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PRODUCTS PARTNERS L P : Management's Discussion and Analysis of Financial Condition and Results of Operations. (form 10-K)

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02/24/2017 | 05:07pm CET

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:


    /d    = per day                       MMBbls = million barrels

BBtus = billion British thermal units MMBPD = million barrels per day

    Bcf   = billion cubic feet            MMBtus = million British thermal 

units

    BPD   = barrels per day               MMcf   = million cubic feet

MBPD = thousand barrels per day TBtus = trillion British thermal units

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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.
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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.
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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.

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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.
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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.
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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.
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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.

                                               Ethylene    Potential    Estimated
                                              Production     Ethane     Completion
                  Company                      Capacity   Consumption      Date
                                               (Billion
                                               lbs/yr)       (MBPD)
Occidental Chemical/Mexichem                     1.2           33          2017
Chevron Phillips Chemical                        3.3           90          2017
ExxonMobil Chemical                              3.3           90          2017
Dow Chemical                                     3.3           90          2017
Indorama                                         1.1           30          2017
Shintech                                         1.1           30          2018
Sasol                                            3.3           90          2018
Formosa Plastics                                 3.5           95          2019
Axiall/Lotte                                     2.2           60          2019
Total Petrochemicals & Refining                  2.2           60          2019
Shell                                            3.5           95      Early 2020s
Total                                            28.0         763


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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.
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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

Debt and equity capital markets for the energy sector were turbulent throughout
2016 as continued volatility and weakness in commodity prices created market
uncertainty.  This has generally impacted both the cost of capital and access to
debt and equity capital markets.  While there were challenges in the capital
markets during 2016, we were able to access both the debt and equity capital
markets to support our growth and balance sheet objectives at acceptable costs.
At December 31, 2016, we had $3.78 billion of consolidated liquidity, which was
comprised of $3.72 billion of available borrowing capacity under EPO's revolving
credit facilities and $63.1 million of unrestricted cash on hand.  Based on
current market conditions (as of the filing date of this annual report), we
believe we will have sufficient liquidity, cash flow from operations, access to
capital markets and access to bank capital to fund our capital expenditures and
working capital needs for the reasonably foreseeable future.

We have $800 million in principal amount of senior notes maturing in September
2017.  We expect to refinance this series of senior notes obligation at or near
to its maturity.  Our next maturing series of senior notes are due in April and
May of 2018 in the aggregate principal amount of $1.1 billion.

The U.S. government is expected to continue to run substantial annual budget
deficits in the coming years that will require a corresponding issuance of debt
by the U.S. Treasury.  The interest rate on U.S. Treasury debt has a direct
impact on the cost of our debt.  At this time, we are uncertain what impact the
expected large issuances of U.S. Treasury debt and the prevailing economic and
capital market conditions during these future periods will have on the cost and
availability of capital.  To that end, we have entered into $275 million of
notional forward-starting interest rate swaps to hedge a portion of our expected
future debt issuances in connection with the refinancing of debt in 2018.  We
continue to monitor and evaluate the condition of the capital markets and our
interest rate risk with respect to funding our capital spending program and
refinancing upcoming maturities.
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Results of Operations

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

                                                         For the Year Ended December 31,
                                                        2016           2015           2014
Revenues                                             $ 23,022.3     $ 27,027.9     $ 47,951.2
Costs and expenses:
Operating costs and expenses:
Cost of sales                                          15,710.9       19,612.9       40,464.1
Other operating costs and expenses                      2,425.6        2,449.4        2,541.8
Depreciation, amortization and accretion expenses       1,456.7        1,428.2        1,282.7
Net losses (gains) attributable to asset sales and
insurance recoveries                                       (2.5 )         15.6         (102.1 )
Asset impairment and related charges                       52.8          162.6           34.0
Total operating costs and expenses                     19,643.5       23,668.7       44,220.5
General and administrative costs                          160.1          192.6          214.5
Total costs and expenses                               19,803.6       23,861.3       44,435.0
Equity in income of unconsolidated affiliates             362.0          373.6          259.5
Operating income                                        3,580.7        3,540.2        3,775.7
Interest expense                                         (982.6 )       (961.8 )       (921.0 )
Change in fair market value of Liquidity Option
Agreement                                                 (24.5 )        (25.4 )           --
Other, net                                                  2.8            2.9            1.9
Benefit from (provision for) income taxes                 (23.4 )          2.5          (23.1 )
Net income                                              2,553.0        2,558.4        2,833.5
Net income attributable to noncontrolling
interests                                                 (39.9 )        

(37.2 ) (46.1 ) Net income attributable to limited partners $ 2,513.1 $ 2,521.2 $ 2,787.4




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

                                                     For the Year Ended December 31,
                                                    2016           2015           2014
NGL Pipelines & Services:
Sales of NGLs and related products               $  8,380.5     $  8,044.8     $ 15,460.1
Midstream services                                  1,862.0        1,743.2        1,629.7
Total                                              10,242.5        9,788.0       17,089.8

Crude Oil Pipelines & Services:

  Sales of crude oil                                5,802.5        9,732.9       19,783.9
  Midstream services                                  712.5          573.0          400.4
    Total                                           6,515.0       10,305.9       20,184.3

Natural Gas Pipelines & Services:

  Sales of natural gas                              1,591.9        1,722.6        3,181.7
  Midstream services                                  951.1        1,020.7        1,022.1
    Total                                           2,543.0        2,743.3        4,203.8

Petrochemical & Refined Products Services:

  Sales of petrochemicals and refined products      2,921.9        3,333.5        5,575.5
  Midstream services                                  799.9          778.4          741.0
    Total                                           3,721.8        4,111.9        6,316.5
Offshore Pipelines & Services:
Sales of natural gas                                     --             --            0.3
Sales of crude oil                                       --            3.2            8.6
Midstream services                                       --           75.6          147.9
Total                                                    --           78.8          156.8
Total consolidated revenues                      $ 23,022.3     $ 27,027.9     $ 47,951.2


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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):

NGL Pipelines & Services                    $ 1,830.1
Crude Oil Pipelines & Services                  171.9
Natural Gas Pipelines & Services                  7.8

Petrochemical & Refined Products Services 270.3 Total

                                       $ 2,280.1



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

                                                                                                                                                                Refinery
                       Natural                                                   Normal                                    Natural                                Grade               WTI                LLS
                        Gas,             Ethane,           Propane,              Butane,             Isobutane,           Gasoline,            PGP,            Propylene,          Crude Oil,         Crude Oil,
                       $/MMBtu          $/gallon           $/gallon             $/gallon              $/gallon            $/gallon            $/pound            $/pound            $/barrel           $/barrel
                         (1)               (2)               (2)                   (2)                   (2)                 (2)                (3)                (3)                (4)                (4)

2014 Averages        $      4.43       $      0.27       $       1.04       $            1.22       $        1.25       $        1.98       $      0.71

$ 0.57 $ 93.01 $ 96.75

2015 by quarter:

   1st Quarter       $      2.99       $      0.19       $       0.53       $            0.68       $        0.68       $        1.10       $      0.50       $        0.37       $      48.63       $      52.83
   2nd Quarter       $      2.65       $      0.18       $       0.46       $            0.59       $        0.60       $        1.26       $      0.42       $        0.29       $      57.94       $      62.97
   3rd Quarter       $      2.77       $      0.19       $       0.40       $            0.55       $        0.55       $        0.98       $      0.33       $        0.21       $      46.43       $      50.17
   4th Quarter       $      2.27       $      0.18       $       0.42       $            0.60       $        0.61       $        0.97       $      0.31

$ 0.18 $ 42.18 $ 43.54 2015 Averages $ 2.67 $ 0.18 $ 0.45 $

            0.61       $        0.61       $        1.08       $      0.39 

$ 0.26 $ 48.80 $ 52.38

2016 by quarter:

   1st Quarter       $      2.09       $      0.16       $       0.38       $            0.53       $        0.53       $        0.76       $      0.31       $        0.18       $      33.45       $      35.11
   2nd Quarter       $      1.95       $      0.20       $       0.49       $            0.62       $        0.63       $        0.96       $      0.33       $        0.19       $      45.59       $      47.35
   3rd Quarter       $      2.81       $      0.19       $       0.47       $            0.63       $        0.67       $        0.98       $      0.38       $        0.24       $      44.94       $      46.52
   4th Quarter       $      2.98       $      0.24       $       0.58       $            0.83       $        0.90       $        1.08       $      0.36

$ 0.24 $ 49.29 $ 50.53 2016 Averages $ 2.46 $ 0.20 $ 0.48 $

            0.65       $        0.68       $        0.94       $      0.34 

$ 0.21 $ 43.32 $ 44.88


(1)  Natural gas prices are based on Henry-Hub Inside FERC commercial index prices as reported by Platts, which is a division of McGraw Hill Financial, Inc.
(2)  NGL prices for ethane, propane, normal butane, isobutane and natural gasoline are based on Mont Belvieu Non-TET commercial index prices as reported by Oil Price Information Service.
(3)  PGP prices represent average contract pricing for such product as reported by IHS Chemical, a division of IHS Inc. ("IHS Chemical"). Refinery grade propylene prices represent weighted-average spot prices
for such product as reported by IHS Chemical.
(4)  Crude oil prices are based on commercial index prices for WTI as measured on the New York Mercantile Exchange ("NYMEX") and for LLS as reported by Platts.



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.  Crude oil, natural gas and NGL prices
have been depressed since the fourth quarter of 2014 primarily due to an
oversupply of these commodities on world markets.  The weighted-average
indicative market price for NGLs was $0.50 per gallon in 2016 versus $0.49 per
gallon in 2015 and $0.97 per gallon in 2014.

A decrease in our consolidated marketing revenues due to lower energy commodity
sales prices may not result in a decrease in gross operating margin or cash
available for distribution, since our consolidated cost of sales amounts would
also be lower due to comparable decreases in the purchase prices of the
underlying energy commodities.  The same correlation would be true in the case
of higher energy commodity sales prices and purchase costs.
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We attempt to mitigate commodity price exposure through our hedging activities
as well as through converting keepwhole and similar contracts to fee-based
arrangements.  See Note 14 of the Notes to Consolidated Financial Statements
included under Part II, Item 8 of this annual report for information regarding
our commodity hedging activities.


Consolidated Income Statement Highlights

The following information highlights significant changes in our comparative income statement amounts and the primary drivers of such changes.

Comparison of 2016 with 2015

Revenues

Total revenues for 2016 decreased $4.01 billion when compared to total revenues
for 2015.  Revenues from the marketing of crude oil decreased $3.93 billion
year-to-year due to lower sales volumes and prices, which accounted for a $2.77
billion decrease and a $1.16 billion decrease, respectively.  Revenues from the
marketing of natural gas, petrochemicals, refined products and octane additives
decreased a net $513.8 million year-to-year primarily due to lower sales prices,
which accounted for a $760.0 million decrease, partially offset by a $246.2
million increase due to higher sales volumes.  Revenues from the marketing of
NGLs increased a net $335.7 million year-to-year primarily due to higher sales
volumes, which accounted for a $956.2 million increase, partially offset by a
$620.5 million decrease due to lower sales prices.

Revenues from midstream services increased a net $134.6 million year-to-year
primarily due to the ongoing expansion of our operations.  Revenues increased
$144.5 million year-to-year from the assets we acquired in the EFS Midstream
acquisition in July 2015.  Revenues from midstream services decreased $76.0
million year-to-year due to the sale of our Offshore Business in July 2015. 

The

remaining $66.1 million year-to-year increase in revenues from midstream services is primarily due to contractual increases in committed volumes on pipeline assets, such as ATEX and the Aegis Ethane Pipeline ("Aegis"), and the expansion of storage capacity at our terminal assets on the Gulf Coast.


Operating costs and expenses
Total operating costs and expenses for 2016 decreased $4.03 billion when
compared to total operating costs and expenses for 2015.  The cost of sales
associated with our marketing of crude oil decreased $3.69 billion year-to-year
due to lower sales volumes and prices, which accounted for a $2.53 billion
decrease and a $1.16 billion decrease, respectively.  The cost of sales
associated with our marketing of natural gas, petrochemicals, refined products
and octane additives decreased a net $416.1 million year-to-year primarily due
to lower purchase prices, which accounted for a $666.1 million decrease,
partially offset by a $250.0 million increase due to higher sales volumes.  The
cost of sales associated with our marketing of NGLs increased a net $206.5
million year-to-year primarily due to higher sales volumes, which accounted for
a $754.2 million increase, partially offset by lower purchase prices, which
accounted for a $547.7 million decrease.

Other operating costs and expenses decreased a net $23.8 million year-to-year primarily due to lower maintenance expenses during 2016 when compared to 2015.


Depreciation, amortization and accretion expense in operating costs and expenses
for 2016 increased a net $28.5 million when compared to 2015.  A $112.8 million
year-to-year increase primarily due to assets we recently constructed and placed
into service or acquired was partially offset by an $84.3 million decrease
attributable to the sale of our Offshore Business.
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Operating costs and expenses also include $52.8 million and $162.6 million of
non-cash asset impairment and related charges for the years ended December 31,
2016 and 2015, respectively.  Non-cash asset impairment charges for 2016
primarily relate to the planned abandonment of plant and pipeline assets in
Texas and New Mexico.  Related charges for 2016 include a $7.1 million non-cash
write-off for assets damaged in a fire at our Pascagoula, Mississippi natural
gas processing facility in June 2016.  In 2015, we recorded a $54.8 million
asset impairment charge in connection with our sale of the Offshore Business.
The remainder of our non-cash asset impairment charges for 2015 primarily relate
to natural gas processing assets in southern Louisiana, certain marine vessels
and the abandonment of certain crude oil and natural gas pipeline assets in
Texas.

General and administrative costs
General and administrative costs for 2016 decreased $32.5 million when compared
to 2015 primarily due to lower costs for employee compensation and professional
services.  General and administrative costs for 2016 include $0.7 million of
non-cash asset impairment charges.

Equity in income of unconsolidated affiliates
Equity income from our unconsolidated affiliates for 2016 decreased a net $11.6
million when compared to 2015.  Results for 2015 reflect $46.6 million of equity
earnings attributable to the Offshore Business sold in July 2015.  This
year-to-year decrease was partially offset by a net $30.5 million increase in
earnings from our investments in crude oil pipelines, which benefited from the
settlement of a rate case by Seaway during 2016.

Operating income
Operating income for 2016 increased $40.5 million when compared to 2015 due to
the previously described year-to-year changes in revenues, operating costs and
expenses, general and administrative costs and equity in income of
unconsolidated affiliates.

Interest expense
Interest expense for 2016 increased $20.8 million when compared to 2015. The
following table presents the components of our consolidated interest expense for
the years indicated (dollars in millions):

                                                                 For the Year Ended
                                                                    December 31,
                                                                 2016          2015
Interest charged on debt principal outstanding                 $ 1,088.9    

$ 1,063.4 Impact of interest rate hedging program, including related amortization

                                                        30.5    

15.4

Interest cost capitalized in connection with construction
projects (1)                                                      (168.2 )      (149.1 )
Other (2)                                                           31.4          32.1
Total                                                          $   982.6     $   961.8

(1)  We capitalize interest costs incurred on funds used to construct property, plant
and equipment while the asset is in its construction phase. Capitalized interest
amounts become part of the historical cost of an asset and are charged to earnings (as
a component of depreciation expense) on a straight line basis over the estimated
useful life of the asset once the asset enters its intended service. When capitalized
interest is recorded, it reduces interest expense from what it would be otherwise.
Capitalized interest amounts fluctuate based on the timing of when projects are placed
into service, our capital spending levels and the interest rates charged on
borrowings.
(2)  Primarily reflects facility commitment fees charged in connection with our
revolving credit facilities and amortization of debt issuance costs.



Interest charged on debt principal outstanding, which is the primary driver of
interest expense, increased a net $25.5 million year-to-year primarily due to
increased debt principal amounts outstanding during 2016, which accounted for a
$54.8 million increase, partially offset by the effect of lower overall interest
rates in 2016, which accounted for a $29.3 million decrease.  Our
weighted-average debt principal balance for 2016 was $23.41 billion compared to
$22.24 billion for 2015.  In general, our debt principal balances have increased
over time due to the partial debt financing of our capital spending program.
For a discussion of our consolidated debt obligations and capital spending
program, see "Liquidity and Capital Resources" and "Capital Spending" within
this Part II, Item 7 of this annual report.
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Change in fair market value of Liquidity Option Agreement
We recognized a decrease of $0.9 million of aggregate non-cash expense
attributable to accretion and changes in management estimates regarding inputs
to the valuation model for the Liquidity Option Agreement.  For information
regarding the Liquidity Option Agreement, see Note 17 of the Notes to
Consolidated Financial Statements included under Part II, Item 8 of this annual
report.

Income taxes
Income taxes primarily reflects our state tax obligations under the Revised
Texas Franchise Tax ("Texas Margin Tax").  Our provision for income taxes for
2016 increased $25.9 million when compared to 2015 primarily due to an increase
in accruals for the Texas Margin Tax.  In June 2015, the State of Texas lowered
the tax rate under the Texas Margin Tax, which resulted in an income tax benefit
for us in 2015.

Noncontrolling interests
Net income attributable to noncontrolling interests increased a net $2.7 million
in 2016 when compared to 2015.  A $7.8 million year-to-year decrease in net
income attributable to the noncontrolling interests in Oiltanking for the period
January 1, 2015 to February 13, 2015, which is the date we completed the
Oiltanking acquisition, was more than offset by a net $10.5 million year-to-year
increase attributable to our majority owned consolidated subsidiaries.

Comparison of 2015 with 2014

Revenues

Total revenues for 2015 decreased $20.92 billion when compared to total revenues
for 2014.  Revenues from the marketing of crude oil and natural gas decreased
$11.52 billion year-to-year primarily due to lower sales prices, which accounted
for a $10.43 billion decrease, and lower sales volumes, which accounted for an
additional $1.09 billion decrease.  Revenues from the marketing of NGLs and
refined products decreased a net $8.13 billion year-to-year primarily due to
lower sales prices, which accounted for an $8.81 billion decrease, partially
offset by higher sales volumes, which accounted for a $680.8 million increase.
Revenues from the marketing of petrochemicals, octane additives and high purity
isobutylene ("HPIB") decreased $1.49 billion year-to-year attributable to lower
sales prices.

Revenues from midstream services increased a net $249.8 million year-to-year
primarily due to the ongoing expansion of our operations.  Revenues increased
$163.4 million year-to-year due to the timing of our acquisition of Oiltanking.
Revenues for 2015 also include $117.8 million from assets we acquired in
connection with the EFS Midstream acquisition.  Revenues decreased $72.6 million
year-to-year primarily due to the sale of our Offshore Business in July 2015.
The remaining $41.2 million year-to-year increase in revenues is primarily due
to the timing of completion of various capital projects, including portions of
Aegis and expanded crude oil storage capacity at our ECHO terminal.

Operating costs and expenses
Total operating costs and expenses for 2015 decreased $20.55 billion when
compared to total operating costs and expenses for 2014.  The cost of sales
associated with our marketing of crude oil and natural gas decreased $11.05
billion year-to-year primarily due to lower purchase prices, which accounted for
a $10.02 billion decrease, and lower sales volumes, which accounted for an
additional $1.03 billion decrease.  The cost of sales associated with our
marketing of NGLs and refined products decreased a net $8.13 billion
year-to-year primarily due to lower purchase prices, which accounted for an
$8.78 billion decrease, partially offset by higher sales volumes, which
accounted for a $651.3 million increase.  The cost of sales associated with our
marketing of petrochemicals, octane additives and HPIB decreased $1.64 billion
year-to-year attributable to lower purchase prices.

Other operating costs and expenses decreased a net $92.4 million year-to-year
due in part to (i) lower fuel costs, which accounted for a $73.9 million
decrease, (ii) a producer settlement involving our San Juan Gathering System in
2014, which accounted for an $18.0 million decrease and (iii) the sale of our
Offshore Business in July 2015, which primarily accounted for an additional
$25.2 million year-to-year decrease. These decreases were partially offset by
the addition of $49.3 million in operating costs attributable to the timing of
the Oiltanking acquisition and assets we acquired in the EFS Midstream
acquisition.
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Depreciation, amortization and accretion expenses in operating costs and
expenses for 2015 increased $145.5 million when compared to 2014 primarily due
to the Oiltanking and EFS Midstream acquisitions, which collectively accounted
for $115.7 million of the year-to-year increase.  Accretion expense for 2015
includes $39.5 million recognized for certain asset retirement obligations of
our former Offshore Business. For information regarding our asset retirement
obligations, see Note 5 of the Notes to Consolidated Financial Statements
included under Part II, Item 8 of this annual report.

We recorded net losses within operating costs and expenses of $15.6 million
attributable to asset sales and insurance recoveries in 2015 compared to net
gains of $102.1 million in 2014.  In 2015, we recognized a $12.3 million loss
attributable to our sale of the Offshore Business.  In 2014, we recognized $95.0
million of gains attributable to the receipt of nonrefundable cash insurance
proceeds. These proceeds were attributable to property damage claims we filed in
connection with the February 2011 NGL release and fire at the West Storage
location of our Mont Belvieu, Texas underground storage facility.

Operating costs and expenses also include $162.6 million and $34.0 million of
non-cash asset impairment charges for 2015 and 2014, respectively.  In 2015, we
recorded a $54.8 million non-cash asset impairment charge  in connection with
the sale of our Offshore Business.  The remainder of our non-cash asset
impairment charges for 2015 primarily relate to natural gas processing assets in
southern Louisiana, certain marine vessels and the abandonment of certain crude
oil and natural gas pipeline assets in Texas.

General and administrative costs
General and administrative costs for 2015 decreased $21.9 million when compared
to 2014 primarily due to lower employee compensation costs, which accounted for
a $14.8 million decrease.  In addition, general and administrative costs for
2014 included $3.8 million of transaction costs associated with Step 1 of the
Oiltanking acquisition and $4.7 million of expense for the settlement of
litigation associated with our merger in 2010 with Enterprise GP Holdings L.P.

Equity in income of unconsolidated affiliates Equity income from our unconsolidated affiliates for 2015 increased $114.1 million when compared to 2014 primarily due to increased earnings from our investments in crude oil and NGL pipeline joint ventures.


Operating income
Operating income for 2015 decreased $235.5 million when compared to 2014 due to
the previously described year-to-year changes in revenues, operating costs and
expenses, general and administrative costs and equity in income of
unconsolidated affiliates.

Interest expense
Interest expense for 2015 increased $40.8 million when compared to 2014. The
following table presents the components of our consolidated interest expense for
the years indicated (dollars in millions):

                                                                  For the Year Ended
                                                                     December 31,
                                                                  2015           2014
Interest charged on debt principal outstanding                 $   1,063.4  

$ 969.1 Impact of interest rate hedging program, including related amortization

                                                          15.4  

9.4

Interest cost capitalized in connection with construction
projects                                                            (149.1 )       (77.9 )
Other                                                                 32.1          20.4
Total                                                          $     961.8     $   921.0



Interest charged on debt principal outstanding, which is the primary driver of
interest expense, increased a net $94.3 million year-to-year primarily due to
increased debt principal amounts outstanding during 2015, which accounted for a
$157.6 million increase, partially offset by the effect of lower overall
interest rates in 2015, which accounted for a $63.3 million decrease.  Our
weighted-average debt principal balance for 2015 was $22.24 billion compared to
$18.96 billion during 2014.  In general, our debt principal balances have
increased over time due to the partial debt financing of our capital spending
program.
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Change in fair market value of Liquidity Option Agreement Results for 2015 include $25.4 million of non-cash expense we recorded to recognize changes in the fair market value of the Liquidity Option Agreement.


Income taxes
We recognized an overall income tax benefit of $2.5 million for 2015 compared to
a provision for income taxes of $23.1 million for 2014. In June 2015, the State
of Texas enacted certain changes to the Texas Margin Tax, which lowered our tax
rate.

Noncontrolling interests
Net income attributable to noncontrolling interests decreased $8.9 million in
2015 when compared to 2014 primarily due to the inclusion of noncontrolling
interests in Oiltanking from October 1, 2014 to February 13, 2015, which is the
date we completed the Oiltanking acquisition.

Business Segment Highlights


We evaluate segment performance based on our financial measure of gross
operating margin.  Gross operating margin is an important performance measure of
the core profitability of our operations and forms the basis of our internal
financial reporting.  We believe that investors benefit from having access to
the same financial measures that our management uses in evaluating segment
results.

The following table presents gross operating margin by segment and non-GAAP
total gross operating margin for the periods indicated (dollars in millions):

                                                                      For the Year Ended December 31,
                                                           2016                2015                      2014
Gross operating margin by segment:
NGL Pipelines & Services                                 $ 2,990.6         $     2,771.6             $     2,877.7
Crude Oil Pipelines & Services                               854.6                 961.9                     762.5
Natural Gas Pipelines & Services                             734.9                 782.6                     803.3
Petrochemical & Refined Products Services                    650.6                 718.5                     681.0
Offshore Pipelines & Services                                   --                  97.5                     162.0
Total segment gross operating margin (1)                   5,230.7               5,332.1                   5,286.5
Net adjustment for shipper make-up rights                     17.1                   7.1                     (81.7 )
Total gross operating margin (non-GAAP)                  $ 5,247.8         $     5,339.2             $     5,204.8

(1) Within the context of this table, total segment gross operating margin represents a subtotal and corresponds
to measures similarly titled within our business segment disclosures found under Note 10 of the Notes to
Consolidated Financial Statements included under Part II, Item 8 of this annual report.



Total gross operating margin includes equity in the earnings of unconsolidated
affiliates, but is exclusive of other income and expense transactions, income
taxes, the cumulative effect of changes in accounting principles and
extraordinary charges.  Total gross operating margin is presented on a 100%
basis before any allocation of earnings to noncontrolling interests.

Gross operating margin by segment for NGL Pipelines & Services and Crude Oil
Pipelines & Services reflect adjustments for shipper make-up rights that are
included in management's evaluation of segment results.  However, these
adjustments are excluded from non-GAAP total gross operating margin.
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The GAAP financial measure most directly comparable to total gross operating
margin is operating income.  For a discussion of operating income and its
components, see the previous section titled "Consolidated Income Statement
Highlights" within this Item 7.  The following table presents a reconciliation
of operating income to total gross operating margin for the periods indicated
(dollars in millions):

                                                         For the Year Ended December 31,
                                                        2016            2015          2014
Operating income (GAAP)                              $   3,580.7      $

3,540.2 $ 3,775.7 Adjustments to reconcile operating income to total gross operating margin:

  Add depreciation, amortization and accretion
expense                                                  1,456.7        

1,428.2 1,282.7

  Add asset impairment and related charges in
operating costs and expenses                                52.8          

162.6 34.0

  Add net losses and subtract net gains
attributable to asset sales and insurance
recoveries                                                  (2.5 )         

15.6 (102.1 )

  Add general and administrative costs                     160.1          192.6         214.5
Total gross operating margin (non-GAAP)              $   5,247.8      $ 

5,339.2 $ 5,204.8




Each of our business segments benefits from the supporting role of our 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 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.

The following information highlights significant changes in our year-to-year
segment results (i.e., our gross operating margin by segment amounts) and the
primary drivers of such changes.  The volume statistics presented in the tabular
information for each segment are reported on a net basis, taking into account
our ownership interests in certain joint ventures, and reflect the periods in
which we owned an interest in such operations.  These statistics reflect volumes
for newly constructed assets from the dates such assets were placed into
service.

NGL Pipelines & Services
The following table presents segment gross operating margin and selected
volumetric data for the NGL Pipelines & Services segment for the years indicated
(dollars in millions, volumes as noted):

                                                            For the Year 

Ended December 31,

                                                           2016             2015          2014
Segment gross operating margin:
Natural gas processing and related NGL marketing
activities                                            $        846.6      $   895.0     $ 1,162.0
NGL pipelines, storage and terminals                         1,625.4        1,380.9       1,145.7
NGL fractionation                                              518.6          495.7         570.0
Total                                                 $      2,990.6      $ 2,771.6     $ 2,877.7
Selected volumetric data:
NGL pipeline transportation volumes (MBPD)                     2,965          2,700         2,634
NGL marine terminal volumes (MBPD)                               436            302           258
NGL fractionation volumes (MBPD)                                 828            826           824
Equity NGL production (MBPD) (1)                                 141            133           116
Fee-based natural gas processing (MMcf/d) (2)                  4,736        

4,905 4,786


(1)  Represents the NGL volumes we earn and take title to in connection with our processing
activities.
(2)  Volumes reported correspond to the revenue streams earned by our gas plants.


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Natural gas processing and related NGL marketing activities

Comparison of 2016 with 2015. Gross operating margin from natural gas processing and related NGL marketing activities for 2016 decreased $48.4 million when compared to 2015.


Gross operating margin from our natural gas processing plants decreased $123.0
million year-to-year.  Collectively, gross operating margin from our Meeker,
Pioneer and Chaco plants decreased $53.8 million year-to-year primarily due to
lower processing margins, including the impact of our related hedging
activities.  Gross operating margin from our South Texas plants decreased $49.8
million year-to-year attributable to lower average processing fees and margins,
which accounted for a combined $38.1 million decrease, and lower fee-based
processing volumes of 227 MMcf/d, which accounted for a $15.8 million decrease.
Gross operating margin from our natural gas processing plants in Louisiana and
Mississippi decreased a combined $21.6 million year-to-year primarily due to
lower processing margins, which accounted for a $6.4 million decrease (including
the impact of related hedging activities), and higher operating expenses.
Operating expenses at these plants increased $12.1 million year-to-year, which
includes $10.4 million of costs attributable to a fire that occurred at our
Pascagoula facility in June 2016.  The Pascagoula facility was repaired and
placed back into commercial service in December 2016.

Gross operating margin from our NGL marketing activities increased a net $74.6
million year-to-year primarily due to higher sales volumes, which accounted for
a $261.3 million increase, partially offset by a $186.7 million decrease due to
lower sales margins. Results from NGL marketing's export-oriented strategies
increased $119.2 million year-to-year, which was partially offset by a $44.6
million net decrease in gross operating margin from NGL marketing's activities
in support of our transportation, storage and plant assets.

Comparison of 2015 with 2014. Gross operating margin from natural gas processing and related NGL marketing activities for 2015 decreased $267.0 million when compared to 2014.


Gross operating margin from our natural gas processing plants decreased $243.0
million year-to-year primarily due to lower processing margins.  In addition,
gross operating margin from our NGL marketing activities for 2015 decreased a
net $24.0 million when compared to 2014 primarily due to lower sales margins,
which accounted for a $167.4 million decrease, partially offset by a $152.0
million increase due to higher sales volumes.  Results from NGL marketing's
activities in support of our transportation, storage and plant assets decreased
$37.6 million year-to-year, which was partially offset by a $13.6 million
increase in gross operating margin from NGL marketing's export-oriented
strategies.

NGL pipelines, storage and terminals


Comparison of 2016 with 2015.  Gross operating margin from NGL pipelines,
storage and terminal assets for 2016 increased $244.5 million when compared to
2015.  On a combined basis, gross operating margin from ATEX and Aegis increased
$117.9 million year-to-year primarily due to a 123 MBPD increase in
transportation volumes.  Contracted volume commitments continue to ramp higher
through 2018 for ATEX and 2019 for Aegis.  The third and final segment of Aegis
was completed in December 2015.

Gross operating margin from EHT and a related pipeline increased $99.5 million
year-to-year, primarily due to higher marine terminal and pipeline
transportation volumes of 122 MBPD and 113 MBPD, respectively. Gross operating
margin from our NGL and related product storage complex in Mont Belvieu, Texas
increased $26.1 million year-to-year primarily due to higher fees.

Gross operating margin from our Mid-America Pipeline System, Seminole Pipeline and related terminals increased $10.7 million year-to-year primarily due to lower operating expenses. Gross operating margin from our South Texas NGL Pipeline System increased $9.3 million year-to-year primarily due to higher transportation fees, which escalated in January 2016.


Gross operating margin from our Morgan's Point Ethane Export Terminal, which was
placed into commercial service in September 2016, was a loss of $16.2 million
primarily due to commissioning costs. The new terminal is expected to become
profitable in 2017 as contractual customer volume commitments increase.
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Comparison of 2015 with 2014.  Gross operating margin from NGL pipelines,
storage and terminal assets for 2015 increased $235.2 million when compared to
2014.  Gross operating margin from the Chaparral Pipeline, Mid-America Pipeline
System, Seminole Pipeline and related terminals increased $63.2 million in 2015
when compared to 2014.  Higher transportation tariffs and other fees, which
accounted for a $66.2 million year-to-year increase in gross operating margin,
and a $41.1 million year-to-year decrease in operating expenses were partially
offset by a $44.1 million decrease in gross operating margin attributable to
lower transportation volumes.  Transportation volumes on these three pipelines
for 2015 decreased a combined 76 MBPD due in part to lower recoveries of ethane
when compared to 2014.  Lower recoveries of ethane at upstream natural gas
processing plants served by these pipelines resulted in lower volumes of ethane
available for transportation.

Gross operating margin from our investments in the Front Range Pipeline, Texas
Express Pipeline and Texas Express Gathering System for 2015 increased $17.8
million primarily due to a combined 28 MBPD increase in transportation volumes
(net to our interest) when compared to 2014.  Gross operating margin from ATEX
and Aegis increased $18.6 million year-to-year primarily due to a combined 37
MBPD increase in transportation volumes.  Gross operating margin from our South
Texas NGL Pipeline System increased $26.5 million year-to-year primarily due to
higher transportation volumes of 39 MBPD.  Lastly, gross operating margin from
our NGL pipelines and related storage assets increased $14.1 million
year-to-year as a result of net operational measurement losses during 2014 that
did not reoccur in 2015.

Gross operating margin from EHT and a related pipeline increased $78.6 million
year-to-year primarily due to (i) increased fee revenues of $41.9 million earned
in 2015 when compared to 2014 due to the timing of our acquisition of Oiltanking
and (ii) $36.7 million due to higher year-to-year marine terminal and pipeline
transportation volumes of 47 MBPD and 60 MBPD, respectively.  EHT continues to
earn margin sharing and other fees from our NGL marketing group as it did prior
to the Oiltanking acquisition in October 2014.  Prior to our acquisition of the
terminal, these fees were paid to Oiltanking.  Following the acquisition, these
fees are charged to our NGL marketing group using intercompany agreements and
are reflected in gross operating margin; however, the intercompany amounts are
eliminated in the preparation of our consolidated financial statements.  With
respect to the $41.9 million year-to-year increase, gross operating margin from
this terminal for 2015 reflects a full year of these intercompany fees compared
to one quarter in 2014.

NGL fractionation

Comparison of 2016 with 2015.  Gross operating margin from NGL fractionation for
2016 increased $22.9 million when compared to 2015 primarily due to higher
fractionation revenues at our Mont Belvieu fractionators.  Fractionation
revenues at Mont Belvieu increased $25.6 million year-to-year primarily due to
higher fees, which accounted for a $13.2 million increase, and higher
fractionation volumes of 10 MBPD, which accounted for an additional $12.4
million increase.

Comparison of 2015 with 2014.  Gross operating margin from NGL fractionation for
2015 decreased $74.3 million when compared to 2014.  Gross operating margin from
our Mont Belvieu NGL fractionators decreased $62.8 million year-to-year
primarily due to lower product blending and other fee revenues as a result of
lower commodity prices in 2015.  Gross operating margin from our Norco NGL
fractionator in Louisiana decreased a net $6.0 million year-to-year primarily
due to lower revenues from product blending and percent-of-liquids contracts
attributable to lower energy commodity prices, which accounted for a $13.4
million year-to-year decrease, partially offset by an $8.9 million increase due
to higher fractionation volumes of 13 MBPD.  Gross operating margin from our
Hobbs NGL fractionator in Gaines County, Texas decreased $5.1 million
year-to-year primarily due to lower fractionation volumes of 8 MBPD.
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Crude Oil Pipelines & Services
The following table presents segment gross operating margin and selected
volumetric data for the Crude Oil Pipelines & Services segment for the years
indicated (dollars in millions, volumes as noted):

                                                           For the Year 

Ended December 31,

                                                        2016              2015           2014
Segment gross operating margin                       $     854.6       $     961.9     $   762.5
Selected volumetric data:
Crude oil pipeline transportation volumes (MBPD)           1,388             1,474         1,278
Crude oil marine terminal volumes (MBPD)                     495               557           691


Comparison of 2016 with 2015. Gross operating margin from our Crude Oil Pipelines & Services segment for 2016 decreased $107.3 million when compared to 2015.


Gross operating margin from our crude oil marketing and related trucking
activities decreased $187.5 million year-to-year primarily due to lower crude
oil sales margins, which accounted for a $147.1 million decrease, and $40.4
million of net non-cash mark-to-market losses recognized in 2016 on financial
instruments related to blending activities.  As a result of lower crude oil
prices, regional price spreads have been less than the transportation costs
incurred by our marketing business, particularly on its 75 MBPD of firm capacity
on the Seaway Pipeline (25 MBPD of this capacity terminates in June 2017).

Gross operating margin from our South Texas Crude Oil Pipeline System decreased
$95.0 million year-to-year primarily due to a 74 MBPD decrease in volumes, which
accounted for a $66.6 million decrease, and a $32.4 million decrease due to
lower average transportation fees.  The decrease in crude oil transportation
volumes is attributable to reduced producer drilling activity in the Eagle Ford
Shale.  Gross operating margin from our EFS Midstream system, which we acquired
effective July 1, 2015, increased $127.9 million year-to-year due to the timing
of the acquisition of these assets.  Gross operating margin for this system
reflects twelve months of ownership in 2016 versus six months in 2015.

Gross operating margin from crude oil terminaling services at our Beaumont Marine West and ECHO facilities increased a combined $33.9 million year-to-year primarily due to expansion projects.


Gross operating margin from our investment in Seaway for 2016 increased $14.2
million when compared to 2015 primarily due to the settlement of a rate case
with the Federal Energy Regulatory Commission ("FERC") in the first quarter of
2016.  In February 2016, the FERC issued its decision regarding the various
challenges to Seaway's committed and uncommitted rates in FERC Docket No.
IS12-226-000.  The FERC upheld the committed rates and rejected the claim that
the committed rates should be reduced to cost-based levels. The FERC's rulings
regarding the uncommitted rates were also largely favorable to Seaway.  Seaway
submitted a compliance filing in March 2016 calculating revised uncommitted
rates consistent with the FERC's order. The compliance filing was not challenged
and the FERC accepted the revised rates.  On a 100% basis, Seaway recorded a
$24.5 million benefit related to settlement of the rate case, with our 50% share
of the benefit equating to $12.3 million.

Comparison of 2015 with 2014. Gross operating margin from our Crude Oil Pipelines & Services segment for 2015 increased $199.4 million when compared to 2014.


Gross operating margin from providing crude oil terminaling services at EHT
increased $99.7 million year-to-year primarily due to the timing of the
Oiltanking acquisition (i.e., gross operating margin from these services for
2015 reflects a full year of operations versus one quarter for 2014).  The EFS
Midstream system contributed $91.1 million of gross operating margin to our 2015
results along with 65 MBPD of throughput volumes.  In addition, gross operating
margin from our ECHO terminal in Houston, Texas increased $11.8 million
year-to-year due to our completion of an expansion project at this facility
during 2015.
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Gross operating margin from our equity investment in the Seaway Pipeline
increased $76.1 million year-to-year primarily due to contributions from the
Seaway Loop, which began commercial operations in December 2014.  Seaway's
transportation volumes increased a net 97 MBPD year-to-year (net to our
interest) primarily due to an increase in long-haul volumes.  Gross operating
margin from our equity investment in the Eagle Ford Crude Oil Pipeline System
increased $18.5 million year-to-year primarily due to a 50 MBPD increase in
pipeline transportation volumes (net to our interest).  Gross operating margin
from our West Texas System increased $11.6 million year-to-year primarily due to
a 22 MBPD increase in pipeline transportation volumes during 2015.

Gross operating margin from our South Texas Crude Oil Pipeline System decreased
$56.5 million year-to-year primarily due to a $45.7 million decrease from the
sale of excess crude oil volumes obtained through pipeline tariff allowances and
a 15 MBPD decrease in volumes, which accounted for an additional $14.0 million
decrease.  The decrease in gross operating margin from the sale of excess crude
oil volumes by the pipeline was primarily due to lower crude oil prices
year-to-year.

Gross operating margin from our crude oil marketing and related trucking activities decreased $53.0 million year-to-year primarily due to lower crude oil sales margins.


Natural Gas Pipelines & Services
The following table presents segment gross operating margin and selected
volumetric data for the Natural Gas Pipelines & Services segment for the years
indicated (dollars in millions, volumes as noted):

                                                             For the Year 

Ended December 31,

                                                           2016              2015          2014
Segment gross operating margin                          $     734.9       $    782.6     $   803.3
Selected volumetric data:
Natural gas pipeline transportation volumes (BBtus/d)        11,874           12,321        12,476


Comparison of 2016 with 2015. Gross operating margin from our Natural Gas Pipelines & Services segment for 2016 decreased $47.7 million when compared to 2015.


Gross operating margin from our Acadian Gas System decreased $18.8 million
year-to-year primarily due to reduced transportation fees.  Gross operating
margin from our Texas Intrastate System decreased $16.8 million year-to-year
primarily due to lower revenues attributable to decreased producer drilling
activity in the Eagle Ford Shale and Barnett Shale.  Transportation volumes on
our Texas Intrastate System decreased 149 BBtus/d year-to-year.  Collectively,
gross operating margin for 2016 from our San Juan, Jonah, Piceance Basin and
Fairplay Gathering Systems decreased $18.4 million when compared to 2015, the
primarily driver of which is a combined 363 BBtus/d decrease in gathering
volumes.  Gross operating margin from our natural gas marketing activities
decreased a net $2.8 million year-to-year primarily due to mark-to-market losses
recorded in 2016 on financial instruments related to commodity hedging.

Gross operating margin from our Carlsbad Gathering System in West Texas and New
Mexico increased $13.0 million year-to-year primarily due to higher gathering
volumes of 97 BBtus/d.

Comparison of 2015 with 2014. Gross operating margin from our Natural Gas Pipelines & Services segment for 2015 decreased $20.7 million when compared to 2014.


Gross operating margin from our San Juan Gathering System decreased a net $19.2
million year-to-year primarily due to (i) a $19.7 million decrease in gathering
fees, which are indexed to natural gas prices, (ii) a $12.2 million decrease in
condensate sales primarily due to lower sales prices and (iii) a $3.1 million
decrease due to lower gathering volumes.  These decreases were partially offset
by an $18.0 million charge recorded in 2014 related to the settlement of a
contract dispute with a producer.  Gross operating margin from our Piceance
Basin and Haynesville Gathering Systems decreased $17.4 million year-to-year
primarily due to lower gathering volumes, which accounted for a $12.0 million
decrease, and lower gathering fees, which accounted for an additional $5.9
million decrease.  Producers served by these three gathering systems curtailed
their drilling programs during 2015 in response to the low price of natural
gas.  Collectively, natural gas transportation volumes for these three gathering
systems decreased 266 BBtus/d year-to-year.  Gross operating margin from our
Texas Intrastate System decreased $13.6 million year-to-year primarily due to an
increase in maintenance and other operating expenses.
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Gross operating margin from our Jonah Gathering System increased a net $20.4
million year-to-year primarily due to higher gathering fees, which accounted for
an $11.6 million increase and higher transportation volumes of 84 BBtus/d, which
accounted for an additional $8.4 million increase. Gross operating margin from
our Carlsbad Gathering System increased $6.4 million year-to-year primarily due
to higher gathering and other fees, which accounted for a $4.1 million increase,
and higher volumes of 47 BBtus/d, which accounted for a $3.5 million increase,
partially offset by a $2.1 million increase in maintenance and other expenses.
Lastly, gross operating margin from our Acadian Gas System increased $5.6
million year-to-year primarily due to lower operating expenses.

Petrochemical & Refined Products Services
The following table presents segment gross operating margin and selected
volumetric data for the Petrochemical & Refined Products Services segment for
the years indicated (dollars in millions, volumes as noted):

                                                           For the Year 

Ended December 31,

                                                        2016              2015           2014
Segment gross operating margin:
Propylene fractionation and related activities       $     212.1       $     189.5     $   227.4
Butane isomerization and related operations                 52.0              65.2          75.3
Octane enhancement and related plant operations             42.2             144.3         122.4
Refined products pipelines and related activities          305.6             258.8         186.7
Marine transportation and other                             38.7              60.7          69.2
Total                                                $     650.6       $     718.5     $   681.0

Selected volumetric data:
Propylene fractionation volumes (MBPD)                        73                71            75
Butane isomerization volumes (MBPD)                          108                96            93
Standalone DIB processing volumes (MBPD)                      89                79            82
Octane additive and related plant production
volumes (MBPD)                                                22                17            17

Pipeline transportation volumes, primarily refined products & petrochemicals (MBPD)

                             837               784           758
Refined products and petrochemical marine terminal
volumes (MBPD)                                               389               355           270


Propylene fractionation and related activities


Comparison of 2016 with 2015.  Gross operating margin from propylene
fractionation and related activities for 2016 increased $22.6 million when
compared to 2015.  Gross operating margin from our Mont Belvieu propylene
fractionation plants increased a net $37.1 million year-to-year. When compared
to results for 2015, these plants benefitted in 2016 from $29.6 million of lower
operating costs, $16.6 million of higher propylene fractionation and other fee
revenues, and a $13.1 million increase in gross operating margin attributable to
higher propylene fractionation volumes of 3 MBPD. The year-to-year decrease in
operating costs is attributable to major maintenance projects that were
completed in 2015.  Partially offsetting these benefits was a $22.2 million
year-to-year decrease in gross operating margin attributable to lower propylene
sales margins.

Pre-commissioning expenses associated with our PDH facility increased $15.5 million during 2016 when compared to 2015. We expect our PDH facility to commence commercial operations mid-2017.


Comparison of 2015 with 2014.  Gross operating margin from propylene
fractionation and related activities decreased $37.9 million for 2015 when
compared to 2014.  Gross operating margin from our Mont Belvieu propylene
fractionation plants decreased $46.4 million year-to-year.  This decrease was
primarily due to (i) a $28.3 million increase in operating expenses primarily
for major maintenance activities we completed during 2015, (ii) lower propylene
sales volumes, which accounted for a $5.0 million decrease, (iii) lower
propylene sales margins, which accounted for an additional $3.9 million
decrease, and (iv) a $9.2 million decrease primarily due to lower propylene
fractionation and other fees.  Gross operating margin from our propylene rail
terminal at Mont Belvieu increased $4.4 million for 2015 primarily due to higher
fees.  Gross operating margin from the remainder of our propylene fractionation
business increased $4.1 million for 2015 when compared to 2014 primarily due to
operational measurement losses in 2014 that did not reoccur in 2015.
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Isomerization and related operations


Comparison of 2016 with 2015.  Gross operating margin from butane isomerization
and deisobutanizer ("DIB") operations for 2016 decreased a net $13.2 million
when compared to 2015.  Operating expenses associated with our isomerization
facility in Mont Belvieu, Texas increased $22.4 million year-to-year primarily
due to major maintenance activities we completed during 2016.  Butane processing
revenues increased $7.8 million year-to-year primarily due to higher butane
isomerization and standalone DIB processing volumes of 12 MBPD and 10 MBPD,
respectively.

Comparison of 2015 with 2014.  Gross operating margin from our butane
isomerization and DIB operations for 2015 decreased $10.1 million when compared
to 2014.  By-product sales revenues decreased $30.7 million year-to-year
primarily due to lower sales prices and isomerization revenues decreased $8.1
million year-to-year primarily due to lower fees.  The decrease in revenues was
partially offset by lower maintenance and other operating expenses, which
declined $29.4 million year-to-year.

Octane enhancement and related operations

Comparison of 2016 with 2015. Gross operating margin from our octane enhancement facility and HPIB plant for 2016 decreased $102.1 million when compared to 2015. This year-to-year decrease in gross operating margin is primarily due to lower sales margins, including the results of our related hedging activities.

Comparison of 2015 with 2014. Gross operating margin from our octane enhancement facility and HPIB plant for 2015 increased $21.9 million when compared to 2014. The year-to-year increase in gross operating margin is primarily due to higher sales volumes during 2015 when compared to 2014.

Refined products pipelines and related activities


Comparison of 2016 with 2015.  Gross operating margin from refined products
pipelines and related marketing activities for 2016 increased $46.8 million when
compared to 2015.  Gross operating margin from our refined products terminals in
Beaumont, Texas increased $24.9 million year-to-year primarily due to expansions
and higher demand for storage and marine vessel loading services.

Gross operating margin for the TE Products Pipeline and related terminals increased $20.1 million year-to-year primarily due to higher volumes. Interstate refined products pipeline transportation volumes on our TE Products Pipeline increased 10 MBPD year-to-year. Intrastate refined products and petrochemical pipeline transportation volumes on our TE Products Pipeline increased a combined 40 MBPD year-to-year.


Comparison of 2015 with 2014.  Gross operating margin from our refined products
pipelines and related marketing activities for 2015 increased $72.1 million when
compared to 2014.  Gross operating margin from providing refined products and
petrochemical terminaling services at Beaumont and EHT increased $60.7 million
year-to-year primarily due to the timing of the Oiltanking acquisition, which
accounted for $45.1 million of the increase (i.e., gross operating margin from
the acquired assets for 2015 reflects a full year of operations versus one
quarter for 2014).

Gross operating margin from our TE Products Pipeline and related refined
products terminals increased $7.9 million year-to-year primarily due to higher
tariffs and other fees.  Overall, transportation volumes on the TE Products
Pipeline increased a net 30 MBPD year-to-year primarily due to higher refined
products and petrochemical transportation volumes.

Other


Gross operating margin from marine transportation and other activities for 2016
decreased $22.0 million when compared to 2015 primarily due to lower demand for
marine transportation services attributable to the lower commodity pricing
environment.
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Offshore Pipelines & Services
We sold our Offshore Business to Genesis on July 24, 2015.  The following table
presents segment gross operating margin and selected volumetric data for the
Offshore Pipelines & Services segment for the years indicated (dollars in
millions, volumes as noted).

                                                    For the Year
                                                 Ended December 31,
                                                 2015           2014
Segment gross operating margin                 $    97.5       $ 162.0
Selected volumetric data:
Natural gas transportation volumes (BBtus/d)         587           627
Crude oil transportation volumes (MBPD)              357           330
Platform natural gas processing (MMcf/d)             101           145
Platform crude oil processing (MBPD)                  13            14



Amounts presented for 2015 reflect results through the closing date of the sale, July 24, 2015.

Liquidity and Capital Resources


Based on current market conditions (as of the filing date of this annual
report), we believe we will have sufficient liquidity, cash flow from operations
and access to capital markets to fund our capital expenditures and working
capital needs for the reasonably foreseeable future.  At December 31, 2016, we
had $3.78 billion of consolidated liquidity, which was comprised of $3.72
billion of available borrowing capacity under EPO's revolving credit facilities
and $63.1 million of unrestricted cash on hand.

We expect to issue additional equity and debt securities to assist us in meeting our future funding and liquidity requirements, including those related to capital spending.


At December 31, 2016, the aggregate carrying value of our product inventories
was $1.77 billion compared to $1.04 billion at December 31, 2015.  Our
inventories, and associated working capital commitments, have increased
significantly since December 31, 2015 primarily due to our marketing groups
utilization of contango opportunities using our storage assets.  We expect to
gradually settle these inventory positions (valued at approximately $1.1
billion) through the first quarter of 2017, with a corresponding decrease in
working capital commitments and related debt.  For additional information
regarding our inventories, see Note 4 of the Notes to Consolidated Financial
Statements included under Part II, Item 8 of this annual report.

Consolidated Debt


The following table presents scheduled maturities of our consolidated debt
obligations outstanding at December 31, 2016 for the years indicated (dollars in
millions):

                                                         Scheduled Maturities of Debt
                  Total          2017          2018          2019          2020          2021        Thereafter
Commercial
Paper Notes     $  1,777.2     $ 1,777.2     $      --     $      --     $      --     $      --     $        --
Senior Notes      20,650.0         800.0       1,100.0       1,500.0       1,500.0         575.0        15,175.0
Junior
Subordinated
Notes              1,474.4            --            --            --            --            --         1,474.4
Total           $ 23,901.6     $ 2,577.2     $ 1,100.0     $ 1,500.0     $ 1,500.0     $   575.0     $  16,649.4


The following information describes significant transactions that affected our consolidated debt obligations during the year ended December 31, 2016:


Issuance of $1.25 Billion of Senior Notes in April 2016
In April 2016, EPO issued $575 million in principal amount of 2.85% senior notes
due April 2021 ("Senior Notes RR"), $575 million in principal amount of 3.95%
senior notes due February 2027 ("Senior Notes SS") and $100 million in principal
amount of 4.90% reopened senior notes due May 2046 ("Senior Notes QQ").  Senior
Notes RR, SS and QQ were issued at 99.898%, 99.760% and 95.516% of their
principal amounts, respectively.  EPO issued these senior notes using the 2013
Shelf (see "Universal shelf registration statement" below).
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Net proceeds from the issuance of these senior notes were used as follows: (i)
the repayment of amounts then outstanding under EPO's commercial paper program,
which included amounts we used to repay $750 million in principal amount of
Senior Notes AA that matured in February 2016, and (ii) for general company
purposes.

Enterprise Products Partners L.P. has unconditionally guaranteed these senior
notes on an unsecured and unsubordinated basis.  These senior notes rank equal
with EPO's existing and future unsecured and unsubordinated indebtedness and are
senior to any existing and future subordinated indebtedness of EPO.  These
senior notes are subject to make-whole redemption rights and were issued under
an indenture containing certain covenants, which generally restrict EPO's
ability (with certain exceptions) to incur debt secured by liens and engage in
sale and leaseback transactions.

Renewal of 364-Day Credit Agreement
In September 2016, EPO amended its 364-Day Credit Agreement to extend its
maturity date to September 2017.  There are currently no principal amounts
outstanding under this revolving credit agreement.  Under the terms of the
364-Day Credit Agreement, EPO may borrow up to $1.5 billion (which may be
increased by up to $200 million to $1.7 billion at EPO's election, provided
certain conditions are met) at a variable interest rate for a term of 364 days,
subject to the terms and conditions set forth therein.  To the extent that
principal amounts are outstanding at the maturity date, EPO may elect to have
the entire principal balance then outstanding continued as a non-revolving term
loan for a period of one additional year, payable in September 2018.  EPO's
obligations under the 364-Day Credit Agreement are not secured by any
collateral; however, they are guaranteed by Enterprise Products Partners L.P.

Issuance of Common Units
The following table summarizes the issuance of common units in connection with
our at-the-market ("ATM") program, distribution reinvestment plan ("DRIP") and
employee unit purchase plan ("EUPP") for the periods indicated (dollars in
millions, number of units issued as shown):

                                                           Number of       Net Cash
                                                            Common         Proceeds
                                                         Units Issued      Received
Year Ended December 31, 2014:

Common units issued in connection with ATM program 1,590,334 $ 57.7

Common units issued in connection with DRIP and EUPP 9,754,227

   331.1
  Total                                                     11,344,561     $   388.8

Year Ended December 31, 2015:

Common units issued in connection with ATM program 25,520,424 $ 817.4

Common units issued in connection with DRIP and EUPP 12,793,913

   371.2
  Total                                                     38,314,337     $ 1,188.6

Year Ended December 31, 2016:

Common units issued in connection with ATM program 87,867,037 $ 2,156.1

Common units issued in connection with DRIP and EUPP 16,316,534

   386.7
  Total                                                    104,183,571     $ 2,542.8



In January 2016, we sold an aggregate 3,830,256 common units under the ATM
program to privately held affiliates of EPCO, which generated gross proceeds of
$100 million.  In February 2016, privately held affiliates of EPCO reinvested an
additional $100 million, resulting in the issuance of 4,481,504 common units
under our DRIP.

Universal shelf registration statement
In May 2016, we filed with the SEC a new universal shelf registration statement
(the "2016 Shelf"), which was immediately effective and replaced our prior
universal shelf registration statement filed with the SEC in June 2013 (the
"2013 Shelf").  The 2016 Shelf allows (and the prior 2013 Shelf allowed)
Enterprise Products Partners L.P. and EPO (each on a standalone basis) to issue
an unlimited amount of equity and debt securities, respectively.
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ATM Program
In July 2016, we filed an amended registration statement with the SEC covering
the issuance of up to $1.89 billion of our common units in amounts, at prices
and on terms to be determined by market conditions and other factors at the time
of such offerings.  Pursuant to the ATM program, we may sell common units under
an equity distribution agreement between Enterprise Products Partners L.P. and
certain broker-dealers from time-to-time by means of ordinary brokers'
transactions through the NYSE at market prices, in block transactions or as
otherwise agreed to with the broker-dealer parties to the agreement.  The new
registration statement was declared effective on July 14, 2016 and replaced our
prior registration statement with respect to the ATM program. Following the
effectiveness of the new ATM registration statement and after taking into
account the aggregate sales price of common units sold under the ATM program
through December 31, 2016, we have the capacity to issue additional common units
under the ATM program up to an aggregate sales price of $1.44 billion.

DRIP and EUPP
In May 2016, we filed with the SEC a new registration statement in connection
with our DRIP, which was immediately effective and amended a prior registration
statement filed in March 2010.  The new registration statement increased the
aggregate number of our common units authorized for issuance under the DRIP from
140,000,000 to 240,000,000.  The DRIP provides unitholders of record and
beneficial owners of our common units a voluntary means by which they can
increase the number of our common units they own by reinvesting the quarterly
cash distributions they receive from us into the purchase of additional new
common units.  After taking into account the new registration statement and the
number of common units issued under the DRIP through December 31, 2016, we have
the capacity to issue an additional 99,258,495 common units under this plan.

In addition to the DRIP, we have registration statements on file with the SEC
authorizing the issuance of up to 8,000,000 of our common units in connection
with our EUPP. After taking into account the number of common units issued under
the EUPP through December 31, 2016, we had the capacity to issue an additional
6,265,475 common units under this plan.

Use of Proceeds
The net cash proceeds we received from the issuance of common units during 2016
were used to temporarily reduce amounts outstanding under EPO's commercial paper
program and revolving credit facilities and for general company purposes.

For additional information regarding our issuance of common units and related registration statements, see Note 9 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Restricted Cash


Restricted cash represents amounts held in segregated bank accounts by our
clearing brokers as margin in support of our commodity derivative instruments
portfolio and related physical purchases and sales of natural gas, NGLs, crude
oil and refined products. Additional cash may be restricted to maintain our
commodity derivative instruments portfolio as prices fluctuate or margin
requirements change.

At December 31, 2016 and 2015, our restricted cash amounts were $354.5 million
and $15.9 million, respectively. The balance at December 31, 2016 consisted of
initial margin requirements of $35.6 million and variation margin requirements
of $318.9 million. The initial margin requirements will be returned to us as the
related derivative instruments are settled.  Our variation margin requirements
increased by $339.3 million since December 31, 2015, primarily due to higher
forward commodity prices for NGLs and related hydrocarbons during 2016 relative
to our short financial derivative positions in these products.  For information
regarding our derivative instruments and hedging activities, see Note 14 of the
Notes to Consolidated Financial Statements included under Part II, Item 8 of
this annual report.
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Credit Ratings


As of February 24, 2017, the investment-grade credit ratings of EPO's long-term
senior unsecured debt securities were BBB+ from Standard and Poor's and Baa1
from Moody's.  In addition, the credit ratings of EPO's short-term senior
unsecured debt securities were A-2 from Standard and Poor's and P-2 from
Moody's.  Fitch Ratings issued non-solicited ratings of BBB+ and F-2 for EPO's
long-term senior unsecured debt securities and short-term senior unsecured debt
securities, respectively.

EPO's credit ratings reflect only the view of a rating agency and should not be interpreted as a recommendation to buy, sell or hold any of our securities.

A

credit rating can be revised upward or downward or withdrawn at any time by a
rating agency, if it determines that circumstances warrant such a change.  A
credit rating from one rating agency should be evaluated independently of credit
ratings from other rating agencies.

Cash Flows from Operating, Investing and Financing Activities


The following table summarizes our consolidated cash flows from operating,
investing and financing activities for the years indicated (dollars in
millions).  For additional information regarding our cash flow amounts, please
refer to the Statements of Consolidated Cash Flows included under Part II, Item
8 of this annual report.

                                                         For the Year Ended December 31,
                                                        2016            2015          2014
Net cash flows provided by operating activities      $   4,066.8      $ 4,002.4     $ 4,162.2
Cash used in investing activities                        4,344.4        3,441.8       5,797.9
Cash provided by (used in) financing activities            321.7         

(616.0 ) 1,653.2




Net cash flows provided by operating activities are largely dependent on
earnings from our consolidated business activities.  We operate 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.

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,
increase the risk of nonpayment and nonperformance by customers, particularly
customers that have sub-investment grade credit ratings or small-scale
companies.  Such non-performance risk could be associated with long-term
contracts with minimum volume commitments or fixed demand charges.  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 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.

For a more complete discussion of these and other risk factors pertinent to our business, see Part I, Item 1A of this annual report.

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The following information highlights significant year-to-year fluctuations in our consolidated cash flow amounts:

Comparison of 2016 with 2015


Operating Activities
Net cash flows provided by operating activities for the year ended December 31,
2016 increased $64.4 million when compared to the year ended December 31, 2015.
The increase in cash provided by operating activities was primarily due to a
$142.4 million year-to-year increase in cash primarily due to the timing of cash
receipts and payments related to operations partially offset by an $81.6 million
year-to-year decrease in cash distributions received on earnings from
unconsolidated affiliates primarily due to the sale of our Offshore Business in
July 2015.

For information regarding significant year-to-year changes in our consolidated
net income and underlying segment results, see "Results of Operations" within
this Part II, Item 7.

Investing Activities
Cash used in investing activities for the year ended December 31, 2016 increased
$902.6 million when compared to the year ended December 31, 2015 primarily due
to:

§ a $1.56 billion year-to-year decrease in cash proceeds from asset sales and

insurance recoveries primarily due to the sale of our Offshore Business in July

2015, which generated proceeds of $1.53 billion; and

§ a $322.7 million year-to-year increase in cash outflows to satisfy restricted

cash requirements; partially offset by

§ an $827.5 million year-to-year decrease in capital spending for consolidated

property, plant and equipment (see "Capital Spending" within this Part II, Item

7 for additional information regarding our capital spending program);

§ an $80.3 million year-to-year decrease in aggregate cash used for business

combinations and investments in and advances to unconsolidated affiliates; and

§ $71.0 million of distributions received in connection with the return of

capital from unconsolidated affiliates during 2016.




Financing Activities
Cash provided by financing activities for the year ended December 31, 2016 was
$321.7 million compared to cash used in financing activities for the year ended
December 31, 2015 of $616.0 million.  The $937.7 million year-to-year change in
cash flow from financing activities was primarily due to:

§ a $1.35 billion year-to-year increase in net cash proceeds from the issuance of

common units. We issued an aggregate 104,183,571 common units in connection

with our ATM program, DRIP and EUPP during 2016, which generated $2.54 billion

of net cash proceeds. This compares to an aggregate 38,314,337 common units we

issued in connection with these programs and plans during 2015, which

collectively generated $1.19 billion of net cash proceeds; partially offset by

§ a $356.8 million year-to-year increase in cash distributions paid to limited

partners during 2016 when compared to 2015. The increase in cash distributions

is due to increases in both the number of distribution-bearing common units

outstanding and the quarterly cash distribution rates per unit; and

§ a $72.6 million year-to-year decrease in net borrowings under our consolidated

debt agreements. EPO issued $1.25 billion and repaid $750.0 billion in

principal amount of senior notes during 2016, compared to the issuance of $2.5

billion and repayment of $1.48 billion in principal amount of senior and junior

notes during 2015. Net proceeds from the issuance of short-term notes under

EPO's commercial paper program were $647.9 million during 2016 compared to

  $202.2 million during 2015.


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Comparison of 2015 with 2014

Operating Activities
Net cash flows provided by operating activities for the year ended December 31,
2015 decreased $159.8 million when compared to the year ended December 31,
2014.  The decrease in cash provided by operating activities was primarily due
to:

§ a $215.1 million year-to-year decrease in cash primarily due to the timing of

cash receipts and payments related to operations; and

§ a $31.7 million decrease in cash attributable to lower partnership income in

2015 compared to 2014 (after adjusting our $275.1 million year-to-year decrease

in net income for changes in the non-cash items identified on our Statements of

Consolidated Cash Flows); partially offset by

§ an $87.0 million year-to-year increase in cash distributions received from

unconsolidated affiliates generally attributable to our investments in crude

oil and NGL pipeline joint ventures.




Investing Activities
Cash used in investing activities for the year ended December 31, 2015 decreased
$2.36 billion when compared to the year ended December 31, 2014 primarily due
to:

§ a $1.46 billion year-to-year increase in cash proceeds from asset sales and

insurance recoveries primarily due to the sale of our Offshore Business in July

2015, which generated proceeds of $1.53 billion;

§ a $1.1 billion cash payment in July 2015 (the initial installment) for the

  acquisition of EFS Midstream compared to an aggregate $2.42 billion cash
  payment made in October 2014 in connection with Step 1 of the Oiltanking
  acquisition; and


§ a $559.8 million year-to-year decrease in cash contributions to our

unconsolidated affiliates primarily due to the completion of construction of

the Front Range Pipeline and the Seaway Loop in 2014, partially offset by

increased investments in the Eagle Ford Terminals Corpus Christi and Delaware

Gas Basin Processing Plant in 2015; partially offset by

§ a $947.6 million year-to-year increase in capital spending for consolidated

property, plant and equipment, net of contributions in aid of construction

  costs; and



§ an $81.5 million year-to-year increase in cash outflows to satisfy restricted

  cash requirements.



Financing Activities
Cash used in financing activities for the year ended December 31, 2015 was
$616.0 million compared to cash provided by financing activities for the year
ended December 31, 2014 of $1.65 billion.  The $2.27 billion year-to-year change
in cash flow from financing activities was primarily due to:

§ a $2.81 billion year-to-year decrease in net borrowings under our consolidated

debt agreements. EPO issued $2.5 billion in senior notes and repaid $1.48

billion in principal amount of debt obligations in 2015 compared to the

issuance of $4.75 billion and repayment of $1.15 billion in principal amount of

  senior notes in 2014.  In addition, net proceeds from the issuance of
  short-term notes under EPO's commercial paper program were $202.2 million
  during 2015 compared to $430.6 million during 2014; and


§ a $305.6 million year-to-year increase in cash distributions paid to limited

partners in 2015 when compared to 2014. The increase in cash distributions is

  due to increases in both the number of distribution-bearing common units
  outstanding and the quarterly cash distribution rates per unit; partially
  offset by


§ a $799.8 million year-to-year increase in net cash proceeds from the issuance

  of common units.


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Cash Distributions to Limited Partners


Our partnership agreement requires us to make quarterly distributions to our
unitholders of all available cash, after any cash reserves established by
Enterprise GP in its sole discretion. Cash reserves include those for the proper
conduct of our business including, for example, those for capital expenditures,
debt service, working capital, operating expenses, commitments and contingencies
and other significant amounts. The retention of cash by the partnership allows
us to reinvest in our growth and reduce our future reliance on the equity and
debt capital markets.

We measure available cash by reference to "distributable cash flow," which is a
non-GAAP liquidity measure.  Distributable cash flow is an important non-GAAP
financial measure for our limited partners since it serves as an indicator of
our success in providing a cash return on investment. Specifically, this
financial measure indicates to investors whether or not we are generating cash
flows at a level that can sustain or support an increase in our quarterly cash
distributions. Distributable cash flow is also a quantitative standard used by
the investment community with respect to publicly traded partnerships because
the value of a partnership unit is, in part, measured by its yield, which is
based on the amount of cash distributions a partnership can pay to a
unitholder. Our management compares the distributable cash flow we generate to
the cash distributions we expect to pay our partners. Using this metric,
management computes our distribution coverage ratio.

Based on the level of available cash, management proposes a quarterly cash
distribution rate to the Board of Enterprise GP, which has sole authority in
approving such matters.  Unlike several other master limited partnerships, our
general partner has a non-economic ownership interest in us and is not entitled
to receive any cash distributions from us based on IDRs or other equity
interests.

Our use of distributable cash flow for the limited purposes described above and
in this report is not a substitute for net cash flows provided by operating
activities, which is the most comparable GAAP measure.  For a discussion of net
cash flows provided by operating activities, see the previous section titled
"Cash Flows from Operating, Investing and Financing Activities" within this Item
7.
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The following table summarizes our calculation of distributable cash flow for the periods indicated (dollars in millions):


                                                                    For the 

Year Ended December 31,

                                                            2016                    2015                2014

Net income attributable to limited partners (1) $ 2,513.1

      $   2,521.2         $   2,787.4
Adjustments to GAAP net income attributable to
limited partners to

derive non-GAAP distributable cash flow:

   Add depreciation, amortization and accretion
expenses                                                      1,552.0                1,516.0             1,360.5
   Add non-cash asset impairment and related
charges                                                          53.5                  162.6                34.0
   Add losses or subtract gains attributable to
asset sales and insurance recoveries                             (2.5 )                 15.6              (102.1 )
   Add cash proceeds from asset sales and
insurance recoveries (2)                                         46.5                1,608.6               145.3
   Add changes in fair value of Liquidity Option
Agreement (3)                                                    24.5                   25.4                  --

Add or subtract changes in fair market value of derivative instruments

                                           45.0                  (18.4 )              30.6
   Add cash distributions received from
unconsolidated affiliates (4)                                   451.5                  462.1               375.1
   Subtract equity in income of unconsolidated
affiliates                                                     (362.0 )               (373.6 )            (259.5 )
   Subtract sustaining capital expenditures (5)                (252.0 )               (272.6 )            (369.0 )
   Add gains from monetization of interest rate
derivative instruments accounted
     for as cash flow hedges (6)                                  6.1                     --                27.6
   Add deferred income tax expense or subtract
benefit, as applicable                                            6.6                  (20.6 )               6.1
   Other, net                                                    20.5                  (19.0 )              42.6
Distributable cash flow                                $      4,102.8            $   5,607.3         $   4,078.6

Total cash distributions paid to limited partners
with respect to period                                 $      3,394.0       

$ 3,036.8 $ 2,707.6

Cash distributions per unit declared by Enterprise GP with respect to period (7)

                          $       1.6100       

$ 1.5300 $ 1.4500


Total distributable cash flow retained by
partnership with respect to period (8)                 $        708.8       

$ 2,570.5 $ 1,371.0


Distribution coverage ratio (9)                                 1.21x                  1.85x               1.51x

(1)  For a discussion of significant changes in our comparative income statement amounts underlying net income
attributable to limited partners, along with the primary drivers of such changes, see "Consolidated Income
Statements Highlights" within this Part II, Item 7.
(2)  For a discussion of significant changes in cash proceeds from asset sales and insurance recoveries as
presented in the investing activities section of our Statements of Consolidated Cash Flows, see "Cash Flows from
Operating, Investing and Financing Activities" within this Part II, Item 7.
(3)  For information regarding the Liquidity Option Agreement, see Note 17 of the Notes to Consolidated
Financial Statements included under Part II, Item 8 of this annual report.
(4)  Reflects both distributions received on earnings from unconsolidated affiliates and those attributable to a
return of capital from unconsolidated affiliates. For information regarding our unconsolidated affiliates, see
Note 6 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
(5)  Sustaining capital expenditures include cash payments and accruals applicable to the period.
(6)  For information regarding these gains and losses, see "Interest Rate Hedging Activities" under Note 14 of
the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
(7)  See Note 9 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual
report for additional information regarding our quarterly cash distributions declared with respect to the
periods presented.
(8)  At the sole discretion of Enterprise GP, cash retained by the partnership with respect to each of these
years was primarily reinvested in our growth capital spending program, which reduced our reliance on the equity
and debt capital markets to fund such major expenditures.
(9)  Distribution coverage ratio is determined by dividing distributable cash flow by total cash distributions
paid to limited partners and in connection with distribution equivalent rights with respect to the period.



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The following table presents a reconciliation of net cash flows provided by operating activities to non-GAAP distributable cash flow for the periods indicated (dollars in millions):


                                                         For the Year Ended 

December 31,

                                                        2016            2015          2014
Net cash flows provided by operating activities      $   4,066.8      $ 4,002.4     $ 4,162.2
Adjustments to reconcile net cash flows provided
by operating activities

to distributable cash flow:

   Subtract sustaining capital expenditures               (252.0 )       

(272.6 ) (369.0 )

   Add cash proceeds from asset sales and
insurance recoveries                                        46.5        

1,608.6 145.3

Subtract losses or add gains from monetization of interest rate derivative instruments accounted for as cash flow hedges

                6.1            

-- 27.6

   Net effect of changes in operating accounts             180.9          323.3         108.2
   Other, net                                               54.5          (54.4 )         4.3
Distributable cash flow                              $   4,102.8      $ 5,607.3     $ 4,078.6



Designated Units Issued in Connection with Holdings Merger
In November 2010, we completed our merger with Enterprise GP Holdings L.P. (the
"Holdings Merger").  In connection with the Holdings Merger, a privately held
affiliate of EPCO agreed to temporarily waive the regular cash distributions it
would otherwise receive from us with respect to a certain number of our common
units it owns (the "Designated Units").  Distributions paid by us to this
privately held affiliate of EPCO during 2015 excluded 35,380,000 Designated
Units.  The temporary distribution waiver expired in November 2015; therefore,
distributions paid to partners during calendar year 2016 were on all outstanding
common units.

Capital Spending

An important part of our business strategy involves expansion through growth
capital projects, business combinations and investments in joint ventures.  We
believe that we are well positioned to continue to expand our network of assets
through the construction of new facilities and to capitalize on expected
increases in natural gas, NGL and crude oil production resulting from
development activities in the Rocky Mountains, Mid-Continent, Northeast and U.S.
Gulf Coast regions, including the Niobrara, Barnett, Eagle Ford, Permian,
Haynesville, Marcellus and Utica Shale plays.  Although our focus in recent
years has been on expansion through growth capital projects, management
continues to analyze potential business combinations, asset acquisitions, joint
ventures and similar transactions with businesses that operate in complementary
markets or geographic regions.  In light of current business conditions, we
expect that these opportunities will increase.

We began commercial service on approximately $2.2 billion of growth capital
projects during 2016.  These projects included our Morgan's Point Ethane Export
Terminal, Waha and South Eddy natural gas processing facilities and the
completion of over 2 MMBbls of additional crude oil storage capacity at our
terminals in Houston and Beaumont.  In addition, we have approximately $6.7
billion of growth capital projects scheduled to be completed by 2020 including
our PDH and iBDH facilities, the Midland-to-Sealy segment of our Midland-to-ECHO
Pipeline System and completion of joint venture-owned dock infrastructure in
Corpus Christi designed to accommodate crude oil volumes.

We currently expect our total capital spending for the year ended December 31,
2017 to approximate $2.3 billion to $2.7 billion, which includes approximately
$250 million for sustaining capital expenditures.  Our forecast of capital
spending for 2017 is based on our announced strategic operating and growth plans
(through the filing date of this annual report), which are dependent upon our
ability to generate the required funds from either operating cash flows or other
means, including borrowings under debt agreements, the issuance of additional
equity and debt securities, and potential divestitures.  We may revise our
forecast of capital spending due to factors beyond our control, such as adverse
economic conditions, weather related issues and changes in supplier prices.
Furthermore, our forecast of capital spending may change as a result of
decisions made by management at a later date, which may include unforeseen
acquisition opportunities.
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Our success in raising capital, including the formation of joint ventures to
share costs and risks, continues to be a significant factor in determining how
much capital we can invest. We believe our access to capital resources is
sufficient to meet the demands of our current and future growth needs and,
although we expect to make the forecast capital expenditures noted above, we may
adjust the timing and amounts of projected expenditures in response to changes
in capital market conditions.

The following table summarizes our capital spending for the periods indicated
(dollars in millions):

                                                                      For the Year Ended December 31,
                                                           2016                2015                      2014
EFS Midstream acquisition                                $ 1,000.0         $     1,056.5             $          --
Oiltanking acquisition:
  Cash consideration                                            --                    --                   2,416.8
  Equity consideration                                          --               1,408.7                   2,171.5
Capital spending for property, plant and
equipment, net:
  Growth capital projects (1)                              2,722.7               3,540.0                   2,502.8
  Sustaining capital projects (2)                            261.4                 271.6                     361.2
Investments in unconsolidated affiliates                     138.8                 162.6                     722.4
Other investing activities                                     0.4                   5.3                       5.8
   Total capital spending                                $ 4,123.3         $     6,444.7             $     8,180.5

(1)  Growth capital projects either (a) result in new sources of cash flow due to enhancements of or additions to
existing assets (e.g., additional revenue streams, cost savings resulting from debottlenecking of a facility,
etc.) or (b) expand our asset base through construction of new facilities that will generate additional revenue
streams and cash flows.
(2)  Sustaining capital expenditures are capital expenditures (as defined by GAAP) resulting from improvements to
existing assets. Such expenditures serve to maintain existing operations but do not generate additional revenues
or result in significant cost savings.



Fluctuations in our spending for growth capital projects and investments in
unconsolidated affiliates are explained in large part by increases or decreases
in spending on major expansion projects.  Our most significant growth capital
expenditures for the year ended December 31, 2016 involved projects at our Mont
Belvieu complex.  Fluctuations in spending for sustaining capital projects are
explained in large part by the timing and cost of pipeline integrity and similar
projects.

Comparison of 2016 with 2015.  We acquired EFS Midstream in July 2015 for
approximately $2.1 billion in cash, 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 using a combination
of cash on hand and proceeds from the issuance of short-term notes under EPO's
commercial paper program. For additional information regarding the EFS Midstream
acquisition, including an allocation of the purchase price, see Note 12 of the
Notes to Consolidated Financial Statements included under Part II, Item 8 of
this annual report.

In total, capital spending for property, plant and equipment decreased $827.5
million year-to-year primarily due to lower growth capital spending during
2016.  Growth capital spending for LPG export expansion projects at EHT and our
ethane export facility decreased a combined $328.9 million year-to-year.  We
completed two expansion projects during 2015 at our EHT facility that increased
our ability to load cargos of fully refrigerated, low-ethane propane to
approximately 16.0 MMBbls per month. In September 2016, we placed our Morgan's
Point Ethane Export Terminal into service.  Likewise, growth capital spending on
our ethane header system between Corpus Christi, Texas and the Mississippi River
in Louisiana decreased $288.1 million year-to-year.  We completed the Aegis
Ethane Pipeline (i.e., the largest component of our ethane header system) in
December 2015.

Growth capital spending at our ECHO and Beaumont Marine West Crude Oil terminals
decreased a combined $146.1 million year-to-year as new storage tanks and
related assets were placed into service at these facilities during 2015 and
2016.  Growth capital spending for our Rancho II crude oil pipeline, which is a
component of our South Texas Crude Oil Pipeline System, and Midland-to-ECHO
Pipeline System decreased a net $95.0 million year-to-year.  We completed the
Rancho II pipeline in September 2015.  The Midland-to-ECHO Pipeline System is
expected to be completed and placed into service at initial rates of 300 MBPD in
the fourth quarter of 2017 once the Midland-to-Sealy segment is constructed.
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Growth capital spending at our Mont Belvieu complex increased $67.1 million
year-to-year primarily due to ongoing construction of our PDH facility.
Currently, we expect construction of the PDH facility to be completed in the
first quarter of 2017 with commercial operations expected to begin in the second
quarter of 2017.

Investments in unconsolidated affiliates decreased $23.8 million year-to-year
primarily due to the completion of expansion projects on our Eagle Ford Crude
Oil Pipeline System during 2015.

Comparison of 2015 with 2014.  Capital spending for 2015 included the initial
payment of approximately $1.1 billion to acquire EFS Midstream.  In addition,
capital spending during 2015 included $1.4 billion of non-cash equity
consideration we issued to complete Step 2 of the Oiltanking acquisition.  Step
2 represented our acquisition of the noncontrolling interests in Oiltanking;
therefore, approximately $1.4 billion of noncontrolling interests attributable
to Oiltanking was reclassified to limited partners' equity to reflect the
February 2015 issuance of 36,827,517 of our common units.  Capital spending for
2014 reflected total cash and equity consideration of approximately $4.6 billion
to OTA to complete Step 1 of the Oiltanking acquisition.  For information
regarding the Oiltanking acquisition, see Note 12 of the Notes to Consolidated
Financial Statements included under Part II, Item 8 of this annual report.

In total, capital spending for property, plant and equipment increased $947.6
million year-to-year primarily due to higher growth capital spending during
2015.  Growth capital spending at our Mont Belvieu complex increased $385.2
million year-to-year primarily due to construction of the PDH facility.  Growth
capital spending for  LPG export expansion projects at EHT and our ethane export
facility increased a combined $282.6 million year-to-year.  Growth capital
spending on our natural gas processing and related pipeline projects in the
Delaware Basin increased a combined $235.2 million year-to-year. Our South Eddy
natural gas processing plant and related pipeline infrastructure began
operations in May 2016.

Growth capital spending on our Rancho II crude oil pipeline and the expansion of
crude oil terminal assets at our ECHO, EHT and Beaumont Marine West terminals
increased a combined $218.2 million year-to-year.  Growth capital spending on
our Gulf Coast ethane header system increased $208.0 million year-to-year.
Growth capital spending attributable to ATEX and the Rocky Mountain expansion of
our Mid-America Pipeline System decreased a combined $264.2 million
year-to-year.  These two projects were completed during the first quarter of
2015.

Investments in unconsolidated affiliates decreased $559.8 million year-to-year primarily due to completion of the Seaway Loop pipeline in December 2014.

Critical Accounting Policies and Estimates


In our financial reporting processes, we employ methods, estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities as of the date of our financial
statements.  These methods, estimates and assumptions also affect the reported
amounts of revenues and expenses for each reporting period.  Investors should be
aware that actual results could differ from these estimates if the underlying
assumptions prove to be incorrect.  The following sections discuss the use of
estimates within our critical accounting policies:

Depreciation Methods and Estimated Useful Lives of Property, Plant and Equipment


In general, depreciation is the systematic and rational allocation of an asset's
cost, less its residual value (if any), to the periods it benefits.  The
majority of our property, plant and equipment is depreciated using the
straight-line method, which results in depreciation expense being incurred
evenly over the life of an asset.  Our estimate of depreciation expense
incorporates management assumptions regarding the useful economic lives and
residual values of our assets.  At the time we place our assets in service, we
believe such assumptions are reasonable; however, circumstances may develop that
would cause us to change these assumptions, which would change our depreciation
amounts prospectively.  Examples of such circumstances include (i) changes in
laws and regulations that limit the estimated economic life of an asset, (ii)
changes in technology that render an asset obsolete, (iii) changes in expected
residual values or (iv) significant changes in our forecast of the remaining
life for the applicable resource basins, if any.
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At December 31, 2016 and 2015, the net carrying value of our property, plant and
equipment was $33.29 billion and $32.03 billion, respectively.  We recorded
$1.22 billion, $1.16 billion and $1.11 billion of depreciation expense for the
years ended December 31, 2016, 2015 and 2014, respectively.  For additional
information regarding our property, plant and equipment, see Note 5 of the Notes
to Consolidated Financial Statements included under Part II, Item 8 of this
annual report.

Measuring Recoverability of Long-Lived Assets and Fair Value of Equity Method Investments


Long-lived assets, which include property, plant and equipment and intangible
assets with finite useful lives, are reviewed for impairment whenever events or
changes in circumstances indicate that their carrying amount may not be
recoverable.  Examples of such events or changes might be production declines
that are not replaced by new discoveries or long-term decreases in the demand or
price of natural gas, NGLs, crude oil, petrochemicals or refined products.  The
carrying value of a long-lived asset is deemed not recoverable if it exceeds the
sum of undiscounted estimated cash flows expected to result from the use and
eventual disposition of the asset.  Estimates of undiscounted cash flows are
based on a number of assumptions including anticipated operating margins and
volumes; estimated useful life of the asset or asset group; and estimated
residual values.  If the carrying value of a long-lived asset is not
recoverable, an impairment charge would be recorded for the excess of a
long-lived asset's carrying value over its estimated fair value, which is
derived from an analysis of the asset's estimated future cash flows, the market
value of similar assets and replacement cost of the asset less any applicable
depreciation or amortization.  In addition, fair value estimates also include
usage of probabilities for a range of possible outcomes.

An equity method investment is evaluated for impairment whenever events or
changes in circumstances indicate that there is a possible permanent loss in
value of the investment (i.e., other than a temporary decline).  Examples of
such events include sustained operating losses of the investee or long-term
negative changes in the investee's industry.  When evidence of a loss in value
has occurred, we compare the estimated fair value of the investment to the
carrying value of the investment to determine whether an impairment has
occurred.  We assess the fair value of our equity method investments using
commonly accepted techniques, and may use more than one method, including, but
not limited to, recent third party sales and discounted estimated cash flow
models.  Estimates of discounted cash flows are based on a number of assumptions
including discount rates; probabilities assigned to different cash flow
scenarios; anticipated margins and volumes and estimated useful life of the
investment's underlying assets.

A significant change in the assumptions we use to measure recoverability of
long-lived assets and the fair value of equity method investments could result
in our recording a non-cash impairment charge. Any write-down of the carrying
values of such assets would increase operating costs and expenses at that time.

During 2016, 2015 and 2014, we recognized non-cash asset impairment charges
related to long-lived assets of $45.2 million, $162.6 million and $34.0 million,
respectively, which are a component of costs and expenses.  For additional
information regarding these impairment charges, see Note 14 of the Notes to
Consolidated Financial Statements included under Part II, Item 8 of this annual
report.

Amortization Methods and Estimated Useful Lives of Customer Relationships

and Contract-Based Intangible Assets


The specific, identifiable intangible assets of a business depend largely upon
the nature of its operations and include items such as customer relationships
and contracts.  The method used to value such assets depends on a number of
factors, including the nature of the asset and the economic returns the asset is
expected to generate.
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Customer relationship intangible assets represent the estimated economic value
assigned to certain relationships acquired in connection with business
combinations and asset purchases whereby (i) we acquired information about or
access to customers and now have the ability to provide services to them and
(ii) the customers now have the ability to make direct contact with us.
Customer relationships may arise from contractual arrangements (such as service
contracts) and through means other than contracts, such as through regular
contact by sales or service representatives.  The value we assign to customer
relationships is amortized to earnings using methods that closely resemble the
pattern in which the economic benefits will be consumed (i.e., the manner in
which the intangible asset is expected to contribute directly or indirectly to
our cash flows).  For example, the amortization periods for certain of our
customer relationship intangible assets are limited by the estimated finite
economic life of the associated hydrocarbon resource basins.  In this context,
our estimate of the useful life of each resource basin is predicated on a number
of factors, including reserve estimates and the economic viability of production
and exploration activities.

Contract-based intangible assets represent specific commercial rights we own
arising from discrete contractual agreements, such as the long-term rights we
possess under the Shell natural gas processing agreement and the Jonah natural
gas transportation contracts.  A contract-based intangible asset with a finite
life is amortized over its estimated economic life, which is the period over
which the asset is expected to contribute directly or indirectly to our cash
flows.  Our estimates of the economic life of contract-based intangible assets
are based on a number of factors, including (i) the expected useful life of the
related tangible assets (e.g., a fractionation facility, pipeline or other
asset), (ii) any legal or regulatory developments that would impact such
contractual rights and (iii) any contractual provisions that enable us to renew
or extend such arrangements.

If our assumptions regarding the estimated economic life of an intangible asset
were to change, then the amortization period for such asset would be adjusted
accordingly.  Changes in the estimated useful life of an intangible asset would
impact operating costs and expenses prospectively from the date of change.  If
we determine that an intangible asset's unamortized cost is not recoverable due
to impairment, we would be required to reduce the asset's carrying value to its
estimated fair value through the recording of a non-cash impairment charge. 

Any

such write-down of the value of an intangible asset would increase operating costs and expenses at that time.


At December 31, 2016 and 2015, the carrying value of our customer relationship
and contract-based intangible asset portfolio was $3.86 billion and $4.04
billion, respectively.  We recorded $171.3 million, $174.1 million and $110.6
million of amortization expense attributable to intangible assets for the years
ended December 31, 2016, 2015 and 2014, respectively.  For additional
information regarding our intangible assets, see Note 7 of the Notes to
Consolidated Financial Statements included under Part II, Item 8 of this annual
report.

Methods We Employ to Measure the Fair Value of Goodwill and Related Assets


Goodwill represents the excess of the purchase price of an acquired business
over the amounts assigned to assets acquired and liabilities assumed in the
transaction.  Goodwill is not amortized; however, it is subject to annual
impairment testing at the end of each fiscal year, and more frequently, if
circumstances indicate it is probable that the fair value of goodwill is below
its carrying amount.  Goodwill impairment testing involves determining the fair
value of the associated reporting unit.  The fair value of a reporting unit is
based on assumptions regarding the future economic prospects of the businesses
that make up the reporting unit. Such assumptions include (i) discrete financial
forecasts for the associated businesses, which, in turn, rely on management's
estimates of operating margins, throughput volumes and similar inputs; (ii)
long-term growth rates for cash flows beyond discrete forecast periods; and
(iii) appropriate discount rates.  If the fair value of a reporting unit
(including its inherent goodwill) is less than its carrying value, a non-cash
charge to operating costs and expenses is required to reduce the carrying value
of goodwill to its implied fair value.  At December 31, 2016 and 2015, the
carrying value of our goodwill was $5.75 billion.

We did not record any goodwill impairment charges in 2016, 2015 or 2014.  Based
on our most recent goodwill impairment test at December 31, 2016, each reporting
unit's fair value was substantially in excess of its carrying value (i.e., by at
least 10%).  For additional information regarding our goodwill, see Note 7 of
the Notes to Consolidated Financial Statements included under Part II, Item 8 of
this annual report.
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Revenue Recognition Policies and Use of Estimates for Revenues and Expenses


In general, we recognize revenue from customers when all of the following
criteria are met: (i) persuasive evidence of an exchange arrangement exists;
(ii) delivery has occurred or services have been rendered; (iii) the buyer's
price is fixed or determinable; and (iv) collectibility is reasonably assured.
We record revenue when sales contracts are settled (i.e., either physical
delivery of product has taken place or the services designated in the contract
have been performed).  We record any necessary allowance for doubtful accounts
as required by our established policy.  For additional information regarding our
revenue recognition policies, see Note 3 of the Notes to Consolidated Financial
Statements included under Part II, Item 8 of this annual report.

Our use of estimates for certain revenues and expenses has increased as a result
of SEC regulations that require us to submit financial information on
accelerated time frames.  Such estimates are necessary due to the time required
to compile actual billing information and receive third party data needed to
record transactions for financial reporting purposes.  One example of our use of
estimates is the accrual of an estimate of processing plant revenue and the cost
of natural gas for a given month (prior to receiving actual customer and
vendor-related plant operating information for a specific period). These
estimates reverse in the following month and are offset by the corresponding
actual customer billing and vendor-invoiced amounts.  Accordingly, we include
one month of certain estimated data in our results of operations.  Such
estimates are generally based on actual volume and price data through the first
part of the month and estimated for the remainder of the month.

Changes in facts and circumstances may result in revised estimates and could
affect our reported financial statements and accompanying disclosures.  If the
assumptions underlying our revenue and expense estimates prove to be
substantially incorrect, it could result in material adjustments in results of
operations between periods.  We review our estimates based on currently
available information.
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Other Items

Contractual Obligations

The following table summarizes our significant contractual obligations at December 31, 2016 (dollars in millions):


                                                         Payment or 

Settlement due by Period

                                                 Less than        1-3       

4-5 More than

Contractual Obligations Total 1 year years

    years        5 years
Scheduled maturities of debt
obligations (1)                   $ 23,901.6     $ 2,577.2     $ 2,600.0     $ 2,075.0     $ 16,649.4
Estimated cash payments for
interest (2)                      $ 20,370.2     $ 1,073.3     $ 2,059.5     $ 1,825.0     $ 15,412.4
Operating lease obligations (3)   $    438.0     $    57.1     $    96.8     $    78.2     $    205.9
Purchase obligations: (4)
Product purchase commitments:
Estimated payment obligations:
Natural gas                       $  3,467.5     $   912.5     $ 1,545.1     $ 1,009.9     $       --
NGLs                              $    140.9     $    68.5     $    72.4     $      --     $       --
Crude oil                         $  1,412.7     $   421.7     $   702.7     $   183.4     $    104.9
Petrochemicals and refined
products                          $    514.3     $   202.5     $   308.8     $     3.0     $       --
Other                             $     46.0     $     9.5     $    18.8     $    12.5     $      5.2
Underlying major volume
commitments:
Natural gas (in TBtus)                   992           261           445           286             --
NGLs (in MMBbls)                          13             6             7            --             --
Crude oil (in MMBbls)                     27             8            13             4              2
Petrochemicals and refined
products
  (in MMBbls)                             18             7            11            --             --

Service payment commitments (5) $ 585.2 $ 180.6 $ 192.6

  $   102.9     $    109.1
Capital expenditure commitments
(6)                               $     57.8     $    57.8     $      --     $      --     $       --
Other long-term liabilities (7)   $    503.9     $      --     $    52.1     $   302.8     $    149.0
Total contractual payment
obligations                       $ 51,438.1     $ 5,560.7     $ 7,648.8     $ 5,592.7     $ 32,635.9

(1)  Represents scheduled future maturities of our consolidated debt principal obligations. For
information regarding our consolidated debt obligations, see Note 8 of the Notes to Consolidated
Financial Statements included under Part II, Item 8 of this annual report.
(2)  Estimated cash payments for interest are based on the principal amount of our consolidated debt
obligations outstanding at December 31, 2016, the contractually scheduled maturities of such
balances, and the applicable fixed or variable interest rates paid during 2016. With respect to our
variable-rate debt obligations, we applied the weighted-average interest rate paid during 2016 to
determine the estimated cash payments. See Note 8 of the Notes to Consolidated Financial Statements
included under Part II, Item 8 of this annual report for the weighted-average variable interest rate
charged in 2016 in connection with our commercial paper program. In general, our estimated cash
payments for interest are significantly influenced by the long-term maturities of our junior
subordinated notes (due August 2066 through January 2068). Our estimated cash payments for interest
with respect to each junior subordinated note are based on the current fixed interest rate for each
note applied to the entire remaining term through the respective maturity date.
(3)  Primarily represents land held pursuant to right-of-way agreements and property leases, leases
of underground salt dome caverns for the storage of natural gas and NGLs, the lease of transportation
equipment used in our operations and office space with affiliates of EPCO.
(4)  Represents enforceable and legally binding agreements to purchase goods or services as of
December 31, 2016. The estimated payment obligations are based on contractual prices in effect at
December 31, 2016 applied to all future volume commitments. Actual future payment obligations may
vary depending on prices at the time of delivery.
(5)  Primarily represents our unconditional payment obligations under firm pipeline transportation
contracts.
(6)  Represents unconditional payment obligations for services to be rendered or products to be
delivered in connection with our capital spending program, including our share of the capital
spending of our unconsolidated affiliates.
(7)  As reflected on our consolidated balance sheet at December 31, 2016, "Other long-term
liabilities" primarily represent the Liquidity Option Agreement, the noncurrent portion of asset
retirement obligations and deferred revenues.



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. Due to the uncertain timing of the
remaining potential capital expenditures, we have excluded this amount from the
preceding table.

 For additional information regarding our significant contractual obligations,
see Note 17 of the Notes to Consolidated Financial Statements included under
Part II, Item 8 of this annual report.
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Off-Balance Sheet Arrangements


We have no off-balance sheet arrangements that have or are reasonably expected
to have a material current or future effect on our financial position, results
of operations and cash flows.

Related Party Transactions


For information regarding our related party transactions, see Note 15 of the
Notes to Consolidated Financial Statements included under Part II, Item 8 of
this annual report.

Insurance Matters

For information regarding insurance matters, see Note 18 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.


Regulation

For information regarding the impact of federal, state or local regulatory measures on our business, see "Regulatory Matters" included under Part I, Item 1 and 2 of this annual report.

Recent Accounting Developments

For information regarding recent accounting developments, see Note 2 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

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Sales 2017 25 436 M
EBIT 2017 4 073 M
Net income 2017 2 943 M
Debt 2017 22 383 M
Yield 2017 5,97%
P/E ratio 2017 20,49
P/E ratio 2018 18,40
EV / Sales 2017 3,23x
EV / Sales 2018 2,86x
Capitalization 59 696 M
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Number of Analysts 28
Average target price 32,7 $
Spread / Average Target 15%
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Managers
NameTitle
A. James Teague Chief Executive Officer & Director
W. Randall Fowler President & Director
Randa Duncan Williams Non-Executive Chairman
Graham W. Bacon Executive Vice President-Operations & Engineering
Bryan F. Bulawa Chief Financial Officer & Senior Vice President
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