Enterprise Products Partners LP (EPD) SEC Annual Report (10-K) for 2016

ENTERPRISE PRODUCTS PARTNERS L.P.

TABLE OF CONTENTS

KEY REFERENCES USED IN THIS REPORT

Unless the context requires otherwise, references to "we," "us," "our," "Enterprise" or "Enterprise Products Partners" are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries.  References to "EPO" mean Enterprise Products Operating LLC, which is a wholly owned subsidiary of Enterprise, and its consolidated subsidiaries, through which Enterprise Products Partners L.P. conducts its business.  Enterprise is managed by its general partner, Enterprise Products Holdings LLC ("Enterprise GP"), which is a wholly owned subsidiary of Dan Duncan LLC, a privately held Texas limited liability company.

The membership interests of Dan Duncan LLC are owned by a voting trust, the current trustees ("DD LLC Trustees") of which are: (i) Randa Duncan Williams, who is also a director and Chairman of the Board of Directors (the "Board") of Enterprise GP; (ii) Richard H. Bachmann, who is also a director and Vice Chairman of the Board of Enterprise GP; and (iii) Dr. Ralph S. Cunningham.  Ms. Duncan Williams and Mr. Bachmann also currently serve as managers of Dan Duncan LLC along with W. Randall Fowler, who is also a director and President of Enterprise GP.

References to "EPCO" mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates.  A majority of the outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees ("EPCO Trustees") of which are:  (i) Ms. Duncan Williams, who serves as Chairman of EPCO; (ii) Dr. Cunningham, who serves as Vice Chairman of EPCO; and (iii) Mr. Bachmann, who serves as the President and Chief Executive Officer of EPCO.  Ms. Duncan Williams and Mr. Bachmann also currently serve as directors of EPCO along with Mr. Fowler, who is also the Executive Vice President and Chief Administrative Officer of EPCO. EPCO, together with its privately held affiliates, owned approximately 32% of our limited partner interests at December 31, 2016.

References to "Oiltanking" and "Oiltanking GP" mean Oiltanking Partners, L.P. and OTLP GP, LLC, the general partner of Oiltanking, respectively.  In October 2014, we acquired approximately 65.9% of the limited partner interests of Oiltanking, all of the member interests of Oiltanking GP and the incentive distribution rights held by Oiltanking GP from Oiltanking Holding Americas, Inc. as the first step of a two-step acquisition of Oiltanking.  In February 2015, we completed the second step of this transaction consisting of the acquisition of the noncontrolling interests in Oiltanking.

As generally used in the energy industry and in this annual report, the acronyms below have the following meanings:

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This annual report on Form 10-K for the year ended December 31, 2016 (our "annual report") contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us.  When used in this document, words such as "anticipate," "project," "expect," "plan," "seek," "goal," "estimate," "forecast," "intend," "could," "should," "would," "will," "believe," "may," "potential" and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements.  Although we and our general partner believe that our expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct.  Forward-looking statements are subject to a variety of risks, uncertainties and assumptions as described in more detail under Part I, Item 1A of this annual report.  If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected.  You should not put undue reliance on any forward-looking statements.  The forward-looking statements in this annual report speak only as of the date hereof.  Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.

PART I

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:

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:

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:

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.

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.

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:

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.

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.

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.

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.

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.

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:

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.

Item 1A.   Risk Factors .

An investment in our common units or debt securities involves certain risks.  If any of the following key risks were to occur, it could have a material adverse effect on our financial position, results of operations and cash flows, as well as our ability to maintain or increase distribution levels.  In any such circumstance and others described below, the trading price of our securities could decline and you could lose part or all of your investment.

Risks Relating to Our Business

Changes in demand for and prices and production of hydrocarbon products could have a material adverse effect on our financial position, results of operations and cash flows.

We operate predominantly in the midstream energy industry, which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs, crude oil, petrochemical and refined products.  As such, changes in the prices of hydrocarbon products and in the relative price levels among hydrocarbon products could have a material adverse effect on our financial position, results of operations and cash flows.  Changes in prices may impact demand for hydrocarbon products, which in turn may impact production, demand and the volumes of products for which we provide services.  In addition, decreases in demand may be caused by other factors, including prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition, adverse weather conditions and government regulations affecting prices and production levels.  We may also incur credit and price risk to the extent customers do not fulfill their obligations to us in connection with our marketing of natural gas, NGLs, propylene, refined products and/or crude oil and long-term take-or-pay agreements.

Crude oil and natural gas prices have been extremely volatile in recent years, and we expect that volatility to continue.  For example, crude oil prices (based on WTI as measured by the NYMEX) ranged from a high of $54.06 per barrel to a low of $26.21 per barrel in 2016.  For January 2017, WTI crude oil prices ranged from a high of $53.99 per barrel to a low of $50.82 per barrel.  Likewise, natural gas prices (based on Henry Hub Inside FERC index prices) ranged from a high of $3.93 per MMBtu to a low of $1.64 per MMBtu in 2016.  Using the same index, natural gas prices for January 2017 ranged from a high of $3.42 per MMBtu to a low of $3.10 per MMBtu.

Generally, prices of hydrocarbon products are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of other uncontrollable factors, such as: (i) the level of domestic production and consumer product demand; (ii) the availability of imported oil and natural gas and actions taken by foreign oil and natural gas producing nations; (iii) the availability of transportation systems with adequate capacity; (iv) the availability of competitive fuels; (v) fluctuating and seasonal demand for oil, natural gas, NGLs and other hydrocarbon products, including demand for NGL products by the petrochemical, refining and heating industries; (vi) the impact of conservation efforts; (vii) governmental regulation and taxation of production; and (viii) prevailing economic conditions.

We are exposed to natural gas and NGL commodity price risks under certain of our natural gas processing and gathering and NGL fractionation contracts that provide for fees to be calculated based on a regional natural gas or NGL price index or to be paid in-kind by taking title to natural gas or NGLs.  A decrease in natural gas and NGL prices can result in lower margins from these contracts, which could have a material adverse effect on our financial position, results of operations and cash flows.  Volatility in the prices of natural gas and NGLs can lead to ethane rejection, which results in lower pipeline and fractionation volumes for our assets.  Volatility in these commodity prices may also have an impact on many of our customers, which in turn could have a negative impact on their ability to fulfill their obligations to us.

The crude oil, natural gas and NGLs currently transported, gathered or processed at our facilities originate primarily from existing domestic resource basins, which naturally deplete over time.  To offset this natural decline, our facilities need access to production from newly discovered properties.  Many economic and business factors beyond our control can adversely affect the decision by producers to explore for and develop new reserves.  These factors could include relatively low oil and natural gas prices, cost and availability of equipment and labor, regulatory changes, capital budget limitations, the lack of available capital or the probability of success in finding hydrocarbons.  A decrease in exploration and development activities in the regions where our facilities and other energy logistics assets are located could result in a decrease in volumes handled by our assets, which could have a material adverse effect on our financial position, results of operations and cash flows.  

For a discussion regarding our current commercial outlook for 2017, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations – General Outlook for 2017" included under Part II, Item 7 of this annual report.

We face competition from third parties in our midstream energy businesses .

Even if crude oil and natural gas reserves exist in the areas served by our assets, we may not be chosen by producers in these areas to gather, transport, process, fractionate, store or otherwise handle the hydrocarbons extracted.  We compete with other companies, including producers of crude oil and natural gas, for any such production on the basis of many factors, including but not limited to geographic proximity to the production, costs of connection, available capacity, rates and access to markets.

Our refined products, NGL and marine transportation businesses may compete with other pipelines and marine transportation companies in the areas they serve.  We also compete with railroads and third party trucking operations in certain of the areas we serve.  Competitive pressures may adversely affect our tariff rates or volumes shipped.  Also, substantial new construction of inland marine vessels could create an oversupply and intensify competition for our marine transportation business.  

The crude oil gathering and marketing business can be characterized by thin operating margins and intense competition for supplies of crude oil at the wellhead.  A decline in domestic crude oil production could intensify this competition among gatherers and marketers.  Our crude oil transportation business competes with common carriers and proprietary pipelines owned and operated by major oil companies, large independent pipeline companies, financial institutions with commodity trading platforms and other companies in the areas where such pipeline systems deliver crude oil.

In our natural gas gathering business, we encounter competition in obtaining contracts to gather natural gas supplies, particularly new supplies.  Competition in natural gas gathering is based in large part on reputation, efficiency, system reliability, gathering system capacity and pricing arrangements.  Our key competitors in the natural gas gathering business include independent gas gatherers and major integrated energy companies.  Alternate gathering facilities are available to producers we serve, and those producers may also elect to construct proprietary gas gathering systems.  

A significant increase in competition in the midstream energy industry could have a material adverse effect on our financial position, results of operations and cash flows.

Our debt level may limit our future financial and operating flexibility.

As of December 31, 2016, we had $20.65 billion in principal amount of consolidated senior long-term debt outstanding, $1.47 billion in principal amount of junior subordinated debt outstanding and $1.78 billion in short-term commercial paper notes outstanding.  The amount of our future debt could have significant effects on our operations, including, among other things:

Our public debt indentures currently do not limit the amount of future indebtedness that we can incur, assume or guarantee.  Although our credit agreements restrict our ability to incur additional debt above certain levels, any debt we may incur in compliance with these restrictions may still be substantial.  For information regarding our long-term debt, see Note 8 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Our credit agreements and each of the indentures related to our public debt instruments include traditional financial covenants and other restrictions.  For example, we are prohibited from making distributions to our partners if such distributions would cause an event of default or otherwise violate a covenant under our credit agreements.  A breach of any of these restrictions by us could permit our lenders or noteholders, as applicable, to declare all amounts outstanding under these debt agreements to be immediately due and payable and, in the case of our credit agreements, to terminate all commitments to extend further credit.

Our ability to access capital markets to raise capital on favorable terms could be affected by our debt level, when such debt matures, and by prevailing market conditions.  Moreover, if the rating agencies were to downgrade our credit ratings, we could experience an increase in our borrowing costs, difficulty assessing capital markets and/or a reduction in the market price of our securities.  Such a development could adversely affect our ability to obtain financing for working capital, capital expenditures or acquisitions, or to refinance existing indebtedness.  If we are unable to access the capital markets on favorable terms in the future, we might be forced to seek extensions for some of our short-term debt obligations or to refinance some of our debt obligations through bank credit, as opposed to long-term public debt securities or equity securities.  The price and terms upon which we might receive such extensions or additional bank credit, if at all, could be more onerous than those contained in existing debt agreements.  Any such arrangements could, in turn, increase the risk that our leverage may adversely affect our future financial and operating flexibility and thereby impact our ability to pay cash distributions at expected levels.

We may not be able to fully execute our growth strategy if we encounter illiquid capital markets or increased competition for investment opportunities.

Our growth strategy contemplates the development and acquisition of a wide range of midstream and other energy infrastructure assets while maintaining a strong balance sheet.  This strategy includes constructing and acquiring additional assets and businesses that enhance our ability to compete effectively and to diversify our asset portfolio, thereby providing us with more stable cash flows.  We consider and pursue potential joint ventures, standalone projects and other transactions that we believe may present opportunities to expand our business, increase our market position and realize operational synergies.

We will require substantial new capital to finance the future development and acquisition of assets and businesses.  For example, our capital spending for 2016 reflected approximately $4.12 billion of cash payments for capital projects and other investments, which includes the $1.0 billion final installment payable in connection with the EFS Midstream acquisition.  Based on information currently available, we expect our total capital spending for 2017 to approximate $2.3 billion to $2.7 billion, which includes approximately $250 million for sustaining capital expenditures. Any limitations on our access to capital may impair our ability to execute this growth strategy.  If our cost of debt or equity capital becomes too expensive, our ability to develop or acquire accretive assets will be limited.  We also may not be able to raise the necessary funds on satisfactory terms, if at all.  

Any sustained tightening of the credit markets may have a material adverse effect on us by, among other things, decreasing our ability to finance growth capital projects or business acquisitions on favorable terms and by the imposition of increasingly restrictive borrowing covenants.  In addition, the distribution yields of any new equity we may issue may be higher than historical levels, making additional equity issuances more expensive. Accordingly, increased costs of equity and debt will make returns on capital expenditures with proceeds from such capital less accretive on a per unit basis.

We also may compete with third parties in the acquisition of energy infrastructure assets that complement our existing asset base.  Increased competition for a limited pool of assets could result in our losing to other bidders more often than in the past or acquiring assets at less attractive prices.  Either occurrence could limit our ability to fully execute our growth strategy.  Our inability to execute our growth strategy may materially adversely affect our ability to maintain or pay higher cash distributions in the future.

Our growth strategy may adversely affect our results of operations if we do not successfully integrate and manage the businesses that we acquire or if we substantially increase our indebtedness and contingent liabilities to make acquisitions.

Our growth strategy includes making accretive acquisitions.  From time to time, we evaluate and acquire additional assets and businesses that we believe complement our existing operations.  We may be unable to successfully integrate and manage the businesses we acquire in the future.  We may incur substantial expenses or encounter delays or other problems in connection with our growth strategy that could have a material adverse effect on our financial position, results of operations and cash flows.  Moreover, acquisitions and business expansions involve numerous risks, such as:

If consummated, any acquisition or investment would also likely result in the incurrence of indebtedness and contingent liabilities and an increase in interest expense and depreciation, amortization and accretion expenses.  As a result, our capitalization and results of operations may change significantly following a material acquisition.  A substantial increase in our indebtedness and contingent liabilities could have a material adverse effect on our financial position, results of operations and cash flows.  In addition, any anticipated benefits of a material acquisition, such as expected cost savings or other synergies, may not be fully realized, if at all.

Acquisitions that appear to increase our operating cash flows may nevertheless reduce our operating cash flows on a per unit basis.

Even if we make acquisitions that we believe will increase our operating cash flows, these acquisitions may ultimately result in a reduction of operating cash flow on a per unit basis, such as if our assumptions regarding a newly acquired asset or business did not materialize or unforeseen risks occurred.  As a result, an acquisition initially deemed accretive based on information available at the time could turn out not to be.  Examples of risks that could cause an acquisition to ultimately not be accretive include our inability to achieve anticipated operating and financial projections or to integrate an acquired business successfully, the assumption of unknown liabilities for which we become liable, and the loss of key employees or key customers.  If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will in making such decisions.  As a result of the risks noted above, we may not realize the full benefits we expect from a material acquisition, which could have a material adverse effect on our financial position, results of operations and cash flows.

Our actual construction, development and acquisition costs could materially exceed forecasted amounts.

We have announced and are engaged in multiple significant construction projects involving existing and new assets for which we have expended or will expend significant capital.  These projects entail significant logistical, technological and staffing challenges.  We may not be able to complete our projects at the costs we estimated at the time of each project's initiation or that we currently estimate.  Similarly, force majeure events such as hurricanes along the U.S. Gulf Coast may cause delays, shortages of skilled labor and additional expenses for these construction and development projects. 

If capital expenditures materially exceed expected amounts, then our future cash flows could be reduced, which, in turn, could reduce the amount of cash we expect to have available for distribution.  In addition, a material increase in project costs could result in decreased overall profitability of the newly constructed asset once it is placed into commercial service.

Our construction of new assets is subject to operational, regulatory, environmental, political, legal and economic risks, which may result in delays, increased costs or decreased cash flows.

One of the ways we intend to grow our business is through the construction of new midstream energy infrastructure assets.  The construction of new assets involves numerous operational, regulatory, environmental, political, legal and economic risks beyond our control and may require the expenditure of significant amounts of capital.  These potential risks include, among other things, the following:

A materialization of any of these risks could adversely affect our ability to achieve growth in the level of our cash flows or realize benefits from expansion opportunities or construction projects, which could impact the level of cash distributions we pay to partners.

Several of our assets have been in service for many years and require significant expenditures to maintain them. As a result, our maintenance or repair costs may increase in the future.

Our pipelines, terminals and storage assets are generally long-lived assets, and many of them have been in service for many years. The age and condition of our assets could result in increased maintenance or repair expenditures in the future. Any significant increase in these expenditures could adversely affect our results of operations, financial position or cash flows, as well as our ability to make cash distributions to our unitholders.

The inability to continue to access lands owned by third parties, including Native American tribes, could adversely affect our operations and have a material adverse effect on our financial position, results of operations and cash flows.

Our ability to operate our pipeline systems on certain lands owned by third parties will depend on our maintaining existing rights-of-way and obtaining new rights-of-way on those lands. We are parties to rights-of-way agreements, permits and licenses authorizing land use with numerous parties, including private land owners, governmental entities, Native American tribes, rail carriers, public utilities and others. Our ability to secure extensions of existing agreements, permits and licenses is essential to our continuing business operations, and securing additional rights-of-way will be critical to our ability to pursue expansion projects. We cannot provide any assurance that we will be able to maintain access to all existing rights-of-way upon the expiration of the current grants, that all of the rights-of-way will be obtained in a timely fashion or that we will acquire new rights-of-way as needed.

In particular, various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs, Bureau of Land Management, and the Office of Natural Resources Revenue, along with each Native American tribe, promulgate and enforce regulations pertaining to natural gas and oil operations on Native American tribal lands. These regulations and approval requirements relate to such matters as drilling and production requirements and environmental standards. In addition, each Native American tribe is a sovereign nation having the right to enforce laws and regulations and to grant approvals independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees, requirements to employ Native American tribal members and other conditions that apply to operators and contractors conducting operations on Native American tribal lands. One or more of these factors may increase our cost of doing business on Native American tribal lands and impact the viability of, or prevent or delay our ability to conduct our operations on such lands.

Furthermore, whether we have the power of eminent domain for our pipelines varies from state to state, depending upon the type of pipeline and the laws of the particular state and the ownership of the land to which we seek access. When we exercise eminent domain rights or negotiate private agreements, we must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. The inability to exercise the power of eminent domain could negatively affect our business if we were to lose the right to use or occupy the property on which our pipelines are located.

A natural disaster, catastrophe, terrorist or cyber-attack or other event could result in severe personal injury, property damage and environmental damage, which could curtail our operations and have a material adverse effect on our financial position, results of operations and cash flows.

Some of our operations involve risks of personal injury, property damage and environmental damage, which could curtail our operations and otherwise materially adversely affect our cash flow.  For example, natural gas facilities operate at high pressures, sometimes in excess of 1,100 pounds per square inch.  In addition, our marine transportation business is subject to additional risks, including the possibility of marine accidents and spill events.  From time to time, our octane enhancement facility may produce MTBE for export, which could expose us to additional risks from spill events.  Virtually all of our operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods and/or earthquakes.  The location of our assets and our customers' assets in the U.S. Gulf Coast region makes them particularly vulnerable to hurricane or tropical storm risk.  In addition, terrorists may target our physical facilities and computer hackers may attack our electronic systems.

If one or more facilities or electronic systems that we own or that deliver products to us or that supply our facilities are damaged by severe weather or any other disaster, accident, catastrophe, terrorist or cyber-attack or event, our operations could be significantly interrupted.  These interruptions could involve significant damage to people, property or the environment, and repairs could take from a week or less for a minor incident to six months or more for a major interruption.  Additionally, some of the storage contracts that we are a party to obligate us to indemnify our customers for any damage or injury occurring during the period in which the customers' product is in our possession.  Any event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions and, accordingly, adversely affect the market price of our common units.

We believe that EPCO maintains adequate insurance coverage on our behalf, although insurance will not cover many types of interruptions that might occur, will not cover amounts up to applicable deductibles and will not cover all risks associated with certain of our products.  As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage.

In the future, circumstances may arise whereby EPCO may not be able to renew existing insurance policies on our behalf or procure other desirable insurance on commercially reasonable terms, if at all.  If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position, results of operations and cash flows.  In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.

The use of derivative financial instruments could result in material financial losses by us.

Historically, we have sought to limit a portion of the adverse effects resulting from changes in energy commodity prices and interest rates by using derivative instruments.  Derivative instruments typically include futures, forward contracts, swaps, options and other instruments with similar characteristics.  Substantially all of our derivatives are used for non-trading activities.

To the extent that we hedge our commodity price and interest rate exposures, we will forego the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor.  In addition, hedging activities can result in losses that might be material to our financial condition, results of operations and cash flows.  Such losses could occur under various circumstances, including those situations where a counterparty does not perform its obligations under a hedge arrangement, the hedge is not effective in mitigating the underlying risk, or our risk management policies and procedures are not followed.  Adverse economic conditions (e.g., a significant decline in energy commodity prices that negatively impact the cash flows of oil and gas producers) increase the risk of nonpayment or performance by our hedging counterparties.  

See Note 14 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for a discussion of our derivative instruments and related hedging activities.

Our business requires extensive credit risk management that may not be adequate to protect against customer nonpayment.

We may incur credit risk to the extent customers do not fulfill their obligations to us in connection with our marketing of natural gas, NGLs, crude oil, petrochemicals and refined products and long-term contracts with minimum volume commitments or fixed demand charges.  Risks of nonpayment and nonperformance by customers are a major consideration in our businesses, and our credit procedures and policies may not be adequate to sufficiently eliminate customer credit risk.  Further, adverse economic conditions in our industry, such as those experienced throughout 2015 and 2016 and that we continue to experience at the beginning of 2017, increase the risk of nonpayment and nonperformance by customers, particularly customers that have sub-investment grade credit ratings.  We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions may utilize letters of credit, prepayments, net out agreements and guarantees.  However, these procedures and policies do not fully eliminate customer credit risk.

Our primary market areas are located in the Gulf Coast, Southwest, Rocky Mountain, Northeast and Midwest regions of the U.S.  We have a concentration of trade receivable balances due from domestic and international major integrated oil companies, independent oil companies and other pipelines and wholesalers.  These concentrations of market areas may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors.  

See Note 2 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for information regarding our allowance for doubtful accounts.

Our risk management policies cannot eliminate all commodity price risks.  In addition, any non-compliance with our risk management policies could result in significant financial losses.

When engaged in marketing activities, it is our policy to maintain physical commodity positions that are substantially balanced with respect to price risks between purchases, on the one hand, and sales or future delivery obligations, on the other hand.  Through these transactions, we seek to earn a margin for the commodity purchased by selling the commodity for physical delivery to third party users, such as producers, wholesalers, local distributors, independent refiners, marketing companies or major oil companies.  These policies and practices cannot, however, eliminate all price risks.  For example, any event that disrupts our anticipated physical supply could expose us to risk of loss resulting from price changes if we are required to obtain alternative supplies to cover our sales transactions.  We are also exposed to basis risks when a commodity is purchased against one pricing index and sold against a different index.  Moreover, we are exposed to some risks that are not hedged, including price risks on product we own, such as pipeline linefill, which must be maintained in order to facilitate transportation of the commodity in our pipelines.  In addition, our marketing operations involve the risk of non-compliance with our risk management policies.  We cannot assure you that our processes and procedures will detect and prevent all violations of our risk management policies, particularly if deception or other intentional misconduct is involved.  If we were to incur a material loss related to commodity price risks, including non-compliance with our risk management policies, it could have a material adverse effect on our financial position, results of operations and cash flows.

Our variable-rate debt, including those fixed-rate debt obligations that may be converted to variable-rate through the use of interest rate swaps, make us vulnerable to increases in interest rates, which could have a material adverse effect on our financial position, results of operation and cash flows.

At December 31, 2016, we had $20.85 billion in principal amount of consolidated fixed-rate debt outstanding, including current maturities thereof.  We also had $1.78 billion of commercial paper notes outstanding at December 31, 2016.  Due to the short term nature of commercial paper notes, we view the interest rates charged in connection with these instruments as variable.

Should interest rates increase significantly, the amount of cash required to service our debt (including any future refinancing of our fixed-rate debt instruments) would increase.  Additionally, from time to time, we may enter into interest rate swap arrangements, which could increase our exposure to variable interest rates.  As a result, significant increases in interest rates could have a material adverse effect on our financial position, results of operations and cash flows.

An increase in interest rates may also cause a corresponding decline in demand for equity securities in general, and in particular, for yield-based equity securities such as our common units.  A reduction in demand for our common units may cause their trading price to decline.

Our pipeline integrity program as well as compliance with pipeline safety laws and regulations may impose significant costs and liabilities on us.

If we were to incur material costs in connection with our pipeline integrity program or pipeline safety laws and regulations, those costs could have a material adverse effect on our financial condition, results of operations and cash flows.

The DOT requires pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in HCAs.  The majority of the costs to comply with this integrity management rule are associated with pipeline integrity testing and any repairs found to be necessary as a result of such testing.  Changes such as advances of in-line inspection tools, identification of additional threats to a pipeline's integrity and changes to the amount of pipe determined to be located in HCAs can have a significant impact on the costs to perform integrity testing and repairs.  We will continue our pipeline integrity testing programs to assess and maintain the integrity of our pipelines.  The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

In total, our pipeline integrity costs for the years ended December 31, 2016, 2015 and 2014 were $103.7 million, $92.7 million and $99.0 million, respectively.  Of these annual totals, we charged $55.8 million, $54.7 million and $59.7 million to operating costs and expenses during the years ended December 31, 2016, 2015 and 2014, respectively.  The remaining annual pipeline integrity costs were capitalized and treated as sustaining capital projects.  We expect the cost of our pipeline integrity program, regardless of whether such costs are capitalized or expensed, to approximate $133 million for 2017.

For additional information regarding the pipeline safety regulations, the Pipeline Safety Act and the SAFE PIPES Act, see "Regulatory Matters-Safety Matters-Pipeline Safety" included under Part I, Item 1 and 2 of this annual report.

Environmental, health and safety costs and liabilities, and changing environmental, health and safety regulation, could have a material adverse effect on our financial position, results of operations and cash flows.

Our operations are subject to various environmental, health and safety requirements and potential liabilities under extensive federal, state and local laws and regulations.  Further, we cannot ensure that existing environmental, health and safety regulations will not be revised or that new regulations will not be adopted or become applicable to us.  Governmental authorities have the power to enforce compliance with applicable regulations and permits and to subject violators to civil and criminal penalties, including substantial fines, injunctions or both.  Certain environmental laws, including the CERCLA and analogous state laws and regulations, may impose strict, joint and several liability for costs required to clean-up and restore sites where hazardous substances or hydrocarbons have been disposed or otherwise released.  Moreover, third parties, including neighboring landowners, may also have the right to pursue legal actions to enforce compliance or to recover for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.  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.

In addition, future environmental, health and safety law developments, such as stricter laws, regulations, permits or enforcement policies, could significantly increase some costs of our operations.  Areas of potential future environmental, health and safety law development include the following items.

Greenhouse Gases/Climate Change

Responding to scientific reports regarding threats posed by global climate change, the U.S. Congress has considered legislation to reduce emissions of greenhouse gases.  In addition, some states, including states in which our facilities or operations are located, have individually or in regional cooperation, imposed restrictions on greenhouse gas emissions under various policies and approaches, including establishing a cap on emissions, requiring efficiency measures, or providing incentives for pollution reduction, use of renewable energy sources, or use of replacement fuels with lower carbon content.

The adoption and implementation of any federal, state or local regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur significant costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the crude oil, natural gas or other hydrocarbon products that we transport, store or otherwise handle in connection with our midstream services.  The potential increase in our operating costs 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, and administer and manage a greenhouse gas emissions program.  We may not be able to recover such increased costs through customer prices or rates.  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.  These developments could have a material adverse effect on our financial position, results of operations and cash flows.

In addition, due to concerns over climate change, numerous countries around the world have adopted or are considering adopting laws or regulations to reduce greenhouse gas emissions.  It is not possible to know how quickly renewable energy technologies may advance, but if significant additional legislation and regulation were enacted, the increased use of renewable energy could ultimately reduce future demand for hydrocarbons.  These developments could have a material adverse effect on our financial position, results of operations and cash flows.

Hydraulic Fracturing

Certain of our customers employ hydraulic fracturing techniques to stimulate natural gas and crude oil production from unconventional geological formations (including shale formations), which entails the injection of pressurized fracturing fluids (consisting of water, sand and certain chemicals) into a well bore.  The U.S. federal government, and some states and localities, have adopted, and others are considering adopting, regulations or ordinances that could restrict hydraulic fracturing in certain circumstances, or that would impose higher taxes, fees or royalties on natural gas production.  Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to crude oil and natural gas drilling activities using hydraulic fracturing techniques, including increased litigation.  Additional legislation or regulation could also lead to operational delays and/or increased operating costs in the production of crude oil and natural gas (including natural gas produced from shale plays like the Eagle Ford, Haynesville, Barnett, Marcellus and Utica Shales) incurred by our customers or could make it more difficult to perform hydraulic fracturing.  If these legislative and regulatory initiatives cause a material decrease in the drilling of new wells and related servicing activities, it may affect the volume of hydrocarbon projects available to our midstream businesses and have a material adverse effect on our financial position, results of operations and cash flows.

See "Regulatory Matters" under Part I, Item 1 and 2 of this annual report for more information and specific disclosures relating to environmental, health and safety laws and regulations, and costs and liabilities.

Federal, state or local regulatory measures could have a material adverse effect on our financial position, results of operations and cash flows.

The FERC regulates our interstate liquids pipelines under the ICA.  State regulatory agencies regulate our intrastate natural gas and NGL pipelines, intrastate storage facilities and gathering lines.

Our intrastate NGL and natural gas pipelines are subject to regulation in many states, including Colorado, Kansas, Louisiana, New Mexico, Texas and Wyoming.  To the extent our intrastate natural gas pipelines engage in interstate transportation, they are also subject to regulation by the FERC pursuant to Section 311 of the NGPA.  We also have natural gas underground storage facilities in Louisiana and Texas.  Although state regulation is typically less comprehensive in scope than regulation by the FERC, our services are typically required to be provided on a nondiscriminatory basis and are also subject to challenge by protest and complaint.

Although our natural gas gathering systems are generally exempt from FERC regulation under the NGA, our natural gas gathering operations could be adversely affected should they become subject to federal regulation of rates and services, or, if the states in which we operate adopt policies imposing more onerous regulation on gas gathering operations.  Additional rules and legislation pertaining to these matters are considered and adopted from time to time at both state and federal levels.  We cannot predict what effect, if any, such regulatory changes and legislation might have on our operations, but we could be required to incur additional capital expenditures.

For a general overview of federal, state and local regulation applicable to our assets, see "Regulatory Matters" included within Part I, Item 1 and 2 of this annual report.  This regulatory oversight can affect certain aspects of our business and the market for our products and could have a material adverse effect on our financial position, results of operations and cash flows.

The rates of our regulated assets are subject to review and possible adjustment by federal and state regulators, which could adversely affect our revenues.

The FERC, pursuant to the ICA (as amended), the Energy Policy Act and rules and orders promulgated thereunder, regulates the tariff rates for our interstate common carrier liquids pipeline operations.  To be lawful under the ICA, interstate tariff rates, terms and conditions of service must be just and reasonable and not unduly discriminatory, and must be on file with the FERC.  In addition, pipelines may not confer any undue preference upon any shipper.  Shippers may protest (and the FERC may investigate) the lawfulness of new or changed tariff rates.  The FERC can suspend those tariff rates for up to seven months.  It can also require refunds of amounts collected pursuant to rates that are ultimately found to be unlawful and prescribe new rates prospectively.  The FERC and interested parties can also challenge tariff rates that have become final and effective.  The FERC can also order new rates to take effect prospectively and order reparations for past rates that exceed the just and reasonable level up to two years prior to the date of a complaint.  Due to the complexity of rate making, the lawfulness of any rate is never assured.  A successful challenge of our rates could adversely affect our revenues.

The FERC uses prescribed rate methodologies for approving regulated tariff rate changes for interstate liquids pipelines.  The FERC's indexing methodology currently allows a pipeline to increase its rates by a percentage linked to the PPI.  However, in any year in which the index is negative, a pipeline must file to lower its rates if its rates would be above the indexed rate ceiling.  As an alternative to this indexing methodology, we may also choose to support our rates based on a cost-of-service methodology, or by obtaining advance approval to charge "market-based rates," or by charging "settlement rates" agreed to by all affected shippers.  These methodologies may limit our ability to set rates based on our actual costs or may delay the use of rates reflecting increased costs.  

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.  In addition, the FERC issued an NOI, to develop a mechanism to demonstrate there is no double recovery of partnership income tax costs.  Changes in the FERC's approved methodology for approving rates, or challenges to our application of that methodology, could adversely affect us.  Adverse decisions by the FERC in approving our regulated rates could adversely affect our cash flow.

The intrastate liquids pipeline transportation services we provide are subject to various state laws and regulations that apply to the rates we charge and the terms and conditions of the services we offer.  Although state regulation typically is less onerous than FERC regulation, the rates we charge and the provision of our services may be subject to challenge.

The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.

The Dodd-Frank Wall Street Reform and Consumer Protection Act enacted in 2010 (the "Dodd-Frank Act") provides for statutory and regulatory requirements for swaps and other derivative transactions, including financial and certain physical oil and gas hedging transactions.  Under the Dodd-Frank Act, the CFTC has adopted regulations requiring registration of swap dealers and major swap participants, mandatory clearing of swaps, election of the end-user exception for any uncleared swaps by certain qualified companies, recordkeeping and reporting requirements, business conduct standards and position limits among other requirements.  Several of these requirements, including position limits rules, allow the CFTC to impose controls that could have an adverse impact on our ability to hedge risks associated with our business and could increase our working capital requirements to conduct these activities.

Based on an assessment of final rules promulgated by the CFTC, we have determined that we are not a swap dealer, major swap participant or a financial entity, and therefore have determined that we currently qualify as an end-user.  In addition, the vast majority of our derivative transactions are currently transacted through a Derivatives Clearing Organization, and we believe our use of the end-user exception will likely not be necessary on a routine basis.  We will also seek to retain our status as an end-user by taking reasonable measures necessary to avoid becoming a swap dealer, major swap participant or financial entity and other measures to preserve our ability to elect the end-user exception should it become necessary.  However, derivative transactions that are not clearable, and transactions that are clearable but for which we choose to elect the end-user exception, are subject to recordkeeping and reporting requirements and potentially additional credit support arrangements including cash margin or collateral.  Posting of additional cash margin or collateral could affect our liquidity and reduce our ability to use cash for capital expenditures or other company purposes.

In September 2012, the U.S. District Court for the District of Columbia vacated and remanded the position limits rules adopted by the CFTC based on a necessity finding.  In December 2013, the CFTC responded by proposing amended rules in an effort to better conform to the Dodd-Frank Act and in December 2016, the CFTC further refined and reproposed rules on position limits.  Under the reproposed rules, the CFTC would place volumetric limitations on certain positions in 25 core physical commodity futures contracts and their economically equivalent futures, options and swaps.  While we believe that the majority of our hedging transactions would meet one or more of the enumerated categories for Bona Fide Hedges, the rules could have an adverse impact on our ability to hedge certain risks associated with our business and could potentially affect our profitability.  The CFTC has announced a 60-day period for public comment on the reproposed rules.  As of the filing of this annual report, the CFTC has yet to provide final rules.

Our standalone operating cash flow is derived primarily from cash distributions we receive from EPO .

On a standalone basis, Enterprise Products Partners L.P. is a holding company with no business operations and conducts all of its business through its wholly owned subsidiary, EPO.  As a result, we depend upon the earnings and cash flows of EPO and its subsidiaries and joint ventures, and the distribution of their cash flows to us in order to meet our obligations and to allow us to make cash distributions to our limited partners.

The amount of cash EPO and its subsidiaries and joint ventures can distribute to us depends primarily on cash flows generated from their operations.  These operating cash flows fluctuate based on, among other things, the: (i) volume of hydrocarbon products transported on their gathering and transmission pipelines; (ii) throughput volumes in their processing and treating operations; (iii) fees charged and the margins realized for their various storage, terminaling, processing and transportation services; (iv) price of natural gas, crude oil and NGLs; (v) relationships among natural gas, crude oil and NGL prices, including differentials between regional markets; (vi) fluctuations in their working capital needs; (vii) level of their operating costs; (viii) prevailing economic conditions; and (ix) level of competition encountered by their businesses.  In addition, the actual amount of cash EPO and its subsidiaries and joint ventures will have available for distribution will depend on factors such as: (i) the level of sustaining capital expenditures incurred; (ii) their cash outlays for expansion (or growth) capital projects and acquisitions; and (iii) their debt service requirements and restrictions included in the provisions of existing and future indebtedness, organizational documents, applicable state business organization laws and other applicable laws and regulations.  Because of these factors, we may not have sufficient available cash each quarter to continue paying distributions at our current levels.

Risks Relating to Our Partnership Structure

We may issue additional securities without the approval of our common unitholders.

At any time, we may issue an unlimited number of limited partner interests of any type (to parties other than our affiliates) without the approval of our unitholders.  Our partnership agreement does not give our common unitholders the right to approve the issuance of equity securities, including equity securities ranking senior to our common units.  The issuance of additional common units or other equity securities of equal or senior rank will have the following effects: (i) the ownership interest of a unitholder immediately prior to the issuance will decrease; (ii) the amount of cash available for distribution on each common unit may decrease; (iii) the ratio of taxable income to distributions may increase; (iv) the relative voting strength of each previously outstanding common unit may be diminished; and (v) the market price of our common units may decline.

We may not have sufficient operating cash flows to pay cash distributions at the current level following establishment of cash reserves and payments of fees and expenses.

Because cash distributions on our common units are dependent on the amount of cash we generate, distributions may fluctuate based on our performance and capital needs.  We cannot guarantee that we will continue to pay distributions at the current level each quarter.  The actual amount of cash that is available to be distributed each quarter will depend upon numerous factors, some of which are beyond our control and the control of our general partner.  These factors include, but are not limited to: (i) the volume of the products that we handle and the prices we receive for our services; (ii) the level of our operating costs; (iii) the level of competition in our business; (iv) prevailing economic conditions, including the price of and demand for oil, natural gas and other products we transport, store and market; (v) the level of capital expenditures we make; (vi) the amount and cost of capital we can raise compared to the amount of our capital expenditures and debt service requirements; (vii)  restrictions contained in our debt agreements; (viii) fluctuations in our working capital needs; (ix) weather volatility; (x) cash outlays for acquisitions, if any; and (xi) the amount, if any, of cash reserves required by our general partner in its sole discretion.

Furthermore, the amount of cash that we have available for distribution is not solely a function of profitability, which will be affected by non-cash items such as depreciation, amortization and provisions for asset impairments.  Our cash flows are also impacted by borrowings under credit agreements and similar arrangements.  As a result, we may be able to make cash distributions during periods when we record losses and may not be able to make cash distributions during periods when we record net income.  An inability on our part to pay cash distributions to partners could have a material adverse effect on our financial position, results of operations and cash flows.

We do not have the same flexibility as other types of organizations to accumulate cash and equity to protect against illiquidity in the future.

Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash, after taking into account reserves for commitments and contingencies, including capital and operating costs and debt service requirements.  The value of our common units and other limited partner interests may decrease in correlation with any reduction in our cash distributions per unit.  Accordingly, if we experience a liquidity problem in the future, we may not be able to issue more equity to recapitalize.

Our general partner and its affiliates have limited fiduciary responsibilities to, and conflicts of interest with respect to, our partnership, which may permit it to favor its own interests to your detriment.

The directors and officers of our general partner and its affiliates have duties to manage our general partner in a manner that is beneficial to its members.  At the same time, our general partner has duties to manage our partnership in a manner that is beneficial to us.  Therefore, our general partner's duties to us may conflict with the duties of its officers and directors to its members.  Such conflicts may include, among others, the following:

We have significant business relationships with entities controlled by EPCO and Dan Duncan LLC.  For information regarding these relationships and related party transactions with EPCO and its affiliates, see Note 15 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.  Additional information regarding our relationship with EPCO and its affiliates can also be found under Part III, Item 13 of this annual report.

The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.

We currently list our common units on the NYSE under the symbol "EPD." Because we are a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our general partner's Board or to establish a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the NYSE's shareholder approval rules that apply to a corporation. Accordingly, unitholders do not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. See Part III, Item 10 of this annual report for additional information.

Unitholders have limited voting rights and are not entitled to elect our general partner or its directors.  In addition, even if unitholders are dissatisfied, they cannot easily remove our general partner.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business.  Unitholders did not elect our general partner or its directors and will have no right to elect our general partner or its directors on an annual or other continuing basis.  The owners of our general partner choose the directors of our general partner.

Furthermore, if unitholders are dissatisfied with the performance of our general partner, they currently have no practical ability to remove our general partner or its officers or directors.  Our general partner may not be removed except upon the vote of the holders of at least 60% of our outstanding units voting together as a single class.  Since affiliates of our general partner currently own approximately 32% of our outstanding common units, the removal of Enterprise GP as our general partner is highly unlikely without the consent of both our general partner and its affiliates.  As a result of this provision, the trading price of our common units may be lower than other forms of equity ownership because of the absence of a takeover premium in the trading price.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Unitholders' voting rights are further restricted by a provision in our partnership agreement stating that any units held by a person that owns 20% or more of any class of our common units then outstanding, other than our general partner and its affiliates, cannot be voted on any matter.  In addition, our partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders' ability to influence our management.  As a result of this provision, the trading price of our common units may be lower than other forms of equity ownership because of the absence of a takeover premium in the trading price.

Our general partner has a limited call right that may require common unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own 85% or more of the common units then outstanding, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining common units held by unaffiliated persons at a price not less than the then current market price.  As a result, common unitholders may be required to sell their common units at an undesirable time or price and may therefore not receive any return on their investment.  Unitholders may also incur a tax liability upon the sale of their common units.

Our common unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business.

Under Delaware law, common unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that the right of limited partners to remove our general partner or to take other action under our partnership agreement constituted participation in the "control" of our business.  Under Delaware law, our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those of our contractual obligations that are expressly made without recourse to our general partner.

The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the states in which we do business. You could have unlimited liability for our obligations if a court or government agency determined that (i) we were conducting business in a state, but had not complied with that particular state's partnership statute; or (ii) your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constituted "control" of our business.

Unitholders may have liability to repay distributions.

Under certain circumstances, our unitholders may have to repay amounts wrongfully distributed to them.  Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.  Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.  Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount.  A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to such purchaser of common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.

Our general partner's interest in us and the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner, in accordance with our partnership agreement, may transfer its general partner interest without the consent of unitholders.  In addition, our general partner may transfer its general partner interest to a third party in a merger or consolidation or in a sale of all or substantially all of its assets without the consent of our unitholders.  Furthermore, there is no restriction in our partnership agreement on the ability of the sole member of our general partner, currently Dan Duncan LLC, to transfer its equity interests in our general partner to a third party.  The new equity owner of our general partner would then be in a position to replace the Board and officers of our general partner with their own choices and to influence the decisions taken by the Board and officers of our general partner.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states.  If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes or if we were otherwise subject to a material amount of entity-level taxation, then cash available for distribution to our unitholders would be reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes.  Despite the fact that we are organized as a limited partnership under Delaware law, we will be treated as a corporation for federal income tax purposes unless we satisfy a "qualifying income" requirement. Based on our current operations, we believe we satisfy the qualifying income requirement.  Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.  We have not requested, and do not plan to request, a ruling from the Internal Revenue Service ("IRS") with respect to our classification as a partnership for federal income tax purposes.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate (which is currently a maximum of 35%) and we would also likely pay additional state and local income taxes at varying rates.  Distributions to our unitholders would generally be taxed again as corporate dividends, and no income, gains, losses or deductions would flow through to our unitholders.  Because a tax would be imposed upon us as a corporation, the cash available for distribution to our unitholders would be reduced.  Thus, treatment of us as a corporation could result in a reduction in the anticipated cash-flow and after-tax return to our unitholders, likely causing a reduction in the value of our common units.

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Specifically, we are subject to an entity-level franchise tax on the portion of our income apportioned to Texas. Imposition of any of these taxes in other jurisdictions in which we own assets or conduct business or an increase in the existing tax rates would substantially reduce the cash available for distribution to our unitholders.

Our partnership agreement provides that, if a law is enacted that subjects us to taxation as a corporation for federal income tax purposes, the minimum quarterly distribution amount and the target distribution levels will be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial interpretation.  For example, from time to time, the U.S. President and members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws including those that affect the tax treatment of certain publicly traded partnerships.

Further, final Treasury Regulations under Section 7704(d)(1)(E) of the Internal Revenue Code recently published in the Federal Register interpret the scope of qualifying income requirements for publicly traded partnerships by providing industry-specific guidance.

Any modification to federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible for us to be treated as a partnership for federal income tax purposes (i.e., not taxable as a corporation).  We are unable to predict whether any of these changes or any other proposals will ultimately be enacted, including as a result of fundamental tax reform.  Any such changes could negatively impact the value of an investment in our common units.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of the units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The U.S. Treasury Department and the IRS recently issued final Treasury Regulations pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders although such tax items must be prorated on a daily basis and the regulations do not specifically authorize all aspects of the proration method we have adopted.  If the IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units and the cost of any IRS contest will reduce our cash available for distribution to unitholders.

The IRS has made no determination as to our status as a partnership for U.S. federal income tax purposes.  The IRS may adopt positions that differ from the positions we take, even positions taken with advice of counsel.  It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and such positions may not ultimately be sustained.  A court may not agree with some or all of the positions we take.  As a result, any such contest with the IRS may materially and adversely impact the market for our common units and the price at which our common units trade.  In addition, our costs of any contest with the IRS, principally legal, accounting and related fees, will be indirectly borne by our unitholders because the costs will reduce our cash available for distribution.

Legislation applicable to us for taxable years beginning after 2017 alters the procedures for auditing large partnerships and also alters the procedures for assessing and collecting taxes due (including penalties and interest) as a result of an audit.  Under these rules, unless we are eligible to, and do, elect to issue revised Schedules K-1 to our partners with respect to an audited and adjusted partnership tax return, the IRS may assess and collect taxes (including any applicable penalties and interest) directly from us in the year in which the audit is completed.  If we are required to pay taxes, penalties and interest as a result of audit adjustments, cash available for distribution to our unitholders may be substantially reduced.  In addition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited tax year.

Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount from the cash that we distribute, our unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive any cash distributions from us.  Our common unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability resulting from their share of our taxable income.

Tax gains or losses on the disposition of our common units could be more or less than expected .

If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units.  Because distributions in excess of a unitholder's allocable share of our net taxable income decrease the unitholder's tax basis in the unitholder's common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if the unitholder sells such common units at a price greater than the unitholder's tax basis in those common units, even if the price received is less than the unitholder's original cost.  A substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture.  In addition, because the amount realized may include a unitholder's share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of the cash received from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investments in our common units by tax-exempt entities, such as individual retirement accounts ("IRAs") or other retirement plans, and non-U.S. persons raise issues unique to them.  For example, virtually all of our income allocated to unitholders who are organizations exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them.  Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. A unitholder that is a tax-exempt entity or a non-U.S. person should consult a tax advisor before investing in our common units.

We treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased.  The IRS may challenge this treatment, which could adversely affect the value of our common units.

Because we cannot match transferors and transferees of common units, we adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations.  A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a common unitholder.  It also could affect the timing of these tax benefits or the amount of gain from a sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the unitholder's tax returns.

Our common unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of an investment in our common units.

In addition to federal income taxes, our common unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes imposed by the various jurisdictions in which we do business or own property even if the unitholder does not live in any of those jurisdictions.  Our common unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions.  Further, our unitholders may be subject to penalties for failure to comply with those requirements.  We currently own property or conduct business in many states, most of which impose an income tax on individuals, corporations and other entities.  As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal or corporate income tax.  It is the responsibility of each unitholder to file its own federal, state and local tax returns, as applicable.

The sale or exchange of 50% or more of the total interests in our capital and profits within any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have technically terminated our existing partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period.  For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once.  Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which could result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if certain relief were unavailable, as described below) for one fiscal year and could result in the deferral of depreciation deductions allowable in computing our taxable income.  In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in the unitholder's taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new partnership for tax purposes.  If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.  The IRS has announced a relief procedure whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to each unitholder for the year notwithstanding two partnership tax years.

A unitholder whose common units are loaned to a "short seller" to cover a short sale of common units may be considered as having disposed of those common units.  If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because a common unitholder whose common units are loaned to a "short seller" to cover a short sale of common units may be considered as having disposed of the loaned units, the unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition.  Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income.  Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

We have adopted certain valuation methodologies in determining a unitholder's allocations of income, gain, loss and deduction.  The IRS may challenge these methods or the resulting allocations and such a challenge could adversely affect the value of our common units.

In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our respective assets.  Although we may from time to time consult with professional appraisers regarding valuation matters, we make fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our respective assets.  The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

A successful IRS challenge to these methods or allocations could adversely affect the amount, character, and timing of taxable income or loss being allocated to our unitholders.  It also could affect the amount of gain from our unitholders' sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.

Item 1B.  Unresolved SEC Staff Comments .

None.

Item 3.  Legal Proceedings .

As part of our normal business activities, we may be named as defendants in legal proceedings, including those arising from regulatory and environmental matters.  Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully indemnify us against losses arising from future legal proceedings.  We will vigorously defend the partnership in litigation matters.  Except as set forth below, we are not aware of any material pending legal proceedings as of the filing date of this annual report to which we are a party, other than routine litigation incidental to our business.

ETP Matter

In connection with a proposed pipeline project, we and Energy Transfer Partners, L.P. ("ETP") signed a non-binding letter of intent in April 2011 that disclaimed any partnership or joint venture related to such project absent executed definitive documents and board approvals of the respective companies.  Definitive agreements were never executed and board approval was never obtained for the potential pipeline project.  In August 2011, the proposed pipeline project was cancelled due to a lack of customer support.

In September 2011, ETP filed suit against us and a third party in connection with the cancelled project alleging, among other things, that we and ETP had formed a "partnership."  The case was tried in the District Court of Dallas County, Texas, 298th Judicial District.  While we firmly believe, and argued during our defense, that no agreement was ever executed forming a legal joint venture or partnership between the parties, the jury found that the actions of the two companies, nevertheless, constituted a legal partnership.  As a result, the jury found that ETP was wrongfully excluded from a subsequent pipeline project involving a third party, and awarded ETP $319.4 million in actual damages on March 4, 2014.  On July 29, 2014, the court entered judgment against us in an aggregate amount of $535.8 million, which includes (i) $319.4 million as the amount of actual damages awarded by the jury, (ii) an additional $150.0 million in disgorgement for the alleged benefit we received due to a breach of fiduciary duties by us against ETP and (iii) prejudgment interest in the amount of $66.4 million.  The court also awarded post-judgment interest on such aggregate amount, to accrue at a rate of 5%, compounded annually.

We do not believe that the verdict or the judgment entered against us is supported by the evidence or the law.  We filed our Brief of the Appellant in the Court of Appeals for the Fifth District of Dallas, Texas on March 30, 2015 and ETP filed its Brief of Appellees on June 29, 2015.  We filed our Reply Brief of Appellant on September 18, 2015.  Oral argument was conducted on April 20, 2016, and the case has now been submitted to the Court of Appeals for its consideration.  We intend to vigorously oppose the judgment through the appeals process.  As of December 31, 2016, we have not recorded a provision for this matter as management believes payment of damages in this case is not probable.

PDH Litigation

In July 2013, we executed a contract with Foster Wheeler USA Corporation ("Foster Wheeler") pursuant to which Foster Wheeler was to serve as the general contractor responsible for the engineering, procurement, construction and installation of our PDH facility.  In November 2014, Foster Wheeler was acquired by an affiliate of AMEC plc to form Amec Foster Wheeler plc, and Foster Wheeler is now known as Amec Foster Wheeler USA Corporation ("AFW").  In December 2015, Enterprise and AFW entered into a transition services agreement under which AFW was partially terminated from the PDH project.  In December 2015, Enterprise engaged a second contractor, Optimized Process Designs LLC ("OPD"), to complete the construction and installation of the PDH facility.

On September 2, 2016, we terminated AFW for cause and filed a lawsuit in the 151st Judicial Civil District Court of Harris County, Texas against AFW and its parent company, Amec Foster Wheeler plc, asserting claims for breach of contract, breach of warranty, fraudulent inducement, string-along fraud, gross negligence, professional negligence, negligent misrepresentation and attorneys' fees.  We intend to diligently prosecute these claims and seek all direct, consequential, and exemplary damages to which we may be entitled.

Environmental Matters

On occasion, we are assessed monetary sanctions by governmental authorities related to administrative or judicial proceedings involving environmental matters.  We do not expect such expenditures to be material to our consolidated financial statements .

Item 4. Mine Safety Disclosures .

Not applicable.

PART II

Item 5.  Market for Registrant's Common Equity, Related Unitholder Matters

and Issuer Purchases of Equity Securities .

Our common units are listed on the NYSE under the ticker symbol "EPD."  As of January 31, 2017, there were approximately 3,030 unitholders of record of our common units.  The following table presents high and low sales prices for our common units for the periods presented (as reported by the NYSE Composite ticker tape) and the amount, record date and payment date of the quarterly cash distributions we paid on each of our common units with respect to such periods.

Actual cash distributions are paid by us within 45 days after the end of each fiscal quarter.  We expect that our cash distributions will be funded primarily through cash provided by operating activities.  Although the payment of cash distributions is not guaranteed, we believe that our operations will continue to generate cash sufficient to pay distributions in the foreseeable future at levels comparable to those presented in the preceding table.

For additional information regarding our cash distributions to partners, see Note 9 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Recent Issuance of Unregistered Securities

On November 8, 2016, we agreed to issue 44,000 common units to an unaffiliated third party in a private placement exempt from the registration requirements of the Securities Act of 1933, as amended (pursuant to Section 4(a)(2) thereof), in exchange for the contribution, assignment, transfer and conveyance of all counterparty rights and interests under a commission agreement between such third party and one of our subsidiaries.  The agreement pursuant to which we issued these common units contained customary representations, warranties and covenants, including the certification of facts relating to the availability of the exemption described above.

Other than as described above, there were no sales of unregistered equity securities during 2016.

Common Units Authorized for Issuance Under Equity Compensation Plan

See "Securities Authorized for Issuance Under Equity Compensation Plans" included under Part III, Item 12 of this annual report, which is incorporated by reference into this Item 5.

Issuer Purchases of Equity Securities

A total of 2,995,957 unit-based awards (restricted common unit and phantom unit awards granted to key employees of EPCO) vested and were converted to common units during 2016.  Of this amount, 409,764 were sold back to us by employees to meet their tax withholding requirements in connection with the vesting of restricted common unit awards.   In addition, 590,855 were sold back to us by employees to meet their tax withholding requirements in connection with the vesting of phantom unit awards.  The total cost of these repurchased units was $ 23.2 million.  We cancelled such treasury units immediately upon acquisition.

The following table summarizes our repurchase activity during 2016 in connection with these vesting transactions:

In December 1998, we announced a common unit repurchase program whereby we, together with certain affiliates, could repurchase up to 4,000,000 of our common units on the open market.  A total of 2,763,200 common units were repurchased under this program; however, no repurchases have been made since 2002.  As of December 31, 2016, we and our affiliates could repurchase up to 1,236,800 additional common units under this program.

Item 6.  Selected Financial Data .

The following table presents selected historical consolidated financial data of our partnership.  This information has been derived from and should be read in conjunction with our audited financial statements included under Part II, Item 8 of this annual report, which presents our audited balance sheets as of December 31, 2016 and 2015 and related statements of consolidated operations, comprehensive income, cash flows and equity for the three years ended December 31, 2016, 2015 and 2014, respectively.  As presented in the table, amounts are in millions (except per unit data).

Fluctuations in our consolidated revenues and cost of sales amounts are explained in large part by changes in energy commodity prices.  Energy commodity prices fluctuate for a variety of reasons, including supply and demand imbalances and geopolitical tensions.  For additional information regarding energy commodity prices, see "Selected Energy Commodity Price Data" included under Part II, Item 7 of this annual report.  General information regarding our results of operations can be found under Part II, Item 7 of this annual report.

Property, plant and equipment balances increased in each of the years presented due to our ongoing capital expenditure program, which includes business combinations such as EFS Midstream and Oiltanking.   For information regarding our capital spending program, see "Capital Spending" included under Part II, Item 7 of this annual report.   For information regarding our acquisition of EFS Midstream in 2015 and Oiltanking in 2014, see Note 12 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Investments in unconsolidated affiliates decreased in 2015 primarily due to the sale of our Offshore Business, which included a number of pipeline and platform joint ventures operating in the Gulf of Mexico.   See Note 5 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for additional information regarding the sale of this business.

Our debt balances, including related interest expense, increased in each of the years presented primarily due to the funding of a portion of our capital spending program using borrowings under bank credit agreements and the issuance of short- and long-term notes.   For information regarding our debt balances, see Note 8 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Our equity balances, along with the number of common units outstanding, increased in each of the years presented due to the issuance of units in connection with business combinations and the sale of units under our at-the-market program, distribution reinvestment plan and employee unit purchase plan.   Net proceeds generated from the sale of common units were primarily used to fund a portion of our capital spending program.

Item 7.  Management's Discussion and Analysis of Financial Condition and Results of Operations .

For the Years Ended December 31, 2016, 2015 and 2014

The following information should be read in conjunction with our Consolidated Financial Statements and accompanying notes included under Part II, Item 8 of this annual report.  Our financial statements have been prepared in accordance with generally accepted accounting principles ("GAAP") in the United States ("U.S.").

Key References Used in this Management's Discussion and Analysis

Unless the context requires otherwise, references to "we," "us," "our," "Enterprise" or "Enterprise Products Partners" are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries.  References to "EPO" mean Enterprise Products Operating LLC, which is a wholly owned subsidiary of Enterprise, and its consolidated subsidiaries, through which Enterprise Products Partners L.P. conducts its business.  Enterprise is managed by its general partner, Enterprise Products Holdings LLC ("Enterprise GP"), which is a wholly owned subsidiary of Dan Duncan LLC, a privately held Texas limited liability company.

The membership interests of Dan Duncan LLC are owned by a voting trust, the current trustees ("DD LLC Trustees") of which are: (i) Randa Duncan Williams, who is also a director and Chairman of the Board of Directors (the "Board") of Enterprise GP; (ii) Richard H. Bachmann, who is also a director and Vice Chairman of the Board of Enterprise GP; and (iii) Dr. Ralph S. Cunningham.  Ms. Duncan Williams and Mr. Bachmann also currently serve as managers of Dan Duncan LLC along with W. Randall Fowler, who is also a director and President of Enterprise GP.

References to "EPCO" mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates.  A majority of the outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees ("EPCO Trustees") of which are:  (i) Ms. Duncan Williams, who serves as Chairman of EPCO; (ii) Dr. Cunningham, who serves as Vice Chairman of EPCO; and (iii) Mr. Bachmann, who serves as the President and Chief Executive Officer of EPCO.  Ms. Duncan Williams and Mr. Bachmann also currently serve as directors of EPCO along with Mr. Fowler, who is also the Executive Vice President and Chief Administrative Officer of EPCO. EPCO, together with its privately held affiliates, owned approximately 32% of our limited partner interests at December 31, 2016.

References to "Oiltanking" and "Oiltanking GP" mean Oiltanking Partners, L.P. and OTLP GP, LLC, the general partner of Oiltanking, respectively.  In October 2014, we acquired approximately 65.9% of the limited partner interests of Oiltanking, all of the member interests of Oiltanking GP and the incentive distribution rights ("IDRs") held by Oiltanking GP from Oiltanking Holding Americas, Inc. ("OTA") as the first step of a two-step acquisition of Oiltanking.  In February 2015, we completed the second step of this transaction consisting of the acquisition of the noncontrolling interests in Oiltanking.

As generally used in the energy industry and in this annual report, the acronyms below have the following meanings:

Cautionary Statement Regarding Forward-Looking Information

This annual report on Form 10-K for the year ended December 31, 2016 (our "annual report") contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us.  When used in this document, words such as "anticipate," "project," "expect," "plan," "seek," "goal," "estimate," "forecast," "intend," "could," "should," "would," "will," "believe," "may," "potential" and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements.  Although we and our general partner believe that our expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct.  Forward-looking statements are subject to a variety of risks, uncertainties and assumptions as described in more detail under Part I, Item 1A of this annual report.  If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected.  You should not put undue reliance on any forward-looking statements.  The forward-looking statements in this annual report speak only as of the date hereof.  Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.

Overview of Business

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 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.  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.

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. ("Genesis").  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.

As a result of our acquisition of the member interests of EFS Midstream LLC ("EFS Midstream") effective July 1, 2015, we began consolidating the financial statements of EFS Midstream as of that date.

Significant Recent Developments

Plans to Construct Isobutane Dehydrogenation Unit at Mont Belvieu

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 to produce 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 propane dehydrogenation ("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 for export.

Completion of Ethane Export Terminal on the Houston Ship Channel

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, and the terminal loaded its first vessel bound for Europe with 265,000 barrels of ethane.  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 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.  By providing producers with access to the export market, the Morgan's Point Ethane Export Terminal is also facilitating continued development of U.S. energy reserves.

Start-Up of Delaware Basin Gas Processing Plant

In August 2016, construction of our joint venture-owned Delaware Basin cryogenic natural gas processing plant (referred to as the "Waha" plant) was completed, and the facility was placed into service.  The Waha plant, the construction of which is supported by long-term contracts, has a natural gas processing capacity of 150 MMcf/d and is able to extract in excess of 22 MBPD of NGLs.  The plant is located in Reeves County, Texas and was designed to accommodate the growing production of NGL-rich natural gas from the Delaware Basin.  We own a 50% equity interest in the joint venture that owns the Waha plant, which we operate.

In conjunction with the completion of the construction of the Waha plant, we completed construction of an 82-mile, 12-inch diameter pipeline that connects the Waha plant to our Chaparral Pipeline system, which transports mixed NGLs from natural gas processing plants in West Texas and New Mexico to our NGL fractionation and storage complex in Mont Belvieu, Texas.  Our Texas Intrastate System provides transportation services for natural gas processed at the Waha plant.

Addition of Propylene Export Capability at our Houston Ship Channel terminal

In July 2016, we initiated polymer grade propylene ("PGP") loading services at our Enterprise Hydrocarbons Terminal ("EHT," formerly known as our "Houston Ship Channel LPG export terminal"), which is located on the Houston Ship Channel.  We are expecting an increase in the number of PGP export cargoes in response to international demand.  We now have the capability to load 5,000 metric tons per day of refrigerated PGP at the EHT dock facilities, which are directly supplied by propylene fractionators and storage wells at our Mont Belvieu, Texas complex.

Final Payment for EFS Midstream Acquisition

In July 2015, we purchased EFS Midstream from affiliates of Pioneer Natural Resources Company ("PXD") and Reliance Industries Limited ("Reliance") for approximately $2.1 billion, which was payable in two installments.  The initial payment of $1.1 billion was paid at closing on July 8, 2015.  The second and final installment of $1.0 billion was paid on July 11, 2016 using a combination of cash on hand and proceeds from the issuance of short-term notes under EPO's commercial paper program.

Expansion of Delaware Basin Network with New 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.  The project is anchored by long-term commitments from a major producer.

Start-Up of South Eddy Natural Gas Processing Plant

In May 2016, we announced that our new cryogenic natural gas processing plant located in Eddy County, New Mexico (the "South Eddy" plant) had been placed into service.  We constructed the South Eddy plant to serve producers in the Delaware Basin region.  The South Eddy plant has a nameplate 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 to supply the new plant.

In addition to the South Eddy plant and its related natural gas gathering infrastructure, we also completed a 71-mile extension of our Mid-America Pipeline System.  This extension provides producers in the Delaware Basin with NGL takeaway capacity and direct access to our integrated network of NGL assets.

General Outlook for 2017

Commercial Outlook

General Commodity Price Observations

As a result of significant advances in non-conventional drilling and production technology, North American reserves and production of hydrocarbons, primarily from shale resource basins such as the Eagle Ford in South Texas, the Permian Basin in West Texas and the Appalachia Basin in the Northeast U.S., increased substantially in recent years.   The increase in U.S. hydrocarbon supplies led to a reduction in imports of crude oil, NGLs, refined products and natural gas into the U.S.  Conversely, this trend has resulted in significant increases in hydrocarbon exports from the U.S., particularly of refined products and LPGs.  In light of weaker global economic growth (especially in Europe and China) and in the face of increasing production from North America and certain countries in the Middle East and Africa, global production and inventories of hydrocarbons (particularly crude oil and refined products) began to exceed demand in 2014.

In response to the growing supplies, beginning in November 2014, the Organization of Petroleum Exporting Countries ("OPEC"), opted to defend its market share by maintaining (and in some cases increasing) its crude oil production levels rather than cutting production to balance global markets.  The result was a dramatic decline in global crude oil prices from an average of $93 per barrel in 2014, to $49 per barrel in 2015 and further to $43 per barrel in 2016, as measured by the price of West Texas Intermediate ("WTI"). Prices reached a low of approximately $26 per barrel in February 2016, but have since recovered to over $50 per barrel beginning in December 2016 and into early 2017.

Likewise, as a result of excess domestic supplies and a warm winter in 2015-2016, natural gas prices have also experienced significant weakness in recent years.  As measured at Henry Hub, natural gas prices declined from an average of $4.43 per MMBtu in 2014, to $2.67 per MMBtu in 2015 and further to $2.46 per MMBtu in 2016.   Natural gas prices at Henry Hub fell to a low of $1.64 per MMBtu in March 2016, but have since rebounded to approximately $3.00 per MMBtu in February 2017.  In response to lower energy commodity prices, domestic producers significantly reduced both their drilling and completion activities in most production basins starting in early 2015. As a result of reduced drilling, domestic crude oil production at the end of 2016 was 840 MBPD lower than at its peak in June 2015; however, production of natural gas and NGLs has been relatively stable during this volatile price environment.

While market sentiment on crude oil prices had generally been negative since the winter of 2014, OPEC members discussed an output "freeze" in September 2016 to try to balance the market and reduce excess crude oil inventories.  These discussions caused crude oil prices to stabilize and start increasing.  In November 2016, OPEC members formally agreed to production cuts, starting January 1, 2017, that will be in effect until at least the next OPEC meeting scheduled in May 2017. In addition to OPEC members, certain non-OPEC producers such as Russia agreed to participate in the production cuts, which has further strengthened crude oil and related energy commodity prices.  In addition to the OPEC-led production cuts, many industry experts expect that strong consumer demand for energy and related products due to the lower prices (combined with routine supply disruptions) will accelerate rebalancing of the global oil market, with daily demand exceeding supply as early as the second half of 2017. With the announced cuts and positive supply and demand trends, the forward markets and most industry experts currently forecast that WTI will trade in the $50 to $60 per barrel range between now and 2020.

Supply Side Observations

Due to lower global energy commodity prices, plans for longer lead time, capital intensive projects continue to be delayed (or in some instances cancelled) by exploration and production companies ("E&P") as they continue to shift their focus to shorter lead time and less risky projects. We believe that projects in U.S. shale resource basins exhibit this low risk, short lead time production profile, and that U.S. shale resources will continue to play an increasing role in both domestic and global markets.  The ongoing impact of U.S. shale production is evident globally as both OPEC members and non-OPEC producers such as Russia adjust their national budgets to deal with the new realities of lower revenues from energy exports and heightened competition from non-conventional resources in the U.S. and Canada.  Many energy economists also believe that outside of some limited excess production capacity within OPEC, U.S. shale production is now the world's swing crude oil supply.

Since this energy cycle began, the effects of lower energy prices have been widespread throughout the energy industry resulting in lower investment to drill and complete wells, personnel layoffs and a total of 240 E&P, oilfield service and midstream companies filing for bankruptcy.  To preserve capital, certain E&P companies deferred well completions known as drilled but uncompleted wells ("DUCs").  Also during this period, oilfield service and E&P companies developed better technologies to drill and complete non-conventional wells more efficiently.  Some of these improvements include reductions in days to drill wells, longer horizontal laterals, and fracturing formations at higher pressures.  Improved technology has enabled E&P companies to realize higher returns on capital from developing non-conventional resources at lower energy prices.

While changes in drilling rig counts (as reported by Baker Hughes) have historically been a reliable leading indicator of future production growth or decline, recent developments in technology, high grading of drilling locations and the large inventory of DUCs have reduced the correlation between changes in rig counts and changes in production.  We believe this to be especially true when comparing current rig counts to those prior to 2015.  Rig counts continue, however, to be a good indicator of overall E&P activity and investment.

U.S. E&P company sentiment has improved over the last few months and indications are that their production budgets for 2017 reflect increased activity when compared to the lows experienced in 2016.  Since May 2016, total U.S. drilling rig counts have increased over 330 rigs, or 83%, to 741 rigs as of February 2017. The crude oil rig count increased by 275 to 591 rigs, an increase of approximately 87% from the low in May 2016.   Likewise, the natural gas rig count increased by 68 rigs, or approximately 84%, from the low in August 2016.  Not all regions have reacted equally to the recovery in rig counts.

Permian outlook

The Permian Basin in West Texas and southeastern New Mexico has experienced the largest increase in drilling activity, with the number of active rigs increasing to 301 in February 2017 from 134 in April 2016. The Permian Basin is an oil prone basin with many attributes, including stacked pay zones, light sweet crude and a long history of support for the oil and gas industry.  The current level of producer activity provides support for the construction of incremental midstream infrastructure in the basin.  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.  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) in the Delaware Basin.   In addition, we are developing a major crude oil pipeline system, the Midland-to-ECHO Pipeline System, that would serve producers in the Permian Basin and originate at our Midland, Texas crude oil terminal and extend to our Sealy terminal and on to our ECHO terminal near Houston, Texas.  We are also evaluating several other natural gas and crude oil projects in the Permian Basin.

Eagle Ford outlook

Rig counts in the Eagle Ford shale region have been significantly impacted by the downturn in oil prices. While the number of active drilling rigs in the Eagle Ford shale has increased by 29 rigs, or 103%, to 57 rigs in February 2017 from the low recorded in May 2016, we do not believe this level of activity is high enough to offset natural production declines in the region. The historical peak for Eagle Ford crude oil and natural gas production occurred in March 2015 and was 1.6 million barrels per day and 6.0 Bcf/d, respectively.  The most recent data for Eagle Ford production was 1.0 million barrels per day of crude oil and 4.9 Bcf/d of natural gas.  Until volumes for the Eagle Ford return to near historical peak production, there is excess capacity of midstream infrastructure available in the region.  We still believe that the Eagle Ford offers producers some of the best returns on capital of any region in the country and is also favorably situated near growing consumption and export markets on the U.S. Gulf Coast. We also believe that a significant amount of production and acreage in the Eagle Ford could change ownership in the near future and that such a change in ownership would be supportive of an increase in rig activity and production.

Haynesville outlook

The rig count in the Haynesville shale region has increased recently as ownership of large parcels of producing acreage has changed hands.  The rig count for February 2017 is 30, which represents a 19 rig increase from the low of 11 rigs recorded in February 2016. Drilling in the Haynesville has benefitted from technological advances, which have improved natural gas recoveries per well and resulted in better returns on capital.  With natural gas futures prices currently at approximately $3.00 per MMBtu, we believe Haynesville natural gas production has reached its low point, and that volumes will begin to gradually increase in 2017.  Haynesville production peaked in November 2011 at approximately 7.8 Bcf/d and is currently 3.9 Bcf/d. Until Haynesville volumes return to near historical peak production, there is excess capacity of midstream infrastructure available in the region.

Rockies outlook

Rig counts have increased in both the Piceance basin and the Jonah and Pinedale fields, although rig counts are still at depressed levels.  Drilling activity in the Piceance basin increased from 2 rigs in May 2016 to 5 rigs in February 2017, and in the Jonah and Pinedale fields increased from a combined 4 rigs in November 2016 to 8 rigs in February 2017.  Furthermore, drilling activity in the San Juan basin declined from 2 rigs in November 2015 to 1 rig in February 2017.  Current rig counts in these producing regions will not be enough to offset natural production declines; however, since the natural gas produced from these areas is often rich in NGL content, the recent increase in NGL prices may spur increased drilling activity in these regions. In addition, drilling economics in these regions should benefit as enhanced completion technologies now being employed in the Gulf Coast and Midcontinent areas become more widespread in the Western Rockies, thus increasing returns on incremental capital invested. The Rockies benefit from adequate natural gas and NGL pipeline infrastructure, resulting in favorable netback prices, which help the region compete with other North American plays where takeaway capacity may be constrained.  Like in other areas, higher energy prices could encourage changes in ownership by producers, which could also improve rig counts.

As a result of higher energy commodity prices in the past few months and continued positive sentiment towards price stability, we expect an increase in producer investment and drilling activity in and around our assets in the Permian, Eagle Ford, Haynesville and Rockies regions.   Furthermore, we expect that our assets in these areas are going to be very competitive in supplying services for the resulting new production. We also believe that basins located closest to prime markets on the U.S. Gulf Coast will be preferred by producers due to more favorable economics as compared to other more distant areas (mostly due to lower transportation costs).

Demand Side Observations

Overall demand for petroleum products continues to increase at rates that have generally exceeded economists' expectations.  We believe the U.S. is very well situated to meet growing global petroleum demand. With the recent improvement in crude oil prices, the U.S Energy Information Administration reports that U.S. crude oil production has started to increase.  As U.S. crude oil production recovers, we expect that some of these new domestic barrels will supplant more of the country's crude oil imports.  We also expect U.S. refineries to operate at higher utilization rates as a result of strong U.S. motor fuels demand and growing global demand.  In addition, as U.S. crude oil supplies increase, we also expect crude oil exports to grow, with likely markets being Central and South America, Asia and Western Europe where the lighter U.S. crudes make good feedstocks for their refining facilities.

In December 2015, the U.S. government lifted its ban on exporting domestically produced crude oil.  We believe that this should be beneficial to the domestic energy industry in general and to Enterprise in particular.  Our marine terminal assets and related infrastructure are strategically located on the U.S. Gulf Coast.  These assets could benefit from concurrent imports and exports of various grades of crude oil as (i) refineries optimize their crude oil input slate, (ii) trading companies import and export different grades of crude oil depending on global and regional supply-demand factors, and (iii) producers optimize their production depending on market price signals. With significant crude oil export capabilities at Freeport, Texas City, on the Houston Ship Channel and at Beaumont, Texas, lifting of the export ban should have a beneficial impact on our crude oil pipeline, storage and marine terminal assets (without any significant capital expenditure).  However, this outlook could be muted if there is a prolonged decline in domestic crude oil drilling and production, or if overseas crude markets become oversupplied for an extended period and thus discounted from a price standpoint when compared to the U.S. Gulf Coast.

Furthermore, as several new world scale ethylene plants begin operations in the U.S. through the early 2020s, we expect growing domestic demand for ethane, which could in turn drive upstream NGL production increases supported by producer investment and higher rig counts.  We also expect that global demand for heavier NGLs (butanes and natural gasoline) will continue to increase supported by rising global economic activity.  With respect to natural gas demand, we expect it to continue to increase in the form of U.S. power generation demand, growing industrial demand, exports to Mexico and as liquefied natural gas, or LNG.  We believe U.S. producers can provide ample supplies of natural gas at very competitive prices to meet growing global demand.

In recent years, U.S. natural gas and NGLs developed a feedstock price advantage over more costly crude oil derivatives (such as naphtha and Gasoil).  In general, we expect this trend to continue due to: (i) competitive domestic production from low risk, short lead time shale resource plays; (ii) the ability of U.S. producers and their suppliers to harness technology to keep costs down; (iii) anticipated long-term increases in demand for crude oil by developing economies; and (iv) ongoing geopolitical risks and poor rule of law in many areas of the world that are major exporters of crude oil, which may cause unexpected disruptions, and crude oil price increases.  These advantages lend themselves to a variety of long-term demand-side opportunities, including higher demand from the U.S. petrochemical industry and increased exports of various hydrocarbons (e.g., LNG, LPG, ethane and crude oil).

We also believe the trend in the feedstock price advantage of domestically-produced NGLs and their abundance has led to a long-term fundamental change in feedstock selection by the U.S. petrochemical industry, which is the largest consumer of domestic NGLs.  In order to capitalize on this cost advantage, U.S. petrochemical companies have maximized their consumption of domestic NGLs.  Many of these companies are investing billions of dollars to construct world-scale ethylene plants on the Gulf Coast that are designed to consume NGLs (particularly ethane) as feedstock.  U.S. ethylene production capacity is expected to increase by over 40% over the next 3 years.  Below is a list of ethylene plants under construction that are scheduled to begin operations over the next few years based on publicly available information.

Additionally, several other petrochemical companies have announced significant expansions and/or conversions at existing facilities that will use ethane as a feedstock.  Almost all of these ethylene plants and the ethylene industry's major expansions are in close proximity to our existing or planned assets, including our recently completed Aegis Ethane Pipeline.

Based on industry publications, domestic production of ethylene in 2015 and 2016 averaged 155 million pounds per day compared to an average of 145 million pounds per day for the five-year period ending in 2014.  Ethane is the most widely used feedstock by the U.S. petrochemical industry in the production of ethylene. As a result, ethane consumption by domestic petrochemical companies has, at times, been in excess of 1.2 MMBPD.  We believe the U.S. ethylene industry could consume approximately 200 MBPD of additional ethane feedstocks over the next few years through modifications, debottlenecking and expansions at existing facilities.  In addition, we believe that publicly announced new petrochemical plant construction projects, including those noted in the preceding table could consume well over 700 MBPD of additional ethane feedstocks when completed.  However, until these new ethylene plants are completed, ethane production capacity continues to exceed demand, resulting in significant volumes of ethane not being extracted from the natural gas stream by producers and natural gas processors in an effort to balance ethane supply with demand.

We also expect exports of domestically produced ethane will increase in the coming years.  Our Morgan's Point Ethane Export Terminal, which we placed into service in September 2016, supports growing international demand for abundant U.S. ethane from shale plays and offers the global petrochemical industry a low-cost feedstock option and supply diversification.   The Morgan's Point Ethane Export Terminal, which is located on the Houston Ship Channel and 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 and is integrated with our Mont Belvieu NGL fractionation and storage complex.

U.S. exports of fully refrigerated LPG continue to increase as a result of ample domestic production, increased export capacity and competitive, transparent pricing when compared to international markets. Overall, U.S. propane waterborne exports increased from approximately 423 MBPD in 2014 to approximately 875 MBPD in 2016.  Markets in Asia and Central and South America have been the major sources of new demand for U.S. LPG exports; however, growing volumes are also being transported to Northwest Europe.  LPG exports from the U.S. Gulf Coast to Central and South America are expected to increase in the future as these economies continue to grow.  Furthermore, we expect that increased volumes of Gulf Coast-sourced LPGs will be exported in the coming years to Asian markets due to faster growth of these economies and the widening of the Panama Canal, which was completed in 2016.  In anticipation of the aforementioned growth in LPG exports, we completed the final phase of the expansion of our LPG export terminal located on the Houston Ship Channel at EHT in December 2015.  This expansion increased our loading rate for LPG at the terminal to approximately 27,500 barrels per hour (nameplate capacity).

Lastly, we believe that natural gas prices will stabilize at around $3.00/MMBtu as U.S. supply and demand fundamentals for this commodity become more balanced through exports and incremental demand from industrial customers and for power generation.  Supply basins with dry natural gas, such as the Haynesville/Bossier, Barnett, Fayetteville, Piceance and Jonah/Pinedale shales, could experience an increase in drilling activity due to their low development costs.  The Haynesville resource basin is an excellent example of a dry gas production area that we believe could experience a substantial increase in drilling activity since it is ideally located to serve future demand from LNG exports and industrial customers on the U.S. Gulf Coast.

Summary

While this period of very low prices has been very difficult for producers, the lower energy commodity prices have led to an increase in energy consumption by individual consumers, particularly for motor fuels, and by energy intensive industries (e.g., steel manufacturing and petrochemicals) as lower energy and feedstock costs reduce the operating costs for such businesses and in some instances make them more competitive globally.  We believe that an increase in demand for crude oil, natural gas and NGLs from these types of industries, along with other positive consumer-driven demand responses to lower energy prices, will continue to balance crude oil supply and demand fundamentals to the extent that current excess inventories begin to decline in 2017.  Regardless of such market dynamics, almost all of the major assets we have under construction or have recently completed, whether supply or demand oriented, are supported by long-term fee-based commitments from producers, shippers and/or end-use customers.  We also believe that as a result of the price downturn which has slowed and/or caused many higher-risk, long-lead time projects to be cancelled, U.S. unconventional resources have gained substantial long-term significance worldwide.

Liquidity Outlook

Results of Operations

The following table summarizes the key components of our results of operations for the years indicated (dollars in millions):

The following table presents each business segment's contribution to consolidated revenues (net of eliminations) for the years indicated (dollars in millions):

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. The following table presents our consolidated revenues from Vitol by business segment for the year ended December 31, 2016 (dollars in millions):

The following table presents selected index prices for natural gas, crude oil and selected NGL and petrochemical products for the periods indicated: