Item 1 and 2.  Business and Properties .

General

We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.”  We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO and are a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, petrochemicals and refined products.  Our midstream energy operations currently include: natural gas gathering, treating, processing, transportation and storage; NGL transportation, fractionation, storage, and export and import terminals (including those used to export liquefied petroleum gases, or “LPG,” and ethane); crude oil gathering, transportation, storage, and export and import terminals; petrochemical and refined products transportation, storage, export and import terminals, and related services; and a marine transportation business that operates primarily on the United States (“U.S.”) inland and Intracoastal Waterway systems.  Our assets currently include approximately 49,300 miles of pipelines; 260 MMBbls of storage capacity for NGLs, crude oil, petrochemicals and refined products; and 14 Bcf of natural gas storage capacity.

We conduct substantially all of our business through EPO and are owned 100% by our limited partners from an economic perspective.  Enterprise GP manages our partnership and owns a non-economic general partner interest in us.  Our principal executive offices are located at 1100 Louisiana Street, 10 ^th Floor, Houston, Texas 77002, our telephone number is (713) 381-6500 and our website address is www.enterpriseproducts.com .

Like many publicly traded partnerships, we have no employees.  All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the “ASA”) or by other service providers.  As of February 1, 2017, there were approximately 6,800 EPCO personnel who spend all or a substantial portion of their time engaged in our business.  For additional information regarding the ASA, see “EPCO ASA” under Note 15 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Business Strategy

Our integrated midstream energy asset network links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the U.S., Canada and Gulf of Mexico with domestic consumers and international markets.  Our business strategy seeks to leverage this network to:

§	capitalize on expected demand growth, including exports, for natural gas, NGLs, crude oil and petrochemical and refined products;

§	maintain a diversified portfolio of midstream energy assets and expand this asset base through growth capital projects and accretive acquisitions of complementary midstream energy assets;

§	enhance the stability of our cash flows by investing in pipelines and other fee-based businesses; and

§	share capital costs and risks through joint ventures or alliances with strategic partners, including those that provide processing, throughput or feedstock volumes for growth capital projects or the purchase of such projects’ end products.

Commercial and Liquidity Outlook for 2017

For information regarding our commercial and liquidity outlook for the year ending December 31, 2017, see “General Outlook for 2017” included under Part II, Item 7 of this annual report.

Major Customer Information

Substantially all of our consolidated revenues are earned in the U.S. and derived from a wide customer base.  Our largest non-affiliated customer for 2016 was Vitol Holding B.V. and its affiliates (collectively, “Vitol”), which accounted for 9.9% of our consolidated revenues.  Vitol is a global energy and commodity trading company.  See Note 10 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for additional information regarding our largest non-affiliated customers for the years ended December 31, 2016, 2015 and 2014.

Business Segments

General

The following sections provide an overview of our business segments, including information regarding principal products produced and/or services rendered and properties owned.  Our historical operations are reported under five business segments:  (i) NGL Pipelines & Services, (ii) Crude Oil Pipelines & Services, (iii) Natural Gas Pipelines & Services, (iv) Petrochemical & Refined Products Services and (v) Offshore Pipelines & Services.  Our business segments are generally organized and managed according to the types of services rendered (or technologies employed) and products produced and/or sold.

On July 24, 2015, we completed the sale of our Gulf of Mexico operations (the “Offshore Business,” which primarily consisted of our Offshore Pipelines & Services segment) to Genesis Energy, L.P.  Our Offshore Business served drilling and development regions, including deepwater production fields, in the northern Gulf of Mexico offshore Alabama, Louisiana, Mississippi and Texas.  These operations included approximately 2,350 miles of offshore natural gas and crude oil pipelines and six offshore hub platforms.  Our consolidated financial statements reflect ownership of the Offshore Business through July 24, 2015.  For additional information regarding sale of the Offshore Business, see Note 5 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Each of our remaining business segments benefits from the supporting role of our related marketing activities.  The main purpose of our marketing activities is to support the utilization and expansion of assets across our midstream energy asset network by increasing the volumes handled by such assets, which results in additional fee-based earnings for each business segment.  In performing these support roles, our marketing activities also seek to participate in supply and demand opportunities as a supplemental source of gross operating margin, a non-generally accepted accounting principle (“non-GAAP”) financial measure, for the partnership.  The financial results of our marketing efforts fluctuate due to changes in volumes handled and overall market conditions, which are influenced by current and forward market prices for the products bought and sold.

For detailed financial information regarding our business segments, see Note 10 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.  Such financial information is incorporated by reference into this Part I, Item 1 and 2 discussion.

Our results of operations and financial condition are subject to certain significant risks.  Factors that can affect the demand for our products and services include domestic and international economic conditions, the market price and demand for energy, the cost to develop natural gas and crude oil reserves in the U.S., federal and state regulation, and the cost and availability of capital to energy companies to invest in upstream exploration and production activities and the credit quality of our customers.  For information regarding such risks, see Part I, Item 1A of this annual report.  In addition, our business activities are subject to various federal, state and local laws and regulations governing a wide variety of topics, including commercial, operational, environmental, safety and other matters.  For a discussion of the principal effects of such laws and regulations on our business activities, see “Regulatory Matters” within this Part I, Item 1 and 2 discussion.

For management’s discussion and analysis of our results of operations, liquidity and capital resources and capital spending program, see Part II, Item 7 of this annual report.

NGL Pipelines & Services Segment

Our NGL Pipelines & Services business segment includes natural gas processing plants and related NGL marketing activities; approximately 19,670 miles of NGL pipelines; NGL and related product storage facilities; and 15 NGL fractionators.  This segment also includes our LPG and ethane export terminals and related operations.

Natural gas processing plants and related NGL marketing activities

At the core of our natural gas processing business are 25 processing plants located in Colorado, Louisiana, Mississippi, New Mexico, Texas and Wyoming.  In its raw form, natural gas produced at the wellhead (especially in association with crude oil) contains varying amounts of mixed NGLs.  Natural gas streams containing NGLs are usually not acceptable for transportation in natural gas pipelines or for commercial use as a fuel; therefore, the streams must be transported to a natural gas processing plant to remove the NGLs and impurities.  Once the natural gas is processed and NGLs and impurities are removed, the natural gas meets pipeline and commercial quality specifications.  On an energy-equivalent basis, most NGLs generally have greater economic value as feedstock for petrochemical and motor gasoline production than as components of a natural gas stream.

In our natural gas processing business, our contracts are either fee-based, commodity-based or a combination of the two.  When a cash fee for natural gas processing services is stipulated by a contract, we record revenue when a producer’s natural gas has been processed and redelivered.  In recent years, our portfolio of natural gas processing contracts has become increasingly weighted towards those with fee-based terms as producers seek to maximize the value of their production by retaining all or a portion of the NGLs extracted from their natural gas stream.  As of December 31, 2016, we estimate that the terms of approximately 48.7% of our current portfolio of natural gas processing contracts (based on natural gas inlet volumes) were entirely fee-based, with an additional 20.4% of this portfolio including a combination of fee-based and commodity-based terms.  The terms of the remaining 30.9% of our portfolio of natural gas processing contracts were entirely commodity-based.

Our commodity-based contracts include keepwhole and margin-band contracts, percent-of-liquids contracts, percent-of-proceeds contracts and contracts featuring a combination of commodity and fee-based terms, as described further below:

§

Under keepwhole and margin-band contracts, we take ownership of mixed NGLs extracted from the producer’s natural gas stream while replacing the equivalent quantity of energy on a natural gas basis to producers.  We recognize revenue when the extracted NGLs are delivered and sold to customers under NGL marketing sales contracts.

§	Under percent-of-liquids contracts, we take ownership of a portion of the mixed NGLs extracted from the producer’s natural gas stream (in lieu of a cash processing fee) and recognize revenue when the extracted NGLs are delivered and sold to customers under NGL marketing sales contracts.

§	Under percent-of-proceeds contracts, we share in the proceeds generated from the sale of mixed NGLs we extract on the producer’s behalf (in lieu of a cash processing fee).

Generally, our natural gas processing agreements have terms ranging from month-to-month to life of the producing lease.  Intermediate terms of one to ten years are also common.

The value of natural gas lost as a result of NGL extraction (i.e., shrinkage) and consumed as plant fuel is referred to as plant thermal reduction, which is a significant cost of natural gas processing.  To the extent that we are obligated under keepwhole and margin-band contracts to compensate the producer for shrinkage and plant fuel, we are exposed to fluctuations in the price of natural gas; however, margin-band contracts typically contain terms that limit our exposure to such risks.  Under the terms of our other processing arrangements (i.e., those agreements with fee-based, percent-of-liquids and percent-of-proceeds terms), the producer typically bears the cost of plant thermal reduction.

If the operating costs of a natural gas processing plant are higher than the incremental value of the NGL products that would be extracted, then recovery levels of certain NGL products, principally ethane, may be purposefully reduced.  This scenario is typically referred to as “ethane rejection” and leads to a reduction in NGL volumes available for subsequent transportation, fractionation, storage and marketing.

Once mixed NGLs are extracted by a natural gas processing plant, the products are typically transported to a centralized fractionation facility for separation into purity NGL products (ethane, propane, normal butane, isobutane and natural gasoline).  Purity NGL products are used as feedstocks by the petrochemical industry, as feedstocks by refineries in the production of motor gasoline and as fuel by industrial and residential consumers, as follows:

§	Ethane is primarily used in the petrochemical industry as a feedstock in the production of ethylene, one of the basic building blocks for a wide range of plastics and other chemical products.

§	Propane is used for heating, as an engine and industrial fuel, and as a petrochemical feedstock in the production of ethylene and propylene.

§	Normal butane is used as a petrochemical feedstock in the production of ethylene and butadiene (a key ingredient of synthetic rubber), as a blendstock for motor gasoline, and to produce isobutane through isomerization.

§

Isobutane is fractionated from mixed butane (a mixed stream of normal butane and isobutane) or produced from normal butane through the process of isomerization, and is used in refinery alkylation to enhance the octane content of motor gasoline, in the production of isooctane and other octane additives, and in the production of propylene oxide.

§	Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is primarily used as a blendstock for motor gasoline, diluent in crude oil to aid in transportation, and as a petrochemical feedstock.

Our NGL marketing activities generate revenues from merchant activities such as term and spot sales of NGLs, which we take title to through our natural gas processing activities (i.e., our equity NGL production) and open market and contract purchases.  The results of operations for NGL marketing are primarily dependent on the difference between NGL sales prices and the associated purchase and other costs, including those costs attributable to the use of our other assets.  In general, sales prices referenced in the underlying contracts are market-based and may include pricing adjustments for factors such as location, timing or NGL product quality.  Market prices for NGLs are subject to fluctuations in response to changes in supply and demand and a variety of additional factors that are beyond our control.  We attempt to mitigate these price risks through the use of commodity derivative instruments.  For a discussion of our commodity hedging program, see Part II, Item 7A of this annual report.

Our NGL marketing activities utilize a fleet of approximately 990 railcars, the majority of which are leased from third parties.  These railcars are used to deliver feedstocks to our facilities and to distribute NGLs throughout the U.S. and parts of Canada.  We have rail loading and unloading capabilities at certain of our terminal facilities in Arizona, Kansas, Louisiana, Minnesota, Mississippi, New York, North Carolina and Texas.  These facilities service both our rail shipments and those of our customers.

Our NGL marketing activities also utilize a fleet of approximately 160 tractor-trailer tank trucks, the majority of which we lease and operate, that are used to transport LPG for us and on behalf of third parties.

The following table presents selected information regarding our natural gas processing facilities at February 1, 2017:

We operate all of our natural gas processing facilities except for the Venice plant.  On a weighted-average basis, utilization rates for our natural gas processing plants were 50.8%, 56.7% and 59.1% during the years ended December 31, 2016, 2015 and 2014, respectively.

An area of focus for us has been the development of midstream infrastructure serving producers in the Delaware Basin, which is part of the overall Permian Basin, in West Texas and southeast New Mexico.  During 2016, we completed and placed into service two natural gas processing facilities (South Eddy and Waha) and announced plans for construction of a third facility (Orla).  The following information describes these new facilities:

South Eddy natural gas processing plant

In May 2016, we announced that construction of our cryogenic natural gas processing plant located in Eddy County, New Mexico (the “South Eddy” plant) had been completed and the facility placed into commercial service.  The South Eddy plant has a natural gas processing capacity of 200 MMcf/d and is capable of extracting up to 25 MBPD of NGLs.  We also completed construction of approximately 90 miles of natural gas gathering pipelines that supply the South Eddy plant and a 71-mile extension of our Mid-America Pipeline System that provides South Eddy customers with NGL takeaway capacity.  Residue gas from the South Eddy plant is handled by interconnections with third party pipelines.

Waha natural gas processing plant

In August 2016, we announced that construction of our joint venture-owned Delaware Basin cryogenic natural gas processing plant (referred to as the “Waha” plant) had been completed and placed into service.  The new plant is located in Reeves County, Texas.  The Waha plant has a natural gas processing capacity of 150 MMcf/d and is capable of extracting in excess of 22 MBPD of NGLs.  We own a 50% equity interest in the joint venture that owns the Waha plant, which we operate.

We also completed construction of and own an 82-mile pipeline that connects the Waha plant to our Chaparral NGL Pipeline System.  Our Texas Intrastate System provides transportation services for residue gas processed at the Waha plant.

Orla natural gas processing plant

In June 2016, we announced plans to build an additional cryogenic natural gas processing plant and associated pipeline infrastructure in the Delaware Basin.  The new processing plant will be located near Orla, Texas in Reeves County and have a natural gas processing capacity of 300 MMcf/d and the capability to extract more than 40 MBPD of NGLs.  In addition, the project includes construction of natural gas gathering lines that will supply the plant, a pipeline that will deliver residue gas to markets at the Waha hub, and an extension of our Mid-America Pipeline System that will provide Orla customers with NGL takeaway capacity.  The facility and related pipeline infrastructure, all of which we will own and operate, are expected to begin service in the second quarter of 2018.

NGL pipelines

Our NGL pipelines transport mixed NGLs and other hydrocarbons from natural gas processing facilities, refineries and import terminals to fractionation plants and storage facilities; gather and distribute purity NGL products to and from fractionation plants, storage and terminal facilities, petrochemical plants, export facilities and refineries; and deliver propane and ethane to destinations along our various pipeline systems.

The results of operations from our NGL pipelines are primarily dependent upon the volume of NGLs transported and the associated fees we charge for such transportation services.  Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies, including the Federal Energy Regulatory Commission (“FERC”), or contractual arrangements.  Typically, pipeline transportation revenue is recognized when volumes are transported and delivered.  However, under certain NGL pipeline transportation agreements (e.g., those associated with committed shippers on our Texas Express Pipeline, Front Range Pipeline, ATEX and Aegis Ethane Pipeline), customers are required to ship a minimum volume over an agreed-upon period.  These arrangements typically entail the shipper paying a transportation fee based on a minimum volume commitment, with a provision that allows the shipper to make-up any volume shortfalls over the agreed-upon period (referred to as shipper “make-up rights”).  Revenue attributable to shipper make-up rights is initially deferred and subsequently recognized at the earlier of when the deficiency volume is shipped, when the shipper’s ability to meet the minimum volume commitment has expired (typically a one year contractual period), or when the pipeline is otherwise released from its transportation service performance obligation.

Excluding inventories owned in connection with our marketing activities, we typically do not take title to the products transported by our NGL pipelines; rather, the shipper retains title and the associated commodity price risk.

The following table presents selected information regarding our NGL pipelines at February 1, 2017:

As noted previously, certain of our NGL pipelines are subject to regulation.  See “Regulatory Matters” within this Part I, Item 1 and 2 discussion for additional information regarding governmental oversight of liquids pipelines, including tariffs charged for transportation services.

The maximum number of barrels per day that our NGL pipelines can transport depends on the operating balance achieved at a given point in time between various segments of each system (e.g., demand levels at each delivery point and the mix of products being transported).  As a result, we measure the utilization rates of our NGL pipelines in terms of net throughput, which is based on our ownership interest.  Total net throughput volumes for these pipelines were 2,965 MBPD, 2,700 MBPD and 2,634 MBPD during the years ended December 31, 2016, 2015 and 2014, respectively.

The following information describes each of our principal NGL pipelines.  We operate our NGL pipelines with the exception of the Skelly-Belvieu Pipeline and Texas Express Gathering System.

§

The Mid-America Pipeline System is an NGL pipeline system consisting of four primary segments:  the 3,145-mile Rocky Mountain pipeline, the 2,138-mile Conway North pipeline, the 632-mile Ethane-Propane Mix pipeline and the 2,217-mile Conway South pipeline.  The Mid-America Pipeline System is present in 13 states: Colorado, Illinois, Iowa, Kansas, Minnesota, Missouri, Nebraska, New Mexico, Oklahoma, Texas, Utah, Wisconsin and Wyoming.  The Rocky Mountain pipeline transports mixed NGLs from the Rocky Mountain Overthrust and San Juan Basin areas to the Hobbs NGL hub located on the Texas-New Mexico border.  The Conway North segment links the NGL hub at Conway, Kansas to refineries, petrochemical plants and propane markets in the upper Midwest.  NGL hubs such as those at Hobbs and Conway provide buyers and sellers a centralized location for the storage and pricing of products, while also providing connections to intrastate and/or interstate pipelines.  The Ethane-Propane Mix segment transports ethane/propane mix primarily to petrochemical plants in Iowa and Illinois from the NGL hub at Conway.  The Conway South pipeline connects the Conway hub with Kansas refineries and provides bi-directional transportation of NGLs between the Conway and Hobbs hubs.  At the Hobbs NGL hub, the Mid-America Pipeline System interconnects with our Seminole Pipeline and Hobbs NGL fractionation and storage facility.  The Mid-America Pipeline System is also connected to 18 non-regulated NGL terminals that we own and operate.

Volumes transported on the Mid-America Pipeline System primarily originate from natural gas processing plants in the Rocky Mountains and Mid-Continent regions, as well as NGL fractionation and storage facilities in Kansas and Texas.

§

The South Texas NGL Pipeline System is a network of NGL gathering and transportation pipelines located in South Texas.  This system gathers and transports mixed NGLs from natural gas processing plants in South Texas (owned by us or third parties) to our NGL fractionators in South Texas and Mont Belvieu, Texas.  In addition, this system transports purity NGL products from our South Texas NGL fractionators to refineries and petrochemical plants located between Corpus Christi, Texas and Houston, Texas and within the Texas City-Houston area, as well as to interconnects with common carrier NGL pipelines.  The South Texas NGL Pipeline System connects with our Aegis Ethane Pipeline, which extends our ethane header system from Mont Belvieu, Texas to Corpus Christi, Texas.  The South Texas NGL Pipeline System also connects our South Texas NGL fractionators with our storage facility in Mont Belvieu, Texas.  The pipeline system includes a 168-mile segment that transports mixed NGLs from our Yoakum natural gas processing plant to our Mont Belvieu NGL fractionation and storage complex.  In addition, a 173-mile segment extends from our Yoakum facility to a third party natural gas processing plant located in LaSalle County, Texas, and provides NGL pipeline takeaway capacity for additional third party gas plants.

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The Dixie   Pipeline extends from southeast Texas to markets in the southeastern U.S., and transports propane and other NGLs.  Propane supplies transported on this system primarily originate from southeast Texas, south Louisiana and Mississippi.  This system operates in seven states:  Alabama, Georgia, Louisiana, Mississippi, North Carolina, South Carolina and Texas, and is connected to eight non-regulated propane terminals that we own and operate.

§

The Seminole Pipeline transports NGLs from the Hobbs hub and the Permian Basin area of West Texas to markets in southeast Texas including our NGL fractionation facility in Mont Belvieu, Texas.  NGLs originating on the Mid-America Pipeline System are the primary source of throughput for the Seminole Pipeline.

§

The ATEX , or Appalachia-to-Texas Express, pipeline primarily transports ethane in southbound service from four NGL fractionation plants located in Ohio, Pennsylvania and West Virginia to our Mont Belvieu storage complex.  The ethane extracted by these fractionation facilities originates from the Marcellus and Utica Shale production areas.  ATEX operates in nine states:  Arkansas, Illinois, Indiana, Louisiana, Missouri, Ohio, Pennsylvania, Texas and West Virginia.

§

The Chaparral NGL System transports mixed NGLs from natural gas processing plants in West Texas and New Mexico to Mont Belvieu, Texas.  This system consists of the 906-mile Chaparral pipeline and the 179-mile Quanah pipeline.  Interstate and intrastate transportation services provided by the Chaparral pipeline are regulated; however, transportation services provided by the Quanah pipeline are not.

§

The Louisiana Pipeline System is a network of NGL pipelines located in southern Louisiana.  This system transports NGLs originating in Louisiana and Texas to refineries and petrochemical plants located along the Mississippi River corridor in southern Louisiana.  This system also provides transportation services for our natural gas processing plants, NGL fractionators and other assets located in Louisiana.  Originating from a central point in Henry, Louisiana, pipelines extend west to Lake Charles, Louisiana, north to an interconnect with the Dixie Pipeline at Breaux Bridge, Louisiana and east in Louisiana, where our Promix, Norco and Tebone NGL fractionation and related storage facilities are located.

§

The Texas Express Pipeline extends from Skellytown, Texas to our NGL fractionation and storage complex at Mont Belvieu, Texas.  Mixed NGLs from the Rocky Mountains, Permian Basin and Mid-Continent regions are delivered to the Texas Express Pipeline via an interconnect with our Mid-America Pipeline System near Skellytown.  The Texas Express Pipeline also transports mixed NGLs from two gathering systems owned by Texas Express Gathering to Mont Belvieu.  In addition, mixed NGLs from the Denver-Julesburg Basin are transported to the Texas Express Pipeline using the Front Range Pipeline.

§	The Skelly-Belvieu Pipeline transports mixed NGLs from Skellytown, Texas to Mont Belvieu, Texas.  The Skelly-Belvieu Pipeline receives NGLs through pipeline interconnects with our Mid-America Pipeline System in Skellytown.

§	The Front Range Pipeline transports mixed NGLs from natural gas processing plants located in the Denver-Julesburg Basin in Colorado to an interconnect with our Texas Express Pipeline and Mid-America Pipeline System and other third party facilities at Skellytown, Texas.

§	The Promix   NGL Gathering System gathers mixed NGLs from natural gas processing plants in southern Louisiana for delivery to our Promix NGL fractionator.

§	The Houston Ship Channel   Pipeline System connects our Mont Belvieu complex to our Houston Ship Channel import/export terminals and various third party petrochemical plants, refineries and other pipelines located along the Houston Ship Channel.

§

The Aegis Ethane Pipeline (“Aegis”) was completed in December 2015 and delivers purity ethane to petrochemical facilities along the southeast Texas and Louisiana Gulf Coast.  Aegis, when combined with a portion of our South Texas NGL Pipeline System, creates an ethane header system stretching approximately 500 miles between Corpus Christi, Texas and the Mississippi River in Louisiana. Aegis is supported by customer commitments that increase to in excess of 360 MBPD over the next two years.

§	The Rio Grande Pipeline transports mixed NGLs from near Odessa, Texas to a pipeline interconnect at the Mexican border south of El Paso, Texas.

§

The Panola Pipeline transports mixed NGLs from points near Carthage, Texas to Mont Belvieu and supports the Haynesville and Cotton Valley oil and gas production areas.  In January 2015, we announced an expansion project involving the Panola Pipeline consisting of the installation of 60 miles of new pipeline, as well as pumps and other related equipment designed to increase the system’s throughput capacity by 50 MBPD to approximately 100 MBPD.  The incremental capacity was placed into service in the second quarter of 2016.

§	The Lou-Tex NGL   Pipeline system transports mixed NGLs, purity NGL products and refinery grade propylene (“RGP”) between the Louisiana and Texas markets.

§	The Tri-States NGL Pipeline transports mixed NGLs from Mobile Bay, Alabama to points near Kenner, Louisiana.

§

The Texas Express Gathering System is comprised of two gathering systems that deliver mixed NGLs to the Texas Express Pipeline.  The Elk City gathering system is comprised of 55 miles of pipeline and gathers mixed NGLs from natural gas processing plants in the Anadarko/Granite Wash production area located in the Texas Panhandle.  The North Texas gathering system comprises 61 miles of pipeline and gathers mixed NGLs from natural gas processing plants in the Barnett Shale production area in North Texas.

NGL fractionation

We own or have interests in 15 NGL fractionators, located in Texas and Louisiana, which separate mixed NGL streams into purity NGL products for third party customers and also our NGL marketing activities.  The primary sources of mixed NGLs fractionated in the U.S. are domestic natural gas processing plants, crude oil refineries and imports of butane and propane mixtures.  Mixed NGLs sourced from domestic natural gas processing plants and crude oil refineries are typically transported to NGL fractionation facilities by NGL pipelines and, to a lesser extent, by railcar and truck.

Mixed NGLs extracted by domestic natural gas processing plants represent the largest source of volumes processed by our NGL fractionators.  Based upon industry data, we believe that sufficient volumes of mixed NGLs, especially those originating from natural gas processing plants located along the Gulf Coast and in the Rocky Mountains and Mid-Continent regions, will be available for fractionation in commercially viable quantities for the foreseeable future.  Significant volumes of mixed NGLs are contractually committed to be processed at our NGL fractionators by joint owners and third party customers.

The results of operations of our NGL fractionation business are generally dependent upon the volume of mixed NGLs fractionated and either the level of fractionation fees charged (under fee-based contracts) or the value of NGLs received (under percent-of-liquids arrangements).  Our fee-based fractionation customers retain title to the NGLs that we process for them.  To the extent we fractionate volumes for customers under percent-of-liquids contracts, we are exposed to fluctuations in NGL prices (i.e., commodity price risk).  We attempt to mitigate these risks through the use of commodity derivative instruments such as forward sales contracts.

The following table presents selected information regarding our NGL fractionation facilities at February 1, 2017:

On a weighted-average basis, overall utilization rates for our NGL fractionators were 90.2%, 90.1% and 89.4% during the years ended December 31, 2016, 2015 and 2014, respectively.  We operate all of our NGL fractionators.  The following information describes each of our principal NGL fractionators:

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Our Mont Belvieu NGL fractionation complex is located at Mont Belvieu, Texas, which is a key hub of the global NGL industry.  Our Mont Belvieu NGL fractionation assets process mixed NGLs from several major NGL supply basins in North America, including the Eagle Ford Shale, Rocky Mountains, Mid-Continent, Permian Basin and San Juan Basin.  Our Mont Belvieu NGL fractionation complex features connectivity to our network of NGL supply and distribution pipelines, approximately 130 MMBbls of salt dome storage capacity, and access to international markets through our existing LPG export facility and ethane export facility.

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Our Shoup and Armstrong NGL fractionators process mixed NGLs supplied by our South Texas natural gas processing plants.  Purity NGL products from the Shoup and Armstrong fractionators are transported to local markets in the Corpus Christi area and also to Mont Belvieu, Texas using our South Texas NGL Pipeline System.

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Our Hobbs NGL fractionator serves NGL producers in West Texas, New Mexico and Colorado.  The Hobbs fractionator receives mixed NGLs from several major supply basins, including the Mid-Continent, Permian Basin, San Juan Basin and Rocky Mountains.  The facility is located at the interconnect of our Mid-America Pipeline System and Seminole Pipeline, thus providing us the operating flexibility to supply both the nation’s largest NGL hub at Mont Belvieu as well as access to the second-largest NGL hub at Conway, Kansas.

§	Our Norco NGL fractionator receives mixed NGLs via pipeline from refineries and natural gas processing plants located in southern Louisiana and along the Mississippi and Alabama Gulf Coast, including our Pascagoula, Venice and Toca facilities.

§

The Promix NGL fractionator receives mixed NGLs via pipeline from natural gas processing plants located in southern Louisiana and along the Mississippi Gulf Coast, including our Neptune and Pascagoula facilities.  In addition to the Promix NGL Gathering System, Promix owns three NGL storage caverns and leases a fourth NGL storage cavern.  Promix also owns a barge loading facility.

§	The Baton Rouge NGL fractionator receives mixed NGLs from natural gas processing plants located in Alabama, Mississippi and southern Louisiana.  This facility includes a leased NGL storage cavern.

§	The Tebone NGL fractionator receives mixed NGLs from our North Terrebonne natural gas processing plant located in southern Louisiana.

NGL and related product storage facilities

We use both underground storage caverns (or wells) and above ground storage tanks to store mixed NGLs and purity NGL, petrochemical and related products owned by us and our customers.  We collect storage revenues under our NGL and related product storage contracts based on the number of days a customer has volumes in storage multiplied by a storage fee (as defined in each contract).  With respect to capacity reservation agreements, we collect a fee for reserving storage capacity for certain customers in our underground storage wells.  Customers pay reservation fees based on the level of storage capacity reserved rather than the actual volumes stored.  When a customer exceeds its reserved capacity, we charge that customer excess storage fees.  In addition, we generally charge customers throughput fees based on volumes delivered into and subsequently withdrawn from storage.  Accordingly, the results of operations from these assets are dependent upon the level of storage capacity reserved by customers, the volume of product delivered into and withdrawn from storage and the level of fees charged.

The following table presents selected information regarding our NGL and related product storage assets at February 1, 2017:

We operate these facilities, with the exception of certain Louisiana storage locations, the leased Markham facility in Texas and another leased facility in Kansas.  Our largest underground storage facility is located in Mont Belvieu, Texas.  This facility consists of 37 underground storage caverns used to store and redeliver mixed NGLs and NGL purity, petrochemical and related products for industrial customers located along the upper Texas Gulf Coast.  This facility has an aggregate usable storage capacity of approximately 130 MMBbls, a brine system with approximately 21 MMBbls of above-ground brine storage pit capacity and four wells available for brine production.

LPG and ethane export terminals and related operations

We own and operate LPG and ethane export terminals and an NGL import facility, all of which are located on the Houston Ship Channel. The results of operations of these facilities are primarily dependent upon the volume handled and the associated fees we charge for such services.  Revenue from terminaling activities is recorded in the period services are provided.  Customers, which include our NGL marketing business, are typically billed a fee per unit of volume loaded or unloaded.

Enterprise Hydrocarbons Terminal

We own and operate a marine terminal complex, the Enterprise Hydrocarbons Terminal (or “EHT”), located on the Houston Ship Channel that provides terminaling services to major integrated oil companies, exporters, marketers, distributors and chemical companies.  EHT has extensive waterfront access, consisting of six deep-water ship docks and two barge docks.  The terminal can accommodate vessels with up to a 45 foot draft, including Suezmax tankers, which are the largest tankers that can navigate the Houston Ship Channel.  We believe that our location on the Houston Ship Channel to the east of the Beltway 8 bridge enables us to handle larger vessels than our competitors who are located to the west of the Beltway 8 bridge because our waterfront has fewer draft and beam (width) restrictions.  The size and structure of our waterfront at the Houston facility allows us not only to receive and unload products for our customers, but also to provide third party docking services for which we receive throughput fees.

EHT’s facilities include those that can load cargoes of fully refrigerated, low-ethane propane and/or butane (collectively referred to as “LPGs”) onto multiple tanker vessels simultaneously.  In December 2015, we completed a new refrigeration train that increased EHT’s loading rate for LPG (nameplate capacity) from 16,500 barrels per hour to approximately 27,500 barrels per hour.  Completion of this expansion project increased overall loading capabilities at EHT from 9.0 MMBbls per month to approximately 16.0 MMBbls per month.  Our LPG export services continue to benefit from increased NGL supplies produced from domestic shale plays such as the Eagle Ford Shale and international demand for propane as a feedstock in ethylene plant operations and for power generation and heating purposes.  On average, LPG loading volumes at EHT were 420 MBPD, 299 MBPD and 248 MBPD during the years ended December 31, 2016, 2015 and 2014, respectively.

The primary customer of EHT is our NGL marketing group, which uses EHT to assist export customers in meeting their volume requirements. NGL marketing transacts with these customers using long-term sales contracts with take-or-pay provisions and/or exchange agreements.  In recent years, the U.S. has become the largest exporter of LPG in the world, with shipments originating from EHT playing a key role.  Of the LPG cargoes we loaded for export at EHT during the year ended December 31, 2016, the destination markets were as follows: 50% to Asia; 23% to North America and the Caribbean; 14% to Europe and Africa; and 13% to Central and South America.  Based on available information, our LPG sales to export customers represented the following percentage of each destination market’s approximate total supply: 58% for North America and the Caribbean; 27% for Central and South America; 14% for Asia; and 9% for Europe and Africa.

We also own and operate an NGL import facility at EHT.  This facility can offload NGLs from tanker vessels at rates up to 14,000 barrels per hour depending on the product.  Our NGL import volumes for the last three years were minimal.

EHT also provides terminaling services involving crude oil, petrochemicals and refined products.  EHT’s assets and activities involving crude oil terminaling and storage are classified and presented as a component of our Crude Oil Pipelines & Services business segment.  EHT’s activities involving petrochemical and refined products customers are classified and described within our Petrochemical & Refined Products Services business segment.

Morgan’s Point Ethane Export Terminal

In September 2016, we placed our ethane export terminal located at Morgan’s Point on the Houston Ship Channel (the “Morgan’s Point Ethane Export Terminal”) into commercial service.  The Morgan’s Point Ethane Export Terminal, which is the largest of its kind in the world, has an aggregate loading rate (nameplate capacity) of approximately 10,000 barrels per hour of fully refrigerated ethane.  Supply for the Morgan’s Point Ethane Export Terminal is sourced from our Mont Belvieu NGL fractionation and storage complex and transported through a new 18-mile, 24-inch diameter pipeline that we completed in February 2016.  The new terminal is supported by customer volume commitments that increase to over 180 MBPD within the next three years (depending on customer elections).

The Morgan’s Point Ethane Export Terminal supports growing international demand for abundant U.S. ethane from shale plays, which offers the global petrochemical industry a low-cost feedstock option and supply diversification. We estimate that U.S. ethane production capacity currently exceeds U.S. demand by 500 to 600 MBPD and could exceed demand by up to 375 MBPD in 2020, after considering the estimated incremental demand from new third party ethylene facilities that have been announced for the Gulf Coast.  By providing producers with access to the export market, the Morgan’s Point Ethane Export Terminal supports continued development of U.S. energy reserves.

Crude Oil Pipelines & Services Segment

Our Crude Oil Pipelines & Services business segment includes approximately 5,400 miles of crude oil pipelines and related operations, crude oil storage and marine terminals and our crude oil marketing activities.

Crude oil pipelines and related operations

Our crude oil pipelines and related operations include crude oil gathering and transportation pipelines in Texas, Oklahoma and New Mexico.  This business includes the condensate gathering operations owned by EFS Midstream LLC (“EFS Midstream”), which we acquired in July 2015 from affiliates of Pioneer Natural Resources Company (“PXD”) and Reliance Industries Limited (“Reliance”).

The results of operations from providing crude oil transportation services is primarily dependent upon the volume handled and the level of fees charged (typically on a per barrel basis). Fees charged to shippers are based on either tariffs regulated by governmental agencies, including the FERC, or contractual arrangements.  Typically, revenue associated with these arrangements is recognized when volumes have been transported and delivered; however, under certain of our transportation agreements (e.g., certain shippers on Seaway), customers are required to ship a minimum volume over an agreed-upon period, with make-up rights.  Revenue attributable to shipper make-up rights is initially deferred and subsequently recognized at the earlier of when the deficiency volume is shipped, when the shipper’s ability to meet the minimum volume commitment has expired (typically a one year contractual period), or when the pipeline is otherwise released from its transportation service performance obligation.

The EFS Midstream System provides condensate gathering, processing and stabilization services as well as gathering, treating and compression services for the associated natural gas volumes.  In connection with this acquisition, we entered into or amended multiple revenue generating agreements with PXD and Reliance having 20-year primary terms.  We also entered into similar agreements with other producers connected to the EFS Midstream System.  In general, revenues under these agreements are recognized based upon the higher of actual volumes handled or minimum volume commitments multiplied by predominantly fixed fees charged for the underlying services.  With respect to those agreements having minimum volume commitments, the producer pays a deficiency fee when its volumes do not meet contractually defined minimum volume thresholds (there are no make-up rights in connection with these agreements).  Under certain of the contracts, if actual volumes handled during a period exceed the respective minimum volume commitment, the excess volume serves to reduce future minimum volume commitments (for periods up to two years in the future), thus reducing any potential deficiency fees that the producer might pay in the future.

The following table presents selected information regarding our crude oil pipelines and related operations at February 1, 2017:

The maximum number of barrels per day that our crude oil pipelines can transport depends on the operating balance achieved at a given point in time between various segments of each system (e.g., demand levels at each delivery point and grades of crude oil being transported).  As a result, we measure the utilization rates of our crude oil pipelines in terms of net throughput, which is based on our ownership interest.  Total net throughput volumes for these pipelines were 1,388 MBPD, 1,474 MBPD and 1,278 MBPD during the years ended December 31, 2016, 2015 and 2014, respectively.

As noted previously, certain of our crude oil pipelines are subject to regulation.  See “Regulatory Matters” within this Part I, Item 1 and 2 discussion for additional information.

The following information describes each of our principal crude oil pipelines, all of which we operate with the exception of the Basin Pipeline and Eagle Ford Crude Oil Pipeline System.

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The Seaway Pipeline connects the Cushing, Oklahoma crude oil hub with markets in southeast Texas.  The Seaway Pipeline is comprised of the Longhaul System, the Freeport System and the Texas City System.  The Cushing hub is a major industry trading hub and price settlement point for West Texas Intermediate (“WTI”) crude oil on the New York Mercantile Exchange (“NYMEX”).

The Longhaul System consists of two 500-mile, 30-inch diameter pipelines that provide north-to-south transportation of crude oil from the Cushing hub to Seaway’s Jones Creek terminal located near Freeport, Texas and a terminal that we own located near Katy, Texas.  The second of these two pipelines, which was placed into commercial service in December 2014, is referred to as the “Seaway Loop.”  The aggregate transportation capacity of the Longhaul System is approximately 850 MBPD, depending on the type and mix of crude oil being transported and other variables.

The Freeport System consists of a marine import and export dock, three pipelines and other related facilities that transport crude oil to and from Freeport, Texas and the Jones Creek terminal.  The Texas City System consists of a marine import and export dock, storage tanks, various pipelines and related facilities that transport crude oil to  refineries in the Texas City, Texas area and to and from terminals in the Galena Park, Texas area, our Enterprise Crude Houston (“ECHO”) terminal and locations along the Houston Ship Channel.  The Texas City System also receives production from certain offshore Gulf of Mexico developments.  The intrastate transportation capacity of the Freeport System and Texas City System is approximately 220 MBPD and 800 MBPD, respectively.

In total, the Seaway Pipeline includes 19 storage tanks located along the Texas Gulf Coast having a combined 8.8 MMBbls of crude oil storage tank capacity (4.4 MMBbls net to our ownership interest).  This includes two storage tanks owned by Seaway that are located at our ECHO terminal and one tank that Seaway leases from a third party.

The interstate tariffs charged by Seaway to its committed and uncommitted shippers were the subject of a rate proceeding at the FERC that concluded in 2016.  For information regarding this proceeding, see “Regulatory Matters – FERC Regulation – Liquids Pipelines,” within this Part I, Item 1 and 2 discussion.

§	The Red River System gathers and transports crude oil from North Texas and southern Oklahoma for delivery to local refineries and pipeline interconnects for further transportation to the Cushing hub.  The Red River System includes 1.1 MMBbls of crude oil storage capacity.

§	The West Texas System connects crude oil gathering systems in West Texas and southeast New Mexico to our terminal facility in Midland, Texas.  The West Texas System includes 0.6 MMBbls of crude oil storage capacity.

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The South Texas Crude Oil Pipeline System transports crude oil and condensate originating in South Texas to refineries in the Greater Houston area.  T he system includes 3.3 MMBbls of crude oil storage capacity. The South Texas Crude Oil Pipeline System also includes our Rancho II pipeline, which extends 89-miles from Sealy, Texas to our ECHO terminal.

§	The Basin Pipeline transports crude oil from the Permian Basin in West Texas and southern New Mexico to the Cushing hub.  The Basin Pipeline includes approximately 6 MMBbls of crude oil storage capacity (0.8 MMBbls net to our ownership interest).

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The EFS Midstream System serves producers in the Eagle Ford Shale, providing condensate gathering and processing services as well as gathering, treating and compression services for associated natural gas.  The EFS Midstream System includes 461 miles of gathering pipelines, 11 central gathering plants having a combined condensate storage capacity of 0.3 MMBbls, 171 MBPD of condensate stabilization capacity and 1.0 Bcf/d of associated natural gas treating capacity.

We acquired EFS Midstream, which owns the EFS Midstream System, in July 2015 for approximately $2.1 billion, which was payable in two installments.  The initial payment of $1.1 billion was paid at closing in July 2015.  The second and final installment of $1.0 billion was paid in July 2016.  Our primary purpose in acquiring the EFS Midstream System was to secure the underlying production, particularly condensate, for our midstream asset network.  Under terms of the associated agreements, PXD and Reliance have dedicated certain of their Eagle Ford Shale acreage to us under 20-year, fixed-fee gathering agreements that include minimum volume requirements for the first seven years.  PXD and Reliance have also entered into related 20-year fee-based agreements with us for natural gas transportation and processing, NGL transportation and fractionation, and for condensate and crude oil transportation services.

In connection with the agreements to acquire EFS Midstream, we are obligated to spend up to an aggregate of $270 million on specified midstream gathering assets for PXD and Reliance, if requested by these producers, over a ten-year period.  If constructed, these new assets would be owned by us and be a component of the EFS Midstream System.  As of December 31, 2016, we have spent approximately $133 million of the $270 million commitment.

For additional information regarding our acquisition of EFS Midstream, see Note 12 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

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The Eagle Ford Crude Oil Pipeline System transports crude oil and condensate for producers in South Texas.  The system, which is effectively looped and has a capacity to transport over 600 MBPD of light and medium grades of crude oil, consists of 376 miles of crude oil and condensate pipelines originating in Gardendale, Texas and extending to Corpus Christi, Texas.  The system also interconnects with our South Texas Crude Oil Pipeline System in Wilson County, Texas.  The Eagle Ford Crude Oil Pipeline System includes an aggregate 4.5 MMBbls of storage capacity across its system (2.2 MMBbls net to our ownership interest) and a marine barge terminal in Corpus Christi.

In addition, we are joint owners of a new deep-water marine crude oil terminal that is being constructed in Corpus Christi that is designed to handle a variety of ocean-going vessels.  The new terminal is expected to be placed into service in 2018.

Midland-to-ECHO Pipeline System

In April 2015, we announced the execution of long-term agreements that support development of a new 24-inch diameter pipeline (the “Midland-to-Sealy” segment of our Midland-to-ECHO Pipeline System) that would transport increasing volumes of crude oil and condensate from the Permian Basin to markets in southeast Texas.  The new pipeline will originate at our Midland, Texas crude oil terminal and extend 416 miles to our Sealy, Texas storage facility. Volumes arriving at Sealy would then be transported to our ECHO terminal using our Rancho II pipeline.  Using the ECHO terminal, shippers will have access to every refinery in Houston, Texas City, Beaumont and Port Arthur, as well as our dock facilities. The Midland-to-ECHO Pipeline System is expected to have a transportation capacity of up to 450 MBPD, with full capacity available during the first quarter of 2018.  We expect to place the pipeline into commercial service during the fourth quarter of 2017 at initial rates up to 300 MBPD.

Crude oil storage and marine terminals

We own terminals located in Houston, Midland and Beaumont, Texas and Cushing, Oklahoma that are used to store crude oil for us and our customers.  Our crude oil terminals, in conjunction with other aspects of our midstream network, provide Gulf Coast refiners with an integrated system featuring supply diversification, significant storage capabilities and a high capacity pipeline distribution system that is connected to customers having an aggregate refining capacity of approximately 3.9 MMBPD.

The results of operations from crude oil terminal services are primarily dependent upon the level of volumes stored and the length of time such storage occurs, including the level of firm storage capacity reserved (if any), pumpover volumes and the fees associated with each activity.  Fees associated with firm storage capacity reservation agreements are charged regardless of the volume the customer actually stores at the terminal.

The following table presents selected information regarding our crude oil terminals at February 1, 2017:

The following information describes each of our principal crude oil storage and marine terminals, all of which we operate.

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As discussed previously, we own and operate EHT, a marine terminal complex, located on the Houston Ship Channel that provides terminaling services to major integrated oil companies, exporters, marketers, distributors and chemical companies.  The EHT crude oil storage complex is one of the largest such facilities on the Gulf Coast with 20.9 MMBbls of aggregate crude oil storage capacity through the use of 74 above-ground storage tanks.  We placed 1.9 MMBbls of crude oil storage capacity into service during 2016 and expect to place an additional 1.6 MMBbls of storage capacity into service in 2017.

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The ECHO   terminal is located in Houston, Texas and provides storage customers with access to major refineries located in the Houston, Texas City and Beaumont/Port Arthur areas.  The ECHO terminal also has connections to marine terminals, including our EHT crude oil terminal, that provide access to any refinery on the U.S. Gulf Coast.  Excluding two tanks aggregating 1.0 MMBbls of storage capacity owned by Seaway, the ECHO terminal has 6.4 MMBbls of aggregate storage capacity through the use of 15 above-ground storage tanks.

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The Beaumont Marine West Crude Oil Terminal is a marine terminal complex located on the Neches River near Beaumont, Texas.  This complex has an aggregate crude oil storage capacity of 4.1 MMBbls through the use of 12 above-ground storage tanks.  All of this storage capacity was completed and placed into service in 2016.

§	The Cushing terminal provides crude oil storage, pumpover and trade documentation services.  Our terminal in Cushing, Oklahoma has an aggregate storage capacity of 3.5 MMBbls through the use of 20 above-ground storage tanks.

§	The Midland terminal provides crude oil storage, pumpover and trade documentation services.  The Midland, Texas terminal has an aggregate storage capacity of 2.7 MMBbls through the use of 14 above-ground storage tanks.

Certain of our crude oil terminals include waterfront access that allows us to load and unload crude oil from ships and barges.   As noted previously, EHT has extensive waterfront access, consisting of six deep-water ship docks and two barge docks.  EHT can accommodate vessels with up to a 45 foot draft, including Suezmax tankers, which are the largest tankers that can navigate the Houston Ship Channel.  In addition, our Beaumont Marine West Crude Oil Terminal includes two deep-water docks and a finger pier that are configured to load and unload crude oil and related products.  Also, the Freeport and Texas City Systems, both of which are components of the Seaway Pipeline, include marine docks used to load and unload crude oil.

The results of operations of these marine facilities are primarily dependent upon the volume handled and the associated fees we charge for such services.  Revenue from such operations is recorded in the period services are provided.  Customers, which include our crude oil marketing business, are typically billed a fee per unit of volume loaded or unloaded.

Since the 1970s, U.S. federal law generally prohibited the export of crude oil, except for crude oil sales to Canada and processed condensate (a type of ultralight crude oil that has been processed through a distillation facility).  This prohibition was lifted in December 2015.  We believe that lifting of the crude oil export ban supports domestic production efforts and creates additional business opportunities for us through the provision of export-related services.  In 2016, we loaded 34.1 MMBbls of crude oil at our dock facilities for export customers.  Prior to lifting the crude oil export ban, the U.S. Department of Commerce allowed us to begin selling processed condensate to international customers at our dock facilities for export.  We loaded 17.1 MMBbls, 15.9 MMBbls and 3.7 MMBbls of processed condensate for export in 2016, 2015 and 2014, respectively.

Crude oil marketing activities

Our crude oil marketing activities generate revenues from the sale and delivery of crude oil purchased either directly from producers or from others on the open market.  The results of operations from our crude oil marketing activities are primarily dependent upon the difference, or spread, between crude oil sales prices and the associated purchase and other costs, including those costs attributable to the use of our pipeline, storage and other midstream assets by the crude oil marketing group.  In general, sales prices referenced in the underlying contracts are market-based and include pricing differentials for factors such as delivery location or crude oil quality.  We also use derivative instruments to mitigate our exposure to commodity price risks associated with our crude oil marketing activities.  For a discussion of our commodity hedging program, see Part II, Item 7A of this annual report.

Our Crude Oil Pipelines & Services segment also includes a fleet of approximately 440 tractor-trailer tank trucks, the majority of which we lease and operate, that are used to transport crude oil.

Natural Gas Pipelines & Services Segment

Our Natural Gas Pipelines & Services business segment includes 19,120 miles of natural gas pipeline systems that provide for the gathering and transportation of natural gas in Colorado, Louisiana, New Mexico, Texas and Wyoming.  We lease underground salt dome natural gas storage facilities located in Texas and Louisiana and own an underground salt dome storage cavern in Texas, all of which are important to our natural gas pipeline operations.  This segment also includes our related natural gas marketing activities.

Natural gas pipelines and related storage assets

Our natural gas pipeline systems gather and transport natural gas from producing regions such as the Eagle Ford Shale, Haynesville Shale, Barnett Shale, Permian, Piceance, San Juan and Greater Green River supply basins.  In addition, certain of these pipeline systems receive natural gas production from Gulf of Mexico developments through coastal pipeline interconnects with offshore pipelines.  Our natural gas pipelines receive natural gas from producers, other pipelines or shippers at the wellhead or through system interconnects and redeliver the natural gas to processing facilities, electric generation plants, local gas distribution companies, industrial or municipal customers, storage facilities or other onshore pipelines.

The results of operations from our natural gas pipelines and related storage assets are primarily dependent upon the volume of natural gas transported or stored, the level of firm capacity reservations made by shippers, and the associated fees we charge for such activities.  Transportation fees charged to shippers (typically per MMBtu of natural gas) are based on either tariffs regulated by governmental agencies, including the FERC, or contractual arrangements.  Certain of our natural gas pipelines offer firm capacity reservation services whereby the shipper pays a contractual fee based on the level of throughput capacity reserved (whether or not the shipper actually utilizes such capacity).  Under our natural gas storage revenue contracts, there are typically two components: (i) monthly demand payments, which are associated with a customer’s storage capacity reservation and paid regardless of actual usage, and (ii) storage fees per unit of volume stored at our facilities.

The following table presents selected information regarding our natural gas pipelines and related storage assets at February 1, 2017:

As noted previously, certain of our natural gas pipelines are subject to regulation.  See “Regulatory Matters” within this Part I, Item 1 and 2 discussion for additional information regarding governmental oversight of natural gas pipelines, including tariffs charged for transportation services.

On a weighted-average basis, overall utilization rates for our natural gas pipelines were approximately 57.4%, 59.3% and 60.5% during the years ended December 31, 2016, 2015 and 2014, respectively.  These utilization rates represent actual natural gas volumes delivered as a percentage of our nominal delivery capacity and do not reflect firm capacity reservation agreements where capacity fees are earned whether or not the shipper actually utilizes such capacity.

The following information describes each of our principal natural gas pipelines.  With the exception of the White River Hub and certain segments of the Texas Intrastate System, we operate our natural gas pipelines and storage facilities.

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The Texas Intrastate System is comprised of the 6,761-mile Enterprise Texas pipeline system and the 630-mile Channel pipeline system. The Texas Intrastate System gathers, transports and stores natural gas from supply basins in Texas such as the Permian Basin and Eagle Ford and Barnett Shales for redelivery to local gas distribution companies and electric generation, industrial and municipal consumers as well as to connections with other intrastate and interstate pipelines.  The Texas Intrastate System serves various commercial markets in Texas, including Corpus Christi, San Antonio/Austin, Beaumont/Orange and Houston, including the Houston Ship Channel industrial market.  The Wilson natural gas storage facility, which is an important part of the Texas Intrastate System, is comprised of a network of leased underground salt dome storage caverns located in Wharton County, Texas.

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The Acadian Gas System transports, stores and markets natural gas in Louisiana.  The Acadian Gas System is comprised of the 589-mile Cypress pipeline, 437-mile Acadian pipeline, 274-mile Haynesville Extension pipeline and 26-mile Enterprise Pelican pipeline.  The Acadian Gas System includes a leased underground salt dome natural gas storage cavern located at Napoleonville, Louisiana.  The Acadian Gas System links natural gas supplies from Louisiana (e.g., from Haynesville Shale supply basin) and offshore Gulf of Mexico developments with local gas distribution companies, electric generation plants and industrial customers located primarily in the Baton Rouge/New Orleans/Mississippi River corridor.

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The Jonah Gathering System is located in the Greater Green River Basin of southwest Wyoming.  This system gathers natural gas from the Jonah and Pinedale supply fields for delivery to regional natural gas processing plants, including our Pioneer facilities, for ultimate delivery into major interstate pipelines.

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The Piceance Basin Gathering System consists of a network of gathering pipelines located in the Piceance Basin of northwestern Colorado.  The Piceance Basin Gathering System gathers natural gas throughout the Piceance Basin to our Meeker natural gas processing complex for ultimate delivery into the White River Hub and other major interstate pipelines.

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The San Juan Gathering System serves producers in the San Juan Basin of northern New Mexico and southern Colorado.  This system gathers natural gas from production wells located in the San Juan Basin and delivers the natural gas either directly into major interstate pipelines or to regional processing and treating plants, including our Chaco processing facility and Val Verde treating plant located in New Mexico, for ultimate delivery into major interstate pipelines.

§	The White River Hub is a natural gas hub facility serving producers in the Piceance Basin of northwest Colorado.  The facility enables producers to access six interstate natural gas pipelines and has a gross throughput capacity of 3 Bcf/d of natural gas (1.5 Bcf/d net to our interest).

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The Haynesville Gathering System consists of the 216-mile State Line gathering system, the 73-mile Southeast Mansfield gathering system, the 70-mile Southeast Stanley gathering system and three natural gas treating plants.  The Haynesville Gathering System gathers natural gas produced from the Haynesville and Bossier Shale supply basins and the Cotton Valley and Taylor Sand formations in Louisiana and eastern Texas for delivery to regional markets, including (through an interconnect with the Haynesville Extension pipeline) markets served by our Acadian Gas System.

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The Permian Basin Gathering System is comprised of the 971-mile Carlsbad pipeline system and 580-mile Waha pipeline system. The Permian Basin Gathering System gathers natural gas from the Permian Basin region of Texas and New Mexico for delivery to natural gas processing plants, including our Chaparral, Carlsbad, South Eddy and Waha plants, and delivers processed natural gas into the El Paso Natural Gas and Transwestern pipelines and our Texas Intrastate System.

§	The Fairplay Gathering System gathers natural gas produced from the Cotton Valley formation within Panola and Rusk Counties in East Texas for delivery to regional markets.

In addition to our natural gas pipelines, we own and operate a natural gas treating facility (the “Central Treating Facility”) located in Rio Blanco County, Colorado.  This facility can treat up to 200 MMcf/d of natural gas and serves Exxon Mobil Corporation’s (“ExxonMobil”) producing properties in the Piceance Basin.  Natural gas delivered to the Central Treating Facility by ExxonMobil is treated to remove impurities and transported to our Meeker gas plant for further processing.

Certain of our natural gas pipelines are subject to regulation.  See “Regulatory Matters” within this Part I, Item 1 and 2 discussion for additional information regarding governmental oversight of natural gas pipelines, including tariffs charged for transportation services.

Natural gas marketing activities

Our natural gas marketing activities generate revenues from the sale and delivery to local gas distribution companies, electric generation plants and other customers of natural gas purchased from producers, regional natural gas processing plants and the open market.  The results of operations from our natural gas marketing activities are primarily dependent upon the difference, or spread, between natural gas sales prices and the associated purchase  and other costs, including those costs attributable to the use of our other assets.  In general, sales prices referenced in the underlying contracts are market-based and may include pricing differentials for factors such as delivery location.

We are exposed to commodity price risk to the extent that we take title to natural gas volumes in connection with our natural gas marketing activities and certain intrastate natural gas transportation contracts.  In addition, we purchase and resell natural gas for certain producers that use our San Juan, Carlsbad and Jonah Gathering Systems and certain segments of our Acadian Gas and Texas Intrastate Systems.  Also, several of our natural gas gathering systems, while not providing marketing services, have some exposure to risks related to fluctuations in commodity prices through transportation arrangements with shippers.  For example, nearly all of the transportation revenues generated by our San Juan Gathering System are based on a percentage of a regional natural gas price index.  This index may fluctuate based on a variety of factors, including changes in natural gas supply and consumer demand.  We attempt to mitigate these price risks through the use of commodity derivative instruments.  For a discussion of our commodity hedging program, see Part II, Item 7A of this annual report.

Petrochemical & Refined Products Services Segment

Our Petrochemical & Refined Products Services business segment includes (i) propylene fractionation and related operations, including 686 miles of pipeline; (ii) a butane isomerization complex, associated deisobutanizer units and related pipeline assets; (iii) octane enhancement and high purity isobutylene production facilities; (iv) refined products pipelines aggregating approximately 4,250 miles, terminals and related marketing activities; and (v) marine transportation.

Propylene fractionation and related operations

Our propylene fractionation and related operations consist of seven propylene fractionation plants, including pipeline systems aggregating 686 miles, and related petrochemical marketing activities.  We operate all of our propylene fractionation and related assets except for the Lake Charles PGP Pipeline in Louisiana.

In general, propylene fractionation plants separate refinery grade propylene (“RGP”), which is a mixture of propane and propylene, into either polymer grade propylene (“PGP”) or chemical grade propylene (“CGP”) along with by-products of propane and mixed butane.  PGP and CGP can also be produced as a by-product of ethylene production.  The demand for PGP primarily relates to the manufacture of polypropylene, which has a variety of end uses including packaging film, fiber for carpets and upholstery and molded plastic parts for appliances and automotive, houseware and medical products.  CGP is a basic petrochemical used in the manufacturing of plastics, synthetic fibers and foams.

The overall results of operations from propylene fractionation are generally dependent upon toll processing arrangements with customers and our petrochemical marketing activities.  Toll processing arrangements typically include a base processing fee per gallon (or other unit of measurement) subject to adjustment for changes in power, fuel and labor costs, all of which are the primary costs of propylene fractionation activities.  The results of operations from our petrochemical pipelines are primarily dependent upon the volume of products transported and the level of fees charged to shippers. Transportation fees are based on contractual arrangements and may include provisions whereby the customer pays us a fee if certain volume thresholds are not met over a contractual term.

In our petrochemical marketing activities, we purchase RGP on the open market for fractionation at our facilities and sell the resulting products at market-based prices.  The sales price of these products may include pricing differentials for factors such as delivery location.  The results of operations from our petrochemical marketing activities are primarily dependent upon the difference, or spread, between the sales prices of the products and associated purchase and other costs, including those costs attributable to the use of our other assets by the petrochemical marketing group.  In order to meet the demand of international customers, this business also includes export assets located at our EHT complex that are capable of loading up to 5,000 metric tons per day of refrigerated PGP.

In order to limit the exposure of our petrochemical marketing activities to commodity price risk, we attempt to match the timing and price of our feedstock purchases with those of the sales of end products.

The following table presents selected information regarding our propylene fractionation facilities at February 1, 2017:

We produce PGP at our Mont Belvieu, Texas propylene fractionation facility and CGP at our BRPC facility located in Baton Rouge, Louisiana.  On a weighted-average basis, overall utilization rates of our propylene fractionation facilities were approximately 81.9%, 80.5% and 84.7% during the years ended December 31, 2016, 2015 and 2014, respectively.

The following table presents selected information regarding our petrochemical pipelines at February 1, 2017:

The maximum number of barrels per day that our petrochemical pipelines can transport depends on the operating balance achieved at a given point in time between various segments of each system (e.g., demand levels at each delivery point and the mix of products being transported).  As a result, we measure the utilization rates of our petrochemical pipelines in terms of net throughput, which is based on our ownership interest.  Total net throughput volumes were 121 MBPD, 126 MBPD and 124 MBPD during the years ended December 31, 2016, 2015 and 2014 , respectively.

The Lou-Tex Propylene pipeline is used to transport CGP from Sorrento, Louisiana to Mont Belvieu, Texas.  In June 2015, we announced plans to convert the Lou-Tex Propylene pipeline from CGP to PGP service.  This conversion is scheduled for completion in 2020.

The North Dean Pipeline System transports PGP from Mont Belvieu, Texas, to Point Comfort, Texas.

In June 2015, we also announced plans for the construction of a new 65-mile, 10-inch diameter pipeline, which will transport RGP between Sorrento and Breaux Bridge, Louisiana.  This pipeline is scheduled for completion in the third quarter of 2017.

In addition, our rail receiving facilities at Mont Belvieu are being expanded to provide us the capability to unload up to 80 RGP rail cars per day.  This expansion project is scheduled for completion during the first quarter of 2017.

Propane Dehydrogenation Facility

We are currently constructing a propane dehydrogenation (“PDH”) facility, with the capacity to produce up to 1.65 billion pounds per year (or approximately 750 thousand metric tons per year or 25 MBPD) of PGP.  The PDH facility is expected to consume approximately 35 MBPD of propane as feedstock and be located adjacent to our Mont Belvieu complex.  The new facility will be integrated with our existing propylene fractionation facilities, which will provide operational reliability and flexibility for both the PDH facility and the fractionation facilities.  The PDH facility, which is underwritten by long-term fee-based, minimum volume commitments, will also be integrated with our PGP storage facilities, pipeline systems and export terminal.  We expect construction of the PDH facility to be completed in the first quarter of 2017 with commercial operations expected to begin in mid-2017.

We have initiated legal proceedings involving the former general contractor for the PDH facility.  For a summary of this litigation, see Note 17 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Isomerization and related operations

We own and operate three isomerization units, which have an aggregate processing capacity of 116 MBPD, located in Mont Belvieu, Texas that comprise the largest commercial isomerization facility in the U.S.  These operations also include a 70-mile pipeline system used to transport high-purity isobutane from Mont Belvieu, Texas to Port Neches, Texas.  Isomerization units convert normal butane feedstock into mixed butane, which is a stream of isobutane and normal butane.  Deisobutanizer (“DIB”) units, of which we own and operate nine located at our Mont Belvieu complex, then separate the isobutane from the normal butane.  Any remaining unconverted (or residual) normal butane generated by the DIB process is then recirculated through the isomerization process until it has been converted into varying grades of isobutane, including high-purity isobutane.  The isomerization process also produces natural gasoline as a by-product.  The primary uses of isobutane are for the production of propylene oxide, isooctane, isobutylene and alkylate for motor gasoline.

The results of operations from our isomerization business are generally dependent on the volume of normal and mixed butanes processed, the level of toll processing fees charged to customers and prices received for by-products.  These processing arrangements typically include a base-processing fee per gallon (or other unit of measurement) subject to adjustment for changes in power, fuel and labor costs, all of which are the primary costs of isomerization.  These assets provide processing services to meet the needs of third party customers and our other businesses, including our NGL marketing activities and octane enhancement production facility.  Our isomerization business also generates revenues from the sale of natural gasoline created as a by-product of the underlying processes.

The demand for commercial isomerization services depends upon the industry’s requirements for isobutane and high-purity isobutane in excess of the isobutane produced through the process of NGL fractionation and refinery operations.  On a weighted-average basis, the utilization rates of our isomerization facility were approximately 93.1%, 82.8% and 80.2% during the years ended December 31, 2016, 2015 and 2014 , respectively.  We own and operate our butane isomerization facility and related pipeline assets.

We also use certain of our DIB units to fractionate mixed butanes produced from NGL fractionation activities, from imports and from other sources into isobutane and normal butane.  The operating flexibility provided by our multiple standalone DIBs enables us to take advantage of fluctuations in demand and prices for different types of butane.  We measure the utilization of our standalone DIB units in terms of processing volumes, which averaged 89 MBPD, 79 MBPD and 82 MBPD for the years ended December 31, 2016, 2015 and 2014 , respectively.

Isobutane Dehydrogenation Unit

In January 2017, we announced plans to construct a new isobutane dehydrogenation (“iBDH”) unit at our Mont Belvieu complex that is expected to have the capability of producing 425,000 tons per year of isobutylene.  The project, which is underwritten by long-term contracts with investment-grade customers, is expected to be completed in the fourth quarter of 2019.  Isobutylene produced by the new plant will provide additional feedstocks for our downstream octane enhancement and petrochemical facilities.

Historically, steam crackers and refineries have been the major source of propane and butane olefins for downstream use.  However, with the increased use of light-end feedstocks, specifically ethane, the need for on-purpose olefins production has increased.  Like our PDH facility, the iBDH plant will help meet market demand where traditional supplies have been reduced.  The new iBDH plant will increase our production of both high purity and low purity isobutylene, both of which are used primarily as feedstock to manufacture lubricants, rubber products and alkylate for gasoline blendstock, as well as methyl tertiary butyl ether (“MTBE”) for export.

Octane enhancement and related operations

We own and operate an octane enhancement production facility located in Mont Belvieu, Texas that is designed to produce isobutylene and either isooctane or MTBE.  The products produced by this facility are used by refiners in the production of reformulated motor gasoline blends to increase octane values.  The high-purity isobutane feedstocks consumed in the production of these products are supplied by our isomerization units.

We sell our octane enhancement products at market-based prices.  We attempt to mitigate the price risk associated with these products by entering into commodity derivative instruments.  To the extent that we produce MTBE, it is sold exclusively into the export market.  We measure the utilization of our octane enhancement facility in terms of combined isooctane, isobutylene and MTBE production volumes, which averaged 19 MBPD, 15 MBPD and 15 MBPD for the years ended December 31, 2016, 2015 and 2014 , respectively.  Octane enhancement production volumes for 2015 and 2014 were adversely impacted by extended maintenance outages in each of these years.

We also own and operate a facility located on the Houston Ship Channel that produces up to 4 MBPD of high purity isobutylene (“HPIB”) and includes an associated storage facility with 0.6 MMBbls of storage capacity.  The primary feedstock for this plant, an isobutane/isobutylene mix, is produced by our Mont Belvieu octane enhancement facility.  HPIB is used in the formulation of polyisobutylene, which is used in the manufacture of lubricants and rubber.  In general, we sell HPIB at market-based prices with a cost-based floor.  On a weighted-average basis, utilization rates for this facility were 58.4%, 54.8% and 47.2% for the years ended December 31, 2016, 2015 and 2014 , respectively.

Refined products pipelines

We own and operate the TE Products Pipeline, which is a 3,423-mile pipeline system comprised of 3,098 miles of regulated interstate pipelines and 325 miles of unregulated intrastate Texas pipelines.  The system primarily transports refined products from the upper Texas Gulf Coast to Seymour, Indiana. From Seymour, segments of the TE Products Pipeline extend to Chicago, Illinois; Lima, Ohio; Selkirk, New York; and near Philadelphia, Pennsylvania.  East of Seymour, Indiana, the TE Products Pipeline is primarily dedicated to NGL transportation service.  The refined products transported by the TE Products Pipeline are produced by refineries and include motor gasoline and distillates.  The results of operations for this pipeline system are dependent upon the volume of products transported and the level of fees charged to shippers.  The tariffs charged for such services are either contractual or regulated by governmental agencies, including the FERC.

The maximum number of barrels per day that our TE Products Pipeline can transport depends on the operating balance achieved at a given point in time between various segments of the system (e.g., demand levels at each delivery point and the mix of products being transported) .  As a result, w e measure the utilization rate of this pipeline in terms of throughput.  Aggregate throughput volumes by product type for the TE Products Pipeline were as follows for the periods presented:

The TE Products Pipeline system includes five refined products truck terminals and 19.1 MMBbls of refined products storage capacity.  In addition, the system includes 3.7 MMBbls of NGL storage capacity, the assets of which are accounted for under our NGL Pipelines & Services business segment.

The TE Products Pipeline is subject to regulation.  See “Regulatory Matters” within this Part I, Item 1 and 2 discussion for additional information regarding governmental oversight of liquids pipelines, including tariffs charged for transportation services.

Centennial

We also own a 50% equity interest in the Centennial Pipeline L.L.C. joint venture.  The Centennial Pipeline is a 795-mile refined products pipeline that extends from an origination facility located on our TE Products Pipeline in Beaumont, Texas to Bourbon, Illinois.  The Centennial Pipeline includes a refined products storage terminal located near Creal Springs, Illinois with a gross storage capacity of 2.3 MMBbls (1.2 MMBbls net to our ownership interest).  The Centennial Pipeline is idle; however, we and our joint venture partner are evaluating a project that would repurpose it as part of an NGL pipeline system that would transport NGLs from third party-owned fractionation facilities located in the Marcellus and Utica Shale production areas to Gulf Coast markets.

Refined products marine terminals

The principal assets of our refined products marine terminal business are the Beaumont Marine East and Beaumont Marine West Refined Products Terminals.  Both facilities are located on the Neches River near Beaumont, Texas, with the East terminal located in Orange County, Texas and the West terminal located in Jefferson County, Texas.  On a combined basis, these refined products terminals include five deep-water ship docks and three barge docks and 5.3 MMBbls of aggregate refined products storage capacity through the use of 64 above-ground storage tanks.  In addition, these terminals have access to 11.7 MMBbls of refined products storage capacity at locations along our TE Products Pipeline between Beaumont and Houston, Texas.

This business also includes refined products marine terminal assets at EHT, which is located on the Houston Ship Channel.  In addition to providing vessel loading and unloading services for refined products, EHT’s refined products operations include 2.4 MMBbls of aggregate storage capacity through the use of 27 above-ground storage tanks.

The results of operations for these marine terminals are primarily dependent upon the volume handled and the associated storage and other fees we charge.  With respect to vessel loading and unloading services, customers are typically billed a fee per unit of volume handled and revenue is recognized in the periods the services are provided.  Revenues from export-related services may also include deficiency fees charged to customers that reserve exporting capacity and later fail to use such capacity.  Deficiency fee revenue is recognized when the customer fails to utilize the specified export capacity as required by contract.  Revenues from storage activities at each terminal are primarily dependent upon the level of volumes a customer stores at each terminal and the length of time such storage occurs, including the level of firm storage capacity reserved (if any), pumpover volumes and the fees associated with each activity.  Fees associated with firm storage capacity reservation agreements are charged regardless of the volume the customer actually stores at the terminal.

Refined products marketing activities

Our refined products marketing activities generate revenues from the sale and delivery of refined products obtained on the open market.  The results of operations from our refined products marketing activities are primarily dependent upon the difference, or spread, between product sales prices and the associated purchase and other costs, including those costs attributable to the use of our other assets.  In general, we sell our refined products at market-based prices, which may include pricing differentials for factors such as delivery location.  We use derivative instruments to mitigate our exposure to commodity price risks associated with our refined products marketing activities.  For a discussion of our commodity hedging program, see Part II, Item 7A of this annual report.

Marine transportation

Our marine transportation business consists of 60 tow boats and 138 tank barges that are used to transport refined products, crude oil, asphalt, condensate, heavy fuel oil, LPG and other petroleum products along key U.S. inland and Intracoastal Waterway systems.  The marine transportation industry uses tow boats as power sources and tank barges for freight capacity.

Our marine transportation assets service refinery and storage terminal customers along the Mississippi River, the intracoastal waterway between Texas and Florida and the Tennessee-Tombigbee Waterway system.  We own and operate a shipyard and repair facility located in Houma, Louisiana and marine fleeting facilities located in Bourg, Louisiana and Channelview, Texas.  The results of operations of our marine transportation business are generally dependent upon the level of fees charged to transport cargo.  These transportation services are typically provided under term contracts, which are agreements with specific customers to transport cargo from within designated operating areas at either set day rates or a set fee per cargo movement.

Our fleet of marine vessels operated at an average utilization rate of 85.2%, 87.9% and 93.1% during the years ended December 31, 2016, 2015 and 2014, respectively.

Our marine transportation business is subject to regulation, including by the U.S. Department of Transportation (“DOT”), Department of Homeland Security, U.S. Department of Commerce and the U.S. Coast Guard (“USCG”).  For information regarding these regulations, see “Regulatory Matters – Federal Regulation of Marine Operations,” within this Part I, Item 1 and 2 discussion.

Regulatory Matters

The following information describes the principal effects of regulation on our business activities, including those regulations involving safety and environmental matters and the rates we charge customers for transportation services.

Safety Matters

The safe operation of our pipelines and other assets is a top priority of our partnership.  We are committed to protecting the environment and the health and safety of the public and those working on our behalf by conducting our business activities in a safe and environmentally responsible manner.

Occupational Safety and Health

Certain of our facilities are subject to the general industry requirements of the Federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes.  We believe we are in material compliance with OSHA and the similar state requirements, including general industry standards, record keeping requirements and monitoring of occupational exposures of employees.

Certain of our facilities are subject to OSHA Process Safety Management (“PSM”) regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals.  These regulations apply to any process involving a chemical at or above a specified threshold (as defined in the regulations) or any process which involves certain flammable gases or liquids.  In addition, we are subject to the Risk Management Plan regulations of the U.S. Environmental Protection Agency (“EPA”) at certain facilities.  These regulations are intended to complement the OSHA PSM regulations.  These EPA regulations require us to develop and implement a risk management program that includes a five-year accident history report, an offsite consequence analysis process, a prevention program and an emergency response program.  We believe we are operating in material compliance with the OSHA PSM regulations and the EPA’s Risk Management Plan requirements.

The OSHA hazard communication standard, the community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require us to organize and disclose information about the hazardous materials used in our operations.  Certain parts of this information must be reported to federal, state and local governmental authorities and local citizens upon request.  These laws and provisions of the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) require us to report spills and releases of hazardous chemicals in certain situations.

Pipeline Safety

We are subject to extensive regulation by the DOT authorized under various provisions of Title 49 of the United States Code and comparable state statutes relating to the design, installation, testing, construction, operation, replacement and management of our pipeline facilities.  These statutes require companies that own or operate pipelines to (i) comply with such regulations, (ii) permit access to and copying of pertinent records, (iii) file certain reports and (iv) provide information as required by the U.S. Secretary of Transportation.  We believe we are in material compliance with these DOT regulations.

We are subject to DOT pipeline integrity management regulations that specify how companies should assess, evaluate, validate and maintain the integrity of pipeline segments that, in the event of a release, could impact High Consequence Areas (“HCAs”).  HCAs include populated areas, unusually sensitive areas and commercially navigable waterways.  The regulation requires the development and implementation of an integrity management program that utilizes internal pipeline inspection techniques, pressure testing or other equally effective means to assess the integrity of pipeline segments in HCAs.  These regulations also require periodic review of HCA pipeline segments to ensure that adequate preventative and mitigative measures exist and that companies take prompt action to address integrity issues raised in the assessment and analysis process.  We have identified our pipeline segments in HCAs and developed an appropriate integrity management program for such assets.

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the “Pipeline Safety Act”) provides for regulatory oversight of the nation’s pipelines, penalties for violations of pipeline safety rules, and other DOT matters.  The Pipeline Safety Act increases penalties for non-compliance with its regulations for a single violation from $100,000 to $200,000 and imposes a maximum fine for the most serious pipeline safety violations involving deaths, injuries or major environmental harm of $2 million per incident.  In addition, the act includes additional safety requirements for newly constructed pipelines.

DOT regulations have incorporated by reference the American Petroleum Institute Standard 653 (“API 653”) as the industry standard for the inspection, repair, alteration and reconstruction of storage tanks.  API 653 requires regularly scheduled inspection and repair of such tanks.  These periodic tank maintenance requirements may result in significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our storage tanks.

In January 2015, former President Obama announced plans to regulate methane emissions attributable to the upstream oil and gas industry, including activities related to gathering and compression, as a greenhouse gas.  See “Climate Change Debate” within this Regulatory Matters section.  This announcement indicated that the DOT through its Pipeline and Hazardous Materials Safety Administration (“PHMSA”), would be issuing new natural gas regulations with the intent to improve safety as well as to reduce methane emissions.

In October 2015, the PHMSA issued a notice of proposed rulemaking proposing new or revised regulations of hazardous liquid pipelines in light of the lessons learned from significant hazardous liquid pipeline accidents, including proposals to: extend reporting requirements to all hazardous liquid gravity and gathering lines; require inspections of pipelines in areas affected by extreme weather; require periodic inline integrity assessments of hazardous liquid pipelines in all locations; modify the provisions for making pipeline repairs; require all pipelines subject to the integrity management requirements be capable of accommodating inline inspection tools within 20 years, with certain exceptions; and clarification of other regulations to improve certainty and compliance.

In March 2016, the PHMSA issued a notice of proposed rulemaking recommending new safety regulations for natural gas transmission pipelines that broaden the scope of safety coverage in several ways, including but not limited to: modifying the regulation of gathering lines by eliminating the exemption from reporting requirements for gas gathering line operators and revising the definition for gathering lines; adding new assessment and revising repair criteria for pipeline segments in HCAs and establishing repair criteria for pipelines that are outside of HCAs; expanding the scope of the regulations to include pipelines located in areas of Medium Consequence Areas (“MCAs”); adding a requirement to test pipelines built before 1970, which are currently exempt from certain pipeline safety requirements; modifying the way that pipeline operators secure and inspect transmission pipeline infrastructure following extreme weather events; clarifying requirements for conducting risk assessment for integrity management; expanding mandatory data collection and integration requirements for integrity management, including data validation; requiring new safety features for launchers and receivers; and requiring a systematic approach to verify a pipeline’s maximum allowable operating pressure and requiring operators to report maximum allowable operating pressure exceedances.

In June 2016, former President Obama signed new pipeline safety legislation, the “Securing America’s Future Energy:  Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016” (the “SAFE PIPES Act”). Extending the PHMSA’s statutory mandate through 2019, the SAFE PIPES Act establishes or continues the development of requirements affecting pipeline safety including, but not limited to, the following: (i) providing the PHMSA with additional authority to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing; (ii) obligating the PHMSA to develop safety standards for natural gas storage facilities by June 22, 2018; and (iii) requiring the PHMSA to complete certain of the outstanding mandates under existing legislation and to report to Congress on the status of overdue rulemakings.  The development and/or implementation of more stringent requirements pursuant to regulations implementing all of the requirements of the Pipeline Safety Act or the SAFE PIPES Act could cause us to incur increased capital costs and costs of operation as necessary to comply with such standards, which costs could be significant.  These new regulations could increase our operating costs which could have an adverse effect on our financial position, results of operations and cash flows.  Until the proposed regulations are finalized, the impact on our operations, if any, is not known.

Environmental Matters

Our operations are subject to various environmental and safety requirements and potential liabilities under extensive federal, state and local laws and regulations.  These include, without limitation: the CERCLA; the Resource Conservation and Recovery Act (“RCRA”); the Federal Clean Air Act (“CAA”); the Clean Water Act (“CWA”); the Oil Pollution Act of 1990 (“OPA”); the OSHA; the Emergency Planning and Community Right to Know Act; and comparable or analogous state and local laws and regulations.  Such laws and regulations affect many aspects of our present and future operations, and generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals with respect to air emissions, water quality, wastewater discharges and solid and hazardous waste management.  Failure to comply with these requirements may expose us to fines, penalties and/or interruptions in our operations that could have a material adverse effect on our financial position, results of operations and cash flows.

If a leak, spill or release of hazardous substances occurs at any facilities that we own, operate or otherwise use, or where we send materials for treatment or disposal, we could be held liable for all resulting liabilities, including investigation, remedial and clean-up costs.  Likewise, we could be required to remove previously disposed waste products or remediate contaminated property, including situations where groundwater has been impacted.  Any or all of these developments could have a material adverse effect on our financial position, results of operations and cash flows.

We believe our operations are in material compliance with applicable environmental and safety laws and regulations.  In addition, we expect that compliance with existing environmental and safety laws and regulations will not have a material adverse effect on our financial position, results of operations and cash flows.  However, environmental and safety laws and regulations are subject to change.  The trend in environmental regulation has been to place more restrictions and limitations on activities that may be perceived to impact the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental regulation compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate.  New or revised regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our financial position, results of operations and cash flows.

On occasion, we are assessed monetary sanctions by governmental authorities related to administrative or judicial proceedings involving environmental matters.  See Part I, Item 3 of this annual report for additional information.

Air Quality

Our operations are associated with regulatory permitted emissions of air pollutants.  As a result, we are subject to the CAA and comparable state laws and regulations including state air quality implementation plans.  These laws and regulations regulate emissions of air pollutants from various industrial sources, including certain of our facilities, and also impose various monitoring and reporting requirements.  Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in an increase in existing air emissions, obtain and strictly comply with the requirements of air permits containing various emission and operational limitations, or utilize specific emission control technologies to limit emissions.  Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and enforcement actions.  We may be required to incur certain capital expenditures for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

Water Quality

The CWA and comparable state laws impose strict controls on the discharge of crude oil and its derivatives into regulated waters.  The CWA provides penalties for any discharge of petroleum products in reportable quantities and imposes substantial potential liability for the costs of removing petroleum or other hazardous substances.  State laws for the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of a release of petroleum or its derivatives in navigable waters or into groundwater.  Spill prevention control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent a petroleum tank release from impacting regulated waters.  The EPA has also adopted regulations that require us to have permits in order to discharge certain storm water run-off.  Storm water discharge permits may also be required by certain states in which we operate and may impose certain monitoring and other requirements.  The CWA further prohibits discharges of dredged and fill material in wetlands and other waters of the U.S. unless authorized by an appropriately issued permit.  We believe that our costs of compliance with these CWA requirements will not have a material adverse effect on our financial position, results of operations and cash flows.

The primary federal law for crude oil spill liability is the OPA, which addresses three principal areas of crude oil pollution: prevention, containment and clean-up and liability.  The OPA applies to vessels, offshore platforms and onshore facilities, including terminals, pipelines and transfer facilities.  In order to handle, store or transport crude oil above certain thresholds, onshore facilities are required to file oil spill response plans with the USCG, the DOT’s OPS or the EPA, as appropriate.  Numerous states have enacted laws similar to the OPA.  Under the OPA and similar state laws, responsible parties for a regulated facility from which crude oil is discharged may be liable for remediation costs, including damage to surrounding natural resources.  Any unpermitted release of petroleum or other pollutants from our pipelines or facilities could result in fines or penalties as well as significant remediation costs.

Contamination resulting from spills or releases of petroleum products is an inherent risk within the pipeline industry.  To the extent that groundwater contamination requiring remediation exists along our pipeline systems or other facilities as a result of past operations, we believe any such contamination could be controlled or remedied without having a material adverse effect on our financial position, results of operations and cash flows, but such costs are site specific and there is no assurance that the impact will not be material in the aggregate.

Environmental groups have instituted lawsuits regarding certain nationwide permits issued by the Army Corps of Engineers. These permits allow for streamlined permitting of pipeline projects.  If these lawsuits are successful, timelines for future pipeline construction projects could be adversely impacted.

Disposal of Hazardous and Non-Hazardous Wastes

In our normal operations, we generate hazardous and non-hazardous solid wastes that are subject to requirements of the federal RCRA and comparable state statutes, which impose detailed requirements for the handling, storage, treatment and disposal of solid waste.  We also utilize waste minimization and recycling processes to reduce the volumes of our solid wastes.

CERCLA, also known as “Superfund,” imposes liability, often without regard to fault or the legality of the original act, on certain classes of persons who contributed to the release of a “hazardous substance” into the environment.  These persons include the owner or operator of a facility where a release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at a facility.  Under CERCLA, responsible parties may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies.  CERCLA and RCRA also authorize the EPA and, in some instances, third parties to take actions in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible parties.  It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.  In the course of our ordinary operations, our pipeline systems and other facilities generate wastes that may fall within CERCLA’s definition of a “hazardous substance” or be subject to CERCLA and RCRA remediation requirements.  It is possible that we could incur liability for remediation or reimbursement of remediation costs under CERCLA or RCRA for remediation at sites we currently own or operate, whether as a result of our or our predecessors’ operations, at sites that we previously owned or operated, or at disposal facilities previously used by us, even if such disposal was legal at the time it was undertaken.

Endangered Species

The federal Endangered Species Act, as amended, and comparable state laws, may restrict commercial or other activities that affect endangered and threatened species or their habitats.  Some of our current or future planned facilities may be located in areas that are designated as a habitat for endangered or threatened species and, if so, may limit or impose increased costs on facility construction or operation.  In addition, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

FERC Regulation – Liquids Pipelines

Certain of our NGL, petroleum products and crude oil pipeline systems are interstate common carriers subject to regulation by the FERC under the Interstate Commerce Act (“ICA”).  These pipelines (referred to as “interstate liquids pipelines”) include, but are not limited to, the following: ATEX, Aegis, Dixie Pipeline, TE Products Pipeline, Front Range Pipeline, Mid-America Pipeline System, Seaway Pipeline, Seminole Pipeline and Texas Express Pipeline.  These pipelines are owned by legal entities that are subject to FERC regulation, including periodic reporting requirements.   For example, ATEX, Aegis and the TE Products Pipeline are owned by Enterprise TE Products Pipeline Company LLC (“Enterprise TE”), which is a FERC-regulated entity.

The ICA prescribes that the interstate rates we charge for transportation on these interstate liquids pipelines must be just and reasonable, and that the rules applied to our services not unduly discriminate against or confer any undue preference upon any shipper.  The FERC regulations implementing the ICA further require that interstate liquids pipeline transportation rates and rules be filed with the FERC.  The ICA permits interested persons to challenge proposed new or changed rates or rules, and authorizes the FERC to investigate such changes and to suspend their effectiveness for a period of up to seven months.  Upon completion of such an investigation, the FERC may require refunds of amounts collected above what it finds to be a just and reasonable level, together with interest.  The FERC may also investigate, upon complaint or on its own motion, rates and related rules that are already in effect, and may order a carrier to change them prospectively.  Upon an appropriate showing, a shipper may obtain reparations (including interest) for damages sustained for a period of up to two years prior to the filing of its complaint.

The rates charged for our interstate liquids pipeline services are generally based on a FERC-approved indexing methodology, which allows a pipeline to charge rates up to a prescribed ceiling that changes annually based on the year-to-year change in the U.S. Producer Price Index for Finished Goods (“PPI”).  A rate increase within the indexed rate ceiling is presumed to be just and reasonable unless a protesting party can demonstrate that the rate increase is substantially in excess of the pipeline’s operating costs.  For the five-year period commencing July 1, 2011 and ending June 30, 2016, we were permitted by the FERC to adjust the indexed rate ceilings annually by the PPI plus 2.65%.  For the five-year period commencing July 1, 2016, the FERC established PPI plus 1.23% as the index.  In any year in which the index is negative due to a decline in the PPI, a pipeline must file to lower its rates if its rates would be above the indexed rate ceiling.  This situation occurred for the year beginning on July 1, 2016 and resulted in the FERC index applicable to our rates reflecting an approximate 2.01% decline.  As an alternative to this indexing methodology, we may also choose to support changes in our rates based on a cost-of-service methodology, by obtaining advance approval to charge “market-based rates,” or by charging “settlement rates” agreed to by all affected shippers.

In June 2013, certain parties filed a complaint at the FERC against Enterprise TE alleging that Enterprise TE’s cancellation of certain distillate and jet fuel transportation services violated a provision of a settlement agreement and requested reinstatement of the transportation services and damages.  In October 2013, the FERC issued an order holding that Enterprise TE violated the provision in the settlement agreement.  While the FERC found that it did not have authority to require Enterprise TE to reinstate the cancelled services, it set the case for an evidentiary hearing to determine if any monetary damages were appropriate.  Certain parties requested rehearing of the FERC’s finding that it lacked authority to reinstate the cancelled services.  In December 2013, Enterprise TE filed a petition for review of the FERC’s October 2013 order with the U.S. Court of Appeals for the District of Columbia Circuit (the “D.C. Circuit”).  Certain parties requested rehearing of the October 2013 order.  In May 2016, the FERC issued an order denying those rehearing requests.  Two of the parties that sought rehearing have filed a petition for review of both the October 2013 order and the May 2016 rehearing order. Enterprise TE has negotiated settlements that have resolved the complaints and has intervened in the pending third party petition for review.  Since Enterprise TE has intervened on behalf of the FERC in the third party petition for review, Enterprise TE voluntarily dismissed its own petition for review at the D.C. Circuit.  We are unable to predict the outcome of the pending third party petition for review.

Seaway is charging “committed shipper” rates to shippers who voluntarily agreed under long term contracts to commit to the transportation of, or nevertheless to pay for (to the extent not transported) the transportation of, a minimum volume of crude oil from Cushing, Oklahoma to the Gulf Coast.  Seaway is also charging “uncommitted shipper” rates to shippers who have not made any long term contractual commitment to the Seaway Pipeline and instead receive service month-to-month. In March 2013, the FERC issued a declaratory order stating that the charging by a pipeline of voluntarily agreed-to committed shipper rates is consistent with the FERC’s policy of honoring contracts (the “March 2013 Order”).  In light of the March 2013 Order, we believed that Seaway’s committed shipper rates were not at issue in the ongoing rate proceeding, which began in 2012.  However, in September 2013, an administrative law judge (“ALJ”) issued an initial decision in the rate proceeding (the “2013 Initial Decision”) distinguishing the March 2013 Order and recommending that the FERC find, among other things, that Seaway’s committed shipper rates are not just and reasonable and should be re-determined on a cost of service basis along with the uncommitted shipper rates.

In October 2013, Seaway and certain committed rate shippers filed briefs on exceptions objecting to this committed shipper rate aspect of the ALJ’s 2013 Initial Decision, and also challenging various aspects of the cost of service determinations in the 2013 Initial Decision.  In February 2014, the FERC issued an order reversing the 2013 Initial Decision with respect to the committed rate issue, reiterating its policy of honoring contracts executed between pipelines and committed shippers and remanding the remaining issues to the ALJ for further review.  In May 2014, the ALJ issued an initial decision on remand, which largely repeated its prior findings, including as to the committed shipper rates. In February 2016, the FERC again reversed the ALJ decision with respect to the committed rate issue and upheld Seaway’s committed rates.  The FERC’s February 2016 order also ruled for and against Seaway on various issues related to the uncommitted rates and required Seaway to submit, by March 17, 2016, a compliance filing calculating new uncommitted rates consistent with the FERC’s order.  Seaway submitted its compliance filing on March 17, 2016 and it was accepted by the FERC in August 2016.  In September 2016, certain parties filed protests alleging that Seaway had not reduced the uncommitted rates by reflecting the FERC’s published index for 2016 and therefore the rates were not just and reasonable. In September 2016, the FERC accepted Seaway’s filing, subject to the condition that Seaway refile its uncommitted rates to reflect the 2016 index adjustment and refund the difference between the rates charged and the rates reflecting the adjustment.  In addition, the FERC directed Seaway to file a refund report.  In September 2016, Seaway paid refunds and filed revised rates reflecting the 2016 index adjustment that became effective in October 2016.  In November 2016, Seaway filed its refund report.

In December 2014, Seaway submitted an application requesting market-based rate setting authority. Certain parties filed protests to the application.  In September 2015, the FERC issued an order setting the matter for hearing. In December 2016, an ALJ issued an initial decision in the market-based rate proceeding (“2016 Initial Decision”) finding that the FERC should grant Seaway’s application for market-based rates. Parties are entitled to file briefs in support of and in opposition to the 2016 Initial Decision, and the 2016 Initial Decision is subject to review by the FERC.  We are unable to predict the ultimate outcome on the rates Seaway charges its shippers.

In October 2016, the FERC issued an advance notice of proposed rulemaking seeking comment regarding potential modifications to its policies for evaluating oil pipeline indexed rate changes and to the reporting requirements. The FERC observed that some pipelines continue to obtain additional index rate increases despite reporting on Form No. 6 that their revenues exceed their costs. The FERC is proposing a new policy that would deny proposed index increases if a pipeline’s Form No. 6 reflects revenues exceeding total cost of service by fifteen percent for both of the prior two years or the proposed  index increases exceed by five percent the annual cost changes reported by the pipeline.  The FERC also is considering requiring pipelines to file additional information for crude and product pipelines, non-contiguous systems and major pipeline systems. Initial comments were due in January 2017 and further comments are due in March 2017.

In December 2016, the FERC issued a Notice of Inquiry (“NOI”), following the recent holding by the D. C. Circuit that the FERC failed to demonstrate that there is no double recovery of taxes for a partnership pipeline as a result of the inclusion of the income tax allowance in a pipeline’s cost of service.  Historically, claims of double recovery have arisen when the FERC has considered permitting master limited partnerships (“MLPs”) to recover an income tax allowance under the FERC’s current income tax allowance policy. Although the issue of income tax allowance arose in the context of an oil pipeline formed as an MLP, the NOI is not limited in its scope to MLPs. Initial and reply comments in response to the NOI are due in March 2017 and April 2017, respectively.  We are unable to predict the outcome of this proceeding.

Changes in the FERC’s methodologies for approving rates could adversely affect Enterprise.  In addition, challenges to our regulated rates could be filed with the FERC and future decisions by the FERC regarding our regulated rates could adversely affect our cash flows.  We believe the transportation rates currently charged by our interstate liquids pipelines are in accordance with the ICA and applicable FERC regulations.  However, we cannot predict the rates we will be allowed to charge in the future for transportation services by such pipelines.

FERC Regulation – Natural Gas Pipelines and Related Matters

Certain of our intrastate natural gas pipelines, including our Texas Intrastate System and our Acadian Gas System, are subject to regulation by the FERC under the Natural Gas Policy Act of 1978 (“NGPA”), in connection with the transportation and storage services they provide pursuant to Section 311 of the NGPA.  Under Section 311 of the NGPA, and the FERC’s implementing regulations, an intrastate pipeline may transport gas “on behalf of” an interstate pipeline company or any local distribution company served by an interstate pipeline, without becoming subject to the FERC’s broader regulatory authority under Natural Gas Act of 1938 (“NGA”).  These services must be provided on an open and nondiscriminatory basis, and the rates charged for these services may not exceed a “fair and equitable” level as determined by the FERC in periodic rate proceedings.

We believe that the transportation rates currently charged and the services performed by our natural gas pipelines are all in accordance with the applicable requirements of the NGPA and FERC regulations.  However, we cannot predict the rates we will be allowed to charge in the future for transportation services by our pipelines.

The resale of natural gas in interstate commerce is subject to FERC oversight.  In order to increase transparency in natural gas markets, the FERC has established rules requiring the annual reporting of data regarding natural gas sales.  The FERC has also established regulations that prohibit energy market manipulation.  The Federal Trade Commission and the Commodity Futures Trading Commission (“CFTC”) have also issued rules and regulations prohibiting energy market manipulation.  We believe that our gas sales activities are in compliance with all applicable regulatory requirements.

A violation of the FERC’s regulations may subject us to civil penalties, suspension or loss of authorization to perform services or make sales of natural gas, disgorgement of unjust profits or other appropriate non-monetary remedies imposed by the FERC.  Pursuant to the Energy Policy Act of 2005, the potential civil and criminal penalties for any violation of the NGPA, or any rules, regulations or orders of the FERC, were increased to up to $1 million per day per violation.

State Regulation of Pipeline Transportation Services

Transportation services rendered by our intrastate liquids and natural gas pipelines are subject to regulation in many states, including Alabama, Colorado, Illinois, Kansas, Louisiana, Minnesota, Mississippi, New Mexico, Oklahoma, Texas and Wyoming.  Although the applicable state statutes and regulations vary widely, they generally require that intrastate pipelines publish tariffs setting forth all rates, rules and regulations applying to intrastate service, and generally require that pipeline rates and practices be reasonable and nondiscriminatory.

Federal Regulation of Marine Operations

The operation of tow boats, barges and marine equipment create maritime obligations involving property, personnel and cargo under General Maritime Law.  These obligations create a variety of risks including, among other things, the risk of collision and allision, which may precipitate claims for personal injury, cargo, contract, pollution, third party claims and property damages to vessels and facilities.

We are subject to the Jones Act and other federal laws that restrict maritime transportation between U.S. departure and destination points to vessels built and registered in the U.S. and owned and manned by U.S. citizens.  As a result of this ownership requirement, we are responsible for monitoring the foreign ownership of our common units and other partnership interests.  If we do not comply with such requirements, we would be prohibited from operating our vessels in U.S. coastwise trade, and under certain circumstances we would be deemed to have undertaken an unapproved foreign transfer, resulting in severe penalties, including permanent loss of U.S. coastwise trading rights for our vessels, fines or forfeiture of the vessels.  In addition, the USCG and American Bureau of Shipping maintain the most stringent regime of vessel inspection in the world, which tends to result in higher regulatory compliance costs for U.S.-flagged operators than for owners of vessels registered under foreign flags of convenience.  Our marine operations are also subject to the Merchant Marine Act of 1936, which under certain conditions would allow the U.S. government to requisition our marine assets in the event of a national emergency.

Climate Change Debate

There is considerable debate over global warming and the environmental effects of greenhouse gas emissions and associated consequences affecting global climate, oceans and ecosystems.  As a commercial enterprise, we are not in a position to validate or repudiate the existence of global warming or various aspects of the scientific debate.  However, if global warming is occurring, it could have an impact on our operations.  For example, our facilities that are located in low lying areas such as the coastal regions of Louisiana and Texas may be at increased risk due to flooding, rising sea levels, or disruption of operations from more frequent and severe weather events.  Facilities in areas with limited water availability may be impacted if droughts become more frequent or severe.  Changes in climate or weather may hinder exploration and production activities or increase the cost of production of oil and gas resources and consequently affect the volume of hydrocarbon products entering our system.  Changes in climate or weather may also affect consumer demand for energy or alter the overall energy mix.  However, we are not in a position to predict the precise effects of global climate change.  We are providing this disclosure based on publicly available information on the matter.

In response to scientific studies suggesting that emissions of certain gases, commonly referred to as greenhouse gases, including gases associated with oil and gas production such as carbon dioxide, methane and nitrous oxide among others, may be contributing to a warming of the earth’s atmosphere and other adverse environmental effects, various governmental authorities have considered or taken actions to reduce emissions of greenhouse gases.  For example, the EPA has taken action under the CAA to regulate greenhouse gas emissions.  In addition, certain states (individually or in regional cooperation), including states in which some of our facilities or operations are located, have taken or proposed measures to reduce emissions of greenhouse gases. Also, the U.S. Congress has proposed legislative measures for imposing restrictions or requiring emissions fees for greenhouse gases.

Actions have also taken place at the international level and the U.S. has been actively involved.  Various policies and approaches, including establishing a cap on emissions, requiring efficiency measures, or providing incentives for pollution reduction, use of renewable energy, or use of fuels with lower carbon content are under discussion and have and may continue to result in additional actions involving greenhouse gases.

These federal, regional and state measures generally apply to industrial sources, including facilities in the oil and gas sector, and could increase the operating and compliance costs of our pipelines, natural gas processing plants, fractionation plants and other facilities.  These regulations could also adversely affect market demand or pricing for our products or products served by our midstream infrastructure, by affecting the price of, or reducing the demand for, fossil fuels or providing competitive advantages to competing fuels and energy sources.  The potential increase in the costs of our operations could include costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions, or administer and manage a greenhouse gas emissions program.  While we may be able to include some or all of such increased costs in the rates charged by our pipelines or other facilities, such recovery of costs is uncertain and may depend on events beyond our control, including the outcome of future rate proceedings before the FERC and the provisions of any final regulations.  In addition, changes in regulatory policies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to greenhouse gases, or restrictions on their use, may reduce volumes available to us for processing, transportation, marketing and storage.

Competition

NGL Pipelines & Services

Within their respective market areas, our natural gas processing business activities and related NGL marketing activities encounter competition primarily from fully integrated oil companies, intrastate pipeline companies, major interstate pipeline companies and their non-rate regulated affiliates, financial institutions with commodity trading platforms and independent processors.  Each of our marketing competitors has varying levels of financial and personnel resources, and competition generally revolves around price, quality of customer service and proximity to customers and other market hubs.  In the markets served by our NGL pipelines, we compete with a number of intrastate and interstate pipeline companies (including those affiliated with major oil, petrochemical and natural gas companies) and barge, rail and truck fleet operations.  In general, our NGL pipelines compete with these entities in terms of transportation fees, reliability and quality of customer service.

Our primary competitors in the NGL and related product storage businesses are integrated major oil companies, chemical companies and other storage and pipeline companies.  We compete with other storage service providers primarily in terms of the fees charged, number of pipeline connections provided and operational dependability.  Our import and export operations compete with those operated by major oil and chemical companies and other midstream service providers primarily in terms of loading and offloading throughput capacity.

We compete with a number of NGL fractionators in Kansas, Louisiana, New Mexico and Texas.  Competition for such services is primarily based on the fractionation fee charged.  However, the ability of an NGL fractionator to receive a customer’s mixed NGLs and store and distribute the resulting purity NGL products is also an important competitive factor and is a function of having the necessary pipeline and storage infrastructure.

Crude Oil Pipelines & Services

Within their respective market areas, our crude oil pipelines, storage terminals and related marketing activities compete with other crude oil pipeline companies, rail carriers, major integrated oil companies and their marketing affiliates, financial institutions with commodity trading platforms and independent crude oil gathering and marketing companies.  The crude oil business can be characterized by strong competition for crude oil volumes.  Competition is based primarily on quality of customer service, competitive pricing and proximity to customers and market hubs.

Natural Gas Pipelines & Services

Within their market areas, our natural gas pipelines compete with other natural gas pipelines on the basis of price (in terms of transportation fees), quality of customer service and operational flexibility.  Our natural gas marketing activities compete primarily with other natural gas pipeline companies and their marketing affiliates as well as standalone natural gas marketing and trading firms.  Competition in the natural gas marketing business is based primarily on competitive pricing, proximity to customers and market hubs, and quality of customer service.

Petrochemical & Refined Products Services

We compete with numerous producers of PGP, which include many of the major refiners and petrochemical companies located along the Gulf Coast.  Generally, our propylene fractionation business competes in terms of the level of toll processing fees charged and access to pipeline and storage infrastructure.  Our petrochemical marketing activities encounter competition from fully integrated oil companies and various petrochemical companies.  Our petrochemical marketing competitors have varying levels of financial and personnel resources and competition generally revolves around price, quality of customer service, logistics and location.

With respect to our isomerization operations, we compete primarily with facilities located in Kansas, Louisiana and New Mexico.  Competitive factors affecting this business include the level of toll processing fees charged, the quality of isobutane that can be produced and access to supporting pipeline and storage infrastructure.  We compete with other octane additive manufacturing companies primarily on the basis of price.

With respect to our TE Products Pipeline, the pipeline’s most significant competitors are third party pipelines in the areas where it delivers products.  Competition among common carrier pipelines is based primarily on transportation fees, quality of customer service and proximity to end users.  Trucks, barges and railroads competitively deliver products into some of the markets served by our TE Products Pipeline and river terminals.  The TE Products Pipeline also faces competition from rail and pipeline movements of NGLs from Canada and waterborne imports into terminals located along the upper East Coast.

Our marine transportation business competes with other inland marine transportation companies as well as providers of other modes of transportation, such as rail tank cars, tractor-trailer tank trucks and, to a limited extent, pipelines.  Competition within the marine transportation business is largely based on performance and price.

Seasonality

Although the majority of our businesses are not materially affected by seasonality, certain aspects of our operations are impacted by seasonal changes such as tropical weather events, energy demand in connection with heating and cooling requirements and for the summer driving season.  Examples include:

§	Our operations along the Gulf Coast, including our Mont Belvieu facility, may be affected by weather events such as hurricanes and tropical storms, which generally arise during the summer and fall months.

§

Residential demand for natural gas typically peaks during the winter months in connection with heating needs and during the summer months for power generation for air conditioning. These seasonal trends affect throughput volumes on our natural gas pipelines and associated natural gas storage levels and marketing results.

§

Due to increased demand for fuel additives used in the production of motor gasoline, our isomerization and octane enhancement businesses experience higher levels of demand during the summer driving season, which typically occurs in the spring and summer months.  Likewise, shipments of refined products and normal butane experience similar changes in demand due to their use in motor fuels.

§	Extreme temperatures and ice during the winter months can negatively affect our inland marine operations on the upper Mississippi and Illinois rivers.

Title to Properties

Our real property holdings fall into two basic categories: (i) parcels that we and our unconsolidated affiliates own in fee (e.g., we own the land upon which our Mont Belvieu NGL fractionators are constructed) and (ii) parcels in which our interests and those of our affiliates are derived from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for our operations.  The fee sites upon which our significant facilities are located have been owned by us or our predecessors in title for many years without any material challenge known to us relating to title to the land upon which the assets are located, and we believe that we have satisfactory title to such fee sites.  We and our affiliates have no knowledge of any material challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our rights pursuant to any material lease, easement, right-of-way, permit or license, and we believe that we have satisfactory rights pursuant to all of our material leases, easements, rights-of-way, permits and licenses.

Available Information

As a publicly traded partnership, we electronically file certain documents with the U.S. Securities and Exchange Commission (“SEC”).  We file annual reports on Form 10-K; quarterly reports on Form 10-Q; and current reports on Form 8-K (as appropriate); along with any related amendments and supplements thereto.  Occasionally, we may also file registration statements and related documents in connection with equity or debt offerings.  You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549.  You may obtain information regarding the Public Reference Room by calling the SEC at (800) SEC-0330.  In addition, the SEC maintains a website at www.sec.gov that contains reports and other information regarding registrants that file electronically with the SEC.

We provide free electronic access to our periodic and current reports on our website, www.enterpriseproducts.com .  These reports are available as soon as reasonably practicable after we electronically file such materials with, or furnish such materials to, the SEC.  You may also contact our Investor Relations department at (866) 230-0745 for paper copies of these reports free of charge.  The information found on our website is not incorporated into this annual report.

Disclosure Under Section 13(r) of the Securities Exchange Act of 1934

U nder Section 13(r) of the Securities Exchange Act of 1934, as amended by the Iran Threat Reduction and Syria Human Rights Act of 2012, issuers are required to include certain disclosures in their periodic reports if they or any of their “affiliates” (as defined in Rule 12b-2 thereunder) have knowingly engaged in certain specified activities relating to Iran.  Disclosure is required even where the activities are conducted outside the U.S. by non-U.S. affiliates in compliance with applicable law, and even if the activities are not covered or prohibited by U.S. law.

Dr. F. Christian Flach was named a director of our general partner in October 2014 in connection with the acquisition of Oiltanking. Dr. Flach is also Chief Executive Officer of Marquard & Bahls (“M&B”), and a member of the M&B executive board.  M&B owns and controls Oiltanking GmbH, which maintains a joint venture interest in Oiltanking Odfjell GmbH, which in turn owns a joint venture interest in the Exir Chemical Terminal (“ECT”) in Iran.  This interest results from an investment dating back to 2002.  Oiltanking GmbH currently has the contractual ri ght to vote for the appointment of one member of ECT’s three-member board. Oiltanking GmbH provides no goods, services, technology, information or support to ECT and plays no role in the management or day-to-day operations of ECT.

Among other activities, ECT provides transit storage for naphtha originating in Iraq en route to Oman for a customer in the United Arab Emirates. ECT does not import or handle any products originated from Iran that are regulated under U.S., European Union or United Nations sanctions laws. ECT pays routine and standard charges (i) to the Petrochemical Special Economic Zone Organization (“Petzone”) for the use of pipelines and (ii) to Terminals and Tanks Petrochemical Co. (“TTPC”), which operates the berth.  Petzone and TTPC are subsidiaries of the National Petrochemical Company, which is owned and controlled by the Government of Iran.  As Oiltanking GmbH has no direct involvement in the day-to-day operations of ECT, we have no information regarding ECT’s intent to continue or not continue making the payments described above.

Oiltanking GmbH maintains an internal compliance program to ensure compliance with all applicable sanctions regimes, including sanctions laws maintained by the U.S., European Union and United Nations.  Although the existence of the routine payments described above may be reportable under Section 13(r), Oiltanking GmbH has informed us that neither it, nor any of its subsidiaries or affiliates, has engaged in any conduct that would be sanctionable under any of these legal regimes.