect to any one or more of the next four quarters. Available Cash is more fully defined in ETP’s Partnership Agreement.
ETP’s distributions declared during the periods presented below were as follows:

Quarter Ended |  | Record Date |  | Payment Date |  | Rate
December 31, 2013 |  | February 7, 2014 |  | February 14, 2014 |  | $ | 0.6133 |
March 31, 2014 |  | May 5, 2014 |  | May 15, 2014 |  | 0.6233 |
June 30, 2014 |  | August 4, 2014 |  | August 14, 2014 |  | 0.6367 |
September 30, 2014 |  | November 3, 2014 |  | November 14, 2014 |  | 0.6500 |
December 31, 2014 |  | February 6, 2015 |  | February 13, 2015 |  | 0.6633 |
March 31, 2015 |  | May 8, 2015 |  | May 15, 2015 |  | 0.6767 |
June 30, 2015 |  | August 6, 2015 |  | August 14, 2015 |  | 0.6900 |
September 30, 2015 |  | November 5, 2015 |  | November 16, 2015 |  | 0.7033 |
December 31, 2015 |  | February 8, 2016 |  | February 16, 2016 |  | 0.7033 |
March 31, 2016 |  | May 6, 2016 |  | May 16, 2016 |  | 0.7033 |
June 30, 2016 |  | August 8, 2016 |  | August 15, 2016 |  | 0.7033 |
September 30, 2016 |  | November 7, 2016 |  | November 14, 2016 |  | 0.7033 |
December 31, 2016 |  | February 7, 2017 |  | February 14, 2017 |  | 0.7033 |

ETE agreed to relinquish its right to the following amounts of incentive distributions in future periods:

|  | Total Year
2017 |  | $ | 626 |
2018 |  | 138 |
2019 |  | 128 |
Each year beyond 2019 |  | 33 |

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Sunoco Logistics Quarterly Distributions of Available Cash
Distributions declared by Sunoco Logistics during the years ended December 31, 2016, 2015, and 2014 were as follows:

Quarter Ended |  | Record Date |  | Payment Date |  | Rate
December 31, 2013 |  | February 10, 2014 |  | February 14, 2014 |  | $ | 0.3312 |
March 31, 2014 |  | May 9, 2014 |  | May 15, 2014 |  | 0.3475 |
June 30, 2014 |  | August 8, 2014 |  | August 14, 2014 |  | 0.3650 |
September 30, 2014 |  | November 7, 2014 |  | November 14, 2014 |  | 0.3825 |
December 31, 2014 |  | February 9, 2015 |  | February 13, 2015 |  | 0.4000 |
March 31, 2015 |  | May 11, 2015 |  | May 15, 2015 |  | 0.4190 |
June 30, 2015 |  | August 10, 2015 |  | August 14, 2015 |  | 0.4380 |
September 30, 2015 |  | November 9, 2015 |  | November 13, 2015 |  | 0.4580 |
December 31, 2015 |  | February 8, 2016 |  | February 12, 2016 |  | 0.4790 |
March 31, 2016 |  | May 9, 2016 |  | May 13, 2016 |  | 0.4890 |
June 30, 2016 |  | August 8, 2016 |  | August 12, 2016 |  | 0.5000 |
September 30, 2016 |  | November 9, 2016 |  | November 14, 2016 |  | 0.5100 |
December 31, 2016 |  | February 7, 2017 |  | February 14, 2017 |  | 0.5200 |

PennTex Quarterly Distributions of Available Cash
PennTex is required by its partnership agreement to distribute a minimum quarterly distribution of $0.2750 per unit at the end of each quarter. Distributions declared during the periods presented were as follows:

Quarter Ended |  | Record Date |  | Payment Date |  | Rate
September 30, 2016 |  | November 7, 2016 |  | November 14, 2016 |  | $ | 0.2950 |
December 31, 2016 |  | February 7, 2017 |  | February 14, 2017 |  | 0.2950 |

Sunoco LP Quarterly Distributions of Available Cash
Distributions declared by Sunoco LP subsequent to our acquisition on August 29, 2014 were as follows:

Quarter Ended |  | Record Date |  | Payment Date |  | Rate
September 30, 2014 |  | November 18, 2014 |  | November 28, 2014 |  | $ | 0.5457 |
December 31, 2014 |  | February 17, 2015 |  | February 27, 2015 |  | 0.6000 |
March 31, 2015 |  | May 19, 2015 |  | May 29, 2015 |  | 0.6450 |
June 30, 2015 |  | August 18, 2015 |  | August 28, 2015 |  | 0.6934 |
September 30, 2015 |  | November 17, 2015 |  | November 27, 2015 |  | 0.7454 |
December 31, 2015 |  | February 5, 2016 |  | February 16, 2016 |  | 0.8013 |
March 31, 2016 |  | May 6, 2016 |  | May 16, 2016 |  | 0.8173 |
June 30, 2016 |  | August 5, 2016 |  | August 15, 2016 |  | 0.8255 |
September 30, 2016 |  | November 7, 2016 |  | November 15, 2016 |  | 0.8255 |
December 31, 2016 |  | February 13, 2017 |  | February 21, 2017 |  | 0.8255 |

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Accumulated Other Comprehensive Income (Loss)
The following table presents the components of AOCI, net of tax:

| December 31,
| 2016 |  | 2015
Available-for-sale securities | $ | 2 |  |  | $ | — |
Foreign currency translation adjustment | (5 | ) |  | (4 | )
Actuarial gain related to pensions and other postretirement benefits | 7 |  |  | 8 |
Investments in unconsolidated affiliates, net | 4 |  |  | — |
Subtotal | 8 |  |  | 4 |
Amounts attributable to noncontrolling interest | (8 | ) |  | (4 | )
Total AOCI included in partners’ capital, net of tax | $ | — |  |  | $ | — |

The table below sets forth the tax amounts included in the respective components of other comprehensive income (loss):

| December 31,
| 2016 |  | 2015
Available-for-sale securities | $ | (2 | ) |  | $ | (2 | )
Foreign currency translation adjustment | 3 |  |  | 4 |
Actuarial loss relating to pension and other postretirement benefits | — |  |  | 7 |
Total | $ | 1 |  |  | $ | 9 |

9. | UNIT-BASED COMPENSATION PLANS:

We, ETP, Sunoco Logistics and Sunoco LP have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase Common Units, restricted units, phantom units, distribution equivalent rights (“DERs”), common unit appreciation rights, cash restricted units and other unit-based awards.
ETE Long-Term Incentive Plan
The Board of Directors or the Compensation Committee of the board of directors of the our General Partner (the “Compensation Committee”) may from time to time grant additional awards to employees, directors and consultants of ETE’s general partner and its affiliates who perform services for ETE. The plan provides for the following types of awards: restricted units, phantom units, unit options, unit appreciation rights and distribution equivalent rights. The number of additional units that may be delivered pursuant to these awards is limited to 12,000,000 units. As of December 31, 2016, 8,271,767 units remain available to be awarded under the plan.
During the year ended December 31, 2016, no ETE unit awards were granted to ETE employees and 23,821 ETE units were granted to non-employee directors. Under our equity incentive plans, our non-employee directors each receive grants that vest 60% in three years and 40% in five years and do not entitle the holders to receive distributions during the vesting period.
During the year ended December 31, 2016 and 2015, a total of 28,648 and 26,244 ETE Common Units vested, with a total fair value of $0.2 million and $0.8 million, respectively, as of the vesting date. As of December 31, 2016, a total of 43,740 restricted units granted to ETE directors remain outstanding, for which we expect to recognize a total of less than $1 million in compensation over a weighted average period of 3.0 years.
Subsidiary Unit-Based Compensation Plans
Both ETP and Sunoco LP have granted restricted or phantom unit awards (collectively, the “Subsidiary Unit Awards” to employees and directors that entitle the grantees to receive common units of the respective subsidiary. In some cases, at the discretion of the respective subsidiary’s compensation committee, the grantee may instead receive an amount of cash equivalent to the value of common units upon vesting. Substantially all of the Subsidiary Unit Awards are time-vested grants, which generally vest over a five-year period, and vesting The Subsidiary Unit Awards entitle the grantees of the unit awards to receive an amount of cash equal to the per unit cash distributions made by the respective subsidiaries during the period the restricted unit is outstanding.
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The following table summarizes the activity of the Subsidiary Unit Awards:

| ETP |  | Sunoco LP
| Number of Units |  | Weighted Average Grant-Date Fair Value Per Unit |  | Number of Units |  | Weighted Average Grant-Date Fair Value Per Unit
Unvested awards as of December 31, 2015 | 7.2 |  |  | $ | 31.74 |  |  | 1.1 |  |  | $ | 41.19 |
Awards granted | 3.8 |  |  | 23.82 |  |  | 1.0 |  |  | 26.95 |
Awards vested | (1.2 | ) |  | 35.48 |  |  | — |  |  | 36.98 |
Awards forfeited | (0.3 | ) |  | 32.26 |  |  | (0.1 | ) |  | 39.77 |
Unvested awards as of December 31, 2016 | 9.5 |  |  | 27.69 |  |  | 2.0 |  |  | 34.43 |
Weighted average grant date fair value for Subsidiary Unit Awards during the year ended December 31: |  |  |  |  |  |  |
2016 |  |  | $ | 23.82 |  |  |  |  | $ | 26.95 |
2015 |  |  | 23.47 |  |  |  |  | 40.63 |
2014 |  |  | 40.57 |  |  |  |  | 45.50 |

The total fair value of Subsidiary Unit Awards vested for the years ended December 31, 2016, 2015, and 2014 was $40 million, $57 million, and $56 million, respectively, based on the market price of the respective subsidiaries’ common units as of the vesting date. As of December 31, 2016, estimated compensation cost related to Subsidiary Unit Awards not yet recognized was $275 million, and the weighted average period over which this cost is expected to be recognized in expense is 3.0 years and 4.3 years for ETP and Sunoco LP, respectively.

10. | INCOME TAXES:

As a partnership, we are not subject to U.S. federal income tax and most state income taxes. However, the Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) of our taxable subsidiaries were summarized as follows:

| Years Ended December 31,
| 2016 |  | 2015 |  | 2014
Current expense (benefit): |  |  |  |  |
Federal | $ | 11 |  |  | $ | (315 | ) |  | $ | 251 |
State | (34 | ) |  | (54 | ) |  | 78 |
Total | (23 | ) |  | (369 | ) |  | 329 |
Deferred expense (benefit): |  |  |  |  |
Federal | (237 | ) |  | 253 |  |  | (29 | )
State | 12 |  |  | (32 | ) |  | 25 |
Total | (225 | ) |  | 221 |  |  | (4 | )
Total income tax expense (benefit) from continuing operations | $ | (248 | ) |  | $ | (148 | ) |  | $ | 325 |

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Historically, our effective tax rate differed from the statutory rate primarily due to partnership earnings that are not subject to U.S. federal and most state income taxes at the partnership level. The completion of the Southern Union Merger, Sunoco Merger, ETP Holdco Transaction and the Susser Merger (see Note 3) significantly increased the activities conducted through corporate subsidiaries. A reconciliation of income tax expense (benefit) at the U.S. statutory rate to the income tax expense (benefit) attributable to continuing operations for the years ended December 31, 2016, 2015 and 2014 is as follows:

| December 31, 2016 |  | December 31, 2015 | December 31, 2014
Income tax expense (benefit) at U.S. statutory rate of 35 percent | $ | 95 |  |  | $ | 302 |  |  | $ | 462 |
Increase (reduction) in income taxes resulting from: |  |  |  |  |
Nondeductible goodwill included in the Lake Charles LNG transaction | — |  |  | — |  |  | 105 |
Partnership earnings not subject to tax | (590 | ) |  | (366 | ) |  | (284 | )
Goodwill impairment | 278 |  |  | — |  |  | — |
State tax, net of federal tax benefit | (10 | ) |  | (35 | ) |  | 52 |
Dividend received deduction | (15 | ) |  | (22 | ) |  | — |
Premium on debt retirement | — |  |  | — |  |  | (10 | )
Audit settlement | — |  |  | (7 | ) |  | — |
Foreign taxes | — |  |  | — |  |  | (8 | )
Other | (6 | ) |  | (20 | ) |  | 8 |
Income tax expense (benefit) from continuing operations | $ | (248 | ) |  | $ | (148 | ) |  | $ | 325 |

Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows:

| December 31,
| 2016 |  | 2015
Deferred income tax assets: |  |  |
Net operating losses and alternative minimum tax credit | $ | 472 |  |  | $ | 217 |
Pension and other postretirement benefits | 30 |  |  | 36 |
Long term debt | 32 |  |  | 61 |
Other | 182 |  |  | 162 |
Total deferred income tax assets | 716 |  |  | 476 |
Valuation allowance | (118 | ) |  | (121 | )
Net deferred income tax assets | 598 |  |  | 355 |
Deferred income tax liabilities: |  |  |
Properties, plants and equipment | (1,633 | ) |  | (1,633 | )
Investments in unconsolidated affiliates | (3,789 | ) |  | (2,976 | )
Trademarks | (273 | ) |  | (286 | )
Other | (15 | ) |  | (50 | )
Total deferred income tax liabilities | (5,710 | ) |  | (4,945 | )
Accumulated deferred income taxes | $ | (5,112 | ) |  | $ | (4,590 | )

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The table below provides a rollforward of the net deferred income tax liability as follows:

| December 31,
| 2016 |  | 2015
Net deferred income tax liability, beginning of year | $ | (4,590 | ) |  | $ | (4,410 | )
Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3) | (460 | ) |  | — |
Net assets (excluding goodwill) associated with Sunoco Retail to Sunoco LP (see Note 3) | (243 | ) |  | — |
Tax provision, including provision from discontinued operations | 201 |  |  | (242 | )
Other | (20 | ) |  | 62 |
Net deferred income tax liability | $ | (5,112 | ) |  | $ | (4,590 | )

ETP Holdco and certain other corporate subsidiaries have federal net operating loss carryforward tax benefits of $292 million, all of which will expire in 2032 through December 31, 2035. Our corporate subsidiaries have state net operating loss carryforward benefits of $127 million, net of federal tax, which expire between January 1, 2017 and 2036. A valuation allowance of $118 million is applicable to the state net operating loss carryforward benefits applicable to significant restriction on their use in the Commonwealth of Pennsylvania.
The following table sets forth the changes in unrecognized tax benefits:

| Years Ended December 31,
| 2016 |  | 2015 |  | 2014
Balance at beginning of year | $ | 610 |  |  | $ | 440 |  |  | $ | 429 |
Additions attributable to tax positions taken in the current year | 8 |  |  | 178 |  |  | 20 |
Additions attributable to tax positions taken in prior years | 18 |  |  | — |  |  | — |
Reduction attributable to tax positions taken in prior years | (20 | ) |  | — |  |  | (1 | )
Settlements | — |  |  | — |  |  | (5 | )
Lapse of statute | (1 | ) |  | (8 | ) |  | (3 | )
Balance at end of year | $ | 615 |  |  | $ | 610 |  |  | $ | 440 |

As of December 31, 2016, we have $596 million ($554 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate. We believe it is reasonably possible that its unrecognized tax benefits may be reduced by $1 million ($0.6 million, net of federal tax) within the next twelve months due to settlement of certain positions.
Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2016, we recognized interest and penalties of less than $1 million. At December 31, 2016, we have interest and penalties accrued of $6 million, net of tax.
Sunoco, Inc. has historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with Sunoco, Inc.’s 2004 through 2011 years, Sunoco, Inc. filed amended returns with the IRS excluding these government incentive payments from federal taxable income. The IRS denied the amended returns, and Sunoco, Inc. petitioned the Court of Federal Claims (“CFC”) in June 2015 on this issue. In November 2016, the CFC ruled against Sunoco, Inc., and Sunoco, Inc. is appealing this decision to the Federal Circuit. If Sunoco, Inc. is ultimately fully successful in its litigation, it will receive tax refunds of approximately $530 million. However, due to the uncertainty surrounding the litigation, a reserve of $530 million was established for the full amount of the litigation. Due to the timing of the litigation and the related reserve, the receivable and the reserve for this issue have been netted in the consolidated balance sheet as of December 31, 2016.
In December of 2015, The Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“Nextel”) that the Pennsylvania limitation on NOL carryforwards violated the uniformity clause of the Pennsylvania Constitution. Based upon the decision in Nextel, Sunoco, Inc. is recognizing approximately $46 million ($30 million after federal income tax benefits) in tax benefit based on previously filed tax returns and certain previously filed protective claims. However, as the Nextel decision is subject to appeal, and because of uncertainty in the breadth of the application of the decision, we have reserved $9 million ($6 million after federal income tax benefits) against the receivable.
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In general, ETP and its subsidiaries are no longer subject to examination by the Internal Revenue Service (“IRS”), and most state jurisdictions, for the 2013 and prior tax years. However, Sunoco, Inc. and its subsidiaries are no longer subject to examination by the IRS for tax years prior to 2007.
Sunoco, Inc. has been examined by the IRS for tax years through 2013. However, statutes remain open for tax years 2007 and forward due to carryback of net operating losses and/or claims regarding government incentive payments discussed above. All other issues are resolved. Though we believe the tax years are closed by statute, tax years 2004 through 2006 are impacted by the carryback of net operating losses and under certain circumstances may be impacted by adjustments for government incentive payments.
ETE and its subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations.

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

Contingent Residual Support Agreement — AmeriGas
In connection with the closing of the contribution of its propane operations in January 2012, ETP agreed to provide contingent residual support of $1.55 billion of intercompany borrowings made by AmeriGas and certain of its affiliates with maturities through 2022 from a finance subsidiary of AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notes issued by this finance company subsidiary to third-party purchases. In 2016, AmeriGas repurchased certain of its senior notes, which caused a reduction in the amount supported by ETP under the contingent residual support agreement. In February 2017, AmeriGas repurchased $378 million of its 7.00% senior notes, which reduced the remaining amount supported by ETP to $122 million.
Guarantee of Sunoco LP Notes
In connection with previous transactions whereby Retail Holdings contributed assets to Sunoco LP, Retail Holdings provided a limited contingent guarantee of collection, but not of payment, to Sunoco LP with respect to (i) $800 million principal amount of 6.375% senior notes due 2023 issued by Sunoco LP, (ii) $800 million principal amount of 6.25% senior notes due 2021 issued by Sunoco LP and (iii) $2.035 billion aggregate principal for Sunoco LP’s term loan due 2019. In December 2016, Retail Holdings contributed its interests in Sunoco LP, along with the assignment of the guarantee of Sunoco LP’s senior notes, to its subsidiary, ETC M-A Acquisition LLC.
NGL Pipeline Regulation
We have interests in NGL pipelines located in Texas and New Mexico. We commenced the interstate transportation of NGLs in 2013, which is subject to the jurisdiction of the FERC under the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992. Under the ICA, tariff rates must be just and reasonable and not unduly discriminatory and pipelines may not confer any undue preference. The tariff rates established for interstate services were based on a negotiated agreement; however, the FERC’s rate-making methodologies may limit our ability to set rates based on our actual costs, may delay or limit the use of rates that reflect increased costs and may subject us to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect our business, revenues and cash flow.
FERC Audit
In March 2016, the FERC commenced an audit of Trunkline for the period from January 1, 2013 to present to evaluate Trunkline’s compliance with the requirements of its FERC gas tariff, the accounting regulations of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s annual reporting requirements. The audit is ongoing.
Commitments
In the normal course of business, ETP purchases, processes and sells natural gas pursuant to long-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations.
ETP’s joint venture agreements require that they fund their proportionate share of capital contributions to their unconsolidated affiliates. Such contributions will depend upon their unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.
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We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2034. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:

|  | Years Ended December 31,
|  | 2016 |  | 2015 |  | 2014
Rental expense(1) |  | $ | 129 |  |  | $ | 205 |  |  | $ | 98 |
Less: Sublease rental income |  | (30 | ) |  | (16 | ) |  | (26 | )
Rental expense, net |  | $ | 99 |  |  | $ | 189 |  |  | $ | 72 |

(1) | Includes contingent rentals totaling $23 million, $26 million and $24 million for the years ended December 31, 2016, 2015 and 2014, respectively.

Future minimum lease commitments for such leases are:

Years Ending December 31: |
2017 | $ | 82 |
2018 | 67 |
2019 | 55 |
2020 | 52 |
2021 | 53 |
Thereafter | 219 |
Future minimum lease commitments | 528 |
Less: Sublease rental income | (79 | )
Net future minimum lease commitments | $ | 449 |

Litigation and Contingencies
We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and crude oil are flammable and combustible. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.
Dakota Access Pipeline
During the summer of 2016, individuals affiliated with, or sympathetic to, the Standing Rock Sioux Tribe (the “SRST”) began gathering near a construction site on the Dakota Access pipeline project in North Dakota to protest the development of the pipeline project. Some of the protesters eventually trespassed on to the construction site, tampered with equipment, and disrupted construction activity at the site. At this time, we are working with the various authorities to mitigate the effects of this largely unlawful protest. We believe that Dakota Access now has the necessary permits and approvals to perform all work on the pipeline project. In response to the protests, Dakota Access filed a lawsuit in federal court in North Dakota to restrain protestors from disrupting construction and also requested a temporary restraining order (“TRO”) against the Chairman of the SRST and the protestors. The U.S. District Court granted Dakota Access’s request for a TRO, and the defendants filed a motion to dismiss the case and dissolve the TRO. The Court later granted the defendants’ motions to dissolve the TRO. Dakota Access filed a response to the defendant’s motion to dismiss, and the Court has yet to rule. At this time, we cannot determine how long the protest will continue, how the legal action will be resolved. Construction work on the pipeline is ongoing, and, barring legal delays, we expect the final portion of the pipeline to be completed in March or April. Additional protests or legal actions may arise in connection with our Dakota Access project or other projects. Trespass on to construction sites or our physical facilities, or other disruptions, could result in further damage to our assets, safety incidents, potential liability or project delays.
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In July 2016, the U.S. Army Corps of Engineers (“USACE”) issued permits to Dakota Access consistent with environmental and historic preservation statutes for the pipeline to make two crossings of the Missouri River in North Dakota, including a crossing of the Missouri River at Lake Oahe. The USACE has also issued an easement to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River in two locations. The SRST filed a lawsuit in the U.S. District Court for the District of Columbia against the USACE challenging the legality of the permits issued for the construction of the Dakota Access pipeline across those waterways and claiming violations of the National Historic Preservation Act (“NHPA”). The SRST also sought a preliminary injunction to rescind the USACE permits while the case is pending. Dakota Access’ moved to intervene in the case and that motion was granted by the Court. The SRST has also sought an emergency TRO to stop construction on the pipeline project. On September 9, 2016, the Court denied SRST’s motion for a preliminary injunction. After that decision, the Department of the Army, the Department of Justice, and the Department of the Interior released a joint statement stating that the USACE would not grant the easement for the land adjacent to Lake Oahe until the federal departments completed a review of the SRST’s claims in its lawsuit with respect to the USACE’s compliance with certain federal statutes in connection with its activities related to the granting of the permits. The SRST appealed the denial of the preliminary injunction to the U.S. Court of Appeals for the D.C. Circuit and filed an emergency motion for an injunction pending the appeal to the U.S. District Court. The U.S. District Court denied SRST’s emergency motion for an injunction pending the appeal. The SRST filed an amended complaint and added claims based on treaties between the tribes and the United States and statues governing the use of government property. The D.C. Circuit denied the SRST’s application for a stay pending appeal and later dismissed the SRST’s appeal of the denied TRO.
In December 2016, the Department of the Army announced that, although its prior actions complied with the law, it intended to conduct further environmental review of the crossing at Lake Oahe. In January 2017, pursuant to a presidential memorandum, the Department the Department of the Army decided that no further environmental review was necessary and delivered Dakota Access an easement to cross Lake Oahe. Construction at the site is ongoing. In the fall of 2016, the Cheyenne River Sioux Tribe intervened alongside the SRST. After USACE gave Dakota Access its final easement, the Cheyenne River Sioux moved for a preliminary injunction and temporary restraining order blocking construction. These motions raised, for the first time, claims based on the religious rights of the Tribe. The district court denied the TRO and has yet to decide whether to grant a preliminary injunction. The SRST has also moved for summary judgment on its claims against the government based on its treaty rights and the National Environmental Policy Act, and the district court is still considering this motion. Briefing is ongoing.
In addition, the Oglala and Yankton Sioux tribes have filed related lawsuits in an effort to prevent construction of the Dakota Access pipeline project.
While we believe that the pending lawsuits are unlikely to block construction or operation of the pipeline and that construction on the land adjacent to Lake Oahe will be completed in a timely manner, we cannot assure this outcome. Any significant delay imposed by the court will delay the receipt of revenue from this project. We cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project.
Mont Belvieu Incident
On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL Mont Belvieu’s (Lone Star) facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal (CMB) and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations have resumed at the facilities with the exception of one of Lone Star’s storage wells. The extent of possible damages is still under investigation.
MTBE Litigation
Sunoco, Inc. and/or Sunoco, Inc. (R&M), along with other refiners, manufacturers and sellers of gasoline, are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs typically include water purveyors and municipalities responsible for supplying drinking water and governmental authorities. The plaintiffs primarily assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws and deceptive business practices. The plaintiffs in all of the cases seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages and attorneys’ fees.
As of December 31, 2016, Sunoco, Inc. is a defendant in six cases, including cases initiated by the States of New Jersey, Vermont, Pennsylvania, Rhode Island, and two others by the Commonwealth of Puerto Rico with the more recent Puerto Rico action being a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. Four of these cases are venued in a multidistrict litigation proceeding in a New York federal court. The New Jersey, Puerto Rico, Vermont, and Pennsylvania cases assert natural resource damage claims.
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Fact discovery has concluded with respect to an initial set of 19 sites each that will be the subject of the first trial phase in the New Jersey case and the initial Puerto Rico case. The initial set of 19 New Jersey trial sites are now pending before the United States District Judge for the District of New Jersey, the Hon. Freda L. Wolfson for the pre-trial and trial phases. Judge Wolfson then referred the case to United States Magistrate Judge for the District of New Jersey, the Hon. Lois H. Goodman. Judge Goodman conducted a status conference with all of the parties and inquired whether the parties will engage in a global mediation and instructed the parties to exchange possible mediator names. All parties agreed to participate in global settlement discussions in a global mediation forum before Hon. Garrett Brown (Ret.), a Judicial Arbitration Mediation Service mediator. The remaining portion of the New Jersey case remains in the multidistrict litigation. The first mediation session with Judge Brown is scheduled for November 2 through November 3, 2016. In early 2017, Sunoco, Inc. and two other co-defendants reached a settlement in principle with the State of New Jersey, subject to the parties agreeing on the terms and conditions of a Settlement and Release agreement. It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. Management believes that an adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any said adverse determination occurs, but does not believe that any such adverse determination would have a material adverse effect on the Partnership’s consolidated financial position.
Regency Merger Litigation
Following the January 26, 2015 announcement of the Regency Merger, purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the Regency Merger. All Regency Merger-related lawsuits have been dismissed, although one lawsuit remains pending on appeal. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the Court of Chancery of the State of Delaware. The lawsuit alleges that the Regency Merger breached the Regency partnership agreement because Regency’s conflicts committee was not properly formed, and the Regency Merger was not approved in good faith. Defendants filed a motion to dismiss, and on March 29, 2016, the Delaware court granted Defendants’ motion and dismissed the lawsuit. On April 26, 2016, Dieckman filed his Notice of Appeal to the Supreme Court of Delaware. This appeal is styled Adrian Dieckman v. Regency GP LP, et al., No. 208, 2016, in the Supreme Court of the State of Delaware. Dieckman filed his Opening Brief on June 9, 2016, and Defendants’ filed their Answering Brief on July 29, 2016. On August 31, 2016, Dieckman filed his Reply Brief. Oral argument was held on November 16, 2016 before the Delaware Supreme Court. On January 20, 2017, the Delaware Supreme Court issued an order reversing the judgment of the Court of Chancery that dismissed Counts I and II of the Dieckman’s Complaint.
Enterprise Products Partners, L.P. and Enterprise Products Operating LLC Litigation
On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc. Trial resulted in a verdict in favor of ETP against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP. The jury also found that ETP owed Enterprise $1 million under a reimbursement agreement. On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest. The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims. Enterprise has filed a notice of appeal with the Texas Court of Appeals, and briefing by Enterprise and ETP is complete. Oral argument was held on April 20, 2016. The Court of Appeals is taking the briefs under advisement. In accordance with GAAP, no amounts related to the original verdict or the July 29, 2014 final judgment will be recorded in our financial statements until the appeal process is completed.
Sunoco Logistics Merger Litigation
Between January 6, 2017 and February 8, 2017, seven purported ETP common unitholders (“Plaintiffs”) separately filed seven putative unitholder class action lawsuits challenging the merger and the disclosures made in connection with the merger. The lawsuits are styled (a) Koma v. Energy Transfer Partners, L.P., et al., Case No. 3:17-cv-00060-G, in the United States District Court for the Northern District of Texas, Dallas Division (the “Koma Lawsuit”); (b) Ashraf v. Energy Transfer Partners, L.P. et al., Case No. 3:17-cv-00118-B, in the United States District Court for the Northern District of Texas, Dallas Division (the “Ashraf Lawsuit”); (c) Shure v. Energy Transfer Partners, L.P. et al., Case No. 1:17-cv-00044-UNA, in the United States District Court for the District of Delaware (the “Shure Lawsuit”); (d) Verlin v. Energy Transfer Partners, L.P. et al., Case No. 1:17-cv-00045-UNA, in the United States District Court for the District of Delaware (the “Verlin Lawsuit”); (e) Duany v. Energy Transfer Partners, L.P. et al., Case No. 1:17-cv-00058-UNA, in the United States District Court for the District of Delaware (the “Duany Lawsuit”); (f) Epstein v. Energy Transfer Partners, L.P. et. al., Case No, 1:17-cv-00069, in the United States District Court for the District of Delaware (the “Epstein Lawsuit”) and (g) Sgnilek v. Energy Transfer Partners, L.P. et al., Case No. 1:17-cv-00141, in the United States District Court for the District of Delaware (the “Sgnilek Lawsuit” and collectively with the Koma Lawsuit, Ashraf Lawsuit, Shure Lawsuit, Verlin Lawsuit, Duany Lawsuit, and Epstein Lawsuit,
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the “Lawsuits”). The Koma Lawsuit, Ashraf Lawsuit, Duany Lawsuit, and Epstein Lawsuit are filed against ETP, ETP GP, ETP GP, LLC, ETE, and the members of the ETP Board. The Shure Lawsuit and Verlin Lawsuit are filed against ETP, ETP GP, the members of the ETP Board, ETE, Sunoco Logistics, and Sunoco Logistics GP. The Sgnilek Lawsuit is filed against ETP, ETP GP, ETP GP LLC, ETE, the members of the ETP Board, Sunoco Logistics and Sunoco Logistics GP (collectively “Defendants”).
Plaintiffs allege causes of action challenging the merger and the preliminary joint proxy statement/prospectus filed in connection with the merger. According to Plaintiffs, the preliminary joint proxy statement/prospectus is allegedly misleading because, among other things, it fails to disclose certain information concerning, in general, (a) the background and process that led to the merger; (b) ETE’s, ETP’s, and Sunoco Logistics’ financial projections; (c) the financial analysis and fairness opinion provided by Barclays; and (d) alleged conflicts of interest concerning Barclays, ETE, and certain officers and directors of ETP and ETE. Based on these allegations, and in general, Plaintiffs allege that (i) Defendants have violated Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder and (ii) the members of the ETP Board have violated Section 20(a) of the Exchange Act. Plaintiffs in the Shure Lawsuit and Verlin Lawsuit also allege that Sunoco Logistics has violated Section 20(a) of the Exchange Act. Plaintiffs also assert, in general, that the terms of the merger (including, among other terms, the merger consideration) are unfair to ETP common unitholders and resulted from an unfair and conflicted process. Based on these allegations, the Sgnilek Lawsuit alleges that (a) the ETP Board, ETP GP, ETP GP LLC, ETP, and ETE have breached the covenant of good faith and/or fiduciary duties, and (b) Sunoco Logistics and Sunoco Logistics GP have aided and abetted those alleged breaches.
Based on these allegations, Plaintiffs seek to enjoin Defendants from proceeding with or consummating the merger unless and until Defendants disclose the allegedly omitted information summarized above. The Koma Lawsuit and Sgnilek Lawsuit also seek to enjoin Defendants from proceeding with or consummating the merger unless and until the ETP Board adopts and implements processes to obtain the best possible terms for ETP common unitholders. To the extent that the merger is consummated before injunctive relief is granted, Plaintiffs seek to have the merger rescinded. Plaintiffs also seek damages and attorneys’ fees.
Defendants’ dates to answer, move to dismiss, or otherwise respond to the Lawsuits have not yet been set. Defendants cannot predict the outcome of these or any other lawsuits that might be filed subsequent to the date of the filing of this annual report, nor can Defendants predict the amount of time and expense that will be required to resolve such litigation. Defendants believe the Lawsuits are without merit and intend to defend vigorously against the Lawsuits and any other actions challenging the merger.
Litigation Filed By or Against WMB
On April 6, 2016, WMB filed a complaint against ETE and LE GP in the Delaware Court of Chancery (the “First Delaware WMB Litigation”). This lawsuit is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., C.A. No. 12168-VCG. WMB alleged that Defendants breached the merger agreement between WMB, ETE, and several of ETE’s affiliates (the “Merger Agreement”) by issuing ETE’s Series A Convertible Preferred Units. According to WMB, the issuance of Convertible Units (the “Issuance”) violates various contractual restrictions on ETE’s actions between the execution and closing of the merger. WMB sought, among other things, to (a) rescind the Issuance and (b) invalidate an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance.
On May 3, 2016, ETE and LE GP filed an answer and counterclaim in the First Delaware WMB Litigation. The counterclaim asserts in general that WMB materially breached its obligations under the Merger Agreement by (a) blocking ETE’s attempts to complete a public offering of the Convertible Units, including, among other things, by declining to allow WMB’s independent registered public accounting firm to provide the auditor consent required to be included in the registration statement for a public offering and (b) bringing the Texas WMB Litigation against Mr. Warren in the District Court of Dallas County, Texas.
On May 13, 2016, WMB filed a second lawsuit in the Delaware Court of Chancery against ETE and LE GP and added Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC as additional defendants (the “Second Delaware WMB Litigation”). This lawsuit is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., et al., C.A. No. 12337-VCG. In general, WMB alleged that the defendants breached the Merger Agreement by (a) failing to use commercially reasonable efforts to obtain from Latham & Watkins LLP (“Latham”) the delivery of a tax opinion under Section 721 of the Tax Code (“721 Opinion”), a condition precedent to the closing of the merger, and (b) taking actions that allegedly delayed the SEC in declaring the Form S-4 filed in connection with the merger (the “Form S-4”) effective. WMB asked the Court, in general, to (a) issue a declaratory judgment that ETE breached the Merger Agreement, (b) enjoin ETE from terminating the Merger Agreement on the basis that it failed to obtain a 721 Opinion, (c) enjoin ETE from terminating the Merger Agreement on the basis that the transaction failed to close by the outside date, and (d) force ETE to close the merger or take various other affirmative actions. WMB sought to expedite the second lawsuit, and ETE agreed to expedite both Delaware actions.
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ETE also filed an answer and counterclaim in the Second Delaware WMB Litigation. In addition to the counterclaims previously asserted, ETE asserted that WMB materially breached the Merger Agreement by, among other things, (a) modifying or qualifying the WMB board of directors’ recommendation to its stockholders regarding the merger, (b) failing to provide material information to ETE for inclusion in the Form S-4 related to the merger necessary to prevent the Form S-4 from being materially misleading, (c) failing to facilitate the financing of the merger, (d) failing to be reasonable with respect to its withholding of its consent to ETE’s offering of Series A Convertible Preferred Units, and (e) failing to use its reasonable best efforts to consummate the merger. ETE sought, among other things, a declaration that it could validly terminate the Merger Agreement after June 28, 2016 in the event that Latham was unable to deliver the 721 Opinion on or prior to June 28, 2016.
After expedited discovery and a two-day trial on June 20 and 21, 2016, the Court ruled in favor of ETE and issued a declaratory judgment that ETE could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court also denied WMB’s requests for injunctive relief. WMB filed a notice of appeal to the Supreme Court of Delaware on June 27, 2016. The appeal is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., No. 330, 2016.
Williams filed an amended complaint on September 16, 2016. In the amended complaint, Williams abandons its request for injunctive relief, including its request that the Court order the ETE Defendants to consummate the merger. Instead, Williams seeks a $410 million termination fee and additional damages of up to $10 billion based on the purported lost value of the merger consideration. These damages claims are based on the alleged breaches of the Merger Agreement detailed above, as well as new allegations that the ETE Defendants breached an additional representation and warranty in the Merger Agreement.
The ETE Defendants filed amended counterclaims and affirmative defenses on September 23, 2016. In the amended counterclaim, the ETE Defendants seek a $1.48 billion termination fee under the Merger Agreement and additional damages caused by Williams’ misconduct. These damages claims are based on the alleged breaches of the Merger Agreement detailed above, as well as new allegations that Williams breached the Merger Agreement by failing to disclose material information that was required to be disclosed in the Form S-4. On September 29, 2016, Williams filed a motion to dismiss the ETE Defendants’ amended counterclaims and to strike certain of the ETE Defendants’ affirmative defenses. Following briefing by the parties on Williams’ motion, the Delaware Court of Chancery held oral arguments on November 30, 2016. The parties are awaiting the Court’s decision.
On January 11, 2017, the Delaware Supreme Court held oral arguments on Williams’ appeal of the June 2016 trial. The parties are awaiting the Court’s decision.
The parties are currently engaging in discovery in connection with their amended claims and counterclaims.
Unitholder Litigation Relating to the Issuance
In April 2016, two purported ETE unitholders (the “Issuance Plaintiffs”) filed putative class action lawsuits against ETE, LE GP, Kelcy Warren, John McReynolds, Marshall McCrea, Matthew Ramsey, Ted Collins, K. Rick Turner, William Williams, Ray Davis, and Richard Brannon in the Delaware Court of Chancery. These lawsuits have been consolidated as In re Energy Transfer Equity, L.P. Unitholder Litigation, Consolidated C.A. No. 12197-VCG, in the Court of Chancery of the State of Delaware. Another purported ETE unitholder, Chester County Employees’ Retirement Fund, joined the consolidated action as an additional plaintiff of April 25, 2016.
The Issuance Plaintiffs allege that the Issuance breached various provisions of ETE’s limited partnership agreement. The Issuance Plaintiffs seek, among other things, preliminary and permanent injunctive relief that (a) prevents ETE from making distributions to the Convertible Units and (b) invalidates an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the issuance of Convertible Units.
The parties engaged in discovery, and Plaintiffs’ filed a consolidated amended complaint on August 29, 2016. In addition to the injunctive relief described above, Plaintiffs seek class-wide damages allegedly resulting from the Issuance.
On September 28, 2016, Defendants and Plaintiffs filed cross-motions for partial summary judgment. The Court held a hearing on the parties’ motions on November 9, 2016 and has taken the matter under advisement.
Other Litigation and Contingencies
We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of December 31, 2016 and 2015, accruals of approximately $93 million and $40 million, respectively, were reflected on our balance sheets related to these contingent obligations. As
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new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.
The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued.
No amounts have been recorded in our December 31, 2016 or 2015 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.
Compliance Orders from the New Mexico Environmental Department
Regency received a Notice of Violation from the New Mexico Environmental Department on September 23, 2015 for allegations of violations of New Mexico air regulations related to Jal #3. The Partnership has accrued $250,000 related to the claims and will continue to assess its potential exposure to the allegations as the matter progresses. The Air Quality Bureau issued a Settlement Offer for Revised Notice of Violation REG-0569-1402-RI on February 7, 2017. The Settlement Agreement includes a civil penalty of $465,000. Energy Transfer and the New Mexico Environmental Department are scheduling a meeting to discuss the Settlement Offer in March 2017.
Lone Star NGL Fractionators Notice of Enforcement
Lone Star NGL Fractionators received a Notice of Enforcement from the Texas Commission on Environmental Quality on August 28, 2015 for allegations of violations of Texas air regulations related to Mont Belvieu Gas Plant. The Partnership has accrued $50,000 related to this claim as of December 31, 2016 and will continue to assess its potential exposure to the allegations as the matter progresses. As of December 31, 2016, the Agreed Order is in the approval process with the Texas Commission on Environmental Quality and includes a $21,000 Supplemental Environmental Project.
Environmental Matters
Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.
Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.
Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.
Environmental Remediation
Our subsidiaries are responsible for environmental remediation at certain sites, including the following:

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

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

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• | Currently operating Sunoco, Inc. retail sites.

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

• | Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it ha s been identified as a “potentially responsible party” (“PRP”). As of December 31, 2016, Sunoco, Inc. had been named as a PRP at approximatel y 50 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.

To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets.
The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.

| December 31,
| 2016 |  | 2015
Current | $ | 37 |  |  | $ | 42 |
Non-current | 348 |  |  | 326 |
Total environmental liabilities | $ | 385 |  |  | $ | 368 |

In 2013, we established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.
During the years ended December 31, 2016 and 2015, the Partnership recorded $43 million and $38 million, respectively, of expenditures related to environmental cleanup programs.
On December 2, 2010, Sunoco, Inc. entered an Asset Sale and Purchase Agreement to sell the Toledo Refinery to Toledo Refining Company LLC (TRC) wherein Sunoco, Inc. retained certain liabilities associated with the pre-Closing time period. On January 2, 2013, USEPA issued a Finding of Violation (FOV) to TRC and, on September 30, 2013, EPA issued an NOV/FOV to TRC alleging Clean Air Act violations. To date, EPA has not issued an FOV or NOV/FOV to Sunoco, Inc. directly but some of EPA’s claims relate to the time period that Sunoco, Inc. operated the refinery. Specifically, EPA has claimed that the refinery flares were not operated in a manner consistent with good air pollution control practice for minimizing emissions and/or in conformance with their design, and that Sunoco, Inc. submitted semi-annual compliance reports in 2010 and 2011 and EPA that failed to include all of the information required by the regulations. EPA has proposed penalties in excess of $200,000 to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannot be reasonably determined at this time, however, we do not expect there to be a material impact to its results of operations, cash flows or financial position.
Our pipeline operations are subject to regulation by the U.S. Department of Transportation under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets
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will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.
In January 2012, Sunoco Logistics experienced a release on its products pipeline in Wellington, Ohio. In connection with this release, the PHMSA issued a Corrective Action Order under which Sunoco Logistics is obligated to follow specific requirements in the investigation of the release and the repair and reactivation of the pipeline. Sunoco Logistics also entered into an Order on Consent with the EPA regarding the environmental remediation of the release site. All requirements of the Order on Consent with the EPA have been fulfilled and the Order has been satisfied and closed. Sunoco Logistics has also received a "No Further Action" approval from the Ohio EPA for all soil and groundwater remediation requirements. In May 2016, Sunoco Logistics received a proposed penalty from the EPA and U.S. Department of Justice associated with this release, and continues to work with the involved parties to bring this matter to closure. The timing and outcome of this matter cannot be reasonably determined at this time. However, Sunoco Logistics does not expect there to be a material impact to its results of operations, cash flows or financial position.
In 2012, the EPA issued a proposed consent agreement related to the releases that occurred at Sunoco Logistics’ pump station/tank farm in Barbers Hill, Texas and pump station/tank farm located in Cromwell, Oklahoma in 2010 and 2011, respectively. These matters were referred to the DOJ by the EPA. In November 2012, Sunoco Logistics received an initial assessment of $1.4 million associated with these releases. Sunoco Logistics is in discussions with the EPA and the DOJ on this matter to resolve the issue. The timing or outcome of this matter cannot be reasonably determined at this time. Sunoco Logistics does not expect there to be a material impact to its results of operations, cash flows or financial position.
In April 2015 and October 2016, the PHMSA issued separate Notices of Probable Violation ("NOPVs") and a Proposed Compliance Order ("PCO") related to Sunoco Logistics’ West Texas Gulf pipeline in connection with repairs being carried out on the pipeline and other administrative and procedural findings. The proposed penalties are in excess of $100,000. Sunoco Logistics does not expect there to be a material impact to its results of operations, cash flows or financial position.
In April 2016, the PHMSA issued a NOPV, PCO and Proposed Civil Penalty related to certain procedures carried out during construction of Sunoco Logistics’ Permian Express 2 pipeline system in Texas. The proposed penalties are in excess of $100,000. Sunoco Logistics does not expect there to be a material impact to its results of operations, cash flows or financial position.
In June 2016, the PHMSA issued NOPVs and a PCO in connection with alleged violations on Sunoco Logistics’ Texas crude oil pipeline system. The proposed penalties are in excess of $100,000. Sunoco Logistics does not expect there to be a material impact to its results of operations, cash flows or financial position.
In July 2016, the PHMSA issued a NOPV and PCO in connection with inspection and maintenance activities related to a 2013 incident on Sunoco Logistics' crude oil pipeline near Wortham, Texas. The proposed penalties are in excess of $100,000, and Sunoco Logistics is currently in discussions with PHMSA to resolve these matters. The timing or outcome of these matters cannot be reasonably determined at this time, however, Sunoco Logistics does not expect there to be a material impact to its results of operations, cash flows, or financial position.
Our operations are also subject to the requirements of the OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our past costs for OSHA required activities, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.

12. | DERIVATIVE ASSETS AND LIABILITIES:

Commodity Price Risk
We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets.
We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price
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result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated 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.
We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage operations and operational gas sales on our interstate transportation and storage operations. These contracts are not designated as hedges for accounting purposes.
We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream operations whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes.
We use derivatives in our NGL and refined products transportation and services operations to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.
Sunoco Logistics utilizes swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs. These contracts are not designated as hedges for accounting purposes.
We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales and transportation costs in our retail marketing operations. These contracts are not designated as hedges for accounting purposes.
We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our transportation and storage operations’ and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other operations which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage operations, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.
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The following table details our outstanding commodity-related derivatives:

| December 31, 2016 |  | December 31, 2015
| Notional Volume |  | Maturity |  | Notional Volume |  | Maturity
Mark-to-Market Derivatives |  |  |  |  |  |  |
(Trading) |  |  |  |  |  |  |
Natural Gas (MMBtu): |  |  |  |  |  |  |
Fixed Swaps/Futures | (682,500 | ) |  | 2017 |  | (602,500 | ) |  | 2016 - 2017
Basis Swaps IFERC/NYMEX (1) | 2,242,500 |  |  | 2017 |  | (31,240,000 | ) |  | 2016 - 2017
Power (Megawatt): |  |  |  |  |  |  |
Forwards | 391,880 |  |  | 2017 - 2018 |  | 357,092 |  |  | 2016 - 2017
Futures | 109,564 |  |  | 2017 - 2018 |  | (109,791 | ) |  | 2016
Options — Puts | (50,400 | ) |  | 2017 |  | 260,534 |  |  | 2016
Options — Calls | 186,400 |  |  | 2017 |  | 1,300,647 |  |  | 2016
Crude (Bbls) – Futures | (617,000 | ) |  | 2017 |  | (591,000 | ) |  | 2016 - 2017
(Non-Trading) |  |  |  |  |  |  |
Natural Gas (MMBtu): |  |  |  |  |  |  |
Basis Swaps IFERC/NYMEX | 10,750,000 |  |  | 2017 - 2018 |  | (6,522,500 | ) |  | 2016 - 2017
Swing Swaps IFERC | (5,662,500 | ) |  | 2017 |  | 71,340,000 |  |  | 2016 - 2017
Fixed Swaps/Futures | (52,652,500 | ) |  | 2017 - 2019 |  | (14,380,000 | ) |  | 2016 - 2018
Forward Physical Contracts | (22,492,489 | ) |  | 2017 |  | 21,922,484 |  |  | 2016 - 2017
Natural Gas Liquid (Bbls) – Forwards/Swaps | (5,786,627 | ) |  | 2017 |  | (8,146,800 | ) |  | 2016 - 2018
Refined Products (Bbls) – Futures | (3,144,000 | ) |  | 2017 |  | (1,289,000 | ) |  | 2016 - 2017
Corn (Bushels) – Futures | 1,580,000 |  |  | 2017 |  | 1,185,000 |  |  | 2016
Fair Value Hedging Derivatives |  |  |  |  |  |  |
(Non-Trading) |  |  |  |  |  |  |
Natural Gas (MMBtu): |  |  |  |  |  |  |
Basis Swaps IFERC/NYMEX | (36,370,000 | ) |  | 2017 |  | (37,555,000 | ) |  | 2016
Fixed Swaps/Futures | (36,370,000 | ) |  | 2017 |  | (37,555,000 | ) |  | 2016
Hedged Item — Inventory | 36,370,000 |  |  | 2017 |  | 37,555,000 |  |  | 2016

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

Interest Rate Risk
We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.
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The following table summarizes our interest rate swaps outstanding, none of which are designated as hedges for accounting purposes:

|  |  |  |  |  | Notional Amount Outstanding
Entity |  | Term |  | Type(1) |  | December 31, 2016 |  | December 31, 2015
ETP |  | July 2016(2) |  | Forward-starting to pay a fixed rate of 3.80% and receive a floating rate |  | $ | — |  |  | $ | 200 |
ETP |  | July 2017(3) |  | Forward-starting to pay a fixed rate of 3.90% and receive a floating rate |  | 500 |  |  | 300 |
ETP |  | July 2018(3) |  | Forward-starting to pay a fixed rate of 4.00% and receive a floating rate |  | 200 |  |  | 200 |
ETP |  | July 2019(3) |  | Forward-starting to pay a fixed rate of 3.25% and receive a floating rate |  | 200 |  |  | 200 |
ETP |  | December 2018 |  | Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% |  | 1,200 |  |  | 1,200 |
ETP |  | March 2019 |  | Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% |  | 300 |  |  | 300 |

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

(2) | Represents the effective date. These forward-starting swaps have terms of 10 and 30 years with a mandatory termination date the same as the effective date.

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

Credit Risk
Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.
The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, municipalities, gas and electric utilities, midstream companies, independent power generators and fuel distributors. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.
The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily independent system operators, and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.
For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.
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Derivative Summary
The following table provides a summary of our derivative assets and liabilities:

| Fair Value of Derivative Instruments
| Asset Derivatives |  | Liability Derivatives
| December 31, 2016 |  | December 31, 2015 |  | December 31, 2016 |  | December 31, 2015
Derivatives designated as hedging instruments: |  |  |  |  |  |  |
Commodity derivatives (margin deposits) | $ | — |  |  | $ | 38 |  |  | $ | (4 | ) |  | $ | (3 | )
| — |  |  | 38 |  |  | (4 | ) |  | (3 | )
Derivatives not designated as hedging instruments: |  |  |  |  |  |  |
Commodity derivatives (margin deposits) | 338 |  |  | 353 |  |  | (416 | ) |  | (306 | )
Commodity derivatives | 25 |  |  | 63 |  |  | (58 | ) |  | (47 | )
Interest rate derivatives | — |  |  | — |  |  | (193 | ) |  | (171 | )
Embedded derivatives in ETP Preferred Units | — |  |  | — |  |  | (1 | ) |  | (5 | )
| 363 |  |  | 416 |  |  | (668 | ) |  | (529 | )
Total derivatives | $ | 363 |  |  | $ | 454 |  |  | $ | (672 | ) |  | $ | (532 | )

The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:

|  |  |  | Asset Derivatives |  | Liability Derivatives
|  | Balance Sheet Location |  | December 31, 2016 |  | December 31, 2015 |  | December 31, 2016 |  | December 31, 2015
Derivatives without offsetting agreements |  | Derivative assets (liabilities) |  | $ | — |  |  | $ | — |  |  | $ | (194 | ) |  | $ | (176 | )
Derivatives in offsetting agreements: |  |  |  |  |  |  |  |
OTC contracts |  | Derivative assets (liabilities) |  | 25 |  |  | 63 |  |  | (58 | ) |  | (47 | )
Broker cleared derivative contracts |  | Other current assets |  | 338 |  |  | 391 |  |  | (420 | ) |  | (309 | )
|  | 363 |  |  | 454 |  |  | (672 | ) |  | (532 | )
Offsetting agreements: |  |  |  |  |  |  |  |
Counterparty netting |  | Derivative assets (liabilities) |  | (4 | ) |  | (17 | ) |  | 4 |  |  | 17 |
Payments on margin deposit |  | Other current assets |  | (338 | ) |  | (309 | ) |  | 338 |  |  | 309 |
Total net derivatives |  | $ | 21 |  |  | $ | 128 |  |  | $ | (330 | ) |  | $ | (206 | )

We disclose the non-exchange traded financial derivative instruments as derivative assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.
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The following tables summarize the amounts recognized with respect to our derivative financial instruments:

| Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) |  | Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
| Years Ended December 31,
| 2016 |  | 2015 |  | 2014
Derivatives in cash flow hedging relationships: |  |  |  |  |  |  |
Commodity derivatives | Cost of products sold |  | $ | — |  |  | $ | — |  |  | $ | (3 | )
Total |  |  | $ | — |  |  | $ | — |  |  | $ | (3 | )

| Location of Gain/(Loss) Recognized in Income on Derivatives |  | Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
| Years Ended December 31,
| 2016 |  | 2015 |  | 2014
Derivatives in fair value hedging relationships (including hedged item): |  |  |  |  |  |  |
Commodity derivatives | Cost of products sold |  | $ | 14 |  |  | $ | 21 |  |  | $ | (8 | )
Total |  |  | $ | 14 |  |  | $ | 21 |  |  | $ | (8 | )

| Location of Gain/(Loss) Recognized in Income on Derivatives |  | Amount of Gain/(Loss) Recognized in Income on Derivatives
|  | Years Ended December 31,
|  | 2016 |  | 2015 |  | 2014
Derivatives not designated as hedging instruments: |  |  |  |  |  |  |
Commodity derivatives – Trading | Cost of products sold |  | $ | (35 | ) |  | $ | (11 | ) |  | $ | (6 | )
Commodity derivatives – Non-trading | Cost of products sold |  | (177 | ) |  | 15 |  |  | 199 |
Interest rate derivatives | Losses on interest rate derivatives |  | (12 | ) |  | (18 | ) |  | (157 | )
Embedded derivatives | Other, net |  | 4 |  |  | 12 |  |  | 3 |
Total |  |  | $ | (220 | ) |  | $ | (2 | ) |  | $ | 39 |

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13. | RETIREMENT BENEFITS:

Savings and Profit Sharing Plans
We and our subsidiaries sponsor defined contribution savings and profit sharing plans, which collectively cover virtually all eligible employees, including those of ETP, Sunoco LP and Lake Charles LNG. Employer matching contributions are calculated using a formula based on employee contributions. We and our subsidiaries have made matching contributions of $44 million, $40 million and $50 million to the 401(k) savings plan for the years ended December 31, 2016, 2015, and 2014, respectively.
Pension and Other Postretirement Benefit Plans
Panhandle
Postretirement benefits expense for the years ended December 31, 2016 and 2015 reflect the impact of changes Panhandle or its affiliates adopted as of September 30, 2013, to modify its retiree medical benefits program, effective January 1, 2014. The modification placed all eligible retirees on a common medical benefit platform, subject to limits on Panhandle’s annual contribution toward eligible retirees’ medical premiums. Prior to January 1, 2013, affiliates of Panhandle offered postretirement health care and life insurance benefit plans (other postretirement plans) that covered substantially all employees. Effective January 1, 2013, participation in the plan was frozen and medical benefits were no longer offered to non-union employees. Effective January 1, 2014, retiree medical benefits were no longer offered to union employees.
Sunoco, Inc.
Sunoco, Inc. sponsors a defined benefit pension plan, which was frozen for most participants on June 30, 2010. On October 31, 2014, Sunoco, Inc. terminated the plan, and paid lump sums to eligible active and terminated vested participants in December 2015.
Sunoco, Inc. also has a plan which provides health care benefits for substantially all of its current retirees. The cost to provide the postretirement benefit plan is shared by Sunoco, Inc. and its retirees. Access to postretirement medical benefits was phased out or eliminated for all employees retiring after July 1, 2010. In March, 2012, Sunoco, Inc. established a trust for its postretirement benefit liabilities. Sunoco made a tax-deductible contribution of approximately $200 million to the trust. The funding of the trust eliminated substantially all of Sunoco, Inc.’s future exposure to variances between actual results and assumptions used to estimate retiree medical plan obligations.
Obligations and Funded Status
Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services.
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The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis:

| December 31, 2016 |  | December 31, 2015
| Pension Benefits |  |  |  | Pension Benefits |  |
| Funded Plans |  | Unfunded Plans |  | Other Postretirement Benefits |  | Funded Plans |  | Unfunded Plans |  | Other Postretirement Benefits
Change in benefit obligation: |  |  |  |  |  |  |  |  |  |  |
Benefit obligation at beginning of period | $ | 20 |  |  | $ | 57 |  |  | $ | 181 |  |  | $ | 718 |  |  | $ | 65 |  |  | $ | 203 |
Interest cost | 1 |  |  | 2 |  |  | 4 |  |  | 23 |  |  | 2 |  |  | 4 |
Amendments | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Benefits paid, net | (1 | ) |  | (7 | ) |  | (21 | ) |  | (46 | ) |  | (8 | ) |  | (20 | )
Actuarial (gain) loss and other | (2 | ) |  | (1 | ) |  | 2 |  |  | 16 |  |  | (2 | ) |  | (6 | )
Settlements | — |  |  | — |  |  | — |  |  | (691 | ) |  | — |  |  | — |
Benefit obligation at end of period | $ | 18 |  |  | $ | 51 |  |  | $ | 166 |  |  | $ | 20 |  |  | $ | 57 |  |  | $ | 181 |
Change in plan assets: |  |  |  |  |  |  |  |  |  |  |
Fair value of plan assets at beginning of period | $ | 15 |  |  | $ | — |  |  | $ | 261 |  |  | $ | 598 |  |  | $ | — |  |  | $ | 272 |
Return on plan assets and other | (2 | ) |  | — |  |  | 6 |  |  | 16 |  |  | — |  |  | — |
Employer contributions | — |  |  | — |  |  | 10 |  |  | 138 |  |  | — |  |  | 9 |
Benefits paid, net | (1 | ) |  | — |  |  | (21 | ) |  | (46 | ) |  | — |  |  | (20 | )
Settlements | — |  |  | — |  |  | — |  |  | (691 | ) |  | — |  |  | — |
Fair value of plan assets at end of period | $ | 12 |  |  | $ | — |  |  | $ | 256 |  |  | $ | 15 |  |  | $ | — |  |  | $ | 261 |
Amount underfunded (overfunded) at end of period | $ | 6 |  |  | $ | 51 |  |  | $ | (90 | ) |  | $ | 5 |  |  | $ | 57 |  |  | $ | (80 | )
Amounts recognized in the consolidated balance sheets consist of: |  |  |  |  |  |  |  |  |  |  |
Non-current assets | $ | — |  |  | $ | — |  |  | $ | 114 |  |  | $ | — |  |  | $ | — |  |  | $ | 103 |
Current liabilities | — |  |  | (7 | ) |  | (2 | ) |  | — |  |  | (9 | ) |  | (2 | )
Non-current liabilities | (6 | ) |  | (44 | ) |  | (23 | ) |  | (5 | ) |  | (48 | ) |  | (22 | )
| $ | (6 | ) |  | $ | (51 | ) |  | $ | 89 |  |  | $ | (5 | ) |  | $ | (57 | ) |  | $ | 79 |
Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of: |  |  |  |  |  |  |  |  |  |  |
Net actuarial gain | $ | — |  |  | $ | — |  |  | $ | (13 | ) |  | $ | 2 |  |  | $ | 4 |  |  | $ | (18 | )
Prior service cost | — |  |  | — |  |  | 15 |  |  | — |  |  | — |  |  | 16 |
| $ | — |  |  | $ | — |  |  | $ | 2 |  |  | $ | 2 |  |  | $ | 4 |  |  | $ | (2 | )

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The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets:

| December 31, 2016 |  | December 31, 2015
| Pension Benefits |  |  |  | Pension Benefits |  |
| Funded Plans |  | Unfunded Plans |  | Other Postretirement Benefits |  | Funded Plans |  | Unfunded Plans |  | Other Postretirement Benefits
Projected benefit obligation | $ | 18 |  |  | $ | 51 |  |  | N/A |  |  | $ | 20 |  |  | $ | 57 |  |  | N/A |
Accumulated benefit obligation | 18 |  |  | 51 |  |  | $ | 166 |  |  | 20 |  |  | 57 |  |  | $ | 181 |
Fair value of plan assets | 12 |  |  | — |  |  | 256 |  |  | 15 |  |  | — |  |  | 261 |

Components of Net Periodic Benefit Cost

| December 31, 2016 |  | December 31, 2015
| Pension Benefits |  | Other Postretirement Benefits |  | Pension Benefits |  | Other Postretirement Benefits
Net Periodic Benefit Cost: |  |  |  |  |  |  |
Interest cost | $ | 3 |  |  | $ | 4 |  |  | $ | 25 |  |  | $ | 4 |
Expected return on plan assets | (1 | ) |  | (8 | ) |  | (16 | ) |  | (8 | )
Prior service cost amortization | — |  |  | 1 |  |  | — |  |  | 1 |
Actuarial loss amortization | — |  |  | — |  |  | — |  |  | — |
Settlements | — |  |  | — |  |  | 32 |  |  | — |
Net periodic benefit cost | $ | 2 |  |  | $ | (3 | ) |  | $ | 41 |  |  | $ | (3 | )

Assumptions
The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below:

| December 31, 2016 |  | December 31, 2015
| Pension Benefits |  | Other Postretirement Benefits |  | Pension Benefits |  | Other Postretirement Benefits
Discount rate | 3.65 | % |  | 2.34 | % |  | 3.59 | % |  | 2.38 | %
Rate of compensation increase | N/A |  |  | N/A |  |  | N/A |  |  | N/A |

The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below:

| December 31, 2016 |  | December 31, 2015
| Pension Benefits |  | Other Postretirement Benefits |  | Pension Benefits |  | Other Postretirement Benefits
Discount rate | 3.60 | % |  | 3.06 | % |  | 3.65 | % |  | 2.79 | %
Expected return on assets: |  |  |  |  |  |  |
Tax exempt accounts | 3.50 | % |  | 7.00 | % |  | 7.50 | % |  | 7.00 | %
Taxable accounts | N/A |  |  | 4.50 | % |  | N/A |  |  | 4.50 | %
Rate of compensation increase | N/A |  |  | N/A |  |  | N/A |  |  | N/A |

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The long-term expected rate of return on plan assets was estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness.
The assumed health care cost trend rates used to measure the expected cost of benefits covered by Panhandle’s and Sunoco, Inc.’s other postretirement benefit plans are shown in the table below:

| December 31,
| 2016 |  | 2015
Health care cost trend rate | 6.73 | % |  | 7.16 | %
Rate to which the cost trend is assumed to decline (the ultimate trend rate) | 4.96 | % |  | 5.39 | %
Year that the rate reaches the ultimate trend rate | 2021 |  |  | 2018 |

Changes in the health care cost trend rate assumptions are not expected to have a significant impact on postretirement benefits.
Plan Assets
For the Panhandle plans, the overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification. To achieve diversity within its other postretirement plan asset portfolio, Panhandle has targeted the following asset allocations: equity of 25% to 35%, fixed income of 65% to 75% and cash and cash equivalents of up to 10%.
The investment strategy of Sunoco, Inc. funded defined benefit plans is to achieve consistent positive returns, after adjusting for inflation, and to maximize long-term total return within prudent levels of risk through a combination of income and capital appreciation. The objective of this strategy is to reduce the volatility of investment returns and maintain a sufficient funded status of the plans. In anticipation of the pension plan termination, Sunoco, Inc. targeted the asset allocations to a more stable position by investing in growth assets and liability hedging assets.
The fair value of the pension plan assets by asset category at the dates indicated is as follows:

|  |  |  | Fair Value Measurements at December 31, 2016
|  | Fair Value Total |  | Level 1 |  | Level 2 |  | Level 3
Asset Category: |  |  |  |  |  |  |  |
Mutual funds (1) |  | $ | 12 |  |  | $ | 12 |  |  | $ | — |  |  | $ | — |
Total |  | $ | 12 |  |  | $ | 12 |  |  | $ | — |  |  | $ | — |

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

|  |  |  | Fair Value Measurements at December 31, 2015
|  | Fair Value Total |  | Level 1 |  | Level 2 |  | Level 3
Asset Category: |  |  |  |  |  |  |  |
Mutual funds (1) |  | $ | 15 |  |  | $ | — |  |  | $ | 15 |  |  | $ | — |
Total |  | $ | 15 |  |  | $ | — |  |  | $ | 15 |  |  | $ | — |

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

The fair value of the other postretirement plan assets by asset category at the dates indicated is as follows:
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|  |  |  | Fair Value Measurements at December 31, 2016
|  | Fair Value Total |  | Level 1 |  | Level 2 |  | Level 3
Asset Category: |  |  |  |  |  |  |  |
Cash and Cash Equivalents |  | $ | 23 |  |  | $ | 23 |  |  | $ | — |  |  | $ | — |
Mutual funds (1) |  | 142 |  |  | 142 |  |  | — |  |  | — |
Fixed income securities |  | 91 |  |  | — |  |  | 91 |  |  | — |
Total |  | $ | 256 |  |  | $ | 165 |  |  | $ | 91 |  |  | $ | — |

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

|  |  |  | Fair Value Measurements at December 31, 2015
|  | Fair Value Total |  | Level 1 |  | Level 2 |  | Level 3
Asset Category: |  |  |  |  |  |  |  |
Cash and Cash Equivalents |  | $ | 18 |  |  | $ | 18 |  |  | $ | — |  |  | $ | — |
Mutual funds (1) |  | 141 |  |  | 141 |  |  | — |  |  | — |
Fixed income securities |  | 102 |  |  | — |  |  | 102 |  |  | — |
Total |  | $ | 261 |  |  | $ | 159 |  |  | $ | 102 |  |  | $ | — |

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

The Level 1 plan assets are valued based on active market quotes. The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines.
Contributions
We expect to contribute $12 million to pension plans and $10 million to other postretirement plans in 2017. The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.
Benefit Payments
Panhandle’s and Sunoco, Inc.’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below:

|  | Pension Benefits |  |
Years |  | Funded Plans |  | Unfunded Plans |  | Other Postretirement Benefits (Gross, Before Medicare Part D)
2017 |  | $ | 1 |  |  | $ | 7 |  |  | $ | 26 |
2018 |  | 1 |  |  | 7 |  |  | 25 |
2019 |  | 1 |  |  | 6 |  |  | 23 |
2020 |  | 1 |  |  | 6 |  |  | 22 |
2021 |  | 1 |  |  | 5 |  |  | 19 |
2022 – 2026 |  | 6 |  |  | 17 |  |  | 39 |

The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.
Panhandle does not expect to receive any Medicare Part D subsidies in any future periods.
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14. | RELATED PARTY TRANSACTIONS:

The Parent Company has agreements with subsidiaries to provide or receive various general and administrative services. The Parent Company pays ETP to provide services on its behalf and the behalf of other subsidiaries of the Parent Company. The Parent Company receives management fees from certain of its subsidiaries, which include the reimbursement of various general and administrative services for expenses incurred by ETP on behalf of those subsidiaries. All such amounts have been eliminated in our consolidated financial statements.
In the ordinary course of business, our subsidiaries have related party transactions between each other which are generally based on transactions made at market-related rates. Our consolidated revenues and expenses reflect the elimination of all material intercompany transactions (see Note 15).
In addition, subsidiaries of ETE recorded sales with affiliates of $221 million, $290 million and $965 million during the years ended December 31, 2016, 2015 and 2014, respectively.

15. | REPORTABLE SEGMENTS:

Subsequent to ETE’s acquisition of a controlling interest in Sunoco LP, our financial statements reflect the following reportable business segments:

• | Investment in ETP, including the consolidated operations of ETP;

• | Investment in Sunoco LP, including the consolidated operations of Sunoco LP;

• | Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and

• | Corporate and Other, including the following:

• | activities of the Parent Company; and

• | the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

ETP completed its acquisition of Regency in April 2015; therefore, the Investment in ETP segment amounts have been retrospectively adjusted to reflect Regency for the periods presented.
The Investment in Sunoco LP segment reflects the results of Sunoco LP beginning August 29, 2014, the date that ETP originally obtained control of Sunoco LP. ETE’s consolidated results reflect the elimination of MACS, Sunoco, LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco, LLC, and a continuing investment in Sunoco LP the equity in earnings from which is also eliminated in ETE’s consolidated financial statements.
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.
Based on the change in our reportable segments we have recast the presentation of our segment results for the prior years to be consistent with the current year presentation.
Eliminations in the tables below include the following:

• | ETP’s Segment Adjusted EBITDA reflected the results of Lake Charles LNG prior to the Lake Charles LNG Transaction, which was effective January 1, 2014. The Investment in Lake Charles LNG segment reflected the results of operations of Lake Charles LNG for all periods presented. Consequently, the results of operations of Lake Charles LNG were reflected in two segments for the year ended December 31, 2013. Therefore, the results of Lake Charles LNG were included in eliminations for 2013.

• | MACS, Sunoco LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP, as discussed above.

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| Years Ended December 31,
| 2016 |  | 2015 |  | 2014
Revenues: |  |  |  |  |
Investment in ETP: |  |  |  |  |
Revenues from external customers | $ | 21,618 |  |  | $ | 34,156 |  |  | $ | 55,475 |
Intersegment revenues | 209 |  |  | 136 |  |  | — |
| 21,827 |  |  | 34,292 |  |  | 55,475 |
Investment in Sunoco LP: |  |  |  |  |
Revenues from external customers | 8,287 |  |  | 10,527 |  |  | 4,291 |
Intersegment revenues | 9 |  |  | 11 |  |  | — |
| 8,296 |  |  | 10,538 |  |  | 4,291 |
Investment in Lake Charles LNG: |  |  |  |  |
Revenues from external customers | 197 |  |  | 216 |  |  | 216 |
Adjustments and Eliminations: | (218 | ) |  | (10,842 | ) |  | (7,343 | )
Total revenues | $ | 30,102 |  |  | $ | 34,204 |  |  | $ | 52,639 |
Costs of products sold: |  |  |  |  |
Investment in ETP | $ | 15,394 |  |  | $ | 27,029 |  |  | $ | 48,414 |
Investment in Sunoco LP | 7,459 |  |  | 9,902 |  |  | 4,214 |
Adjustments and Eliminations | (217 | ) |  | (9,496 | ) |  | (6,767 | )
Total costs of products sold | $ | 22,636 |  |  | $ | 27,435 |  |  | $ | 45,861 |
Depreciation, depletion and amortization: |  |  |  |  |
Investment in ETP | $ | 1,986 |  |  | $ | 1,929 |  |  | $ | 1,669 |
Investment in Sunoco LP | 126 |  |  | 103 |  |  | 31 |
Investment in Lake Charles LNG | 39 |  |  | 39 |  |  | 39 |
Corporate and Other | 15 |  |  | 17 |  |  | 16 |
Adjustments and Eliminations | — |  |  | (184 | ) |  | (86 | )
Total depreciation, depletion and amortization | $ | 2,166 |  |  | $ | 1,904 |  |  | $ | 1,669 |

| Years Ended December 31,
| 2016 |  | 2015 |  | 2014
Equity in earnings of unconsolidated affiliates: |  |  |  |  |
Investment in ETP | $ | 336 |  |  | $ | 469 |  |  | $ | 332 |
Adjustments and Eliminations | (66 | ) |  | (193 | ) |  | — |
Total equity in earnings of unconsolidated affiliates | $ | 270 |  |  | $ | 276 |  |  | $ | 332 |

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| Years Ended December 31,
| 2016 |  | 2015 |  | 2014
Segment Adjusted EBITDA: |  |  |  |  |
Investment in ETP | $ | 5,605 |  |  | $ | 5,714 |  |  | $ | 5,710 |
Investment in Sunoco LP | 665 |  |  | 719 |  |  | 332 |
Investment in Lake Charles LNG | 179 |  |  | 196 |  |  | 195 |
Corporate and Other | (170 | ) |  | (104 | ) |  | (97 | )
Adjustments and Eliminations | (272 | ) |  | (590 | ) |  | (300 | )
Total Segment Adjusted EBITDA | 6,007 |  |  | 5,935 |  |  | 5,840 |
Depreciation, depletion and amortization | (2,166 | ) |  | (1,904 | ) |  | (1,669 | )
Interest expense, net of interest capitalized | (1,803 | ) |  | (1,621 | ) |  | (1,368 | )
Gains on acquisitions | 83 |  |  | — |  |  | — |
Gain on sale of AmeriGas common units | — |  |  | — |  |  | 177 |
Impairment of investment in affiliate | (308 | ) |  | — |  |  | — |
Impairment losses | (970 | ) |  | (339 | ) |  | (370 | )
Losses on interest rate derivatives | (12 | ) |  | (18 | ) |  | (157 | )
Non-cash unit-based compensation expense | (70 | ) |  | (91 | ) |  | (82 | )
Unrealized gains (losses) on commodity risk management activities | (136 | ) |  | (65 | ) |  | 116 |
Losses on extinguishments of debt | — |  |  | (43 | ) |  | (25 | )
Inventory valuation adjustments | 267 |  |  | (229 | ) |  | (445 | )
Adjusted EBITDA related to discontinued operations | (293 | ) |  | (345 | ) |  | (208 | )
Adjusted EBITDA related to unconsolidated affiliates | (675 | ) |  | (713 | ) |  | (748 | )
Equity in earnings of unconsolidated affiliates | 270 |  |  | 276 |  |  | 332 |
Other, net | 78 |  |  | 21 |  |  | (74 | )
Income from continuing operations before income tax expense | $ | 272 |  |  | $ | 864 |  |  | $ | 1,319 |

| December 31,
| 2016 |  | 2015 |  | 2014
Total assets: |  |  |  |  |
Investment in ETP | $ | 70,191 |  |  | $ | 65,173 |  |  | $ | 62,518 |
Investment in Sunoco LP | 8,701 |  |  | 8,842 |  |  | 8,773 |
Investment in Lake Charles LNG | 1,508 |  |  | 1,369 |  |  | 1,210 |
Corporate and Other | 711 |  |  | 638 |  |  | 1,119 |
Adjustments and Eliminations | (2,100 | ) |  | (4,833 | ) |  | (9,341 | )
Total | $ | 79,011 |  |  | $ | 71,189 |  |  | $ | 64,279 |

| Years Ended December 31,
| 2016 |  | 2015 |  | 2014
Additions to property, plant and equipment, net of contributions in aid of construction costs (accrual basis): |  |  |  |  |
Investment in ETP | $ | 5,810 |  |  | $ | 8,167 |  |  | $ | 5,494 |
Investment in Sunoco LP | 439 |  |  | 491 |  |  | 154 |
Investment in Lake Charles LNG | — |  |  | 1 |  |  | 1 |
Adjustments and Eliminations | — |  |  | (123 | ) |  | (90 | )
Total | $ | 6,249 |  |  | $ | 8,536 |  |  | $ | 5,559 |

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| December 31,
| 2016 |  | 2015 |  | 2014
Advances to and investments in affiliates: |  |  |  |  |
Investment in ETP | $ | 4,280 |  |  | $ | 5,003 |  |  | $ | 3,760 |
Adjustments and Eliminations | (1,240 | ) |  | (1,541 | ) |  | (101 | )
Total | $ | 3,040 |  |  | $ | 3,462 |  |  | $ | 3,659 |

The following tables provide revenues, grouped by similar products and services, for our reportable segments. These amounts include intersegment revenues for transactions between ETP and Sunoco LP.
Investment in ETP

| Years Ended December 31,
| 2016 |  | 2015 |  | 2014
Intrastate Transportation and Storage | $ | 2,155 |  |  | $ | 1,912 |  |  | $ | 2,645 |
Interstate Transportation and Storage | 946 |  |  | 1,008 |  |  | 1,057 |
Midstream | 2,342 |  |  | 2,607 |  |  | 4,770 |
NGL and refined products transportation and services | 5,973 |  |  | 4,569 |  |  | 4,746 |
Crude oil transportation and services | 7,539 |  |  | 8,980 |  |  | 16,904 |
All Other | 2,872 |  |  | 15,216 |  |  | 25,353 |
Total revenues | 21,827 |  |  | 34,292 |  |  | 55,475 |
Less: Intersegment revenues | 209 |  |  | 136 |  |  | — |
Revenues from external customers | $ | 21,618 |  |  | $ | 34,156 |  |  | $ | 55,475 |

Investment in Sunoco LP

| Years Ended December 31,
| 2016 |  | 2015 |  | 2014
Retail operations | $ | 301 |  |  | $ | 334 |  |  | $ | 43 |
Wholesale operations | 7,995 |  |  | 10,204 |  |  | 4,248 |
Total revenues | 8,296 |  |  | 10,538 |  |  | 4,291 |
Less: Intersegment revenues | 9 |  |  | 11 |  |  | — |
Revenues from external customers | $ | 8,287 |  |  | $ | 10,527 |  |  | $ | 4,291 |

Investment in Lake Charles LNG
Lake Charles LNG’s revenues of $197 million, $216 million and $216 million for the years ended December 31, 2016, 2015 and 2014, respectively, were related to LNG terminalling.
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16. | QUARTERLY FINANCIAL DATA (UNAUDITED):

Summarized unaudited quarterly financial data is presented below. Earnings per unit are computed on a stand-alone basis for each quarter and total year.

| Quarters Ended |  |
| March 31 |  | June 30 |  | September 30 |  | December 31 |  | Total Year
2016: |  |  |  |  |  |  |  |  |
Revenues | $ | 6,083 |  |  | $ | 7,415 |  |  | $ | 7,705 |  |  | $ | 8,899 |  |  | $ | 30,102 |
Operating income (loss) | 695 |  |  | 805 |  |  | 646 |  |  | (236 | ) |  | 1,910 |
Net income (loss) | 336 |  |  | 424 |  |  | 41 |  |  | (760 | ) |  | 41 |
Limited Partners’ interest in net income | 311 |  |  | 239 |  |  | 207 |  |  | 226 |  |  | 983 |
Basic net income per limited partner unit | $ | 0.30 |  |  | $ | 0.23 |  |  | $ | 0.20 |  |  | $ | 0.22 |  |  | $ | 0.94 |
Diluted net income per limited partner unit | $ | 0.30 |  |  | $ | 0.23 |  |  | $ | 0.19 |  |  | $ | 0.21 |  |  | $ | 0.92 |

| Quarters Ended |  |
| March 31 |  | June 30 |  | September 30 |  | December 31 |  | Total Year
2015: |  |  |  |  |  |  |  |  |
Revenues | $ | 8,564 |  |  | $ | 9,423 |  |  | $ | 8,473 |  |  | $ | 7,744 |  |  | $ | 34,204 |
Operating income | 589 |  |  | 878 |  |  | 573 |  |  | 210 |  |  | 2,250 |
Net income (loss) | 221 |  |  | 772 |  |  | 238 |  |  | (138 | ) |  | 1,093 |
Limited Partners’ interest in net income | 282 |  |  | 298 |  |  | 291 |  |  | 312 |  |  | 1,183 |
Basic net income per limited partner unit | $ | 0.26 |  |  | $ | 0.28 |  |  | $ | 0.28 |  |  | $ | 0.30 |  |  | $ | 1.11 |
Diluted net income per limited partner unit | $ | 0.26 |  |  | $ | 0.28 |  |  | $ | 0.28 |  |  | $ | 0.30 |  |  | $ | 1.11 |

The three months ended December 31, 2015 reflected the unfavorable impact of $120 million related to non-cash inventory valuation adjustments primarily in ETP’s retail marketing operations and our investment in Sunoco LP. The three months ended December 31, 2016 and 2015 reflected the recognition of impairment losses of $970 million and $339 million, respectively. Impairment losses in 2016 were primarily related to ETP’s interstate operations, midstream midcontinent operations and retail operations. In 2015, impairment losses were primarily related to Lone Star Refinery Services operations and ETP’s Transwestern pipeline. The three months ended September 30, 2016 reflected the recognition of a non-cash impairment of ETP’s investment in MEP of $308 million in our interstate transportation and storage operations.
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17. | SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION:

Following are the financial statements of the Parent Company, which are included to provide additional information with respect to the Parent Company’s financial position, results of operations and cash flows on a stand-alone basis:
BALANCE SHEETS

| December 31,
| 2016 |  | 2015
ASSETS |  |  |
CURRENT ASSETS: |  |  |
Cash and cash equivalents | $ | 2 |  |  | $ | 1 |
Accounts receivable from related companies | 55 |  |  | 34 |
Total current assets | 57 |  |  | 35 |
PROPERTY, PLANT AND EQUIPMENT, net | 36 |  |  | 20 |
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 5,088 |  |  | 5,764 |
INTANGIBLE ASSETS, net | 1 |  |  | 6 |
GOODWILL | 9 |  |  | 9 |
OTHER NON-CURRENT ASSETS, net | 10 |  |  | 10 |
Total assets | $ | 5,201 |  |  | $ | 5,844 |
LIABILITIES AND PARTNERS’ CAPITAL |  |  |
CURRENT LIABILITIES: |  |  |
Accounts payable | $ | 1 |  |  | $ | — |
Accounts payable to related companies | 22 |  |  | 111 |
Interest payable | 66 |  |  | 66 |
Accrued and other current liabilities | 3 |  |  | 1 |
Total current liabilities | 92 |  |  | 178 |
LONG-TERM DEBT, less current maturities | 6,358 |  |  | 6,332 |
NOTE PAYABLE TO AFFILIATE | 443 |  |  | 265 |
OTHER NON-CURRENT LIABILITIES | 2 |  |  | 1 |
COMMITMENTS AND CONTINGENCIES |  |  |
PARTNERS’ DEFICIT: |  |  |
General Partner | (3 | ) |  | (2 | )
Limited Partners: |  |  |
Common Unitholders (1,046,947,157 and 1,044,767,336 units authorized, issued and outstanding as of December 31, 2016 and 2015, respectively) | (1,871 | ) |  | (952 | )
Class D Units (2,156,000 units authorized, issued and outstanding as of December 31, 2015) | — |  |  | 22 |
Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2016) | 180 |  |  | — |
Total partners’ deficit | (1,694 | ) |  | (932 | )
Total liabilities and partners’ deficit | $ | 5,201 |  |  | $ | 5,844 |

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STATEMENTS OF OPERATIONS

| Years Ended December 31,
| 2016 |  | 2015 |  | 2014
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES | $ | (185 | ) |  | $ | (112 | ) |  | $ | (111 | )
OTHER INCOME (EXPENSE): |  |  |  |  |
Interest expense, net of interest capitalized | (327 | ) |  | (294 | ) |  | (205 | )
Equity in earnings of unconsolidated affiliates | 1,511 |  |  | 1,601 |  |  | 955 |
Other, net | (4 | ) |  | (5 | ) |  | (5 | )
INCOME BEFORE INCOME TAXES | 995 |  |  | 1,190 |  |  | 634 |
Income tax expense | — |  |  | 1 |  |  | 1 |
NET INCOME | 995 |  |  | 1,189 |  |  | 633 |
General Partner’s interest in net income | 3 |  |  | 3 |  |  | 2 |
Convertible Unitholders’ interest in income | 9 |  |  | — |  |  | — |
Class D Unitholder’s interest in net income | — |  |  | 3 |  |  | 2 |
Limited Partners’ interest in net income | $ | 983 |  |  | $ | 1,183 |  |  | $ | 629 |

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STATEMENTS OF CASH FLOWS

| Years Ended December 31,
| 2016 |  | 2015 |  | 2014
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES | $ | 918 |  |  | $ | 1,103 |  |  | $ | 816 |
CASH FLOWS FROM INVESTING ACTIVITIES: |  |  |  |  |
Cash paid for Bakken Pipeline Transaction | — |  |  | (817 | ) |  | — |
Contributions to unconsolidated affiliates | (70 | ) |  | — |  |  | (118 | )
Capital expenditures | (16 | ) |  | (19 | ) |  | — |
Purchase of additional interest in Regency | — |  |  | — |  |  | (800 | )
Net cash used in investing activities | (86 | ) |  | (836 | ) |  | (918 | )
CASH FLOWS FROM FINANCING ACTIVITIES: |  |  |  |  |
Proceeds from borrowings | 225 |  |  | 3,672 |  |  | 3,020 |
Principal payments on debt | (210 | ) |  | (1,985 | ) |  | (1,142 | )
Distributions to partners | (1,022 | ) |  | (1,090 | ) |  | (821 | )
Proceeds from affiliate | 176 |  |  | 210 |  |  | 54 |
Units repurchased under buyback program | — |  |  | (1,064 | ) |  | (1,000 | )
Debt issuance costs | — |  |  | (11 | ) |  | (15 | )
Net cash provided by (used in) financing activities | (831 | ) |  | (268 | ) |  | 96 |
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | 1 |  |  | (1 | ) |  | (6 | )
CASH AND CASH EQUIVALENTS, beginning of period | 1 |  |  | 2 |  |  | 8 |
CASH AND CASH EQUIVALENTS, end of period | $ | 2 |  |  | $ | 1 |  |  | $ | 2 |

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