Delaware
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76-0568219
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(State
or Other Jurisdiction of
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(I.R.S.
Employer Identification No.)
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Incorporation
or Organization)
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1100 Louisiana Street, 10 th Floor, Houston, Texas |
77002
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(Address of Principal Executive Offices) |
(Zip
Code)
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(713)
381-6500
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(Registrant's
Telephone Number, Including Area Code)
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Title of Each
Class
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Name of Each Exchange
On Which Registered
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Common
Units
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New
York Stock Exchange
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Large
accelerated filer
þ
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Accelerated
filer
o
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Non-accelerated
filer
o
(Do not check if a smaller reporting company)
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Smaller
reporting company
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Page
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Number
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§
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capitalize
on expected development in natural gas, NGL and crude oil production
resulting from development activities in the Rocky Mountains,
Midcontinent, Northeast and U.S. Gulf Coast regions, including the Barnett
Shale, Haynesville Shale, Eagle Ford Shale, Marcellus Shale and deepwater
Gulf of Mexico producing regions;
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capitalize
on expected demand growth for natural gas, NGLs, crude oil and refined and
petrochemical products;
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maintain
a diversified portfolio of midstream energy assets and expand this asset
base through growth capital projects and accretive acquisitions of
complementary midstream energy
assets;
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share
capital costs and risks through joint ventures or alliances with strategic
partners, including those that will provide the raw materials for these
growth capital projects or purchase the projects’ end products;
and
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enhance
the stability of our cash flows by investing in pipelines and other
fee-based businesses.
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NGL
Pipelines & Services;
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Onshore
Natural Gas Pipelines &
Services;
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Onshore
Crude Oil Pipelines & Services;
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Offshore
Pipelines & Services; and
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Petrochemical
& Refined Products Services.
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The
Mid-America Pipeline
System
is a regulated NGL pipeline system consisting of three
primary segments: the 2,793-mile Rocky Mountain pipeline, the 2,773-mile
Conway North pipeline and the 2,266-mile Conway South
pipeline. This system is present in 13 states: Wyoming, Utah,
Colorado, New Mexico, Texas, Oklahoma, Kansas, Missouri, Nebraska, Iowa,
Illinois, Minnesota and Wisconsin. The Rocky Mountain pipeline
transports mixed NGLs from the Rocky Mountain Overthrust and San Juan
Basin areas to the Hobbs hub located on the Texas-New Mexico
border. The Conway North segment links the NGL hub at Conway,
Kansas to refineries, petrochemical plants and propane markets in the
upper Midwest. In addition, the Conway North segment has access
to NGL supplies from Canada’s Western Sedimentary Basin through
third-party connections. The Conway South pipeline connects the
Conway hub with Kansas refineries and transports NGLs to and from Conway,
Kansas to the Hobbs hub. The Mid-America Pipeline System
interconnects with our Seminole Pipeline and Hobbs NGL fractionator and
storage facility at the Hobbs hub. This system includes 15
unregulated propane terminals.
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The
Seminole Pipeline
is a regulated pipeline that transports NGLs from the Hobbs hub and the
Permian Basin area of west Texas to markets in southeast Texas including
our NGL fractionator in Mont Belvieu, Texas. NGLs originating
on the Mid-America Pipeline System are the primary source of throughput
for the Seminole Pipeline.
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The
South Texas NGL
System
is a network of NGL gathering and transportation pipelines
located in south Texas. The system gathers and transports mixed
NGLs from our south Texas natural gas processing plants to our south Texas
NGL fractionation facilities. In turn, the system
transports NGLs from our south Texas NGL fractionation
facilities to refineries and petrochemical plants located between Corpus
Christi, Texas and Houston, Texas and within the Texas City-Houston area,
as well as to interconnects with common carrier NGL
pipelines.
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The
Dixie
Pipeline
is a regulated
pipeline that extends from southeast Texas and Louisiana to markets in the
southeastern United States and transports propane and other
NGLs. Propane supplies transported on this system primarily
originate from southeast Texas, south Louisiana and
Mississippi. This system includes eight unregulated propane
terminals and operates in seven states: Texas, Louisiana,
Mississippi, Alabama, Georgia, South Carolina and North
Carolina.
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The
Chaparral NGL
System
transports NGLs from natural gas processing plants in west
Texas and New Mexico to Mont Belvieu, Texas. This system
consists of the 830-mile regulated Chaparral pipeline and the 180-mile
unregulated Quanah pipeline.
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The
Louisiana Pipeline
System
is a network of NGL pipelines located in south
Louisiana. This system transports NGLs originating in Louisiana
and Texas to refineries and petrochemical companies located along the
Mississippi River corridor in south Louisiana. This system also
provides transportation services for our natural gas processing plants,
NGL fractionators and other assets located in Louisiana. In
December 2009, we acquired 215 miles of intrastate pipelines from Chevron
Midstream Pipelines LLC that expand and extend our Louisiana Pipeline
System. Originating from a central point in Henry, Louisiana,
the acquired pipelines extend westward to Lake Charles, northward to an
interconnect with the Dixie Pipeline at Breaux Bridge, and eastward to
Napoleonville, Louisiana, where our Promix NGL fractionation and storage
facilities are located.
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The
Skelly-Belvieu
Pipeline
is a regulated pipeline that transports mixed NGLs from
Skellytown, Texas to Mont Belvieu, Texas. We anticipate
becoming operator of this pipeline by January 1,
2011.
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The
Promix
NGL Gathering System
gathers mixed NGLs from natural gas processing plants in south Louisiana
for delivery to our Promix NGL
fractionator.
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The
Houston Ship
Channel
pipeline system connects our Mont Belvieu, Texas facilities
with our Houston Ship Channel import/export terminals and various
third-party petrochemical plants, refineries and other pipelines located
along the Houston Ship Channel.
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The
Rio Grande Pipeline
is
a regulated pipeline originating near Odessa, Texas that transports mixed
NGLs to a pipeline interconnect at the Mexican border south of El Paso,
Texas.
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The
Lou-Tex NGL
Pipeline
system
transports NGLs and refinery grade propylene between the Louisiana and
Texas markets.
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Our
Mont Belvieu
NGL
fractionation facility is located in Mont Belvieu, Texas, which is a key
hub of the NGL industry. This facility fractionates mixed NGLs
from several major NGL supply basins in North America including the
Mid-Continent, Permian Basin, San Juan Basin, Rocky Mountains, east Texas
and the Gulf Coast.
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Our
Shoup
and
Armstrong
fractionators
process mixed NGLs supplied by our south Texas natural gas processing
plants. Purity NGL products from the Shoup and Armstrong
fractionators are transported to local markets in the Corpus Christi area
and also to Mont Belvieu, Texas using our South Texas NGL Pipeline
System.
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Our
Hobbs
NGL
fractionation facility is located in Gaines County, Texas, where it serves
petrochemical plants and refineries in west Texas, New Mexico, California
and northern Mexico. The Hobbs facility receives mixed NGLs
from several major supply basins including Mid-Continent, Permian Basin,
San Juan Basin and the Rocky Mountains. The facility is located
at the interconnect of our Mid-America Pipeline System and Seminole
Pipeline, thus providing us the flexibility to supply the nation’s largest
NGL hub at Mont Belvieu, Texas as well as access to the second-largest NGL
hub at Conway, Kansas.
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Our
Norco
NGL
fractionation facility receives mixed NGLs via pipeline from refineries
and natural gas processing plants located in south Louisiana and along the
Mississippi and Alabama Gulf Coast, including from our Yscloskey,
Pascagoula, Venice and Toca
facilities.
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The
Promix
NGL
fractionation facility receives mixed NGLs via pipeline from natural gas
processing plants located in south Louisiana and along the Mississippi
Gulf Coast, including from our Calumet, Neptune, Burns Point and
Pascagoula facilities. In addition to the Promix NGL Gathering
System (described previously), Promix owns five NGL storage caverns and a
barge loading facility that are integral to its
operations.
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The
BRF
facility
fractionates mixed NGLs from natural gas processing plants located in
Alabama, Mississippi and south
Louisiana.
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The
Texas Intrastate
System
gathers and transports natural gas from supply basins in
Texas (from both onshore and offshore sources) to local gas distribution
companies and electric generation and industrial and municipal consumers
as well as to connections with intrastate and interstate
pipelines. The Texas Intrastate System is comprised of the
6,560-mile Enterprise Texas pipeline system, the 641-mile Channel pipeline
system, the 660-mile Waha gathering system and the 190-mile TPC Offshore
gathering system. The Enterprise Texas pipeline system includes
a 263-mile
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pipeline
we lease from an affiliate of ETP. The leased Wilson natural
gas storage facility located in Wharton County, Texas is an integral part
of the Texas Intrastate System. Collectively, the Texas
Intrastate System serves important natural gas producing regions and
commercial markets in Texas, including Corpus Christi, the San
Antonio/Austin area, the Beaumont/Orange area and the Houston area,
including the Houston Ship Channel industrial
market.
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The
Jonah Gathering
System
is located in the Greater Green River Basin of southwest
Wyoming. This system gathers natural gas from the Jonah and
Pinedale supply basins for delivery to regional natural gas processing
plants, including our Pioneer facility, and major interstate
pipelines. In mid-2009, we completed an expansion of that
portion of the system that serves the Pinedale field, which increased
total capacity of the Jonah Gathering System from 2.35 Bcf/d to 2.55
Bcf/d.
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The
Piceance Basin Gathering
System
consists of the 48-mile Piceance Creek, 32-mile Great Divide
and 22-mile Collbran Valley gathering systems located in the Piceance
Basin of northwestern Colorado. The Piceance Creek gathering
system extends from a connection with the Great Divide gathering system to
our Meeker natural gas processing plant. The Great Divide
gathering system gathers natural gas from the southern portion of the
Piceance Basin, including natural gas gathered on the Collbran Valley
gathering system, to an interconnect with our Piceance Creek gathering
system.
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The
White River Hub
is a regulated interstate natural gas transportation hub
facility. The White River Hub connects to six interstate
natural gas pipelines in northwest Colorado and has a gross capacity of 3
Bcf/d of natural gas (1.5 Bcf/d net to our 50% ownership
interest). White River Hub began service in December
2008.
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The
San Juan Gathering
System
serves producers in the San Juan Basin of north New Mexico
and south Colorado. This system gathers natural gas from
production wells located in the San Juan Basin and delivers the natural
gas to regional processing facilities, including our Chaco natural gas
processing plant located in New
Mexico.
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The
Acadian Gas
System
purchases, transports, stores and resells natural gas in
south Louisiana. The Acadian Gas System is comprised of the
576-mile Cypress pipeline, the 438-mile Acadian pipeline and the 27-mile
Evangeline pipeline. The Acadian Gas System includes a leased
natural gas storage facility at Napoleonville, Louisiana that is an
integral part of its pipeline
operations.
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The
Val Verde Gas Gathering
System
gathers natural gas, including coal bed methane from the
Fruitland Coal Formation in the San Juan Basin, from producing regions in
north New Mexico and south
Colorado.
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The
C
arlsbad Gathering
System
gathers natural gas from the Permian Basin region of Texas
and New Mexico for delivery into the El Paso Natural Gas, Transwestern and
Oasis pipelines.
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The
Alabama Intrastate
System
gathers natural gas, primarily coal bed methane, from the
Black Warrior supply basin in Alabama. This system is also
involved in the purchase, transportation and sale of natural
gas.
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The
Encinal Gathering
System
gathers natural gas from the Olmos, Wilcox and Eagle Ford
formations in south Texas for processing at our south Texas natural gas
processing plants.
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The
Seaway Crude Pipeline
System
is a regulated system that transports imported crude oil
from Freeport, Texas to Cushing, Oklahoma and supplies refineries in the
Houston, Texas area through its terminal facility at Texas City,
Texas. The Seaway Crude Pipeline System also has a connection
to our South Texas System that allows it to receive both onshore and
offshore domestic crude oil production from the Texas Gulf Coast area for
delivery to Cushing.
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The Red River System is a regulated pipeline that transports crude oil from north Texas to south Oklahoma for delivery to either two local refineries or pipeline interconnects for further transportation to Cushing, Oklahoma. |
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The
South Texas System
transports crude oil from an origination point in south Texas to the
Houston, Texas area. Crude oil transported on the South Texas
System is delivered either to Houston area refineries or pipeline
interconnects (including those with our Seaway Crude Pipeline System) for
ultimate delivery to Cushing,
Oklahoma.
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The
West Texas System
connects crude oil gathering systems in west Texas and southeast New
Mexico to our terminal facility in Midland,
Texas.
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The
Cushing
and
Midland terminals
provide crude oil storage, pumpover and trade documentation
services. Our terminal in Cushing, Oklahoma has 19 above-ground
storage tanks with aggregate crude oil storage capacity of 3.1
MMBbls. The Midland terminal has a storage capacity of 1.0
MMBbls through the use of 12 above-ground storage
tanks.
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The
High Island Offshore
System
(“HIOS”) transports natural gas from producing fields
located in the Galveston, Garden Banks, West Cameron, High Island and East
Breaks areas of the Gulf of Mexico to the ANR pipeline system, Tennessee
Gas Pipeline and the U-T Offshore System. The HIOS pipeline
system includes eight pipeline junction and service
platforms. In addition, this system includes the 86-mile East
Breaks System that connects HIOS to the Hoover-Diana deepwater platform
located in Alaminos Canyon Block
25.
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The
Viosca Knoll Gathering
System
transports natural gas from producing fields located in the
Main Pass, Mississippi Canyon and Viosca Knoll areas of the Gulf of Mexico
to several major interstate pipelines, including the Tennessee Gas,
Columbia Gulf, Southern Natural, Transco, Dauphin Island Gathering System
and Destin Pipelines.
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The
Independence
Trail
natural gas pipeline transports natural gas from our
Independence Hub platform to the Tennessee Gas Pipeline platform at West
Delta 68. Natural gas transported on the Independence Trail
pipeline originates from production fields in the Atwater Valley, DeSoto
Canyon, Lloyd Ridge and Mississippi Canyon areas of the Gulf of
Mexico.
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The
Green Canyon
Laterals
consist of 13 pipeline laterals (which are extensions of
natural gas pipelines) that transport natural gas to downstream pipelines,
including HIOS.
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The
Phoenix Gathering
System
connects the Red Hawk platform located in the Garden Banks
area of the Gulf of Mexico to the ANR pipeline
system.
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The
Falcon Natural Gas
Pipeline
delivers natural gas processed at our Falcon Nest platform
to a connection with the Central Texas Gathering System located at the
Brazos Addition Block 133 platform.
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The
Anaconda Gathering
System
connects our Marco Polo platform and the third-party owned
Constitution platform to the ANR pipeline
system.
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The
Manta Ray Offshore
Gathering System
transports natural gas from producing fields
located in the Green Canyon, Southern Green Canyon, Ship Shoal, South
Timbalier and Ewing Bank areas of the Gulf of Mexico to numerous
downstream pipelines, including our Nautilus
System.
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The
Nautilus System
connects our Manta Ray Offshore Gathering System to our Neptune natural
gas processing plant located in south
Louisiana.
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The
Nemo Gathering
System
transports natural gas from Green Canyon developments to an
interconnect with our Manta Ray Offshore Gathering
System.
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The
VESCO Gathering
System
is a regulated natural gas pipeline system associated with
the Venice natural gas processing plant in south
Louisiana. This gathering pipeline is an integral part of the
natural gas processing operations of VESCO and is accounted for under our
NGL Pipelines & Services business
segment.
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The
Cameron Highway Oil
Pipeline
gathers crude oil production from deepwater areas of the
Gulf of Mexico, primarily the South Green Canyon area, for delivery to
refineries and terminals in southeast Texas. This system
includes one pipeline junction
platform.
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The
Poseidon Oil Pipeline
System
gathers production from the outer continental shelf and
deepwater areas of the Gulf of Mexico for delivery to onshore locations in
south Louisiana. This system includes one pipeline junction
platform.
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The
Shenzi Oil
Pipeline
provides gathering services from the BHP Billiton
Plc-operated Shenzi production field located in the South Green Canyon
area of the central Gulf of Mexico. The Shenzi Oil Pipeline
allows producers to access our Cameron Highway Oil Pipeline and Poseidon
Oil Pipeline System.
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The
Allegheny Oil
Pipeline
connects the Allegheny and South Timbalier 316 platforms
in the Green Canyon area of the Gulf of Mexico with our Cameron Highway
Oil Pipeline and Poseidon Oil Pipeline
System.
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The
Marco Polo Oil
Pipeline
transports crude oil from our Marco Polo platform to an
interconnect with our Allegheny Oil Pipeline in Green Canyon Block
164.
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The
Constitution Oil
Pipeline
serves the Constitution and Ticonderoga fields located in
the central Gulf of Mexico. The Constitution Oil Pipeline
connects with our Cameron Highway Oil Pipeline and Poseidon Oil Pipeline
System at a pipeline junction
platform.
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The
Independence Hub
platform is located in Mississippi Canyon Block
920. This platform processes natural gas gathered from
deepwater production fields in the Atwater Valley, DeSoto Canyon, Lloyd
Ridge and Mississippi Canyon areas of the Gulf of
Mexico.
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The
Marco Polo
platform, which is located in Green Canyon Block 608, processes
crude oil and natural gas from the Marco Polo, K2, K2 North and Genghis
Khan fields. These fields are located in the South Green Canyon
area of the Gulf of Mexico.
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The
Viosca Knoll 817
platform is centrally located on our Viosca Knoll Gathering
System. This platform primarily serves as a base for gathering
deepwater production in the area, including the Ram Powell
development.
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The
Garden Banks 72
platform serves as a base for gathering deepwater production from the
Garden Banks Block 161 development and the Garden Banks Block 378 and 158
leases. This platform also serves as a junction platform for
our Cameron Highway Oil Pipeline and Poseidon Oil Pipeline
System.
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The
East Cameron 373
platform serves as the host for East Cameron Block 373 production and also
processes production from Garden Banks Blocks 108, 152, 197, 200 and
201.
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The
Falcon Nest
platform, which is located in the Mustang Island Block 103 area of the
Gulf of Mexico, processes natural gas from the Falcon
field.
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For
Year Ended December 31,
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2009
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2008
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2007
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Refined
products transportation (MBPD)
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459 | 492 | 542 | |||||||||
Petrochemical
transportation (MBPD)
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118 | 104 | 111 | |||||||||
NGLs
transportation (MBPD)
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105 | 106 | 115 |
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The
Products Pipeline
System
is a regulated pipeline system that transports refined
products, petrochemicals and NGLs. This pipeline system
includes receiving, storage and terminaling facilities and is present in
12 states: Texas, Louisiana, Arkansas, Tennessee, Missouri, Illinois,
Kentucky, Indiana, Ohio, West Virginia, Pennsylvania and New
York. Our Products Pipeline System transports refined products
from the upper Texas Gulf Coast, eastern Texas and southern Arkansas to
the Central and Midwest regions of the United States with deliveries in
Texas, Louisiana, Arkansas, Missouri, Illinois, Indiana, Ohio and
Kentucky. At these points, refined products are delivered to
terminals owned by us, connecting pipelines and customer-owned
terminals. Petrochemicals are transported on our Products
Pipeline System between Mont Belvieu, Texas and Port Arthur,
Texas. Our Products Pipeline System transports NGLs from the
upper Texas Gulf Coast to the Central, Midwest and Northeast regions of
the United States and is
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the
only pipeline that transports NGLs from the upper Texas Gulf Coast to the
Northeast. The Centennial Pipeline effectively loops our
Products Pipeline System between Beaumont, Texas and southern
Illinois.
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Centennial
Pipeline is a regulated refined products pipeline system that extends from
Texas to Illinois. The Centennial Pipeline extends from an
origination facility located on our Products Pipeline System in Beaumont,
Texas, to Bourbon, Illinois. Centennial owns a 2.3 MMBbl
refined products storage terminal located near Creal Springs,
Illinois.
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Class
of Equipment
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Number
in Class
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Capacity
(bbl)/
Horsepower
(hp)
(as
indicated by sign)
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Inland
marine transportation assets:
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Barges
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32
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<
25,000 bbl
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Barges
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96
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>
25,000 bbl
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Tow
boats
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32
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<
2,000 hp
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Tow
boats
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30
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=/>
2,000 hp
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Offshore
marine transportation assets:
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Barges
(includes three single-bottom barges)
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8
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>
20,000 bbl
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Tow
boats
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4
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<
2,000 hp
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Tow
boats
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3
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>
2,000 hp
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§
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the
level of domestic production and consumer product
demand;
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the
availability of imported oil and natural gas and actions taken by foreign
oil and natural gas producing
nations;
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the
availability of transportation systems with adequate
capacity;
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the
availability of competitive fuels;
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fluctuating
and seasonal demand for oil, natural gas and
NGLs;
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the
impact of conservation efforts;
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the
extent of governmental regulation and taxation of production;
and
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the
overall economic environment.
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demand
for gasoline depends upon market price, prevailing economic conditions,
demographic changes in the markets we serve and availability of gasoline
produced in refineries located in these
markets;
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demand
for distillates is affected by truck and railroad freight, the price of
natural gas used by utilities that use distillates as a substitute and
usage for agricultural operations;
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demand
for jet fuel depends on prevailing economic conditions and military usage;
and
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propane
deliveries are generally sensitive to the weather and meaningful
year-to-year variances have occurred and will likely continue to
occur.
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§
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a
substantial portion of our cash flow, including that of Duncan Energy
Partners, could be dedicated to the payment of principal and interest on
our future debt and may not be available for other purposes, including the
payment of distributions on our common units and capital
expenditures;
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§
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credit
rating agencies may view our consolidated debt level
negatively;
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covenants
contained in our existing and future credit and debt arrangements will
require us to continue to meet financial tests that may adversely affect
our flexibility in planning for and reacting to changes in our business,
including possible acquisition
opportunities;
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§
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our
ability to obtain additional financing, if necessary, for working capital,
capital expenditures, acquisitions or other purposes may be impaired or
such financing may not be available on favorable
terms;
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§
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we
may be at a competitive disadvantage relative to similar companies that
have less debt; and
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§
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we
may be more vulnerable to adverse economic and industry conditions as a
result of our significant debt
level.
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difficulties
in the assimilation of the operations, technologies, services and products
of the acquired companies or business
segments;
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establishing
the internal controls and procedures that we are required to maintain
under the Sarbanes-Oxley Act of
2002;
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managing
relationships with new joint venture partners with whom we have not
previously partnered;
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experiencing
unforeseen operational interruptions or the loss of key employees,
customers or suppliers;
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inefficiencies
and complexities that can arise because of unfamiliarity with new assets
and the businesses associated with them, including with their
markets; and
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diversion
of the attention of management and other personnel from day-to-day
business to the development or acquisition of new businesses and other
business opportunities.
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we
may be unable to complete construction projects on schedule or at the
budgeted cost due to the unavailability of required construction personnel
or materials, accidents, weather conditions or an inability to obtain
necessary permits;
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§
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we
will not receive any material increases in revenues until the project is
completed, even though we may have expended considerable funds during the
construction phase, which may be
prolonged;
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we
may construct facilities to capture anticipated future growth in
production in a region in which such growth does not
materialize;
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§
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since
we are not engaged in the exploration for and development of natural gas
reserves, we may not have access to third-party estimates of reserves in
an area prior to our constructing facilities in the area. As a
result, we may construct facilities in an area where the reserves are
materially lower than we
anticipate;
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§
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where
we do rely on third-party estimates of reserves in making a decision to
construct facilities, these estimates may prove to be inaccurate because
there are numerous uncertainties inherent in estimating
reserves;
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the
completion or success of our project may depend on the completion of a
project that we do not control, such as a refinery, that may be subject to
numerous of its own potential risks, delays and complexities;
and
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we
may be unable to obtain rights-of-way to construct additional pipelines or
the cost to do so may be
uneconomical.
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§
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the
ownership interest of a unitholder immediately prior to the issuance will
decrease;
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§
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the
amount of cash available for distributions on each common unit may
decrease;
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§
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the
ratio of taxable income to distributions may
increase;
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§
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the
relative voting strength of each previously outstanding common unit may be
diminished; and
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the
market price of our common units may
decline.
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§
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the
volume of the products that we handle and the prices we receive for our
services;
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§
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the
level of our operating costs;
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the
level of competition in our business segments and marketing
areas;
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prevailing
economic conditions, including the price of and demand for oil, natural
gas and other products we transport, store and
market;
|
§
|
the
level of capital expenditures we
make;
|
§
|
the
amount and cost of capital we can raise compared to the amount of our
capital expenditures and debt
maturities;
|
§
|
the
restrictions contained in our debt agreements and our debt service
requirements;
|
§
|
fluctuations
in our working capital needs;
|
§
|
the
weather in our operating areas;
|
§
|
cash
outlays for acquisitions, if any;
and
|
§
|
the
amount, if any, of cash reserves required by EPGP in its sole
discretion.
|
§
|
neither
our partnership agreement nor any other agreement requires EPGP or EPCO to
pursue a business strategy that favors
us;
|
§
|
decisions
of EPGP regarding the amount and timing of asset purchases and sales, cash
expenditures, borrowings, issuances of additional units and reserves in
any quarter may affect the level of cash available to pay quarterly
distributions to unitholders and
EPGP;
|
§
|
under
our partnership agreement, EPGP determines which costs incurred by it and
its affiliates are reimbursable by
us;
|
§
|
EPGP
is allowed to resolve any conflicts of interest involving us and EPGP and
its affiliates;
|
§
|
EPGP
is allowed to take into account the interests of parties other than us,
such as EPCO, in resolving conflicts of interest, which has the effect of
limiting its fiduciary duty to
unitholders;
|
§
|
any
resolution of a conflict of interest by EPGP not made in bad faith and
that is fair and reasonable to us shall be binding on the partners and
shall not be a breach of our partnership
agreement;
|
§
|
affiliates
of EPGP may compete with us in certain
circumstances;
|
§
|
EPGP
has limited its liability and reduced its fiduciary duties and has also
restricted the remedies available to our unitholders for actions that
might, without the limitations, constitute breaches of fiduciary
duty. As a result of purchasing our units, you are deemed to
consent to some actions and conflicts of interest that might otherwise
constitute a breach of fiduciary or other duties under applicable
law;
|
§
|
we
do not have any employees and we rely solely on employees of EPCO and its
affiliates;
|
§
|
in
some instances, EPGP may cause us to borrow funds in order to permit the
payment of distributions, even if the purpose or effect of the borrowing
is to make incentive distributions;
|
§
|
our
partnership agreement does not restrict EPGP from causing us to pay it or
its affiliates for any services rendered to us or entering into additional
contractual arrangements with any of these entities on our
behalf;
|
§
|
EPGP
intends to limit its liability regarding our contractual and other
obligations and, in some circumstances, may be entitled to be indemnified
by us;
|
§
|
EPGP
controls the enforcement of obligations owed to us by our general partner
and its affiliates; and
|
§
|
EPGP
decides whether to retain separate counsel, accountants or others to
perform services for us.
|
§
|
we
were conducting business in a state, but had not complied with that
particular state’s partnership
statute; or
|
§
|
your
right to act with other unitholders to remove or replace our general
partner, to approve some amendments to our partnership agreement or to
take other actions under our partnership agreement constituted “control”
of our business.
|
Cash
Distribution History
|
|||||
Price
Ranges
|
Per
|
Record
|
Payment
|
||
High
|
Low
|
Unit
|
Date
|
Date
|
|
2008
|
|||||
1st
Quarter
|
$32.630
|
$26.750
|
$0.5075
|
Apr.
30, 2008
|
May
7, 2008
|
2nd
Quarter
|
$32.640
|
$29.040
|
$0.5150
|
Jul.
31, 2008
|
Aug.
7, 2008
|
3rd
Quarter
|
$30.070
|
$22.580
|
$0.5225
|
Oct.
31, 2008
|
Nov.
12, 2008
|
4th
Quarter
|
$26.300
|
$16.000
|
$0.5300
|
Jan.
30, 2009
|
Feb.
9, 2009
|
2009
|
|||||
1st
Quarter
|
$24.200
|
$17.710
|
$0.5375
|
Apr.
30, 2009
|
May
8, 2009
|
2nd
Quarter
|
$26.550
|
$21.100
|
$0.5450
|
Jul.
31, 2009
|
Aug.
7, 2009
|
3rd
Quarter
|
$29.450
|
$24.500
|
$0.5525
|
Oct.
30, 2009
|
Nov.
5, 2009
|
4th
Quarter
|
$32.240
|
$27.250
|
$0.5600
|
Jan.
29, 2010
|
Feb.
4, 2010
|
§
|
Cautionary
Note Regarding Forward-Looking
Statements.
|
§
|
Overview
of Business.
|
§
|
Basis
of Financial Statement
Presentation.
|
§
|
Significant
Recent Developments – Discusses significant developments during the year
ended December 31, 2009 and through the date of this
filing.
|
§
|
General
Outlook for 2010.
|
§
|
Results
of Operations – Discusses material year-to-year variances in our
Statements of Consolidated
Operations.
|
§
|
Liquidity
and Capital Resources – Addresses available sources of liquidity and
capital resources and includes a discussion of our capital spending
program.
|
§
|
Critical
Accounting Policies and Estimates.
|
§
|
Other
Items – Includes information related to contractual obligations,
off-balance sheet arrangements and other
matters.
|
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Revenues
|
$ | 25,510.9 | $ | 35,469.6 | $ | 26,713.8 | ||||||
Operating
costs and expenses
|
23,565.8 | 33,618.9 | 25,402.1 | |||||||||
General
and administrative costs
|
172.3 | 137.2 | 127.2 | |||||||||
Equity
in income of unconsolidated affiliates
|
51.2 | 34.9 | 10.5 | |||||||||
Operating
income
|
1,824.0 | 1,748.4 | 1,195.0 | |||||||||
Interest
expense
|
641.8 | 540.7 | 413.0 | |||||||||
Provision
for income taxes
|
25.3 | 31.0 | 15.7 | |||||||||
Net
income
|
1,155.1 | 1,188.9 | 838.0 | |||||||||
Net
income attributable to noncontrolling interest
|
124.2 | 234.9 | 304.4 | |||||||||
Net
income attributable to Enterprise Products Partners L.P.
|
1,030.9 | 954.0 | 533.6 |
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Gross
operating margin by segment:
|
||||||||||||
NGL
Pipelines & Services
|
$ | 1,628.7 | $ | 1,325.0 | $ | 848.0 | ||||||
Onshore
Natural Gas Pipelines & Services
|
501.5 | 589.9 | 493.2 | |||||||||
Onshore
Crude Oil Pipelines & Services
|
164.4 | 132.2 | 109.6 | |||||||||
Offshore
Pipeline & Services
|
180.5 | 187.0 | 171.6 | |||||||||
Petrochemical
& Refined Products Services
|
364.7 | 374.9 | 342.0 | |||||||||
Total
segment gross operating margin
|
$ | 2,839.8 | $ | 2,609.0 | $ | 1,964.4 |
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
NGL
Pipelines & Services:
|
||||||||||||
Sales
of NGLs
|
$ | 11,598.9 | $ | 14,573.5 | $ | 11,701.3 | ||||||
Sales
of other petroleum and related products
|
1.8 | 2.4 | 3.0 | |||||||||
Midstream
services
|
708.3 | 737.9 | 746.4 | |||||||||
Total
|
12,309.0 | 15,313.8 | 12,450.7 | |||||||||
Onshore
Natural Gas Pipelines & Services:
|
||||||||||||
Sales
of natural gas
|
2,410.5 | 3,083.1 | 1,676.7 | |||||||||
Midstream
services
|
739.4 | 733.3 | 649.2 | |||||||||
Total
|
3,149.9 | 3,816.4 | 2,325.9 | |||||||||
Onshore
Crude Oil Pipelines & Services:
|
||||||||||||
Sales
of crude oil
|
7,110.6 | 12,696.2 | 9,048.5 | |||||||||
Midstream
services
|
80.4 | 67.6 | 55.3 | |||||||||
Total
|
7,191.0 | 12,763.8 | 9,103.8 | |||||||||
Offshore
Pipelines & Services:
|
||||||||||||
Sales
of natural gas
|
1.2 | 2.8 | 3.2 | |||||||||
Sales
of crude oil
|
5.3 | 11.1 | 12.1 | |||||||||
Midstream
services
|
333.4 | 254.5 | 208.5 | |||||||||
Total
|
339.9 | 268.4 | 223.8 | |||||||||
Petrochemical
& Refined Products Services:
|
||||||||||||
Sales
of other petroleum and related products
|
1,991.8 | 2,757.6 | 2,207.2 | |||||||||
Midstream
services
|
529.3 | 549.6 | 402.4 | |||||||||
Total
|
2,521.1 | 3,307.2 | 2,609.6 | |||||||||
Total
consolidated revenues
|
$ | 25,510.9 | $ | 35,469.6 | $ | 26,713.8 |
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Net
cash flows provided by operating activities
|
$ | 2,377.2 | $ | 1,567.1 | $ | 1,953.6 | ||||||
Cash
used in investing activities
|
1,546.9 | 3,246.9 | 2,871.8 | |||||||||
Cash
provided by (used in) financing activities
|
(837.1 | ) | 1,690.7 | 946.3 |
§
|
Net
cash flows from consolidated operations (excluding distributions received
from unconsolidated affiliates, cash payments for interest and cash
payments for income taxes) increased $908.8 million
year-to-year. The increase in operating cash flow is generally
due to increased profitability and the timing of related cash receipts and
disbursements. The total year-to-year increase also reflects a
$68.9 million increase in operating cash proceeds we received from
insurance claims related to certain named storms. For
information regarding cash proceeds from business interruption and
property damage claims, see Note 19 of the Notes to Consolidated Financial
Statements included under Item 8 of this annual
report.
|
§
|
Cash
payments for interest increased $81.8 million year-to-year primarily due
to increased borrowings to finance our capital spending
program. Our average debt principal outstanding for 2009 was
$11.92 billion compared to $10.17 billion for
2008.
|
§
|
Cash
payments for income taxes increased $22.7 million year-to-year primarily
due to higher payments made for the Texas Margin tax and a taxable gain
incurred in 2009 arising from Dixie’s sale of certain
assets.
|
§
|
Capital
spending for property, plant and equipment, net of contributions in aid of
construction costs, decreased $945.9 million year-to-year. For
additional information related to our capital spending program, see
“Liquidity and Capital Resources – Capital Spending” included within this
Item 7.
|
§
|
Cash
used for business combinations decreased $446.2 million
year-to-year. Our 2009 business combinations primarily
consisted of the acquisition of certain rail and truck terminal facilities
located in Mont Belvieu, Texas, a pipeline system in Texas, and the
acquisition of tow boats and tank barges primarily based in Miami,
Florida, with additional assets located in Mobile, Alabama and Houston,
Texas. In 2008, our most significant business combinations
consisted of our acquisition of marine transportation
businesses. In addition, during 2008 we acquired 100% of the
membership interest in Great Divide Gathering LLC (“Great Divide”) and
additional interests in consolidated subsidiaries. For additional
information regarding our business combinations, see Note 10 of the Notes
to Consolidated Financial Statements included under Item 8 of this annual
report.
|
§
|
Restricted
cash related to our hedging activities decreased $140.2 million (a cash
inflow) during 2009 primarily due to the reduction of margin requirements
related to derivative instruments we utilized. For 2008,
restricted cash related to our hedging activities increased $132.8 million
(a cash outflow). See Note 6 of the Notes to Consolidated
Financial Statements included under Item 8 of this annual report for
information regarding our interest rate and commodity risk hedging
portfolios.
|
§
|
Net
repayments under our consolidated debt agreements of $276.9 million in
2009 compared to net borrowings under our consolidated debt agreements of
$2.75 billion in 2008. During 2008, EPO and TEPPCO issued a
combined $2.6 billion in principal amount of senior notes. For
information regarding our consolidated debt obligations see Note 12 of the
Notes to Consolidated Financial Statements included under Item 8 of this
annual report.
|
§
|
Cash
distributions paid to our partners increased $217.4 million year-to-year
primarily due to increases in our common units outstanding and quarterly
distribution rates.
|
§
|
Distributions
paid to noncontrolling interests decreased $43.9 million year-to-year
primarily due to the cessation of TEPPCO’s cash distributions following
the TEPPCO Merger.
|
§
|
Net
cash proceeds from the issuance of our common units increased $769.9
million year-to-year due to underwritten and private equity offerings in
2009 along with increased participation in our
DRIP.
|
§
|
Contributions
from noncontrolling interests decreased $172.8 million year-to-year
primarily due to the $137.4 million of net cash proceeds that Duncan
Energy Partners received from the issuance of its common units in June and
July 2009 compared to net cash proceeds of $271.3 million received from
unit offerings of TEPPCO during
2008.
|
§
|
Net
cash flows from consolidated operations (excluding distributions received
from unconsolidated affiliates and cash payments for interest) decreased
$240.1 million year-to-year. Although our gross operating
margin increased year-to-year (see “Results of Operations” within this
Item 7), the reduction in operating cash flow is generally due to the
timing of related cash receipts and disbursements. The $240.1
million total year-to-year decrease also reflects a $127.3 million
decrease in cash proceeds we received from insurance claims related to
certain named storms. For information regarding cash proceeds
from business interruption and property damage claims, see Note 19 of the
Notes to Consolidated Financial Statements included under Item 8 of this
annual report.
|
§
|
Cash
payments for interest increased $140.2 million year-to-year primarily due
to increased borrowings to finance our capital spending
program. Our average debt balance for 2008 was $10.17 billion
compared to $7.82 billion for 2007.
|
§
|
Cash
used for business combinations increased $517.5 million year-to-year,
primarily due to approximately $346.0 million in business combinations
related to our marine transportation businesses. In addition,
during 2008 we acquired 100% of the membership interest in Great Divide
and additional interest in consolidated
subsidiaries.
|
§
|
Capital
spending for property, plant and equipment, net of contributions in aid of
construction costs, decreased $194.0 million year-to-year. For
additional information related to our capital
spending
program, see “Liquidity and Capital Resources – Capital Spending” included
within this Item 7.
|
§
|
Proceeds
from the sale of assets and related transactions decreased $146.9 million
year-to-year primarily due to the sale of certain equity interests and
related storage assets located in Mont Belvieu, Texas during
2007.
|
§
|
Cash
outlays for investments in unconsolidated affiliates decreased by $172.1
million year-to-year. Expenditures for 2007 include the $216.5
million we contributed to Cameron Highway during the second quarter of
2007. Cameron Highway used these funds, along with an equal
contribution from our 50% joint venture partner in Cameron Highway, to
repay approximately $430.0 million of its outstanding
debt. Expenditures for 2008 include (i) $22.5 million in
contributions to White River Hub, (ii) $11.1 million in contributions to
Centennial and (iii) $36.0 million to acquire a 49% interest in
Skelly-Belvieu.
|
§
|
An
$85.5 million increase in restricted cash (a cash outflow) due to margin
requirements related to our hedging activities. See Note 6 of
the Notes to Consolidated Financial Statements included under Item 8 of
this annual report for information regarding our interest rate and
commodity risk hedging portfolios.
|
§
|
Net
borrowings under our consolidated debt agreements increased $923.8 million
year-to-year. During 2008, we and TEPPCO issued a combined $2.6
billion in principal amount of senior notes. For information
regarding our consolidated debt obligations, see Note 12 of the Notes to
Consolidated Financial Statements included under Item 8 of this annual
report.
|
§
|
Net
cash proceeds from the issuance of our common units increased $73.6
million year-to-year due to increased participation in our
DRIP.
|
§
|
Cash
distributions paid to our partners increased $79.7 million year-to-year
primarily due to increases in our common units outstanding and quarterly
distribution rates.
|
§
|
Distributions
paid to noncontrolling interests increased $57.1 million year-to-year
primarily due to increases in the quarterly distribution rates of Duncan
Energy Partners and TEPPCO, along with an increase in TEPPCO’s units
outstanding.
|
§
|
The
early termination and settlement of interest rate hedging derivative
instruments during 2008 resulted in net cash payments of $66.5 million
compared to net cash receipts of $49.1 million during the same period in
2007, which resulted in a $115.6 million decrease in financing cash flows
between years.
|
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Expensed
|
$ | 44.9 | $ | 55.4 | $ | 51.9 | ||||||
Capitalized
|
37.7 | 86.2 | 78.9 | |||||||||
Total
|
$ | 82.6 | $ | 141.6 | $ | 130.8 |
§
|
changes
in laws and regulations that limit the estimated economic life of an
asset;
|
§
|
changes
in technology that render an asset
obsolete;
|
§
|
changes
in expected salvage values; or
|
§
|
changes
in the forecast life of applicable resource basins, if
any.
|
§
|
the
expected useful life of the related tangible assets (e.g., fractionation
facility, pipeline or other asset);
|
§
|
any
legal or regulatory developments that would impact such contractual
rights; and
|
§
|
any
contractual provisions that enable us to renew or extend such
agreements.
|
§
|
discrete
financial forecasts for the assets classified within the reporting unit,
which rely on management’s estimates of operating margins and
transportation volumes;
|
§
|
long-term
growth rates for cash flows beyond the discrete forecast period;
and
|
§
|
appropriate
discount rates.
|
§
|
persuasive
evidence of an exchange arrangement
exists;
|
§
|
delivery
has occurred or services have been
rendered;
|
§
|
the
buyer’s price is fixed or determinable;
and
|
§
|
collectability
is reasonably assured.
|
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 long-term debt (1)
|
$ | 11,297.0 | $ | 554.0 | $ | 2,102.8 | $ | 2,350.0 | $ | 6,290.2 | ||||||||||
Estimated
cash payments for interest (2)
|
12,372.2 | 667.4 | 1,190.2 | 939.4 | 9,575.2 | |||||||||||||||
Operating
lease obligations (3)
|
343.9 | 37.6 | 68.0 | 48.8 | 189.5 | |||||||||||||||
Purchase
obligations: (4)
|
||||||||||||||||||||
Product
purchase commitments:
|
||||||||||||||||||||
Estimated
payment obligations:
|
||||||||||||||||||||
Natural
gas
|
5,697.6 | 1,308.9 | 1,381.8 | 959.3 | 2,047.6 | |||||||||||||||
NGLs
|
2,943.0 | 997.0 | 669.1 | 659.4 | 617.5 | |||||||||||||||
Crude
oil
|
237.3 | 237.3 | -- | -- | -- | |||||||||||||||
Petrochemicals
& refined products
|
2,642.2 | 1,486.6 | 824.5 | 186.3 | 144.8 | |||||||||||||||
Other
|
114.1 | 21.2 | 24.1 | 22.8 | 46.0 | |||||||||||||||
Underlying
major volume commitments:
|
||||||||||||||||||||
Natural
gas (in BBtus)
|
969,180 | 221,530 | 230,450 | 165,008 | 352,192 | |||||||||||||||
NGLs
(in MBbls)
|
49,300 | 19,048 | 10,496 | 10,316 | 9,440 | |||||||||||||||
Crude
oil (in MBbls)
|
2,985 | 2,985 | -- | -- | -- | |||||||||||||||
Petrochemicals
& refined products (in MBbls)
|
35,034 | 19,523 | 11,122 | 2,469 | 1,920 | |||||||||||||||
Service
payment commitments (5)
|
575.6 | 72.0 | 113.7 | 110.1 | 279.8 | |||||||||||||||
Capital
expenditure commitments (6)
|
497.5 | 497.5 | -- | -- | -- | |||||||||||||||
Other
long-term liabilities (7)
|
155.2 | -- | 30.2 | 15.2 | 109.8 | |||||||||||||||
Total
|
$ | 36,875.6 | $ | 5,879.5 | $ | 6,404.4 | $ | 5,291.3 | $ | 19,300.4 | ||||||||||
(1)
Represents
our scheduled future maturities of consolidated debt principal
obligations. For additional information regarding our consolidated
debt obligations, see Note 12 of the Notes to Consolidated Financial
Statements included under Item 8 of this annual report.
(2)
Our
estimated cash payments for interest are based on the principal amount of
consolidated debt obligations outstanding at December 31, 2009. With
respect to variable-rate debt obligations, we applied the weighted-average
interest rate paid during 2009 associated with such debt. See Note 12
of the Notes to Consolidated Financial Statements included under Item 8 of
this annual report for the weighted-average variable interest rates
charged in 2009 under our credit agreements. In addition, our
estimate of cash payments for interest gives effect to interest rate swap
agreements that were in place at December 31, 2009. See Note 6 of the
Notes to Consolidated Financial Statements included under Item 8 of this
annual report for information regarding these derivative
instruments. Our estimated cash payments for interest are
significantly influenced by the long-term maturities of our $550.0 million
Junior Subordinated Notes A (due August 2066), $682.7 million Junior
Subordinated Notes B (due January 2068), $300.0 million Junior
Subordinated Notes C (due June 2067) and TEPPCO Junior Subordinated Notes
(due June 2067). Our estimated cash payments for interest assume that
these subordinated notes are not called prior to their respective maturity
dates.
(3)
Primarily
represents operating leases for (i) underground caverns for the storage of
natural gas and NGLs, (ii) leased office space with an affiliate of EPCO
and (iii) land held pursuant to right-of-way agreements.
(4)
Represents
enforceable and legally binding agreements to purchase goods or services
under the terms of each agreement at December 31, 2009. The estimated
payment obligations are based on contractual prices in effect at December
31, 2009 applied to all future volume commitments. Actual future
payment obligations may vary depending on prices at the time of
delivery.
(5)
Represents
future payment commitments for services provided by
third-parties.
(6)
Represents
short-term unconditional payment obligations relating to our capital
projects, including our share of those of our unconsolidated affiliates,
for services rendered or products purchased.
(7)
As
reflected on our Consolidated Balance Sheet at December 31, 2009, other
long-term liabilities primarily represent noncurrent portions
of asset retirement obligations, reserves for environmental
remediation costs, accrued pipeline transportation deficiency fees,
deferred revenues and the Centennial guarantee.
|
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Total
segment gross operating margin
|
$ | 2,839.8 | $ | 2,609.0 | $ | 1,964.4 | ||||||
Adjustments
to reconcile total segment gross operating margin
|
||||||||||||
to
operating income:
|
||||||||||||
Depreciation,
amortization and accretion in operating costs and expenses
|
(809.3 | ) | (725.4 | ) | (647.9 | ) | ||||||
Impairment
charges in operating costs and expenses
|
(33.5 | ) | -- | -- | ||||||||
Operating
lease expenses paid by EPCO
|
(0.7 | ) | (2.0 | ) | (2.1 | ) | ||||||
Gain
from asset sales and related transactions in operating
costs
and expenses
|
-- | 4.0 | 7.8 | |||||||||
General
and administrative costs
|
(172.3 | ) | (137.2 | ) | (127.2 | ) | ||||||
Operating
income
|
1,824.0 | 1,748.4 | 1,195.0 | |||||||||
Other
expense, net
|
(643.6 | ) | (528.5 | ) | (341.3 | ) | ||||||
Income
before provision for income taxes
|
$ | 1,180.4 | $ | 1,219.9 | $ | 853.7 |
§
|
Fair
Value Measurements; and
|
§
|
Consolidation
of Variable Interest Entities.
|
Enterprise
Products Partners (excluding
Duncan
Energy Partners)
|
Swap
Fair Value at
|
||||||||||||
Resulting
|
December
31,
|
December
31,
|
January
31,
|
||||||||||
Scenario
|
Classification
|
2008
|
2009
|
2010
|
|||||||||
FV
assuming no change in underlying interest rates
|
Asset
|
$ | 46.7 | $ | 41.3 | $ | 53.2 | ||||||
FV
assuming 10% increase in underlying interest rates
|
Asset
|
42.4 | 35.0 | 47.9 | |||||||||
FV
assuming 10% decrease in underlying interest rates
|
Asset
|
51.1 | 47.8 | 58.5 |
Duncan
Energy Partners
|
Swap
Fair Value at
|
||||||||||||
Resulting
|
December
31,
|
December
31,
|
January
31,
|
||||||||||
Scenario
|
Classification
|
2008
|
2009
|
2010
|
|||||||||
FV
assuming no change in underlying interest rates
|
Liability
|
$ | (9.8 | ) | $ | (5.5 | ) | $ | (5.7 | ) | |||
FV
assuming 10% increase in underlying interest rates
|
Liability
|
(9.4 | ) | (5.5 | ) | (5.7 | ) | ||||||
FV
assuming 10% decrease in underlying interest rates
|
Liability
|
(10.2 | ) | (5.6 | ) | (5.7 | ) |
Swap
Fair Value at
|
|||||||||
Scenario
|
Resulting
Classification
|
December
31,
2009
|
January
31,
2010
|
||||||
FV
assuming no change in underlying interest rates
|
Asset
|
$ | 21.0 | $ | 13.3 | ||||
FV
assuming 10% increase in underlying interest rates
|
Asset
|
31.1 | 26.1 | ||||||
FV
assuming 10% decrease in underlying interest rates
|
Asset
(Liability)
|
10.5 | (0.5 | ) |
Swap
Fair Value at
|
|||||||||||||
Resulting
|
December
31,
|
December
31,
|
January
31,
|
||||||||||
Scenario
|
Classification
|
2008
|
2009
|
2010
|
|||||||||
FV
assuming no change in underlying commodity prices
|
Asset
(Liability)
|
$ | 6.5 | $ | (1.5 | ) | $ | (2.3 | ) | ||||
FV
assuming 10% increase in underlying commodity prices
|
Asset
(Liability)
|
2.7 | (7.0 | ) | (6.3 | ) | |||||||
FV
assuming 10% decrease in underlying commodity prices
|
Asset
|
9.9 | 4.1 | 1.8 |
Swap
Fair Value at
|
|||||||||||||
Resulting
|
December
31,
|
December
31,
|
January
31,
|
||||||||||
Scenario
|
Classification
|
2008
|
2009
|
2010
|
|||||||||
FV
assuming no change in underlying commodity prices
|
Asset
(Liability)
|
$ | (102.1 | ) | $ | (9.2 | ) | $ | 21.3 | ||||
FV
assuming 10% increase in underlying commodity prices
|
Liability
|
(94.0 | ) | (43.2 | ) | (19.5 | ) | ||||||
FV
assuming 10% decrease in underlying commodity prices
|
Asset
(Liability)
|
(110.1 | ) | 24.8 | 62.0 |
Swap
Fair Value at
|
|||||||||||||
Resulting
|
December
31,
|
December
31,
|
January
31,
|
||||||||||
Scenario
|
Classification
|
2008
|
2009
|
2010
|
|||||||||
FV
assuming no change in underlying commodity prices
|
Asset
|
$ | -- | $ | 2.0 | $ | 1.1 | ||||||
FV
assuming 10% increase in underlying commodity prices
|
Asset
|
-- | 2.0 | 1.1 | |||||||||
FV
assuming 10% decrease in underlying commodity prices
|
Asset
|
-- | 2.1 | 1.1 |
§
|
the
forward sale of a portion of our expected equity NGL production at fixed
prices through December 2010, achieved through the use of forward physical
sales and commodity derivative instruments
and
|
§
|
the
purchase of commodity derivative instruments with a notional amount
determined by the amount of natural gas expected to be consumed as PTR in
the production of such equity NGL
production.
|
(i)
|
that
our disclosure controls and procedures are designed to ensure that
information required to be disclosed by us in the reports that we file or
submit under the Securities Exchange Act of 1934 is recorded, processed,
summarized and reported within the time periods specified in the SEC’s
rules and forms, and that such information is accumulated and communicated
to our management, including the CEO and CFO, as appropriate to allow
timely decisions regarding required disclosure;
and
|
(ii)
|
that
our disclosure controls and procedures are
effective.
|
/s/
Michael A. Creel
|
/s/
W. Randall Fowler
|
|||
Name:
|
Michael
A. Creel
|
Name:
|
W.
Randall Fowler
|
|
Title:
|
Chief
Executive Officer of
|
Title:
|
Chief
Financial Officer of
|
|
our
general partner,
|
our
general partner,
|
|||
Enterprise
Products GP, LLC
|
Enterprise
Products GP, LLC
|
§
|
reviewing
potential conflicts of interests, including related party
transactions;
|
§
|
monitoring
the integrity of our financial reporting process and related systems of
internal control;
|
§
|
ensuring
our legal and regulatory compliance and that of
EPGP;
|
§
|
overseeing
the independence and performance of our independent public
accountant;
|
§
|
approving
all services performed by our independent public
accountant;
|
§
|
providing
for an avenue of communication among the independent public accountant,
management, internal audit function and the
Board;
|
§
|
encouraging
adherence to and continuous improvement of our policies, procedures and
practices at all levels;
|
§
|
reviewing
areas of potential significant financial risk to our businesses;
and
|
§
|
approving
awards granted under our long-term incentive
plans.
|
Name
|
Age
|
Position
with EPGP
|
Dan
L. Duncan (1)
|
77
|
Director
and Chairman
|
Michael
A. Creel (1)
|
56
|
Director,
President and CEO
|
W.
Randall Fowler (1)
|
53
|
Director,
Executive Vice President and CFO
|
Richard
H. Bachmann (1)
|
57
|
Director,
Executive Vice President, Chief Legal Officer and
Secretary
|
A.
James Teague (1)
|
64
|
Director,
Executive Vice President and Chief Commercial Officer
|
Dr.
Ralph S. Cunningham
|
69
|
Director
|
E.
William Barnett (2,3)
|
77
|
Director
|
Rex
C. Ross (2)
|
66
|
Director
|
Charles
M. Rampacek (2)
|
66
|
Director
|
William
Ordemann (1)
|
50
|
Executive
Vice President and Chief Operating Officer
|
Lynn
L. Bourdon, III (1)
|
48
|
Senior
Vice President
|
Bryan
F. Bulawa (1)
|
40
|
Senior
Vice President and Treasurer
|
James
M. Collingsworth (1)
|
55
|
Senior
Vice President
|
Mark
Hurley (1)
|
51
|
Senior
Vice President
|
Michael
J. Knesek (1)
|
55
|
Senior
Vice President, Controller and Principal Accounting
Officer
|
Christopher
Skoog (1)
|
46
|
Senior
Vice President
|
Thomas
M. Zulim (1)
|
52
|
Senior
Vice President
|
(1)
Executive
officer
(2)
Member
of ACG Committee
(3)
Chairman
of ACG Committee
|
Cash
|
Cash
|
Unit
|
Option
|
All
Other
|
|||||||||||||||||||||
Name
and
|
Salary
|
Bonus
|
Awards
|
Awards
|
Comp.
|
Total
|
|||||||||||||||||||
Principal
Position
|
Year
|
($)
|
($)
(1)
|
($)
(2)
|
($)
(3)
|
($)
(4)
|
($)
|
||||||||||||||||||
Michael
A. Creel
|
2009
|
$ | 580,000 | $ | 1,280,000 | $ | 2,616,695 | $ | 718,920 | $ | 216,630 | $ | 5,412,245 | ||||||||||||
(President
and CEO)
|
2008
|
563,200 | 552,000 | 3,668,620 | 171,360 | 200,241 | 5,155,421 | ||||||||||||||||||
2007
|
361,808 | 365,370 | 1,435,901 | 94,390 | 108,017 | 2,365,486 | |||||||||||||||||||
W.
Randall Fowler
|
2009
|
206,719 | 354,375 | 973,475 | 242,422 | 80,271 | 1,857,262 | ||||||||||||||||||
(Executive
Vice President and CFO)
|
2008
|
190,781 | 131,250 | 1,377,456 | 53,550 | 62,646 | 1,815,683 | ||||||||||||||||||
2007
|
213,145 | 129,720 | 1,026,528 | 57,526 | 53,425 | 1,480,344 | |||||||||||||||||||
A.
James Teague
|
2009
|
650,000 | 950,000 | 2,445,585 | 665,400 | 233,747 | 4,944,732 | ||||||||||||||||||
(Executive
Vice President and
|
2008
|
558,333 | 500,000 | 3,627,701 | 142,800 | 176,651 | 5,005,485 | ||||||||||||||||||
Chief
Commercial Officer)
|
2007
|
445,660 | 300,000 | 2,175,230 | 160,800 | 110,336 | 3,192,026 | ||||||||||||||||||
William
Ordemann
|
2009
|
395,200 | 310,000 | 1,643,242 | 565,950 | 220,470 | 3,134,862 | ||||||||||||||||||
(Executive
Vice President and
|
2008
|
391,400 | 265,000 | 1,779,805 | 142,800 | 157,884 | 2,736,889 | ||||||||||||||||||
Chief
Operating Officer)
|
2007
|
331,337 | 228,000 | 1,554,414 | 80,400 | 86,671 | 2,280,822 | ||||||||||||||||||
Richard
H. Bachmann
|
2009
|
346,688 | 510,625 | 1,480,455 | 357,653 | 127,103 | 2,822,524 | ||||||||||||||||||
(Executive
Vice President and
|
2008
|
351,313 | 233,750 | 2,140,435 | 78,540 | 129,921 | 2,933,959 | ||||||||||||||||||
Chief
Legal Officer)
|
2007
|
306,900 | 186,000 | 1,264,670 | 83,134 | 94,752 | 1,935,456 | ||||||||||||||||||
(1)
Amounts
represent discretionary annual cash awards accrued with respect to the
years presented. Cash awards are paid in February of the following
year (e.g., the cash awards for 2009 were paid in February
2010).
(2)
Amounts
represent the aggregate grant date fair value of restricted unit and
profits interests awards in the Employee Partnerships granted during each
year presented. For information about assumptions made in the
valuation of these awards, see Note 5 of the Notes to Consolidated
Financial Statements included under Item 8 of this annual report, which
information is incorporated by reference herein.
(3)
Amounts
represent the aggregate grant date fair value of unit option awards
granted during each year presented. For information about assumptions
made in the valuation of these awards, see Note 5 of the Notes to
Consolidated Financial Statements included under Item 8 of this annual
report, which information is incorporated by reference
herein.
(4)
Amounts
primarily represent (i) matching contributions under funded, qualified,
defined contribution retirement plans, (ii) quarterly distributions paid
on incentive plan awards and (iii) the imputed value of life insurance
premiums paid on behalf of the officer.
|
Enterprise
|
EPCO
and
|
Total
|
||
Products
|
other
|
Time
|
||
Named
Executive Officer
|
Year
|
Partners
|
affiliates
|
Allocated
|
Michael
A. Creel (CEO)
|
2009
|
80%
|
20%
|
100%
|
2008
|
80%
|
20%
|
100%
|
|
2007
|
59%
|
41%
|
100%
|
|
W.
Randall Fowler (CFO)
|
2009
|
40%
|
60%
|
100%
|
2008
|
38%
|
62%
|
100%
|
|
2007
|
48%
|
52%
|
100%
|
|
A.
James Teague
|
2009
|
100%
|
--
|
100%
|
2008
|
100%
|
--
|
100%
|
|
2007
|
100%
|
--
|
100%
|
|
William
Ordemann
|
2009
|
100%
|
--
|
100%
|
2008
|
100%
|
--
|
100%
|
|
2007
|
100%
|
--
|
100%
|
|
Richard
H. Bachmann
|
2009
|
54%
|
46%
|
100%
|
2008
|
55%
|
45%
|
100%
|
|
2007
|
52%
|
48%
|
100%
|
§
|
Annual
cash base salary;
|
§
|
Discretionary
annual cash bonus awards;
|
§
|
Awards
under long-term incentive arrangements;
and
|
§
|
Other
compensation, including very limited
perquisites.
|
Percentage
Ownership of Class B Interests
|
||||||||||||||||
EPE
|
EPE
|
Enterprise
|
EPCO
|
|||||||||||||
Named
Executive Officer
|
Unit
I
|
Unit
III
|
Unit
|
Unit
|
||||||||||||
Michael
A. Creel (CEO)
|
9.3 | % | 8.9 | % | 18.5 | % | 20.0 | % | ||||||||
W.
Randall Fowler (CFO)
|
6.2 | % | 8.9 | % | 8.2 | % | 20.0 | % | ||||||||
A.
James Teague
|
6.2 | % | 7.4 | % | 10.3 | % | 20.0 | % | ||||||||
Richard
H. Bachmann
|
9.3 | % | 8.9 | % | 10.3 | % | 20.0 | % | ||||||||
William
Ordemann
|
3.1 | % | 5.2 | % | 8.2 | % | -- |
Option
Awards
|
Unit
Awards
|
|||
Number
of
|
Gross
|
Number
of
|
Gross
|
|
Units
|
Value
|
Units
|
Value
|
|
Acquired
on
|
Realized
on
|
Acquired
on
|
Realized
on
|
|
Exercise
|
Exercise
|
Vesting
|
Vesting
|
|
Name
|
(#)
|
($)
(1)
|
(#)
|
($)
(2)
|
Michael
A. Creel (CEO)
|
35,000
|
$330,400
|
10,000
|
$280,500
|
W.
Randall Fowler (CFO)
|
10,000
|
93,200
|
6,000
|
168,300
|
A.
James Teague
|
35,000
|
326,200
|
10,000
|
280,500
|
Richard
H. Bachmann
|
35,000
|
330,400
|
10,000
|
280,500
|
William
Ordemann
|
--
|
--
|
16,000
|
451,900
|
(1)
Amount
determined by multiplying the number of units acquired on exercise of the
options by the difference between the closing price of Enterprise Products
Partners’ common units on the date of exercise less the exercise
price.
(2)
Amount
determined by multiplying the number of restricted unit awards that vested
during 2009 by the closing price of Enterprise Products Partners’ common
units on the date of vesting.
|
Submitted by: | Dan L. Duncan |
Michael A. Creel | |
E. William Barnett | |
Charles M. Rampacek | |
Rex C. Ross | |
Richard H. Bachmann | |
Ralph S. Cunningham | |
W. Randall Fowler | |
A. James Teague |
Fees
Earned
|
|
or
Paid
|
|
in
Cash
|
|
Name
|
($)
|
E.
William Barnett
|
$ 90,000
|
Rex
C. Ross
|
$ 75,000
|
Charles
M. Rampacek
|
$ 75,000
|
§
|
Each
independent director will receive $75,000 in cash
annually;
|
§
|
If
the individual serves as chairman of a committee of the Board of
Directors, then he will receive an additional $15,000 in cash
annually;
|
§
|
Each
independent director will receive a meeting fee of $1,500 in cash for each
meeting of the Board attended. In addition, each independent
director will receive a meeting fee of $1,500 in cash for each meeting of
a duly appointed committee of the Board attended, provided that he is duly
elected or appointed to the committee;
and
|
§
|
Each
independent director shall receive an annual grant of our common units
having a fair market value, based on the closing price of our common units
on the trading day immediately preceding the date of grant, of
$75,000.
|
Amount
and
|
|||
Nature
of
|
|||
Title
of
|
Name
and Address
|
Beneficial
|
Percent
|
Class
|
of
Beneficial Owner
|
Ownership
|
of
Class
|
Common
units
|
Dan
L. Duncan
|
186,843,182
(1)
|
30.8%
|
1100
Louisiana Street, 10
th
Floor
|
|||
Houston,
Texas 77002
|
|||
Class
B units
|
Dan
L. Duncan
|
4,520,431
|
100%
|
1100
Louisiana Street, 10
th
Floor
|
|||
Houston,
Texas 77002
|
|||
(1)
For
a detailed listing of ownership amounts that comprise Mr. Duncan’s total
beneficial ownership of our common units, see the table presented in the
following section, “Security Ownership of Management,” within this Item
12.
|
Duncan
Energy Partners L.P. Common Units
|
||||||||
Amount
|
||||||||
and
Nature of
|
||||||||
Name
of
|
Beneficial
|
Percent
of
|
||||||
Beneficial
Owner
|
Ownership
|
Class
|
||||||
Dan
L. Duncan:
|
||||||||
Units
owned by EPCO Holdings, Inc.
|
99,453 | * | ||||||
Units
owned by EPO
|
33,783,587 | 58.6 | % | |||||
Units
owned by DD Securities LLC
|
103,100 | * | ||||||
Units
owned personally
|
382,500 | * | ||||||
Total
for Dan L. Duncan
|
34,368,640 | 59.6 | % | |||||
Michael
A. Creel (1)
|
7,500 | * | ||||||
W.
Randall Fowler (1,2)
|
2,000 | * | ||||||
Richard
H. Bachmann (1,3)
|
14,172 | * | ||||||
A.
James Teague (1)
|
6,000 | * | ||||||
William
Ordemann (1)
|
3,810 | * | ||||||
Dr.
Ralph S. Cunningham
|
3,000 | * | ||||||
All
current directors and executive officers of EPGP,
|
||||||||
as
a group (16 individuals in total)
|
34,435,712 | 59.7 | % | |||||
*
The beneficial ownership of each individual is less than 1% of the
registrant’s units outstanding.
|
||||||||
(1)
These
individuals are named executive officers for 2009.
(2)
Mr.
Fowler is the CFO of Duncan Energy Partners.
(3)
Mr.
Bachmann is the CEO of Duncan Energy Partners.
|
§
|
each
non-management director of our general partner is required to own our
common units having an aggregate value (as defined in the guidelines) of
three times the dollar amount of such non-management director’s aggregate
annual cash retainer for service on the Board paid for the most recently
completed calendar year; and
|
§
|
each
executive officer of our general partner is required to own our common
units having an aggregate value (as defined in the guidelines) of three
times the dollar amount of such executive officer’s aggregate annual base
salary for the most recently completed calendar year; provided, however,
that the value of any units representing limited partnership interests in
Duncan Energy Partners or Enterprise GP Holdings (each of which we refer
to as an “Affiliated MLP”), owned by an executive officer of our general
partner who is also an executive officer of the general partner of such
Affiliated MLP, shall be counted toward the equity ownership requirements
set forth above.
|
Number
of
|
||||||||||||
Units
|
||||||||||||
Remaining
|
||||||||||||
Available
For
|
||||||||||||
Number
of
|
Future
Issuance
|
|||||||||||
Units
to
|
Weighted-
|
Under
Equity
|
||||||||||
Be
Issued
|
Average
|
Compensation
|
||||||||||
Upon
Exercise
|
Exercise
Price
|
Plans
(excluding
|
||||||||||
of
Outstanding
|
of
Outstanding
|
securities
|
||||||||||
Common
Unit
|
Common
Unit
|
reflected
in
|
||||||||||
Plan
Category
|
Options
|
Options
|
column
(a)
|
|||||||||
(a)
|
(b)
|
(c)
|
||||||||||
Equity
compensation plans approved by unitholders:
|
||||||||||||
1998
Plan (1)
|
1,572,500 | $ | 27.30 | 652,543 | ||||||||
2006
Plan (2)
|
118,420 | $ | 26.11 | n/a | ||||||||
2008
Plan (3)
|
2,135,000 | $ | 25.97 | 7,865,000 | ||||||||
Equity
compensation plans not approved by unitholders:
|
||||||||||||
None
|
-- | -- | -- | |||||||||
Total
for equity compensation plans
|
3,825,920 | $ | 26.52 | 8,517,543 | ||||||||
(1)
Of
the 1,572,500 unit options outstanding at December 31, 2009, 447,500 were
immediately exercisable, an additional 410,000, 685,000 and 30,000 options
are exercisable in 2010, 2012 and 2013, respectively.
(2)
No
additional awards are expected to be issued under the 2006
Plan.
(3)
Of
the 2,135,000 unit options outstanding at December 31, 2009, 705,000 are
exercisable in 2013 and 1,430,000 are exercisable in 2014.
|
§
|
for
which Board approval is required by our management authorization policy,
as such policy may be amended from time to
time;
|
§
|
where
an officer or director of the general partner or any of our subsidiaries
is a party, without regard to the size of the
transaction;
|
§
|
when
requested to do so by management or the Board;
or
|
§
|
pursuant
to our partnership agreement or the limited liability company agreement of
the general partner, as such agreements may be amended from time to
time.
|
§
|
Duncan
Energy Partners’ June 2009 repurchase from EPO of 8,943,400 Duncan Energy
Partners common units in connection with the transactions described in
“Liquidity and Capital Resources – Registration Statements” included under
Item 7 of this annual report;
|
§
|
the
TEPPCO Merger; and
|
§
|
our
September 2009 issuance and sale of 5,940,594 of our common units in a
private placement to EPCO Holdings, Inc., a privately held affiliate
controlled by Dan L. Duncan, for $150.0 million (as more fully described
in “Recent Sales of Unregistered Securities” included under Item 5 of this
annual report).
|
§
|
asset
purchase or sale transactions;
|
§
|
capital
expenditures; and
|
§
|
purchase
orders and operating and administrative expenses not governed by the
ASA.
|
§
|
If
a business opportunity to acquire “equity securities” (as defined
below)
is
presented to the EPCO Group, or to Enterprise Products Partners (including
EPGP), Enterprise GP Holdings (including EPE Holdings), or Duncan Energy
Partners (including DEP GP), then Enterprise GP Holdings will have the
first right to pursue such opportunity. The term “equity
securities” is defined to
include:
|
§
|
general
partner interests (or securities which have characteristics similar to
general partner interests) or interests in “persons” that own or control
such general partner or similar interests (collectively, “GP Interests”)
and securities convertible, exercisable, exchangeable or otherwise
representing ownership or control of such GP Interests;
and
|
§
|
incentive
distribution rights (“IDRs”) and limited partner interests (or securities
which have characteristics similar to IDRs or limited partner interests)
in publicly traded partnerships or interests in “persons” that own or
control such limited partner or similar interests (collectively, “non-GP
Interests”); provided that such non-GP Interests are associated with GP
Interests and are owned by the owners of GP Interests or their respective
affiliates.
|
§
|
If
any business opportunity not covered by the preceding bullet point (i.e.,
not involving equity securities) is presented to the EPCO Group, or to
Enterprise Products Partners (including EPGP), Enterprise GP Holdings
(including EPE Holdings), or Duncan Energy Partners (including DEP GP),
Enterprise Products Partners will have the first right to pursue such
opportunity either for itself or, if desired by Enterprise Products
Partners in its sole discretion, for the benefit of Duncan Energy
Partners. It will be presumed that Enterprise Products Partners
will pursue the business opportunity until such time as its general
partner advises the EPCO Group, EPE Holdings and DEP GP that it has
abandoned the pursuit of such business
opportunity.
|
§
|
the
relative interests of any party to such conflict, agreement, transaction
or situation and the benefits and burdens relating to such
interest;
|
§
|
the
totality of the relationships between the parties involved (including
other transactions that may be particularly favorable or advantageous to
us);
|
§
|
any
customary or accepted industry practices and any customary or historical
dealings with a particular person;
|
§
|
any
applicable generally accepted accounting or engineering practices or
principles;
|
§
|
the
relative cost of capital of the parties and the consequent rates of return
to the equity holders of the parties;
and
|
§
|
such
additional factors as the committee determines in its sole discretion to
be relevant, reasonable or appropriate under the
circumstances.
|
§
|
assessing
the business rationale for the
transaction;
|
§
|
reviewing
the terms and conditions of the proposed transaction, including
consideration and financing requirements, if
any;
|
§
|
assessing
the effect of the transaction on our earnings and distributable cash flow
per unit, and on our results of operations, financial condition,
properties or prospects;
|
§
|
conducting
due diligence, including by interviews and discussions with management and
other representatives and by reviewing transaction materials and findings
of management and other
representatives;
|
§
|
considering
the relative advantages and disadvantages of the transactions to the
parties;
|
§
|
engaging
third-party financial advisors to provide financial advice and assistance,
including by providing fairness opinions if
requested;
|
§
|
engaging
legal advisors; and
|
§
|
evaluating
and negotiating the transaction and recommending for approval or approving
the transaction, as the case may
be.
|
(a)
|
The
following documents are filed as a part of this annual
report:
|
(1)
|
Financial
Statements: See Index to Consolidated Financial Statements on
page F-1 of this annual report for financial statements filed as part of
this annual report.
|
(2)
|
Financial
Statement Schedules: All schedules have been omitted because
they are either not applicable, not required or the information called for
therein appears in the consolidated financial statements or notes
thereto.
|
(3)
|
Exhibits.
|
Exhibit
Number
|
Exhibit*
|
2.1
|
Merger
Agreement, dated as of December 15, 2003, by and among Enterprise Products
Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management
LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C.
(incorporated by reference to Exhibit 2.1 to Form 8-K filed December 15,
2003).
|
2.2
|
Amendment
No. 1 to Merger Agreement, dated as of August 31, 2004, by and among
Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise
Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra
Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form
8-K filed September 7, 2004).
|
2.3
|
Parent
Company Agreement, dated as of December 15, 2003, by and among Enterprise
Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products
GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine
River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra
GP Holding Company (incorporated by reference to Exhibit 2.2 to Form 8-K
filed December 15, 2003).
|
2.4
|
Amendment
No. 1 to Parent Company Agreement, dated as of April 19, 2004, by and
among Enterprise Products Partners L.P., Enterprise Products GP, LLC,
Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors
I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments,
L.L.C. and GulfTerra GP Holding Company (incorporated by reference to
Exhibit 2.1 to Form 8-K filed April 21, 2004).
|
2.5
|
Purchase
and Sale Agreement (Gas Plants), dated as of December 15, 2003, by and
between El Paso Corporation, El Paso Field Services Management, Inc., El
Paso Transmission, L.L.C., El Paso Field Services Holding Company and
Enterprise Products Operating L.P. (incorporated by reference to Exhibit
2.4 to Form 8-K filed December 15, 2003).
|
2.6
|
Agreement
and Plan of Merger, dated as of June 28, 2009, by and among Enterprise
Products Partners L.P., Enterprise Products GP, LLC, Enterprise Sub B LLC,
TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC
(incorporated by reference to Exhibit 2.1 to Form 8-K filed June 29,
2009).
|
2.7
|
Agreement
and Plan of Merger, dated as of June 28, 2009, by and among Enterprise
Products Partners L.P., Enterprise Products GP, LLC, Enterprise Sub A LLC,
TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC
(incorporated by reference to Exhibit 2.2 to Form 8-K filed June 29,
2009).
|
3.1
|
Certificate
of Limited Partnership of Enterprise Products Partners L.P. (incorporated
by reference to Exhibit 3.6 to Form 10-Q filed November 9,
2007).
|
3.2
|
Fifth
Amended and Restated Agreement of Limited Partnership of Enterprise
Products Partners L.P., dated August 8, 2005 (incorporated by reference to
Exhibit 3.1 to Form 8-K filed August 10, 2005).
|
3.3
|
Amendment
No. 1 to Fifth Amended and Restated Agreement of Limited Partnership of
Enterprise Products Partners L.P. dated December 27, 2007
(incorporated by reference to Exhibit 3.1 to Form 8-K/A filed January 3,
2008).
|
3.4
|
Amendment
No. 2 to Fifth Amended and Restated Agreement of Limited Partnership of
Enterprise Products Partners L.P. dated April 14, 2008 (incorporated by
reference to Exhibit 10.1 to Form 8-K filed April 16,
2008).
|
3.5
|
Amendment
No. 3 to Fifth Amended and Restated Agreement of Limited Partnership of
Enterprise Products Partners L.P. dated November 6, 2008 (incorporated by
reference to Exhibit 3.5 to Form 10-Q filed November 10,
2008).
|
3.6
|
Amendment
No. 4 to Fifth Amended and Restated Agreement of Limited Partnership of
Enterprise Products Partners L.P. dated October 26, 2009 (incorporated by
reference to Exhibit 3.1 to Form 8-K filed October 28,
2009).
|
3.7
|
Fifth
Amended and Restated Limited Liability Company Agreement of Enterprise
Products GP, LLC, dated November 7, 2007 (incorporated by reference to
Exhibit 3.2 to Form 10-Q filed November 9, 2007).
|
3.8
|
First
Amendment to Fifth Amended and Restated Limited Liability Company
Agreement of Enterprise Products GP, LLC, dated November 6, 2008
(incorporated by reference to Exhibit 3.7 to Form 10-Q filed November 10,
2008).
|
3.9
|
Company
Agreement of Enterprise Products Operating LLC dated June 30, 2007
(incorporated by reference to Exhibit 3.3 to Form 10-Q filed August 8,
2007).
|
3.10
|
Certificate
of Incorporation of Enterprise Products OLPGP, Inc., dated December 3,
2003 (incorporated by reference to Exhibit 3.5 to Form S-4 Registration
Statement, Reg. No. 333-121665, filed December 27,
2004).
|
3.11
|
Bylaws
of Enterprise Products OLPGP, Inc., dated December 8, 2003 (incorporated
by reference to Exhibit 3.6 to Form S-4 Registration Statement, Reg. No.
333-121665, filed December 27, 2004).
|
4.1
|
Form
of Common Unit certificate (incorporated by reference to Exhibit 4.1 to
Form S-1A Registration Statement, Reg. No. 333-52537, filed July 21,
1998).
|
4.2
|
Indenture,
dated as of March 15, 2000, among Enterprise Products Operating L.P., as
Issuer, Enterprise Products Partners L.P., as Guarantor, and First Union
National Bank, as Trustee (incorporated by reference to Exhibit 4.1 to
Form 8-K filed March 10, 2000).
|
4.3
|
First
Supplemental Indenture, dated as of January 22, 2003, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Guarantor, and Wachovia Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.2 to
Registration
|
Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003). | |
4.4
|
Second
Supplemental Indenture, dated as of February 14, 2003, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Guarantor, and Wachovia Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.3 to Form 10-K filed March 31,
2003).
|
4.5
|
Third
Supplemental Indenture, dated as of June 30, 2007, among Enterprise
Products Operating L.P., as Original Issuer, Enterprise Products Partners
L.P., as Parent Guarantor, Enterprise Products Operating LLC, as New
Issuer, and U.S. Bank National Association, as successor Trustee
(incorporated by reference to Exhibit 4.55 to Form 10-Q filed August 8,
2007).
|
4.6
|
Indenture,
dated as of October 4, 2004, among Enterprise Products Operating L.P., as
Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells
Fargo Bank, National Association, as Trustee (incorporated by reference to
Exhibit 4.1 to Form 8-K filed October 6, 2004).
|
4.7
|
First
Supplemental Indenture, dated as of October 4, 2004, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.2 to Form 8-K filed October 6,
2004).
|
4.8
|
Second
Supplemental Indenture, dated as of October 4, 2004, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.3 to Form 8-K filed October 6,
2004).
|
4.9
|
Third
Supplemental Indenture, dated as of October 4, 2004, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.4 to Form 8-K filed October 6,
2004).
|
4.10
|
Fourth
Supplemental Indenture, dated as of October 4, 2004, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.5 to Form 8-K filed October 6,
2004).
|
4.11
|
Fifth
Supplemental Indenture, dated as of March 2, 2005, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.2 to Form 8-K filed March 3,
2005).
|
4.12
|
Sixth
Supplemental Indenture, dated as of March 2, 2005, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.3 to Form 8-K filed March 3,
2005).
|
4.13
|
Seventh
Supplemental Indenture, dated as of June 1, 2005, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.46 to Form 10-Q filed November 4,
2005).
|
4.14
|
Eighth
Supplemental Indenture, dated as of July 18, 2006, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.2 to Form 8-K filed July 19,
2006).
|
4.15
|
Ninth
Supplemental Indenture, dated as of May 24, 2007, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.2 to Form 8-K filed
May 24, 2007).
|
4.16
|
Tenth
Supplemental Indenture, dated as of June 30, 2007, among Enterprise
Products Operating L.P., as Original Issuer, Enterprise Products Partners
L.P., as Parent Guarantor, Enterprise Products Operating LLC, as New
Issuer, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.54 to Form 10-Q filed August 8,
2007).
|
4.17
|
Eleventh
Supplemental Indenture, dated as of September 4, 2007, among Enterprise
Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.3 to Form
|
8-K filed September 5, 2007). | |
4.18
|
Twelfth
Supplemental Indenture, dated as of April 3, 2008, among Enterprise
Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.3 to Form 8-K filed April 3,
2008).
|
4.19
|
Thirteenth
Supplemental Indenture, dated as of April 3, 2008, among Enterprise
Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.4 to Form 8-K filed April 3,
2008).
|
4.20
|
Fourteenth
Supplemental Indenture, dated as of December 8, 2008, among Enterprise
Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.3 to Form 8-K filed December 8,
2008).
|
4.21
|
Fifteenth
Supplemental Indenture, dated as of June 10, 2009, among Enterprise
Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.3 to Form 8-K filed June 10,
2009).
|
4.22
|
Sixteenth
Supplemental Indenture, dated as of October 5, 2009, among Enterprise
Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.3 to Form 8-K filed October 5,
2009).
|
4.23
|
Seventeenth
Supplemental Indenture, dated as of October 27, 2009, among Enterprise
Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.1 to Form 8-K filed October 28,
2009).
|
4.24
|
Eighteenth
Supplemental Indenture, dated as of October 27, 2009, among Enterprise
Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as
Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.2 to Form 8-K filed October 28,
2009).
|
4.25
|
Global
Note representing $350.0 million principal amount of 6.375% Series B
Senior Notes due 2013 with attached Guarantee (incorporated by reference
to Exhibit 4.3 to Registration Statement on Form S-4, Reg. No. 333-102776,
filed January 28, 2003).
|
4.26
|
Global
Note representing $499.2 million principal amount of 6.875% Series B
Senior Notes due 2033 with attached Guarantee (incorporated by reference
to Exhibit 4.5 to Form 10-K filed March 31, 2003).
|
4.27
|
Global
Notes representing $450.0 million principal amount of 7.50% Senior Notes
due 2011 (incorporated by reference to Exhibit 4.1 to Form 8-K filed
January 25, 2001).
|
4.28
|
Global
Note representing $500.0 million principal amount of 4.00% Series B Senior
Notes due 2007 with attached Guarantee (incorporated by reference to
Exhibit 4.14 to Form S-3 Registration Statement, Reg. No. 333-123150,
filed March 4, 2005).
|
4.29
|
Global
Note representing $500.0 million principal amount of 5.60% Series B Senior
Notes due 2014 with attached Guarantee (incorporated by reference to
Exhibit 4.17 to Form S-3 Registration Statement, Reg. No. 333-123150,
filed March 4, 2005).
|
4.30
|
Global
Note representing $150.0 million principal amount of 5.60% Series B Senior
Notes due 2014 with attached Guarantee (incorporated by reference to
Exhibit 4.18 to Form S-3 Registration Statement, Reg. No. 333-123150,
filed March 4, 2005).
|
4.31
|
Global
Note representing $350.0 million principal amount of 6.65% Series B Senior
Notes due 2034 with attached Guarantee (incorporated by reference to
Exhibit 4.19 to Form S-3 Registration Statement, Reg. No. 333-123150,
filed March 4, 2005).
|
4.32
|
Global
Note representing $500.0 million principal amount of 4.625% Series B
Senior Notes due 2009 with attached Guarantee (incorporated by reference
to Exhibit 4.27 to Form 10-K filed March 15, 2005).
|
4.33
|
Global
Note representing $250.0 million principal amount of 5.00% Series B Senior
Notes due 2015 with attached Guarantee (incorporated by reference to
Exhibit 4.31 to Form 10-Q filed November 4, 2005).
|
4.34
|
Global
Note representing $250.0 million principal amount of 5.75% Series B Senior
Notes due
|
2035 with attached Guarantee (incorporated by reference to Exhibit 4.32 to Form 10-Q filed November 4, 2005). | |
4.35
|
Global
Note representing $500.0 million principal amount of 4.95% Senior Notes
due 2010 with attached Guarantee (incorporated by reference to Exhibit
4.47 to Form 10-Q filed November 4, 2005).
|
4.36
|
Form
of Junior Subordinated Note, including Guarantee (incorporated by
reference to Exhibit 4.2 to Form 8-K filed July 19,
2006).
|
4.37
|
Global
Note representing $800.0 million principal amount of 6.30% Senior Notes
due 2017 with attached Guarantee (incorporated by reference to Exhibit
4.38 to Form 10-Q filed November 9, 2007).
|
4.38
|
Form
of Global Note representing $400.0 million principal amount of 5.65%
Senior Notes due 2013 with attached Guarantee (incorporated by reference
to Exhibit 4.3 to Form 8-K filed April 3,
2008).
|
4.39
|
Form
of Global Note representing $700.0 million principal amount of 6.50%
Senior Notes due 2019 with attached Guarantee (incorporated by reference
to Exhibit 4.4 to Form 8-K filed April 3,
2008).
|
4.40
|
Form
of Global Note representing $500.0 million principal amount of 9.75%
Senior Notes due 2014 with attached Guarantee (incorporated by reference
to Exhibit 4.3 to Form 8-K filed December 8,
2008).
|
4.41
|
Form
of Global Note representing $500.0 million principal amount of 4.60%
Senior Notes due 2012 with attached Guarantee (incorporated by reference
to Exhibit 4.3 to Form 8-K filed June 10, 2009).
|
4.42
|
Form
of Global Note representing $500.0 million principal amount of 5.25%
Senior Notes due 2020 with attached Guarantee (incorporated by reference
to Exhibit 4.3 to Form 8-K filed October 5, 2009).
|
4.43
|
Form
of Global Note representing $600.0 million principal amount of 6.125%
Senior Notes due 2039 with attached Guarantee (incorporated by reference
to Exhibit 4.3 to Form 8-K filed October 5, 2009).
|
4.44
|
Form
of Global Note representing $490.5 million principal amount of 7.625%
Senior Notes due 2012 with attached Guarantee (incorporated by reference
to Exhibit 4.3 to Form 8-K filed October 28, 2009).
|
4.45
|
Form
of Global Note representing $182.6 million principal amount of 6.125%
Senior Notes due 2013 with attached Guarantee (incorporated by reference
to Exhibit 4.4 to Form 8-K filed October 28, 2009).
|
4.46
|
Form
of Global Note representing $237.6 million principal amount of 5.90%
Senior Notes due 2013 with attached Guarantee (incorporated by reference
to Exhibit 4.5 to Form 8-K filed October 28, 2009).
|
4.47
|
Form
of Global Note representing $349.7 million principal amount of 6.65%
Senior Notes due 2018 with attached Guarantee (incorporated by reference
to Exhibit 4.6 to Form 8-K filed October 28, 2009).
|
4.48
|
Form
of Global Note representing $399.6 million principal amount of 7.55%
Senior Notes due 2038 with attached Guarantee (incorporated by reference
to Exhibit 4.7 to Form 8-K filed October 28, 2009).
|
4.49
|
Form
of Global Note representing $285.8 million principal amount of 7.000%
Junior Subordinated Notes due 2067 with attached Guarantee (incorporated
by reference to Exhibit 4.8 to Form 8-K filed October 28,
2009).
|
4.50
|
Replacement
Capital Covenant, dated May 24, 2007, executed by Enterprise Products
Operating L.P. and Enterprise Products Partners L.P. in favor of the
covered debtholders described therein (incorporated by reference to
Exhibit 99.1 to Form 8-K filed May 24,
2007).
|
4.51
|
First
Amendment to Replacement Capital Covenant dated August 25, 2006,
executed by Enterprise Products Operating L.P. in favor of the covered
debtholders described therein (incorporated by reference to Exhibit 99.2
to Form 8-K filed August 25, 2006).
|
4.52
|
Purchase
Agreement, dated as of July 12, 2006 between Cerrito Gathering Company,
Ltd., Cerrito Gas Marketing, Ltd., Encinal Gathering, Ltd., as Sellers,
Lewis Energy Group, L.P. as Guarantor, and Enterprise Products Partners
L.P., as Buyer (incorporated by reference to Exhibit 4.6 to Form 10-Q
filed August 8, 2006).
|
4.53
|
Replacement
Capital Covenant, dated October 27, 2009, among Enterprise Products
Operating LLC and Enterprise Products Partners L.P. in favor of the
covered debtholders described therein (incorporated by reference to
Exhibit 4.9 to Form 8-K filed October 28, 2009).
|
4.54
|
Indenture,
dated February 20, 2002, by and among TEPPCO Partners, L.P., as Issuer, TE
Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO
Midstream Companies, L.P. and Jonah Gas Gathering Company, as Subsidiary
Guarantors, and First Union National Bank, NA, as Trustee (incorporated by
reference to Exhibit 99.2 to the Form 8-K filed by TEPPCO Partners, L.P.
on February 20, 2002).
|
4.55
|
First
Supplemental Indenture, dated February 20, 2002, by and among TEPPCO
Partners, L.P., as Issuer, TE Products Pipeline Company, Limited
Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas
Gathering Company, as Subsidiary Guarantors, and First Union National
Bank, NA, as Trustee (incorporated by reference to Exhibit 99.3 to the
Form 8-K filed by TEPPCO Partners, L.P. on February 20,
2002).
|
4.56
|
Second
Supplemental Indenture, dated June 27, 2002, by and among TEPPCO Partners,
L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM,
L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as
Initial Subsidiary Guarantors, Val Verde Gas Gathering Company, L.P., as
New Subsidiary Guarantor, and Wachovia Bank, National Association,
formerly known as First Union National Bank, as Trustee (incorporated by
reference to Exhibit 4.6 to the Form 10-Q filed by TEPPCO Partners, L.P.
on August 14, 2002).
|
4.57
|
Third
Supplemental Indenture, dated January 20, 2003, by and among TEPPCO
Partners, L.P. as Issuer, TE Products Pipeline Company, Limited
Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas
Gathering Company and Val Verde Gas Gathering Company, L.P. as Subsidiary
Guarantors, and Wachovia Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.7 to the Form 10-K filed by TEPPCO
Partners, L.P. on March 21, 2003).
|
4.58
|
Full
Release of Guarantee, dated July 31, 2006, by Wachovia Bank, National
Association, as Trustee, in favor of Jonah Gas Gathering Company
(incorporated by reference to Exhibit 4.8 to the Form 10-Q filed by TEPPCO
Partners, L.P. on November 7, 2006).
|
4.59
|
Fourth
Supplemental Indenture, dated June 30, 2007, by and among TEPPCO Partners,
L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM,
L.P., TEPPCO Midstream Companies, L.P., Val Verde Gas Gathering Company,
L.P., TE Products Pipeline Company, LLC and TEPPCO Midstream Companies,
LLC, as Subsidiary Guarantors, and U.S. Bank National Association, as
Trustee (incorporated by reference to Exhibit 4.3 to the Form 8-K filed by
TE Products Pipeline Company, LLC on July 6, 2007).
|
4.60
|
Fifth
Supplemental Indenture, dated March 27, 2008, by and among TEPPCO
Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P.,
TEPPCO Midstream Companies, LLC and Val Verde Gathering Company, L.P., as
Subsidiary Guarantors, and U.S. Bank National Association, as Trustee
(incorporated by reference to Exhibit 4.11 to the Form 10-Q filed by
TEPPCO Partners, L.P. on May 8, 2008).
|
4.61
|
Sixth
Supplemental Indenture, dated March 27, 2008, by and among TEPPCO
Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P.,
TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P.,
as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee
(incorporated by reference to Exhibit 4.12 to the Form 10-Q filed by
TEPPCO Partners, L.P. on May 8, 2008).
|
4.62
|
Seventh
Supplemental Indenture, dated March 27, 2008, by and among TEPPCO
Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P.,
TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P.,
as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee
(incorporated by reference to Exhibit 4.13 to the Form 10-Q filed by
TEPPCO Partners, L.P. on May 8, 2008).
|
4.63
|
Eighth
Supplemental Indenture, dated October 27, 2009, by and among TEPPCO
Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P.,
TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P.,
as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee
(incorporated by reference to Exhibit 4.1 to the Form 8-K filed by TEPPCO
Partners, L.P. on October 28, 2009).
|
4.64#
|
Full
Release of Guarantee, dated November 23, 2009, of TE Products Pipeline
Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde
Gas Gathering Company,
|
L.P. by U.S. Bank National Association, as Trustee. | |
4.65
|
Indenture,
dated May 14, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE
Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO
Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as
Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as
Trustee (incorporated by reference to Exhibit 99.1 of the Form 8-K filed
by TEPPCO Partners, L.P. on May 15, 2007).
|
4.66
|
First
Supplemental Indenture, dated May 18, 2007, by and among TEPPCO
Partners, L.P., as Issuer, TE Products Pipeline Company, Limited
Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde
Gas Gathering Company, L.P., as Subsidiary Guarantors, and The Bank of New
York Trust Company, N.A., as Trustee (incorporated by reference to Exhibit
4.2 to the Form 8-K filed by TEPPCO Partners, L.P. on May 18,
2007).
|
4.67
|
Replacement
of Capital Covenant, dated May 18, 2007, executed by TEPPCO Partners,
L.P., TE Products Pipeline Company, Limited Partnership, TCTM, L.P.,
TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P.
in favor of the covered debt holders described therein (incorporated by
reference to Exhibit 99.1 to the Form 8-K of TEPPCO Partners, L.P. on May
18, 2007).
|
4.68
|
Second
Supplemental Indenture, dated as of June 30, 2007, by and among TEPPCO
Partners, L.P., as Issuer, TE Products Pipeline Company, Limited
Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde
Gas Gathering Company, L.P., as Existing Subsidiary Guarantors, TE
Products Pipeline Company, LLC and TEPPCO Midstream Companies, LLC, as New
Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as
Trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by
TE Products Pipeline Company, LLC on July 6, 2007).
|
4.69
|
Third
Supplemental Indenture, dated as of October 27, 2009, by and among TEPPCO
Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P.,
TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P.,
as Subsidiary Guarantors, and The Bank of New York Mellon Trust Company,
N.A., as Trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K
filed by TEPPCO Partners, L.P. on October 28, 2009).
|
4.70#
|
Full
Release of Guarantee, dated as of November 23, 2009, of TE Products
Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val
Verde Gas Gathering Company, L.P. by The Bank of New York Mellon Trust
Company, N.A., as Trustee.
|
10.1
|
Transportation
Contract between Enterprise Products Operating L.P. and Enterprise
Transportation Company dated June 1, 1998 (incorporated by reference to
Exhibit 10.3 to Form S-1/A Registration Statement, Reg. No. 333-52537,
filed July 8, 1998).
|
10.2***
|
Enterprise
Products 1998 Long-Term Incentive Plan (Amended and Restated as of
February 23, 2010) (incorporated by reference to Exhibit 10.1 to Form 8-K
filed February 26, 2010).
|
10.3***
|
Form
of Option Grant Award under the Enterprise Products 1998 Long-Term
Incentive Plan for awards issued before May 7, 2008 (incorporated by
reference to Exhibit 10.2 to Form 10-Q filed November 8,
2007).
|
10.4***
|
Form
of Option Grant Award under the Enterprise Products 1998 Long-Term
Incentive Plan for awards issued on or after May 7, 2008 but before
February 23, 2010 (incorporated by reference to Exhibit 10.4 to Form 10-Q
filed May 12, 2008).
|
10.5***
|
Amendment
to Form of Option Grant Award under the Enterprise Products 1998 Long-Term
Incentive Plan for awards issued before February 23, 2010 (incorporated by
reference to Exhibit 10.2 to Form 8-K filed February 26,
2010).
|
10.6***
|
Form
of Option Grant Award under the Enterprise Products 1998 Long-Term
Incentive Plan (incorporated by reference to Exhibit 10.3 to Form 8-K
filed February 26, 2010).
|
10.7***
|
Form
of Restricted Unit Grant Award under the Enterprise Products 1998
Long-Term Incentive Plan for awards issued before February 23, 2010
(incorporated by reference to Exhibit 10.3 to Form 10-Q filed November 9,
2007).
|
10.8***
|
Amendment
to Form of Restricted Unit Grant Award under the Enterprise Products 1998
Long-Term Incentive Plan for awards issued before February 23, 2010
(incorporated by reference to Exhibit 10.4 to Form 8-K filed February 26,
2010).
|
10.9***
|
Form
of Employee Restricted Unit Grant Award under the Enterprise Products 1998
Long-Term Incentive Plan (incorporated by reference to Exhibit 10.5 to
Form 8-K filed February 26, 2010).
|
10.10***
|
Form
of Non-Employee Director Restricted Unit Grant Award under the Enterprise
Products
|
1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.6 to Form 8-K filed February 26, 2010). | |
10.11***
|
Enterprise
Products Company 2005 EPE Long-Term Incentive Plan (amended and restated
as of February 23, 2010) (incorporated by reference to Exhibit 10.1 to
Form 8-K filed by Enterprise GP Holdings L.P. on February 26,
2010).
|
10.12***
|
Form
of Unit Appreciation Right Grant Award (Enterprise Products GP, LLC
Directors) under the Enterprise Products Company 2005 EPE Long-Term
Incentive Plan (incorporated by reference to Exhibit 10.3 to Form 8-K
filed by Enterprise GP Holdings on May 8, 2006).
|
10.13***
|
Form
of Employee Restricted Unit Grant Award under the Enterprise Products
Company 2005 EPE Long-Term Incentive Plan (incorporated by reference to
Exhibit 10.3 to Form 8-K filed by Enterprise GP Holdings L.P. on February
26, 2010).
|
10.14***
|
Form
of Non-Employee Director Restricted Unit Grant Award under the Enterprise
Products Company 2005 EPE Long-Term Incentive Plan (incorporated by
reference to Exhibit 10.4 to Form 8-K filed by Enterprise GP Holdings L.P.
on February 26, 2010).
|
10.15***
|
Form
of Phantom Unit Grant Award under the Enterprise Products Company 2005 EPE
Long-Term Incentive Plan (incorporated by reference to Exhibit 10.5 to
Form 8-K filed by Enterprise GP Holdings L.P. on February 26,
2010).
|
10.16***
|
Amended
and Restated 2008 Enterprise Products Long-Term Incentive Plan (February
23, 2010) (incorporated by reference to Exhibit 10.7 to Form 8-K filed
February 26, 2010).
|
10.17***
|
Form
of Option Grant Award under the Amended and Restated 2008 Enterprise
Products Long-Term Incentive Plan for awards issued before February 23,
2010 (incorporated by reference to Exhibit 4.3 to Form S-8 filed May 6,
2008).
|
10.18***
|
Amendment
to Form of Option Grant Award under the Amended and Restated 2008
Enterprise Products Long-Term Incentive Plan for awards issued before
February 23, 2010 (incorporated by reference to Exhibit 10.8 to Form 8-K
filed February 26, 2010).
|
10.19***
|
Form
of Option Grant Award under the Amended and Restated 2008 Enterprise
Products Long-Term Incentive Plan (incorporated by reference to Exhibit
10.9 to Form 8-K filed February 26, 2010).
|
10.20***
|
Form
of Employee Restricted Unit Grant Award under the Amended and Restated
2008 Enterprise Products Long-Term Incentive Plan (incorporated by
reference to Exhibit 10.10 to Form 8-K filed February 26,
2010).
|
10.21***
|
Form
of Non-Employee Director Restricted Unit Grant Award under the Amended and
Restated 2008 Enterprise Products Long-Term Incentive Plan (incorporated
by reference to Exhibit 10.11 to Form 8-K filed February 26,
2010).
|
10.22***
|
2010
Duncan Energy Partners L.P. Long-Term Incentive Plan (Amended and Restated
February 23, 2010) (incorporated by reference to Exhibit 10.1 to Form 8-K
filed by Duncan Energy Partners L.P. on February 26,
2010).
|
10.23***
|
Form
of Option Grant Award under the 2010 Duncan Energy Partners L.P. Long-Term
Incentive Plan (incorporated by reference to Exhibit 10.2 to Form 8-K
filed by Duncan Energy Partners L.P. on February 26,
2010).
|
10.24***
|
Form
of Employee Restricted Unit Grant Award under the 2010 Duncan Energy
Partners L.P. Long-Term Incentive Plan (incorporated by reference to
Exhibit 10.3 to Form 8-K filed by Duncan Energy Partners L.P. on February
26, 2010).
|
10.25***
|
Form
of Non-Employee Director Restricted Unit Grant Award under the 2010 Duncan
Energy Partners L.P. Long-Term Incentive Plan (incorporated by reference
to Exhibit 10.4 to Form 8-K filed by Duncan Energy Partners L.P. on
February 26, 2010).
|
10.26***
|
Agreement
of Limited Partnership of EPE Unit L.P. dated August 23, 2005
(incorporated by reference to Exhibit 10.2 to Form 8-K filed by Enterprise
GP Holdings L.P. on September 1, 2005).
|
10.27***
|
First
Amendment to Agreement of Limited Partnership of EPE Unit L.P. dated
August 7, 2007 (incorporated by reference to Exhibit 10.3 to Form 10-Q
filed by Duncan Energy Partners L.P. on August 8,
2007).
|
10.28***
|
Second
Amendment to Agreement of Limited Partnership of EPE Unit L.P. dated July
1, 2008 (incorporated by reference to Exhibit 10.1 to Form 8-K filed by
Enterprise GP Holdings L.P. on July 7, 2008).
|
10.29***
|
Third
Amendment to Agreement of Limited Partnership of EPE Unit L.P. dated
December 2,
|
2009 (incorporated by reference to Exhibit 10.1 to Form 8-K filed by Enterprise GP Holdings L.P. on December 8, 2009). | |
10.30***
|
Agreement
of Limited Partnership of EPE Unit II, L.P. dated December 5, 2006
(incorporated by reference to Exhibit 10.13 to Form 10-K filed February
28, 2007).
|
10.31***
|
First
Amendment to Agreement of Limited Partnership of EPE Unit II, L.P. dated
August 7, 2007 (incorporated by reference to Exhibit 10.4 to Form 10-Q
filed by Duncan Energy Partners L.P. on August 8,
2007).
|
10.32***
|
Second
Amendment to Agreement of Limited Partnership of EPE Unit II, L.P. dated
July 1, 2008 (incorporated by reference to Exhibit 10.2 to Form 8-K filed
by Enterprise GP Holdings L.P. on July 7, 2008).
|
10.33***
|
Third
Amendment to Agreement of Limited Partnership of EPE Unit II, L.P. dated
December 2, 2009 (incorporated by reference to Exhibit 10.2 to Form 8-K
filed by Enterprise GP Holdings L.P. on December 8,
2009).
|
10.34***
|
Agreement
of Limited Partnership of EPE Unit III, L.P. dated May 7, 2007
(incorporated by reference to Exhibit 10.6 to Form 8-K filed by
Enterprise GP Holdings L.P. on May 10, 2007).
|
10.35***
|
First
Amendment to Agreement of Limited Partnership of EPE Unit III, L.P. dated
August 7, 2007 (incorporated by reference to Exhibit 10.5 to Form 10-Q
filed by Duncan Energy Partners L.P. on August 8,
2007).
|
10.36***
|
Second
Amendment to Agreement of Limited Partnership of EPE Unit III, L.P. dated
July 1, 2008 (incorporated by reference to Exhibit 10.3 to Form 8-K filed
by Enterprise GP Holdings L.P. on July 7, 2008).
|
10.37***
|
Third
Amendment to Agreement of Limited Partnership of EPE Unit III, L.P. dated
December 2, 2009 (incorporated by reference to Exhibit 10.3 to Form 8-K
filed by Enterprise GP Holdings L.P. on December 8,
2009).
|
10.38***
|
Agreement
of Limited Partnership of Enterprise Unit L.P. dated February 20, 2008
(incorporated by reference to Exhibit 10.1 to Form 8-K filed
February 26, 2008).
|
10.39***
|
First
Amendment to Agreement of Limited Partnership of Enterprise Unit L.P.
dated December 2, 2009 (incorporated by reference to Exhibit 10.4 to Form
8-K filed by Enterprise GP Holdings L.P. on December 8,
2009).
|
10.40***
|
Agreement
of Limited Partnership of EPCO Unit L.P. dated November 13, 2008
(incorporated by reference to Exhibit 10.5 to Form 8-K filed
November 18, 2008).
|
10.41***
|
First
Amendment to Agreement of Limited Partnership of EPCO Unit L.P. dated
December 2, 2009 (incorporated by reference to Exhibit 10.5 to Form 8-K
filed by Enterprise GP Holdings L.P. on December 8,
2009).
|
10.42
|
Fifth
Amended and Restated Administrative Services Agreement, dated as of
January 30, 2009, by and among EPCO, Inc., Enterprise GP Holdings L.P.,
EPE Holdings, LLC, Enterprise Products Partners L.P., Enterprise Products
Operating LLC, Enterprise Products GP, LLC, Enterprise Products OLPGP,
Inc., DEP Holdings, LLC, Duncan Energy Partners L.P., DEP Operating
Partnership L.P., TEPPCO Partners, L.P., Texas Eastern Products Pipeline
Company, LLC, TE Products Pipeline Company, LLC, TEPPCO Midstream
Companies, LLC, TCTM, L.P. and TEPPCO GP, Inc. (incorporated by reference
to Exhibit 10.1 to Form 8-K filed February 5, 2009).
|
10.43
|
Amended
and Restated Omnibus Agreement dated as of December 8, 2008 among
Enterprise Products Operating LLC, DEP Holdings, LLC, Duncan Energy
Partners L.P., DEP OLPGP, LLC, DEP Operating Partnership, L.P., Enterprise
Lou-Tex Propylene Pipeline L.P., Sabine Propylene Pipeline L.P., Acadian
Gas, LLC, Mont Belvieu Caverns, LLC, South Texas NGL Pipelines, LLC,
Enterprise Holding III, L.L.C., Enterprise Texas Pipeline, LLC, Enterprise
Intrastate, L.P. and Enterprise GC, LP (incorporated by reference to
Exhibit 10.6 of Form 8-K filed by Duncan Energy Partners L.P. filed
December 8, 2008).
|
10.44
|
Contribution,
Conveyance and Assumption Agreement dated as of February 5, 2007, by and
among Enterprise Products Operating L.P., DEP Holdings, LLC, Duncan Energy
Partners L.P., DEP OLPGP, LLC and DEP Operating Partnership, L.P.
(incorporated by reference to Exhibit 10.1 to Form 8-K filed by Duncan
Energy Partners on February 5, 2007).
|
10.45
|
Amended
and Restated Agreement of Limited Partnership of Duncan Energy Partners
L.P., dated February 5, 2007 (incorporated by reference to Exhibit
3.1 to Form 8-K filed by Duncan Energy Partners L.P. on February 5,
2007).
|
10.46
|
Amendment
No. 1 to the Amended and Restated Agreement of Limited Partnership of
Duncan Energy Partners L.P. dated December 27, 2007 (incorporated by
reference to Exhibit 3.1 to Form 8-K/A filed by Duncan Energy Partners
L.P. on January 3, 2008).
|
10.47
|
Amendment
No. 2 to the Amended and Restated Agreement of Limited Partnership of
Duncan Energy Partners L.P. dated November 6, 2008 (incorporated by
reference to Exhibit 3.4 to Form 10-Q filed by Duncan Energy Partners L.P.
on November 10, 2008).
|
10.48
|
Third
Amendment to the Amended and Restated Agreement of Limited Partnership of
Duncan Energy Partners L.P. dated December 8, 2008 (incorporated by
reference to Exhibit 3.1 to Form 8-K filed by Duncan Energy Partners L.P.
on December 8, 2008).
|
10.49
|
Fourth
Amendment to the Amended and Restated Agreement of Limited Partnership of
Duncan Energy Partners L.P. dated June 15, 2009 (incorporated by reference
to Exhibit 3.1 of Form 8-K filed by Duncan Energy Partners L.P. on June
15, 2009).
|
10.50
|
Amended
and Restated Credit Agreement dated as of June 29, 2005, among Cameron
Highway Oil Pipeline Company, the Lenders party thereto, and SunTrust
Bank, as Administrative Agent and Collateral Agent (incorporated by
reference to Exhibit 4.1 to Form 8-K filed July 1,
2005).
|
10.51
|
Revolving
Credit Agreement, dated as of January 5, 2007, among Duncan Energy
Partners L.P., as Borrower, Wachovia Bank, National Association, as
Administrative Agent, The Bank of Nova Scotia and Citibank, N.A., as
Co-Syndication Agents, JPMorgan Chase Bank, N.A. and Mizuho Corporate
Bank, Ltd., as Co-Documentation Agents, and Wachovia Capital Markets, LLC,
The Bank of Nova Scotia and Citigroup Global Markets Inc., as Joint Lead
Arrangers and Joint Book Runners (incorporated by reference to
Exhibit 10.20 to Form S-1/A Registration Statement, Reg.
No. 333-138371, filed by Duncan Energy Partners L.P. on
January 12, 2007).
|
10.52
|
First
Amendment to Revolving Credit Agreement, dated as of June 30, 2007, among
Duncan Energy Partners L.P., as Borrower, Wachovia Bank, National
Association, as Administrative Agent, The Bank of Nova Scotia and
Citibank, N.A., as Co-Syndication Agents, JPMorgan Chase Bank, N.A. and
Mizuho Corporate Bank, Ltd., as Co-Documentation Agents, and Wachovia
Capital Markets, LLC, The Bank of Nova Scotia and Citigroup Global Markets
Inc., as Joint Lead Arrangers and Joint Book Runners (incorporated by
reference to Exhibit 4.2 to Form 10-Q filed by Duncan Energy
Partners L.P. on August 8, 2007).
|
10.53
|
Amended
and Restated Revolving Credit Agreement dated as of November 19, 2007
among Enterprise Products Operating LLC, the financial institutions party
thereto as lenders, Wachovia Bank, National Association, as Administrative
Agent, Issuing Bank and Swingline Lender, Citibank, N.A. and JPMorgan
Chase Bank, as Co-Syndication Agents, and SunTrust Bank, Mizuho Corporate
Bank, Ltd. and The Bank of Nova Scotia, as Co-Documentation Agents
(incorporated by reference to Exhibit 10.1 to Form 8-K filed November 20,
2007).
|
10.54
|
Amended
and Restated Guaranty Agreement dated as of November 19, 2007
executed by Enterprise Products Partners L.P. in favor of Wachovia Bank,
National Association, as Administrative Agent (incorporated by reference
to Exhibit 10.2 to Form 8-K filed November 20, 2007).
|
10.55
|
Term
Loan Credit Agreement dated as of November 12, 2008 among Enterprise
Products Operating LLC, the financial institutions party thereto as
Lenders, Mizuho Corporate Bank, Ltd., as Administrative Agent, a Lender
and as Sole Lead Arranger (incorporated by reference to Exhibit 10.1 to
Form 8-K filed November 18, 2008).
|
10.56
|
Guaranty
Agreement dated as of November 12, 2008 executed by Enterprise
Products Partners L.P. in favor of Mizuho Corporate Bank, Ltd., as
Administrative Agent (incorporated by reference to Exhibit 10.2 to Form
8-K filed November 18, 2008).
|
10.57
|
364-Day
Revolving Credit Agreement dated as of November 17, 2008 among Enterprise
Products Operating LLC, the financial institutions party thereto as
Lenders, The Royal Bank of Scotland plc, as Administrative Agent, and
Barclays Bank plc, The Bank of Nova Scotia, DnB NOR Bank ASA and Wachovia
Bank, National Association, as Co-Arrangers (incorporated by reference to
Exhibit 10.3 to Form 8-K filed November 18, 2008).
|
10.58
|
Guaranty
Agreement dated as of November 17, 2008 executed by Enterprise
Products Partners L.P. in favor of The Royal Bank of Scotland plc, as
Administrative Agent (incorporated by reference to Exhibit 10.4 to Form
8-K filed November 18, 2008).
|
10.59
|
Second
Amended and Restated Limited Liability Company Agreement of Mont Belvieu
Caverns, LLC, dated November 6, 2008 (incorporated by reference to
Exhibit 10.4 to Form 10-
|
Q filed by Duncan Energy Partners L.P. on November 10, 2008). | |
10.60
|
Contribution,
Conveyance and Assumption Agreement dated as of December 8, 2008 by and
among Duncan Energy Partners L.P., DEP OLPGP, LLC, DEP Operating
Partnership, L.P., Enterprise GTM Holdings L.P. and Enterprise Holding
III, L.L.C. (incorporated by reference to Exhibit 10.2 of Form 8-K filed
by Duncan Energy Partners L.P. on December 8, 2008).
|
10.61
|
Purchase
and Sale Agreement dated as of December 8, 2008 by and among (a)
Enterprise Products Operating LLC and Enterprise GTM Holdings L.P. as the
Seller Parties and (b) Duncan Energy Partners L.P., DEP Holdings, LLC, DEP
Operating Partnership, L.P. and DEP OLPGP, LLC as the Buyer Parties
(incorporated by reference to Exhibit 10.1 of Form 8-K filed by Duncan
Energy Partners L.P. on December 8, 2008).
|
10.62
|
Third
Amended and Restated Agreement of Limited Partnership of Enterprise GC,
L.P. dated December 8, 2008 (incorporated by reference to Exhibit 10.3 of
Form 8-K filed by Duncan Energy Partners L.P. on December 8,
2008).
|
10.63
|
Fourth
Amended and Restated Agreement of Limited Partnership of Enterprise
Intrastate L.P. dated December 8, 2008 (incorporated by reference to
Exhibit 10.4 of Form 8-K filed by Duncan Energy Partners L.P. on December
8, 2008).
|
10.64
|
Amended
and Restated Company Agreement of Enterprise Texas Pipeline LLC dated
December 8, 2008 (incorporated by reference to Exhibit 10.5 of Form 8-K
filed by Duncan Energy Partners L.P. on December 8,
2008).
|
10.65
|
Unit
Purchase Agreement, dated as of December 8, 2008, by and between Duncan
Energy Partners L.P. and Enterprise Products Operating LLC (incorporated
by reference to Exhibit 10.9 of Form 8-K filed by Duncan Energy Partners
L.P. on December 8, 2008).
|
10.66
|
Term
Loan Credit Agreement dated as of April 1, 2009 among Enterprise Products
Operating LLC, the financial institutions party thereto as Lenders, Mizuho
Corporate Bank, Ltd., as Administrative Agent, a Lender and as Sole Lead
Arranger (incorporated by reference to Exhibit 10.1 to Form 8-K filed
April 2, 2009).
|
10.67
|
Guaranty
Agreement dated as of April 1, 2009 executed by Enterprise Products
Partners L.P. in favor of Mizuho Corporate Bank, Ltd., as Administrative
Agent (incorporated by reference to Exhibit 10.2 to Form 8-K filed April
2, 2009).
|
10.68
|
Support
Agreement, dated as of June 28, 2009, by and among Enterprise Products
Partners L.P., Enterprise GP Holdings L.P., DD Securities LLC, DFI GP
Holdings, L.P., Duncan Family Interests Inc., Duncan Family 2000 Trust and
Dan L. Duncan (incorporated by reference to Exhibit 10.1 to Form 8-K filed
June 29, 2009).
|
10.69
|
Memorandum
of Understanding, dated June 28, 2009 (incorporated by reference to
Exhibit 10.2 to Form 8-K filed June 29, 2009).
|
10.70
|
Stipulation
and Agreement of Compromise, Settlement and Release, dated August 5, 2009
(incorporated by reference to Exhibit 10.3 to Form 10-Q filed by TEPPCO
Partners, L.P. on August 6, 2009).
|
10.71
|
Common
Unit Purchase Agreement, dated September 3, 2009, by and between
Enterprise Products Partners L.P. and EPCO Holdings, Inc. (incorporated by
reference to Exhibit 10.1 to Form 8-K filed September 4,
2009).
|
12.1
|
Computation
of ratio of earnings to fixed charges for each of the five years ended
December 31, 2009, 2008, 2007, 2006 and 2005.
|
21.1#
|
List
of subsidiaries as of February 1, 2010.
|
23.1#
|
Consent
of Deloitte & Touche LLP.
|
31.1#
|
Sarbanes-Oxley
Section 302 certification of Michael A. Creel for Enterprise Products
Partners L.P. for the December 31, 2009 Annual Report on Form
10-K.
|
31.2#
|
Sarbanes-Oxley
Section 302 certification of W. Randall Fowler for Enterprise Products
Partners L.P. for the December 31, 2009 Annual Report on Form
10-K.
|
32.1#
|
Section
1350 certification of Michael A. Creel for the December 31, 2009 Annual
Report on Form 10-K.
|
32.2#
|
Section
1350 certification of W. Randall Fowler for the December 31, 2009 Annual
Report on Form 10-K.
|
101.CAL#
|
XBRL
Calculation Linkbase Document
|
101.DEF#
|
XBRL
Definition Linkbase Document
|
101.INS#
|
XBRL
Instance Document
|
101.LAB#
|
XBRL
Labels Linkbase Document
|
101.PRE#
|
XBRL
Presentation Linkbase Document
|
101.SCH#
|
XBRL
Schema Document
|
*
|
With
respect to any exhibits incorporated by reference to any Exchange Act
filings, the Commission file numbers for Enterprise GP Holdings L.P,
Duncan Energy Partners L.P., TEPPCO Partners, L.P. and TE Products
Pipeline Company, LLC are 1-32610, 1-33266, 1-10403 and 1-13603,
respectively.
|
***
|
Identifies
management contract and compensatory plan arrangements.
|
#
|
Filed
with this report.
|
ENTERPRISE
PRODUCTS PARTNERS L.P.
|
||||||
(A
Delaware Limited Partnership)
|
||||||
By: Enterprise
Products GP, LLC, as General Partner
|
||||||
By:
|
/s/
Michael J. Knesek
|
|||||
Name:
|
Michael
J. Knesek
|
|||||
Title:
|
Senior
Vice President, Controller
and
Principal Accounting Officer
of
the General Partner
|
Signature
|
Title
(Position with Enterprise Products GP, LLC)
|
|
/s/
Dan L. Duncan
|
Director
and Chairman
|
|
Dan
L. Duncan
|
||
/s/
Michael A. Creel
|
Director,
President and Chief Executive Officer
|
|
Michael
A. Creel
|
||
/s/
W. Randall Fowler
|
Director,
Executive Vice President and Chief Financial Officer
|
|
W.
Randall Fowler
|
||
/s/
Richard H. Bachmann
|
Director,
Executive Vice President, Chief Legal Officer and
Secretary
|
|
Richard
H. Bachmann
|
||
/s/
A. James Teague
|
Director,
Executive Vice President and Chief Commercial Officer
|
|
A.
James Teague
|
||
/s/
Dr. Ralph S. Cunningham
|
Director
|
|
Dr.
Ralph S. Cunningham
|
||
/s/
E. William Barnett
|
Director
|
|
E.
William Barnett
|
||
/s/
Rex C. Ross
|
Director
|
|
Rex
C. Ross
|
||
/s/
Charles M. Rampacek
|
Director
|
|
Charles
M. Rampacek
|
||
/s/
Michael J. Knesek
|
Senior
Vice President, Controller and Principal Accounting
Officer
|
|
Michael
J. Knesek
|
Page
No.
|
||
December
31,
|
||||||||
ASSETS
|
2009
|
2008* | ||||||
Current
assets:
|
||||||||
Cash
and cash equivalents
|
$ | 54.7 | $ | 61.7 | ||||
Restricted
cash
|
63.6 | 203.8 | ||||||
Accounts
and notes receivable – trade, net of allowance for doubtful
accounts
of
$16.8 at December 31, 2009 and $17.7 at December 31, 2008
|
3,099.0 | 2,028.5 | ||||||
Accounts
receivable – related parties
|
38.4 | 35.3 | ||||||
Inventories
|
711.9 | 405.0 | ||||||
Derivative
assets
|
113.8 | 218.6 | ||||||
Prepaid
and other current assets
|
165.5 | 149.8 | ||||||
Total
current assets
|
4,246.9 | 3,102.7 | ||||||
Property,
plant and equipment, net
|
17,689.2 | 16,732.8 | ||||||
Investments
in unconsolidated affiliates
|
890.6 | 911.9 | ||||||
Intangible
assets, net of accumulated amortization of $795.0 at
December
31, 2009 and $675.1 at December 31, 2008
|
1,064.8 | 1,182.9 | ||||||
Goodwill
|
2,018.3 | 2,019.6 | ||||||
Other
assets
|
241.8 | 261.7 | ||||||
Total
assets
|
$ | 26,151.6 | $ | 24,211.6 | ||||
LIABILITIES
AND EQUITY
|
||||||||
Current
liabilities:
|
||||||||
Accounts
payable – trade
|
$ | 410.6 | $ | 388.9 | ||||
Accounts
payable – related parties
|
69.8 | 17.4 | ||||||
Accrued
product payables
|
3,393.0 | 1,845.7 | ||||||
Accrued
expenses
|
108.5 | 65.7 | ||||||
Accrued
interest
|
228.0 | 188.3 | ||||||
Derivative
liabilities
|
93.0 | 302.9 | ||||||
Other
current liabilities
|
233.1 | 292.3 | ||||||
Total
current liabilities
|
4,536.0 | 3,101.2 | ||||||
Long-term debt:
(see
Note 12)
|
||||||||
Senior
debt obligations – principal
|
9,764.3 | 10,030.1 | ||||||
Junior
subordinated notes – principal
|
1,532.7 | 1,532.7 | ||||||
Other
|
49.4 | 75.1 | ||||||
Total
long-term debt
|
11,346.4 | 11,637.9 | ||||||
Deferred
tax liabilities
|
71.7 | 66.1 | ||||||
Other
long-term liabilities
|
155.2 | 110.5 | ||||||
Commitments
and contingencies
|
||||||||
Equity:
(see Note
13)
|
||||||||
Enterprise
Products Partners L.P. partners’ equity:
|
||||||||
Limited
Partners:
|
||||||||
Common
units (603,202,828 units outstanding at December 31, 2009
and
439,354,731 units outstanding at December 31, 2008)
|
9,173.5 | 6,036.9 | ||||||
Restricted
common units (2,720,882 units outstanding at December 31,
2009
and
2,080,600 units outstanding at December 31, 2008)
|
37.7 | 26.2 | ||||||
Class
B units (4,520,431 units outstanding at December 31, 2009)
|
118.5 | -- | ||||||
General
partner
|
190.8 | 123.6 | ||||||
Accumulated
other comprehensive loss
|
(8.4 | ) | (97.2 | ) | ||||
Total
Enterprise Products Partners L.P. partners’ equity
|
9,512.1 | 6,089.5 | ||||||
Noncontrolling
interest
|
530.2 | 3,206.4 | ||||||
Total
equity
|
10,042.3 | 9,295.9 | ||||||
Total
liabilities and equity
|
$ | 26,151.6 | $ | 24,211.6 |
For
Year Ended December 31,
|
||||||||||||
2009
|
2008* | 2007* | ||||||||||
Revenues:
|
||||||||||||
Third
parties
|
$ | 24,911.9 | $ | 34,454.2 | $ | 26,128.6 | ||||||
Related
parties
|
599.0 | 1,015.4 | 585.2 | |||||||||
Total
revenues (see Note 14)
|
25,510.9 | 35,469.6 | 26,713.8 | |||||||||
Costs
and expenses:
|
||||||||||||
Operating
costs and expenses:
|
||||||||||||
Third
parties
|
22,547.6 | 32,861.9 | 24,938.2 | |||||||||
Related
parties
|
1,018.2 | 757.0 | 463.9 | |||||||||
Total
operating costs and expenses
|
23,565.8 | 33,618.9 | 25,402.1 | |||||||||
General
and administrative costs:
|
||||||||||||
Third
parties
|
77.3 | 43.4 | 44.6 | |||||||||
Related
parties
|
95.0 | 93.8 | 82.6 | |||||||||
Total
general and administrative costs
|
172.3 | 137.2 | 127.2 | |||||||||
Total
costs and expenses
|
23,738.1 | 33,756.1 | 25,529.3 | |||||||||
Equity
in income of unconsolidated affiliates
|
51.2 | 34.9 | 10.5 | |||||||||
Operating
income
|
1,824.0 | 1,748.4 | 1,195.0 | |||||||||
Other
income (expense):
|
||||||||||||
Interest
expense
|
(641.8 | ) | (540.7 | ) | (413.0 | ) | ||||||
Interest
income
|
2.3 | 7.4 | 11.1 | |||||||||
Other,
net
|
(4.1 | ) | 4.8 | 60.6 | ||||||||
Total
other expense, net
|
(643.6 | ) | (528.5 | ) | (341.3 | ) | ||||||
Income
before provision for income taxes
|
1,180.4 | 1,219.9 | 853.7 | |||||||||
Provision
for income taxes
|
(25.3 | ) | (31.0 | ) | (15.7 | ) | ||||||
Net
income
|
1,155.1 | 1,188.9 | 838.0 | |||||||||
Net
income attributable to noncontrolling interest (see Note
13)
|
(124.2 | ) | (234.9 | ) | (304.4 | ) | ||||||
Net
income attributable to Enterprise Products Partners L.P.
|
$ | 1,030.9 | $ | 954.0 | $ | 533.6 | ||||||
Net income allocated to:
(see Note 13)
|
||||||||||||
Limited
partners
|
$ | 852.2 | $ | 811.5 | $ | 417.7 | ||||||
General
partner
|
$ | 178.7 | $ | 142.5 | $ | 115.9 | ||||||
Earnings per unit:
(see
Note 17)
|
||||||||||||
Basic
and diluted earnings per unit
|
$ | 1.73 | $ | 1.84 | $ | 0.95 |
For
Year Ended December 31,
|
||||||||||||
2009
|
2008* | 2007* | ||||||||||
Net
income
|
$ | 1,155.1 | $ | 1,188.9 | $ | 838.0 | ||||||
Other
comprehensive income (loss):
|
||||||||||||
Cash
flow hedges:
|
||||||||||||
Commodity
derivative instrument losses during period
|
(179.6 | ) | (170.2 | ) | (46.9 | ) | ||||||
Reclassification
adjustment for losses included in net income
related
to commodity derivative instruments
|
294.2 | 96.3 | 9.5 | |||||||||
Interest
rate derivative instrument gains (losses) during period
|
18.6 | (52.0 | ) | (8.9 | ) | |||||||
Reclassification
adjustment for (gains) losses included in net income
related
to interest rate derivative instruments
|
10.8 | (1.1 | ) | (5.8 | ) | |||||||
Foreign
currency derivative gains (losses)
|
(10.2 | ) | 9.3 | 1.3 | ||||||||
Total
cash flow hedges
|
133.8 | (117.7 | ) | (50.8 | ) | |||||||
Foreign
currency translation adjustment
|
2.1 | (2.5 | ) | 2.0 | ||||||||
Change
in funded status of pension and postretirement plans, net of
tax
|
-- | (1.3 | ) | -- | ||||||||
Total
other comprehensive income (loss)
|
135.9 | (121.5 | ) | (48.8 | ) | |||||||
Comprehensive
income
|
1,291.0 | 1,067.4 | 789.2 | |||||||||
Comprehensive
income attributable to noncontrolling interest
|
(130.2 | ) | (229.7 | ) | (258.8 | ) | ||||||
Comprehensive
income attributable to Enterprise Products Partners L.P.
|
$ | 1,160.8 | $ | 837.7 | $ | 530.4 |
For
Year Ended December 31,
|
||||||||||||
2009
|
2008* | 2007* | ||||||||||
Operating
activities:
|
||||||||||||
Net
income
|
$ | 1,155.1 | $ | 1,188.9 | $ | 838.0 | ||||||
Adjustments
to reconcile net income to net cash
flows
provided by operating activities:
|
||||||||||||
Depreciation,
amortization and accretion
|
833.4 | 737.8 | 658.4 | |||||||||
Non-cash
impairment charges
|
33.5 | -- | -- | |||||||||
Equity
in income of unconsolidated affiliates
|
(51.2 | ) | (34.9 | ) | (10.5 | ) | ||||||
Distributions
received from unconsolidated affiliates
|
86.6 | 80.8 | 87.0 | |||||||||
Operating
lease expenses paid by EPCO
|
0.7 | 2.0 | 2.1 | |||||||||
Gain
from asset sales and related transactions
|
-- | (4.0 | ) | (67.4 | ) | |||||||
Loss
on forfeiture of investment in Texas Offshore Port System
|
68.4 | -- | -- | |||||||||
Loss
on early extinguishment of debt
|
-- | 1.6 | 1.6 | |||||||||
Deferred
income tax expense
|
4.5 | 6.2 | 7.6 | |||||||||
Changes
in fair market value of derivative instruments
|
0.4 | (0.1 | ) | 1.3 | ||||||||
Effect
of pension settlement recognition
|
(0.1 | ) | (0.1 | ) | 0.6 | |||||||
Net
effect of changes in operating accounts (see Note 20)
|
245.9 | (411.1 | ) | 434.9 | ||||||||
Net
cash flows provided by operating activities
|
2,377.2 | 1,567.1 | 1,953.6 | |||||||||
Investing
activities:
|
||||||||||||
Capital
expenditures
|
(1,584.3 | ) | (2,539.6 | ) | (2,764.0 | ) | ||||||
Contributions
in aid of construction costs
|
17.8 | 27.2 | 57.6 | |||||||||
Decrease
(increase) in restricted cash
|
140.2 | (132.8 | ) | (47.3 | ) | |||||||
Cash
used for business combinations (see Note 10)
|
(107.3 | ) | (553.5 | ) | (35.9 | ) | ||||||
Acquisition
of intangible assets
|
(1.4 | ) | (5.8 | ) | (14.5 | ) | ||||||
Investments
in unconsolidated affiliates
|
(18.8 | ) | (64.7 | ) | (236.8 | ) | ||||||
Proceeds
from asset sales and related transactions
|
3.6 | 22.3 | 169.1 | |||||||||
Other
investing activities
|
3.3 | -- | -- | |||||||||
Cash
used in investing activities
|
(1,546.9 | ) | (3,246.9 | ) | (2,871.8 | ) | ||||||
Financing
activities:
|
||||||||||||
Borrowings
under debt agreements
|
7,376.6 | 13,188.0 | 7,629.8 | |||||||||
Repayments
of debt
|
(7,653.5 | ) | (10,434.3 | ) | (5,799.9 | ) | ||||||
Debt
issuance costs
|
(14.9 | ) | (27.6 | ) | (20.6 | ) | ||||||
Cash
distributions paid to partners
|
(1,254.8 | ) | (1,037.4 | ) | (957.7 | ) | ||||||
Cash
distributions paid to noncontrolling interest
|
(340.0 | ) | (383.9 | ) | (326.8 | ) | ||||||
Cash
contributions from noncontrolling interest
|
138.7 | 311.5 | 304.7 | |||||||||
Net
cash proceeds from issuance of common units
|
912.7 | 142.8 | 69.2 | |||||||||
Repurchase
of restricted units and options
|
-- | -- | (1.5 | ) | ||||||||
Acquisition
of treasury units
|
(2.1 | ) | (1.9 | ) | -- | |||||||
Monetization
of interest rate derivative instruments (see Note 6)
|
0.2 | (66.5 | ) | 49.1 | ||||||||
Cash
provided by (used in) financing activities
|
(837.1 | ) | 1,690.7 | 946.3 | ||||||||
Effect
of exchange rate changes on cash
|
(0.2 | ) | (0.5 | ) | 0.4 | |||||||
Net
change in cash and cash equivalents
|
(6.8 | ) | 10.9 | 28.1 | ||||||||
Cash
and cash equivalents, January 1
|
61.7 | 51.3 | 22.8 | |||||||||
Cash
and cash equivalents, December 31
|
$ | 54.7 | $ | 61.7 | $ | 51.3 |
Enterprise
Products Partners L.P.
|
||||||||||||||||||||
Limited
Partners
|
General
Partner
|
Accumulated
Other
Comprehensive
Income
(Loss)
|
Noncontrolling
Interest
|
Total
|
||||||||||||||||
Balance,
December 31, 2006*
|
$ | 6,329.8 | $ | 129.3 | $ | 21.1 | $ | 2,644.7 | $ | 9,124.9 | ||||||||||
Net
income
|
417.7 | 115.9 | -- | 304.4 | 838.0 | |||||||||||||||
Operating
lease expenses paid by EPCO
|
2.1 | -- | -- | -- | 2.1 | |||||||||||||||
Cash
distributions paid to partners
|
(833.8 | ) | (124.4 | ) | -- | -- | (958.2 | ) | ||||||||||||
Unit
option reimbursements to EPCO
|
(3.0 | ) | -- | -- | -- | (3.0 | ) | |||||||||||||
Cash
distributions paid to noncontrolling interest
|
-- | -- | -- | (326.8 | ) | (326.8 | ) | |||||||||||||
Net
cash proceeds from issuance of common units
|
60.4 | 1.2 | -- | -- | 61.6 | |||||||||||||||
Cash
proceeds from exercise of unit options
|
7.5 | 0.1 | -- | -- | 7.6 | |||||||||||||||
Cash
contributions from noncontrolling interest
|
-- | -- | -- | 304.7 | 304.7 | |||||||||||||||
Repurchase
of restricted units and options
|
(1.5 | ) | -- | -- | -- | (1.5 | ) | |||||||||||||
Amortization
of equity awards
|
13.7 | 0.2 | -- | 0.8 | 14.7 | |||||||||||||||
Change
in funded status of pension and
postretirement
plans, net of tax
|
-- | -- | 1.2 | -- | 1.2 | |||||||||||||||
Foreign
currency translation adjustment
|
-- | -- | 2.0 | -- | 2.0 | |||||||||||||||
Cash
flow hedges
|
-- | -- | (5.2 | ) | (45.6 | ) | (50.8 | ) | ||||||||||||
Balance,
December 31, 2007*
|
5,992.9 | 122.3 | 19.1 | 2,882.2 | 9,016.5 | |||||||||||||||
Net
income
|
811.5 | 142.5 | -- | 234.9 | 1,188.9 | |||||||||||||||
Operating
lease expenses paid by EPCO
|
2.0 | -- | -- | -- | 2.0 | |||||||||||||||
Cash
distributions paid to partners
|
(892.7 | ) | (144.1 | ) | -- | -- | (1,036.8 | ) | ||||||||||||
Unit
option reimbursements to EPCO
|
(0.6 | ) | -- | -- | -- | (0.6 | ) | |||||||||||||
Cash
distributions paid to noncontrolling interest
|
-- | -- | -- | (383.9 | ) | (383.9 | ) | |||||||||||||
Acquisition
of treasury units
|
(1.9 | ) | -- | -- | -- | (1.9 | ) | |||||||||||||
Net
cash proceeds from issuance of common units
|
139.3 | 2.8 | -- | -- | 142.1 | |||||||||||||||
Cash
proceeds from exercise of unit options
|
0.7 | -- | -- | -- | 0.7 | |||||||||||||||
Cash
contributions from noncontrolling interest
|
-- | -- | -- | 311.5 | 311.5 | |||||||||||||||
Issuance
of units by TEPPCO in connection with
Cenac
acquisition (see Note 10)
|
-- | -- | -- | 186.6 | 186.6 | |||||||||||||||
Amortization
of equity awards
|
11.9 | 0.1 | -- | 2.1 | 14.1 | |||||||||||||||
Acquisition
of additional interest in subsidiaries
|
-- | -- | -- | (22.3 | ) | (22.3 | ) | |||||||||||||
Change
in funded status of pension and
postretirement
plans, net of tax
|
-- | -- | (1.3 | ) | -- | (1.3 | ) | |||||||||||||
Foreign
currency translation adjustment
|
-- | -- | (2.5 | ) | -- | (2.5 | ) | |||||||||||||
Cash
flow hedges
|
-- | -- | (112.5 | ) | (5.2 | ) | (117.7 | ) | ||||||||||||
Other
|
-- | -- | -- | 0.5 | 0.5 | |||||||||||||||
Balance,
December 31, 2008*
|
6,063.1 | 123.6 | (97.2 | ) | 3,206.4 | 9,295.9 | ||||||||||||||
Net
income
|
852.2 | 178.7 | -- | 124.2 | 1,155.1 | |||||||||||||||
Operating
lease expenses paid by EPCO
|
0.7 | -- | -- | -- | 0.7 | |||||||||||||||
Cash
distributions paid to partners
|
(1,069.3 | ) | (183.1 | ) | -- | -- | (1,252.4 | ) | ||||||||||||
Unit
option reimbursements to EPCO
|
(2.4 | ) | -- | -- | -- | (2.4 | ) | |||||||||||||
Cash
distributions paid to noncontrolling interest
|
-- | -- | -- | (340.0 | ) | (340.0 | ) | |||||||||||||
Acquisition
of treasury units
|
(2.1 | ) | -- | -- | -- | (2.1 | ) | |||||||||||||
Net
cash proceeds from issuance of common units
|
892.8 | 18.2 | -- | -- | 911.0 | |||||||||||||||
Cash
proceeds from exercise of unit options
|
1.7 | -- | -- | -- | 1.7 | |||||||||||||||
Common
and Class B units issued in connection with TEPPCO Merger
|
2,574.1 | 53.1 | (41.1 | ) | (2,585.8 | ) | 0.3 | |||||||||||||
Deconsolidation
of Texas Offshore Port System
|
-- | -- | -- | (33.4 | ) | (33.4 | ) | |||||||||||||
Acquisition
of interest in subsidiary
|
-- | -- | -- | 10.3 | 10.3 | |||||||||||||||
Cash
contributions from noncontrolling interest
|
-- | -- | -- | 138.7 | 138.7 | |||||||||||||||
Amortization
of equity awards
|
18.9 | 0.3 | -- | 4.1 | 23.3 | |||||||||||||||
Foreign
currency translation adjustment
|
-- | -- | 2.1 | -- | 2.1 | |||||||||||||||
Cash
flow hedges
|
-- | -- | 127.8 | 6.0 | 133.8 | |||||||||||||||
Other
|
-- | -- | -- | (0.3 | ) | (0.3 | ) | |||||||||||||
Balance,
December 31, 2009
|
$ | 9,329.7 | $ | 190.8 | $ | (8.4 | ) | $ | 530.2 | $ | 10,042.3 |
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Balance
at beginning of period
|
$ | 17.7 | $ | 21.8 | $ | 23.5 | ||||||
Charges
to expense
|
0.1 | 3.5 | 2.6 | |||||||||
Payments
|
(1.0 | ) | (7.6 | ) | (4.3 | ) | ||||||
Balance
at end of period
|
$ | 16.8 | $ | 17.7 | $ | 21.8 |
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Balance
at beginning of period
|
$ | 22.3 | $ | 30.5 | $ | 26.0 | ||||||
Charges
to expense
|
1.9 | 3.1 | 4.2 | |||||||||
Acquisition-related
additions and other
|
-- | 2.9 | 6.7 | |||||||||
Payments
|
(5.1 | ) | (8.3 | ) | (6.1 | ) | ||||||
Adjustments
|
(2.4 | ) | (5.9 | ) | (0.3 | ) | ||||||
Balance
at end of period
|
$ | 16.7 | $ | 22.3 | $ | 30.5 |
December
31, 2009
|
December
31, 2008
|
|||||||||||||||
Carrying
|
Fair
|
Carrying
|
Fair
|
|||||||||||||
Financial
Instruments
|
Value
|
Value
|
Value
|
Value
|
||||||||||||
Financial
assets:
|
||||||||||||||||
Cash
and cash equivalents and restricted cash
|
$ | 118.3 | $ | 118.3 | $ | 265.5 | $ | 265.5 | ||||||||
Accounts
receivable
|
3,137.4 | 3,137.4 | 2,063.8 | 2,063.8 | ||||||||||||
Financial
liabilities:
|
||||||||||||||||
Accounts
payable and accrued expenses
|
4,209.9 | 4,209.9 | 2,506.0 | 2,506.0 | ||||||||||||
Other
current liabilities
|
233.1 | 233.1 | 292.3 | 292.3 | ||||||||||||
Fixed-rate
debt (principal amount)
|
10,586.7 | 11,056.2 | 9,704.3 | 8,192.2 | ||||||||||||
Variable-rate
debt
|
710.3 | 710.3 | 1,858.5 | 1,858.5 |
§
|
Effective
with the first quarter of 2010, additional disclosures will be required
regarding the reporting of transfers of fair value information between the
three levels of the fair value hierarchy (i.e., Levels 1, 2 and
3).
|
§
|
Effective
with the first quarter of 2011, companies will need to present purchases,
sales, issuances and settlements whose fair values are based on
unobservable inputs on a gross
basis.
|
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Restricted
unit awards (1)
|
$ | 12.9 | $ | 10.9 | $ | 8.7 | ||||||
Unit
option awards (1)
|
1.8 | 0.7 | 4.5 | |||||||||
Unit
appreciation rights (2)
|
0.1 | -- | 0.1 | |||||||||
Phantom
units (2)
|
0.2 | (0.5 | ) | 2.3 | ||||||||
Profits
interests awards (1)
|
8.5 | 6.3 | 4.3 | |||||||||
Total
compensation expense
|
$ | 23.5 | $ | 17.4 | $ | 19.9 | ||||||
(1)
Accounted
for as equity-classified awards.
(2)
Accounted
for as liability-classified awards.
|
Weighted-
|
||||||||
Average
Grant
|
||||||||
Number
of
|
Date
Fair Value
|
|||||||
Units
|
per Unit
(1)
|
|||||||
Restricted
units at December 31, 2006
|
1,105,237 | $ | 24.79 | |||||
Granted
(2)
|
738,040 | $ | 30.64 | |||||
Vested
|
(4,884 | ) | $ | 25.28 | ||||
Forfeited
|
(36,800 | ) | $ | 23.51 | ||||
Settled
(3)
|
(113,053 | ) | $ | 23.24 | ||||
Restricted
units at December 31, 2007
|
1,688,540 | $ | 27.23 | |||||
Granted
(4)
|
766,200 | $ | 30.73 | |||||
Vested
|
(285,363 | ) | $ | 23.11 | ||||
Forfeited
|
(88,777 | ) | $ | 26.98 | ||||
Restricted
units at December 31, 2008
|
2,080,600 | $ | 29.09 | |||||
Granted
(5)
|
1,025,650 | $ | 24.89 | |||||
Vested
|
(281,500 | ) | $ | 26.70 | ||||
Forfeited
|
(411,884 | ) | $ | 28.37 | ||||
Awards
assumed in connection with TEPPCO Merger
|
308,016 | $ | 27.64 | |||||
Restricted
units at December 31, 2009
|
2,720,882 | $ | 27.70 | |||||
(1)
Determined
by dividing the aggregate grant date fair value of awards before an
allowance for forfeitures by the number of awards issued. With
respect to restricted unit awards assumed in connection with the TEPPCO
Merger, the weighted-average grant date fair value per unit was determined
by dividing the aggregate grant date fair value of the assumed awards
before an allowance for forfeitures by the number of awards
assumed.
(2)
Aggregate
grant date fair value of restricted unit awards issued during 2007 was
$22.6 million based on grant date market prices of our common units
ranging from $28.00 to $31.83 per unit. Estimated forfeiture rates ranging
between 4.6% and 17% were applied to these awards.
(3)
Reflects
the settlement of restricted units in connection with the resignation of
our general partner’s former chief executive officer.
(4)
Aggregate
grant date fair value of restricted unit awards issued during 2008 was
$23.5 million based on grant date market prices of our common units
ranging from $25.00 to $32.31 per unit. An estimated forfeiture rate
of 17% was applied to these awards.
(5)
Aggregate
grant date fair value of restricted unit awards issued during 2009 was
$25.5 million based on grant date market prices of our common units
ranging from $20.08 to $28.73 per unit. Estimated forfeiture rates ranging
between 4.6% and 17% were applied to these awards.
|
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Cash
distributions paid to restricted unit holders
|
$ | 5.2 | $ | 3.9 | $ | 2.6 | ||||||
Total
fair value of restricted unit awards vesting during period
|
7.5 | 6.6 | 0.1 |
Weighted-
|
||||||||||||||||
Weighted-
|
Average
|
|||||||||||||||
Average
|
Remaining
|
Aggregate
|
||||||||||||||
Number
of
|
Strike
Price
|
Contractual
|
Intrinsic
|
|||||||||||||
Units
|
(dollars/unit)
|
Term
(in years)
|
Value
(1)
|
|||||||||||||
Outstanding
at December 31, 2006
|
2,416,000 | $ | 23.32 | |||||||||||||
Granted
(2)
|
895,000 | 30.63 | ||||||||||||||
Exercised
|
(256,000 | ) | 19.26 | |||||||||||||
Settled
or forfeited (3)
|
(740,000 | ) | 24.62 | |||||||||||||
Outstanding
at December 31, 2007
|
2,315,000 | 26.18 | ||||||||||||||
Granted
(4)
|
795,000 | 30.93 | ||||||||||||||
Exercised
|
(61,500 | ) | 20.38 | |||||||||||||
Forfeited
|
(85,000 | ) | 26.72 | |||||||||||||
Outstanding
at December 31, 2008
|
2,963,500 | 27.56 | ||||||||||||||
Granted
(5)
|
1,460,000 | 23.46 | ||||||||||||||
Exercised
|
(261,000 | ) | 19.61 | |||||||||||||
Forfeited
|
(930,540 | ) | 26.69 | |||||||||||||
Awards
assumed in connection
with
TEPPCO Merger
|
593,960 | 26.12 | ||||||||||||||
Outstanding at December 31,
2009
(6)
|
3,825,920 | 26.52 | 4.6 | $ | 2.8 | |||||||||||
Options
exercisable at:
|
||||||||||||||||
December
31, 2007
|
335,000 | $ | 22.06 | 4.0 | $ | 3.3 | ||||||||||
December
31, 2008
|
548,500 | $ | 21.47 | 4.1 | $ | -- | ||||||||||
December
31, 2009 (6)
|
447,500 | $ | 25.09 | 4.8 | $ | 2.8 | ||||||||||
(1)
Aggregate
intrinsic value reflects fully vested unit options at the date
indicated.
(2)
Aggregate
grant date fair value of these unit options issued during 2007 was $2.4
million based on the following assumptions: (i) a weighted-average grant
date market price of our common units of $30.63 per unit; (ii) expected
life of options of 7.0 years; (iii) weighted-average risk-free interest
rate of 4.8%; (iv) weighted-average expected distribution yield on our
common units of 8.4% and (v) weighted-average expected unit price
volatility on our common units of 23.2%.
(3)
Includes
the settlement of 710,000 options in connection with the resignation of
our general partner’s former chief executive officer.
(4)
Aggregate
grant date fair value of these unit options issued during 2008 was $1.9
million based on the following assumptions: (i) a grant date market price
of our common units of $30.93 per unit; (ii) expected life of options of
4.7 years; (iii) risk-free interest rate of 3.3%; (iv) expected
distribution yield on our common units of 7.0% and (v) expected unit price
volatility on our common units of 19.8%. An estimated forfeiture rate
of 17% was applied to awards granted during 2008.
(5)
Aggregate
grant date fair value of these unit options issued during 2009 was $8.1
million based on the following assumptions: (i) a weighted-average grant
date market price of our common units of $23.46 per unit; (ii)
weighted-average expected life of options of 4.8 years; (iii)
weighted-average risk-free interest rate of 2.1%; (iv) weighted-average
expected distribution yield on our common units of 9.4% and (v)
weighted-average expected unit price volatility on our common units of
57.4%. An estimated forfeiture rate of 17% was applied to awards
granted during 2009.
(6)
We
were committed to issue 3,825,920 and 2,963,500 of our common units at
December 31, 2009 and 2008, respectively, if all outstanding options
awarded (as of these dates) were exercised. Of the option awards
outstanding at December 31, 2009, an additional 410,000, 712,280, 736,000
and 1,520,140 are exercisable in 2010, 2012, 2013 and 2014,
respectively.
|
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Total
intrinsic value of option awards exercised during period
|
$ | 2.4 | $ | 0.6 | $ | 3.0 | ||||||
Cash
received from EPCO in connection with the
exercise
of unit option awards
|
1.7 | 0.7 | 7.6 | |||||||||
Option-related
reimbursements to EPCO
|
2.4 | 0.6 | 3.0 |
Phantom
Unit Awards Issued by
|
||||||||||||
TEPPCO
|
Enterprise
Products
Partners
|
Total
|
||||||||||
Phantom
units at December 31, 2006
|
154,479 | -- | 154,479 | |||||||||
Granted
|
259 | -- | 259 | |||||||||
Vested
|
(13,533 | ) | -- | (13,533 | ) | |||||||
Settled
or forfeited
|
(13,800 | ) | -- | (13,800 | ) | |||||||
Phantom
units at December 31, 2007
|
127,405 | -- | 127,405 | |||||||||
Granted
|
1,698 | 4,400 | 6,098 | |||||||||
Vested
|
(58,168 | ) | -- | (58,168 | ) | |||||||
Settled
or forfeited
|
(1,600 | ) | -- | (1,600 | ) | |||||||
Phantom
units at December 31, 2008
|
69,335 | 4,400 | 73,735 | |||||||||
Granted
|
124 | 6,200 | 6,324 | |||||||||
Vested
|
(61,519 | ) | -- | (61,519 | ) | |||||||
Settled
or forfeited
|
(4,447 | ) | -- | (4,447 | ) | |||||||
Awards
assumed in connection with TEPPCO Merger
|
(3,493 | ) | 4,327 | 834 | ||||||||
Phantom
units at December 31, 2009
|
-- | 14,927 | 14,927 |
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Accrued
liability for phantom unit awards, at end of period
|
$ | 0.2 | $ | 1.2 | $ | 4.5 | ||||||
Liabilities
paid for phantom unit awards
|
1.2 | 2.5 | 0.6 |
UARs
Issued by
|
||||||||||||||||
TEPPCO
|
Enterprise
Products
Partners
|
EPE
|
Total
|
|||||||||||||
UARs
at December 31, 2006
|
-- | -- | -- | -- | ||||||||||||
Granted
|
404,704 | -- | 90,000 | 494,704 | ||||||||||||
Settled
or forfeited
|
(2,756 | ) | -- | -- | (2,756 | ) | ||||||||||
UARs
at December 31, 2007
|
401,948 | -- | 90,000 | 491,948 | ||||||||||||
Granted
|
29,429 | -- | -- | 29,429 | ||||||||||||
UARs
at December 31, 2008
|
431,377 | -- | 90,000 | 521,377 | ||||||||||||
Settled
or forfeited
|
(166,217 | ) | (186,614 | ) | -- | (352,831 | ) | |||||||||
Awards
assumed in connection with the TEPPCO Merger
|
(265,160 | ) | 328,810 | -- | 63,650 | |||||||||||
UARs
at December 31, 2009
|
-- | 142,196 | 90,000 | 232,196 |
At
December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Accrued
liability for UARs
|
$ | 0.3 | $ | 0.1 | $ | 0.1 |
§
|
Changes
in the fair value of a recognized asset or liability, or an unrecognized
firm commitment - In a fair value hedge, gains and losses for both the
derivative instrument and the hedged item are recognized in income during
the period of change.
|
§
|
Variable
cash flows of a forecasted transaction - In a cash flow hedge, the
effective portion of the hedge is reported in other comprehensive income
or loss (“OCI”) and is reclassified into earnings when the forecasted
transaction affects earnings.
|
§
|
Foreign
currency exposure - A foreign currency hedge can be treated as either a
fair value hedge or a cash flow hedge depending on the risk being
hedged.
|
Number
and Type of
|
Notional
|
Period
of
|
Average
Rate
|
Accounting
|
|
Hedged
Transaction
|
Derivative
Employed
|
Amount
|
Hedge
|
Locked
|
Treatment
|
Future
debt offering
|
1
forward starting swap
|
$50.0
|
6/10
to 6/20
|
3.3%
|
Cash
flow hedge
|
Future
debt offering
|
3
forward starting swaps
|
$250.0
|
2/11
to 2/21
|
3.6%
|
Cash
flow hedge
|
Asset
Derivatives
|
Liability
Derivatives
|
|||||||||||||||||||
December
31, 2009
|
December
31, 2008
|
December
31, 2009
|
December
31, 2008
|
|||||||||||||||||
Balance
Sheet
|
Fair
|
Balance
Sheet
|
Fair
|
Balance
Sheet
|
Fair
|
Balance
Sheet
|
Fair
|
|||||||||||||
Location
|
Value
|
Location
|
Value
|
Location
|
Value
|
Location
|
Value
|
|||||||||||||
Derivatives
designated as hedging instruments
|
||||||||||||||||||||
Interest
rate derivatives
|
Derivative
assets
|
$ | 32.7 |
Derivative
assets
|
$ | 7.8 |
Derivative
liabilities
|
$ | 5.5 |
Derivative
liabilities
|
$ | 5.9 | ||||||||
Interest
rate derivatives
|
Other
assets
|
31.8 |
Other
assets
|
38.9 |
Other
liabilities
|
2.2 |
Other
liabilities
|
3.9 | ||||||||||||
Total
interest rate derivatives
|
64.5 | 46.7 | 7.7 | 9.8 | ||||||||||||||||
Commodity
derivatives
|
Derivative
assets
|
52.0 |
Derivative
assets
|
150.6 |
Derivative
liabilities
|
62.6 |
Derivative
liabilities
|
253.5 | ||||||||||||
Commodity
derivatives
|
Other
assets
|
0.5 |
Other
assets
|
-- |
Other
liabilities
|
1.8 |
Other
liabilities
|
0.2 | ||||||||||||
Total
commodity derivatives (1)
|
52.5 | 150.6 | 64.4 | 253.7 | ||||||||||||||||
Foreign
currency derivatives (2)
|
Derivative
assets
|
0.2 |
Derivative
assets
|
9.3 |
Derivative
liabilities
|
-- |
Derivative
liabilities
|
-- | ||||||||||||
Total
derivatives designated
as hedging
instruments
|
$ | 117.2 | $ | 206.6 | $ | 72.1 | $ | 263.5 | ||||||||||||
Derivatives
not designated as hedging instruments
|
||||||||||||||||||||
Commodity
derivatives
|
Derivative
assets
|
$ | 28.9 |
Derivative
assets
|
$ | 50.9 |
Derivative
liabilities
|
$ | 24.9 |
Derivative
liabilities
|
$ | 43.4 | ||||||||
Commodity
derivatives
|
Other
assets
|
2.0 |
Other
assets
|
-- |
Other
liabilities
|
2.7 |
Other
liabilities
|
-- | ||||||||||||
Total
commodity derivatives
|
30.9 | 50.9 | 27.6 | 43.4 | ||||||||||||||||
Foreign
currency derivatives
|
Derivative
assets
|
-- |
Derivative
assets
|
-- |
Derivative
liabilities
|
-- |
Derivative
liabilities
|
0.1 | ||||||||||||
Total
derivatives not designated
as hedging
instruments
|
$ | 30.9 | $ | 50.9 | $ | 27.6 | $ | 43.5 | ||||||||||||
(1)
Represents
commodity derivative transactions that either have not settled or have
settled and not been invoiced. Settled and invoiced transactions are
reflected in either accounts receivable or accounts payable depending on
the outcome of the transaction.
(2)
Relates
to the hedging of our exposure to fluctuations in the foreign currency
exchange rate related to our Canadian NGL marketing
subsidiary.
|
Derivatives
in Fair Value
|
Gain
(Loss) Recognized in
|
||||||||
Hedging
Relationships
|
Location
|
Income
on Derivative
|
|||||||
For
Year Ended December 31,
|
|||||||||
2009
|
2008
|
||||||||
Interest
rate
|
Interest
expense
|
$ | (8.8 | ) | $ | 31.2 | |||
Commodity
|
Revenue
|
1.8 | -- | ||||||
Total
|
$ | (7.0 | ) | $ | 31.2 |
Derivatives
in Fair Value
|
Gain
(Loss) Recognized in
|
||||||||
Hedging
Relationships
|
Location
|
Income
on Hedged Item
|
|||||||
For
Year Ended December 31,
|
|||||||||
2009
|
2008
|
||||||||
Interest
rate
|
Interest
expense
|
$ | 3.2 | $ | (31.2 | ) | |||
Commodity
|
Revenue
|
(1.3 | ) | -- | |||||
Total
|
$ | 1.9 | $ | (31.2 | ) |
|
Change
in Value Recognized
|
|||||||
Derivatives
in Cash Flow
|
in
OCI on Derivative
|
|||||||
Hedging
Relationships
|
(Effective
Portion)
|
|||||||
For
Year Ended December 31,
|
||||||||
2009
|
2008
|
|||||||
Interest
rate derivatives
|
$ | 18.6 | $ | (52.0 | ) | |||
Commodity
derivatives – Revenue
|
(34.8 | ) | (34.8 | ) | ||||
Commodity
derivatives – Operating costs and expenses
|
(144.8 | ) | (135.4 | ) | ||||
Foreign
currency derivatives
|
(10.2 | ) | 9.3 | |||||
Total
|
$ | (171.2 | ) | $ | (212.9 | ) |
Amount
of Gain/(Loss)
|
|||||||||
Derivatives
in Cash Flow
|
Reclassified
from AOCI
|
||||||||
Hedging
Relationships
|
Location
|
into
Income (Effective Portion)
|
|||||||
For
Year Ended December 31,
|
|||||||||
2009
|
2008
|
||||||||
Interest
rate derivatives
|
Interest
expense
|
$ | (10.8 | ) | $ | 1.1 | |||
Commodity
derivatives
|
Revenue
|
(61.0 | ) | (56.7 | ) | ||||
Commodity
derivatives
|
Operating
costs and expenses
|
(233.2 | ) | (39.6 | ) | ||||
Total
|
$ | (305.0 | ) | $ | (95.2 | ) |
Amount
of Gain/(Loss)
|
|||||||||
Derivatives
in Cash Flow
|
Recognized
in Income on
|
||||||||
Hedging
Relationships
|
Location
|
Ineffective
Portion of Derivative
|
|||||||
For
Year Ended December 31,
|
|||||||||
2009
|
2008
|
||||||||
Interest
rate derivatives
|
Interest
expense
|
$ | 0.1 | $ | (3.6 | ) | |||
Commodity
derivatives
|
Revenue
|
0.2 | -- | ||||||
Commodity
derivatives
|
Operating
costs and expenses
|
(0.1 | ) | (1.7 | ) | ||||
Foreign
currency derivatives
|
-- | (0.1 | ) | ||||||
Total
|
$ | 0.2 | $ | (5.4 | ) |
Derivatives
Not Designated as
|
Gain/(Loss)
Recognized in
|
||||||||
Hedging
Instruments
|
Location
|
Income
on Derivative
|
|||||||
For
Year Ended December 31,
|
|||||||||
2009
|
2008
|
||||||||
Commodity
derivatives
|
Revenue
|
$ | 40.7 | $ | 39.3 | ||||
Commodity
derivatives
|
Operating
costs and expenses
|
-- | (7.6 | ) | |||||
Foreign
currency derivatives
|
Other
expense
|
(0.1 | ) | (0.1 | ) | ||||
Total
|
$ | 40.6 | $ | 31.6 |
§
|
Level
1 fair values are based on quoted prices, which are available in active
markets for identical assets or liabilities as of the measurement
date. Active markets are defined as those in which transactions
for identical assets or liabilities occur with sufficient frequency so as
to provide pricing information on an ongoing basis (e.g., the New York
Mercantile Exchange). Our Level 1 fair values primarily consist
of financial assets and liabilities such as exchange-traded commodity
derivative instruments.
|
§
|
Level
2 fair values are based on pricing inputs other than quoted prices in
active markets (as reflected in Level 1 fair values) and are either
directly or indirectly observable as of the measurement
date. Level 2 fair values include instruments that are valued
using financial models or other appropriate valuation
methodologies. Such financial models are primarily
industry-standard models that consider various assumptions, including
quoted forward prices for commodities, the time value of money, volatility
factors, current market and contractual prices for the underlying
instruments and other relevant economic measures. Substantially
all of these assumptions are: (i) observable in the marketplace throughout
the full term of the instrument, (ii) can be derived from observable data
or (iii) are validated by inputs other than quoted prices (e.g., interest
rate and yield curves at commonly quoted intervals). Our Level
2 fair values primarily consist of commodity derivative instruments such
as forwards, swaps and other instruments transacted on an exchange or over
the counter. The fair values of these derivatives are based on
observable price quotes for similar products and locations. The
value of our interest rate derivatives are valued by using appropriate
financial models with the implied forward London Interbank
Offered Rate (“LIBOR”) yield curve for the same period as the future
interest swap settlements.
|
§
|
Level
3 fair values are based on unobservable inputs. Unobservable
inputs are used to measure fair value to the extent that observable inputs
are not available, thereby allowing for situations in which there is
little, if any, market activity for the asset or liability at the
measurement date. Unobservable inputs reflect the reporting
entity’s own ideas about the assumptions that market participants would
use in pricing an asset or liability (including assumptions about
risk). Unobservable inputs are based on the best information
available in the circumstances, which might include the reporting entity’s
internally developed data. The reporting entity must not ignore
information about market participant assumptions that is reasonably
available without undue cost and effort. Level 3 inputs are
typically used in connection with internally developed valuation
methodologies where management makes its best estimate of an instrument’s
fair value. Our Level 3 fair values largely consist of ethane,
normal butane and natural gasoline-based contracts with a range of two to
12 months in term. We rely on price quotes from reputable
brokers in the marketplace who publish price quotes on certain
products. Whenever possible, we compare these prices to other
reputable brokers for the same product in the same
market. These prices, combined with our forward transactions,
are used in our model to determine the fair value of such
instruments.
|
At
December 31, 2009
|
||||||||||||||||
Level
1
|
Level
2
|
Level
3
|
Total
|
|||||||||||||
Financial
assets:
|
||||||||||||||||
Interest
rate derivative instruments
|
$ | -- | $ | 64.5 | $ | -- | $ | 64.5 | ||||||||
Commodity
derivative instruments
|
14.6 | 34.4 | 34.4 | 83.4 | ||||||||||||
Foreign
currency derivative instruments
|
-- | 0.2 | -- | 0.2 | ||||||||||||
Total
|
$ | 14.6 | $ | 99.1 | $ | 34.4 | $ | 148.1 | ||||||||
Financial
liabilities:
|
||||||||||||||||
Interest
rate derivative instruments
|
$ | -- | $ | 7.7 | $ | -- | $ | 7.7 | ||||||||
Commodity
derivative instruments
|
17.1 | 46.2 | 28.7 | 92.0 | ||||||||||||
Total
|
$ | 17.1 | $ | 53.9 | $ | 28.7 | $ | 99.7 |
At
December 31, 2008
|
||||||||||||||||
Level
1
|
Level
2
|
Level
3
|
Total
|
|||||||||||||
Financial
assets:
|
||||||||||||||||
Commodity
derivative instruments
|
$ | 4.0 | $ | 164.7 | $ | 32.8 | $ | 201.5 | ||||||||
Foreign
currency derivative instruments
|
-- | 9.3 | -- | 9.3 | ||||||||||||
Interest
rate derivative instruments
|
-- | 46.7 | -- | 46.7 | ||||||||||||
Total
|
$ | 4.0 | $ | 220.7 | $ | 32.8 | $ | 257.5 | ||||||||
Financial
liabilities:
|
||||||||||||||||
Commodity
derivative instruments
|
$ | 7.1 | $ | 289.6 | $ | 0.4 | $ | 297.1 | ||||||||
Foreign
currency derivative instruments
|
-- | 0.1 | -- | 0.1 | ||||||||||||
Interest
rate derivative instruments
|
-- | 9.8 | -- | 9.8 | ||||||||||||
Total
|
$ | 7.1 | $ | 299.5 | $ | 0.4 | $ | 307.0 |
Level
3
|
Impairment
Charges
|
|||||||
Property,
plant and equipment (see Note 8)
|
$ | 29.6 | $ | 29.4 | ||||
Intangible
assets (see Note 11)
|
0.6 | 0.6 | ||||||
Goodwill
(see Note 11)
|
-- | 1.3 | ||||||
Other
current assets
|
1.2 | 2.2 | ||||||
Total
|
$ | 31.4 | $ | 33.5 |
December
31,
|
||||||||
2009
|
2008
|
|||||||
Working
inventory (1)
|
$ | 466.4 | $ | 188.1 | ||||
Forward
sales inventory (2)
|
245.5 | 216.9 | ||||||
Total
inventory
|
$ | 711.9 | $ | 405.0 | ||||
(1)
Working
inventory is comprised of inventories of natural gas, NGLs, crude oil,
refined products, lubrication oils and certain petrochemical products that
are either available-for-sale or used in the provision for
services.
(2)
Forward
sales inventory consists of identified natural gas, NGL, refined product
and crude oil volumes dedicated to the fulfillment of forward sales
contracts. In general, the increase in volumes dedicated to forward
physical sales contracts improves the overall utilization and
profitability of our fee-based assets. The cash invested in forward
sales NGL inventories is expected to be recovered within the next twelve
months as physical delivery from inventory occurs.
|
§
|
Write-downs
of NGL inventories are recorded as an expense related to our NGL marketing
activities within our NGL Pipelines & Services business
segment;
|
§
|
Write-downs
of natural gas inventories are recorded as an expense related to our
natural gas pipeline operations within our Onshore Natural Gas Pipelines
& Services business segment;
|
§
|
Write-downs
of crude oil inventories are recorded as an expense related to our crude
oil operations within our Onshore Crude Oil Pipelines & Services
business segment; and
|
§
|
Write-downs
of petrochemical, refined products and related inventories are recorded as
an expense related to our petrochemical and refined products marketing
activities or octane additive production business, as applicable, within
our Petrochemical & Refined Products Services business
segment.
|
Estimated
|
||||||||||||
Useful
Life
|
December
31,
|
|||||||||||
in
Years
|
2009
|
2008
|
||||||||||
Plants
and pipelines (1)
|
3-45 (5) | $ | 17,681.9 | $ | 15,444.7 | |||||||
Underground
and other storage facilities (2)
|
5-40 (6) | 1,280.5 | 1,203.9 | |||||||||
Platforms
and facilities (3)
|
20-31 | 637.6 | 634.8 | |||||||||
Transportation
equipment (4)
|
3-10 | 60.1 | 50.9 | |||||||||
Marine
vessels
|
20-30 | 559.4 | 453.0 | |||||||||
Land
|
82.9 | 76.5 | ||||||||||
Construction
in progress
|
1,207.2 | 2,015.4 | ||||||||||
Total
|
21,509.6 | 19,879.2 | ||||||||||
Less
accumulated depreciation
|
3,820.4 | 3,146.4 | ||||||||||
Property,
plant and equipment, net
|
$ | 17,689.2 | $ | 16,732.8 | ||||||||
(1)
Plants
and pipelines include processing plants; NGL, petrochemical, crude oil and
natural gas pipelines; terminal loading and unloading facilities; office
furniture and equipment; buildings; laboratory and shop equipment and
related assets.
(2)
Underground
and other storage facilities include underground product storage caverns;
above ground storage tanks; water wells and related assets.
(3)
Platforms
and facilities include offshore platforms and related facilities and other
associated assets.
(4)
Transportation
equipment includes vehicles and similar assets used in our
operations.
(5)
In
general, the estimated useful lives of major components of this category
are as follows: processing plants, 20-35 years; pipelines and related
equipment, 5-45 years; terminal facilities, 10-35 years; delivery
facilities, 20-40 years; office furniture and equipment, 3-20 years;
buildings, 20-40 years; and laboratory and shop equipment, 5-35
years.
(6)
In
general, the estimated useful lives of major components of this category
are as follows: underground storage facilities, 5-35 years; storage
tanks, 10-40 years; and water wells, 5-35 years.
|
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Depreciation
expense (1)
|
$ | 678.1 | $ | 595.9 | $ | 515.7 | ||||||
Capitalized
interest (2)
|
53.1 | 90.7 | 86.5 | |||||||||
(1)
Depreciation
expense is a component of costs and expenses as presented in our
Statements of Consolidated Operations.
(2)
Capitalized
interest increases the carrying value of the associated asset and reduces
interest expense during the period it is recorded.
|
ARO
liability balance, December 31, 2007
|
$ | 42.2 | ||
Liabilities
incurred
|
1.1 | |||
Liabilities
settled
|
(8.2 | ) | ||
Revisions
in estimated cash flows
|
4.7 | |||
Accretion
expense
|
2.4 | |||
ARO
liability balance, December 31, 2008
|
42.2 | |||
Liabilities
incurred
|
0.5 | |||
Liabilities
settled
|
(17.1 | ) | ||
Revisions
in estimated cash flows
|
26.1 | |||
Accretion
expense
|
3.1 | |||
ARO
liability balance, December 31, 2009
|
$ | 54.8 |
2010
|
2011
|
2012
|
2013
|
2014
|
||||||||||||||
$ | 3.8 | $ | 3.7 | $ | 4.0 | $ | 4.3 | $ | 4.7 |
Ownership
|
||||||||||||
Percentage
at
|
||||||||||||
December
31,
|
December
31,
|
|||||||||||
2009
|
2009
|
2008
|
||||||||||
NGL
Pipelines & Services:
|
||||||||||||
Venice
Energy Service Company, L.L.C.
|
13.1% | $ | 32.6 | $ | 37.7 | |||||||
K/D/S
Promix, L.L.C.
|
50% | 48.9 | 46.4 | |||||||||
Baton
Rouge Fractionators LLC
|
32.2% | 22.2 | 24.2 | |||||||||
Skelly-Belvieu
Pipeline Company, L.L.C.
|
49% | 37.9 | 36.0 | |||||||||
Onshore
Natural Gas Pipelines & Services:
|
||||||||||||
Evangeline
(1)
|
49.5% | 5.6 | 4.5 | |||||||||
White
River Hub, LLC
|
50% | 26.4 | 21.4 | |||||||||
Onshore
Crude Oil Pipelines & Services:
|
||||||||||||
Seaway
Crude Pipeline Company
|
50% | 178.5 | 186.2 | |||||||||
Offshore
Pipelines & Services:
|
||||||||||||
Poseidon
Oil Pipeline, L.L.C.
|
36% | 61.7 | 60.2 | |||||||||
Cameron
Highway Oil Pipeline Company (“Cameron Highway”)
|
50% | 239.6 | 250.9 | |||||||||
Deepwater
Gateway, L.L.C.
|
50% | 101.8 | 104.8 | |||||||||
Neptune
Pipeline Company, L.L.C.
|
25.7% | 53.8 | 52.7 | |||||||||
Nemo
Gas Gathering Company, LLC (“Nemo”)
|
33.9% | -- | 0.4 | |||||||||
Petrochemical
& Refined Products Services:
|
||||||||||||
Baton
Rouge Propylene Concentrator, LLC
|
30% | 11.1 | 12.6 | |||||||||
Centennial
Pipeline LLC (“Centennial”)
|
50% | 66.7 | 69.7 | |||||||||
Other
(2)
|
Varies
|
3.8 | 4.2 | |||||||||
Total
|
$ | 890.6 | $ | 911.9 | ||||||||
|
||||||||||||
(1)
Evangeline
refers to our ownership interests in Evangeline Gas Pipeline Company, L.P.
and Evangeline Gas Corp., collectively.
(2)
Other
unconsolidated affiliates include a 50% interest in a propylene pipeline
extending from Mont Belvieu, Texas to La Porte, Texas and a 25% interest
in a company that provides logistics communications solutions between
petroleum pipelines and their customers.
|
December
31,
|
||||||||
2009
|
2008
|
|||||||
NGL
Pipelines & Services
|
$ | 27.1 | $ | 28.0 | ||||
Onshore
Crude Oil Pipelines & Services
|
20.4 | 21.1 | ||||||
Offshore
Pipelines & Service
|
17.3 | 18.6 | ||||||
Petrochemical
& Refined Products Services
|
4.0 | 7.9 | ||||||
Total
|
$ | 68.8 | $ | 75.6 |
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
NGL
Pipelines & Services
|
$ | 0.9 | $ | 0.5 | $ | 0.6 | ||||||
Onshore
Crude Oil Pipelines & Services
|
0.7 | 0.7 | 0.7 | |||||||||
Offshore
Pipelines & Service
|
1.3 | 1.3 | 1.3 | |||||||||
Petrochemical
& Refined Products Services
|
3.9 | 4.3 | 5.3 | |||||||||
Total
|
$ | 6.8 | $ | 6.8 | $ | 7.9 |
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
NGL
Pipelines & Services
|
$ | 11.3 | $ | 1.4 | $ | 7.1 | ||||||
Onshore
Natural Gas Pipelines & Services
|
4.9 | 1.6 | 0.2 | |||||||||
Onshore
Crude Oil Pipelines & Services
|
9.3 | 11.7 | 2.6 | |||||||||
Offshore
Pipelines & Services
|
36.9 | 33.7 | 12.6 | |||||||||
Petrochemical
& Refined Products Services
|
(11.2 | ) | (13.5 | ) | (12.0 | ) | ||||||
Total
|
$ | 51.2 | $ | 34.9 | $ | 10.5 |
At
December 31,
|
||||||||||||
2009
|
2008
|
|||||||||||
BALANCE
SHEET DATA:
|
||||||||||||
Current
assets
|
$ | 201.0 | $ | 240.8 | ||||||||
Property,
plant and equipment, net
|
1,997.2 | 2,053.3 | ||||||||||
Other
assets
|
36.4 | 23.1 | ||||||||||
Total
assets
|
$ | 2,234.6 | $ | 2,317.2 | ||||||||
Current
liabilities
|
$ | 118.6 | $ | 165.9 | ||||||||
Other
liabilities
|
255.4 | 282.8 | ||||||||||
Combined
equity
|
1,860.6 | 1,868.5 | ||||||||||
Total
liabilities and combined equity
|
$ | 2,234.6 | $ | 2,317.2 | ||||||||
For
Year Ended December 31,
|
||||||||||||
2009 | 2008 | 2007 | ||||||||||
INCOME
STATEMENT DATA:
|
||||||||||||
Revenues
|
$ | 738.1 | $ | 961.7 | $ | 794.1 | ||||||
Operating
income
|
169.2 | 154.3 | 173.4 | |||||||||
Net
income
|
155.9 | 136.1 | 110.5 |
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
NGL
Pipelines & Services
|
$ | 33.3 | $ | 77.0 | $ | 0.4 | ||||||
Onshore
Natural Gas Pipelines & Services
|
0.8 | 125.2 | 35.5 | |||||||||
Petrochemical
& Refined Products Services
|
73.2 | 351.3 | -- | |||||||||
Total
cash used for business combinations
|
$ | 107.3 | $ | 553.5 | $ | 35.9 |
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Assets
acquired in business combination:
|
||||||||||||
Current
assets
|
$ | 1.4 | $ | 6.6 | $ | -- | ||||||
Property,
plant and equipment, net
|
115.9 | 549.6 | 44.5 | |||||||||
Intangible
assets
|
0.3 | 92.5 | (8.5 | ) | ||||||||
Other
assets
|
(0.3 | ) | 0.4 | -- | ||||||||
Total
assets acquired
|
117.3 | 649.1 | 36.0 | |||||||||
Liabilities
assumed in business combination:
|
||||||||||||
Current
liabilities
|
0.3 | (3.2 | ) | -- | ||||||||
Long-term
debt
|
-- | (2.6 | ) | -- | ||||||||
Other
long-term liabilities
|
-- | (109.5 | ) | (1.2 | ) | |||||||
Total
liabilities assumed
|
0.3 | (115.3 | ) | (1.2 | ) | |||||||
Total
assets acquired plus liabilities assumed
|
117.6 | 533.8 | 34.8 | |||||||||
Noncontrolling
interest acquired
|
10.3 | -- | -- | |||||||||
Fair
value of 4,854,899 TEPPCO units
|
-- | 186.6 | -- | |||||||||
Total
cash used for business combinations
|
107.3 | 553.5 | 35.9 | |||||||||
Goodwill
(1)
|
$ | -- | $ | 206.3 | $ | 1.1 | ||||||
(1) See
Note 11 for additional information regarding goodwill.
|
§
|
the
acquisition of certain rail and truck terminal facilities located in Mont
Belvieu, Texas from Martin Midstream Partners LP for $23.7 million in
cash;
|
§
|
the
acquisition of tow boats and tank barges primarily based in Miami,
Florida, with additional assets located in Mobile, Alabama and Houston,
Texas from TransMontaigne Product Services Inc. for $50.0 million in cash;
and
|
§
|
the
acquisition of a majority interest in the Rio Grande Pipeline Company
(“Rio Grande”) purchased from HEP Navajo Southern L.P. for $32.8 million
in cash. Rio Grande owns an NGL pipeline system in
Texas.
|
December
31, 2009
|
December
31, 2008
|
|||||||||||||||||||||||
Gross
|
Accum.
|
Carrying
|
Gross
|
Accum.
|
Carrying
|
|||||||||||||||||||
Value
|
Amort.
|
Value
|
Value
|
Amort.
|
Value
|
|||||||||||||||||||
NGL Pipelines & Services:
(1)
|
||||||||||||||||||||||||
Customer
relationship intangibles
|
$ | 237.4 | $ | (86.5 | ) | $ | 150.9 | $ | 237.4 | $ | (68.7 | ) | $ | 168.7 | ||||||||||
Contract-based
intangibles
|
321.4 | (156.7 | ) | 164.7 | 320.3 | (137.6 | ) | 182.7 | ||||||||||||||||
Segment
total
|
558.8 | (243.2 | ) | 315.6 | 557.7 | (206.3 | ) | 351.4 | ||||||||||||||||
Onshore
Natural Gas Pipelines & Services:
|
||||||||||||||||||||||||
Customer
relationship intangibles (2)
|
372.0 | (124.3 | ) | 247.7 | 372.0 | (103.2 | ) | 268.8 | ||||||||||||||||
Contract-based
intangibles
|
565.3 | (285.8 | ) | 279.5 | 565.3 | (249.7 | ) | 315.6 | ||||||||||||||||
Segment
total
|
937.3 | (410.1 | ) | 527.2 | 937.3 | (352.9 | ) | 584.4 | ||||||||||||||||
Onshore
Crude Oil Pipelines & Services:
|
||||||||||||||||||||||||
Contract-based
intangibles
|
10.0 | (3.5 | ) | 6.5 | 10.0 | (3.1 | ) | 6.9 | ||||||||||||||||
Segment
total
|
10.0 | (3.5 | ) | 6.5 | 10.0 | (3.1 | ) | 6.9 | ||||||||||||||||
Offshore
Pipelines & Services:
|
||||||||||||||||||||||||
Customer
relationship intangibles
|
205.8 | (105.3 | ) | 100.5 | 205.8 | (90.7 | ) | 115.1 | ||||||||||||||||
Contract-based
intangibles
|
1.2 | (0.2 | ) | 1.0 | 1.2 | (0.1 | ) | 1.1 | ||||||||||||||||
Segment
total
|
207.0 | (105.5 | ) | 101.5 | 207.0 | (90.8 | ) | 116.2 | ||||||||||||||||
Petrochemical & Refined
Products Services:
(3)
|
||||||||||||||||||||||||
Customer
relationship intangibles
|
104.6 | (18.8 | ) | 85.8 | 104.9 | (13.8 | ) | 91.1 | ||||||||||||||||
Contract-based
intangibles
|
42.1 | (13.9 | ) | 28.2 | 41.1 | (8.2 | ) | 32.9 | ||||||||||||||||
Segment
total
|
146.7 | (32.7 | ) | 114.0 | 146.0 | (22.0 | ) | 124.0 | ||||||||||||||||
Total
all segments
|
$ | 1,859.8 | $ | (795.0 | ) | $ | 1,064.8 | $ | 1,858.0 | $ | (675.1 | ) | $ | 1,182.9 | ||||||||||
(1)
In
2008, we acquired $6.0 million of certain permits related to our Mont
Belvieu complex and had $12.7 million of purchase price allocation
adjustments related to San Felipe customer relationships from a 2007
business combination.
(2)
In
2008, we acquired $9.8 million of customer relationships due to the Great
Divide business combination.
(3)
Amount
includes a non-cash impairment charge of $0.6 million in 2009 related to
certain intangible assets, see Note 6 for additional
information.
|
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
NGL
Pipelines & Services
|
$ | 36.9 | $ | 40.7 | $ | 38.2 | ||||||
Onshore
Natural Gas Pipelines & Services
|
57.2 | 61.7 | 64.4 | |||||||||
Onshore
Crude Oil Pipelines & Services
|
0.4 | 0.5 | 0.5 | |||||||||
Offshore
Pipelines & Services
|
14.7 | 16.9 | 19.3 | |||||||||
Petrochemical
& Refined Products Services
|
10.7 | 10.2 | 2.8 | |||||||||
Total
all segments
|
$ | 119.9 | $ | 130.0 | $ | 125.2 |
2010
|
2011
|
2012
|
2013
|
2014
|
||||||||||||||
$ | 112.2 | $ | 105.0 | $ | 89.4 | $ | 82.4 | $ | 78.1 |
§
|
San
Juan Gathering System customer relationships – We acquired these customer
relationships in connection with the GulfTerra Merger, which was completed
on September 30, 2004. At December 31, 2009, the carrying value
of this group of intangible assets was $220.8 million. These
intangible assets are being amortized to earnings over their estimated
economic life of 35 years through 2039. Amortization expense is
recorded using a method that closely resembles the pattern in which the
economic benefits of the underlying natural gas resource bases are
expected to be consumed or otherwise
used.
|
§
|
Offshore
Pipeline & Platform customer relationships – We acquired these
customer relationships in connection with the GulfTerra
Merger. At December 31, 2009, the carrying value of this group
of intangible assets was $100.5 million. These intangible
assets are being amortized to earnings over their estimated
economic lives, which range from 18 to 33 years (i.e. through 2022
to 2037). Amortization expense is recorded using a method
that closely resembles the pattern in which the economic benefits of the
underlying crude oil and natural gas resource bases are expected to be
consumed or otherwise used.
|
§
|
Encinal
natural gas processing customer relationship – We acquired this customer
relationship in connection with our Encinal acquisition in
2006. At December 31, 2009, the carrying value of this
intangible asset was $89.3 million. This intangible asset is
being amortized to earnings over its estimated economic life of 20 years
through 2026. Amortization expense is recorded using a method
that closely resembles the pattern in which the economic benefit of the
underlying natural gas resource bases are expected to be consumed or
otherwise used.
|
§
|
Jonah
Gas Gathering Company (“Jonah”) natural gas gathering agreements – These
intangible assets represent the value attributed to certain of Jonah’s
natural gas gathering contracts that were originally acquired by TEPPCO in
2001. At December 31, 2009, the carrying value of this group of
intangible assets was $125.0 million. These intangible assets
are being amortized to earnings using a units-of-production method based
on throughput volumes on the Jonah system, which is estimated to extend
through 2041.
|
§
|
Val
Verde natural gas gathering agreements – These intangible assets represent
the value attributed to certain natural gas gathering agreements
associated with our Val Verde Gathering System that was originally
acquired by TEPPCO in 2002. At December 31, 2009, the carrying
value of these intangible assets was $98.4 million. These
intangible assets are being amortized to earnings using a
units-of-production method based on throughput volumes on the Val Verde
Gathering System, which is estimated to extend through
2032.
|
§
|
Shell
Processing Agreement – This margin-band/keepwhole processing agreement
grants us the right to process Shell Oil Company’s (or its assignee’s)
current and future natural gas production within the state and federal
waters of the Gulf of Mexico. We acquired the Shell Processing
Agreement in connection with our 1999 purchase of certain of Shell’s
midstream energy assets
|
|
located
along the U.S. Gulf Coast. At December 31, 2009, the carrying
value of this intangible asset was $105.9 million. This
intangible asset is being amortized to earnings on a straight-line basis
over its estimated economic life of 20 years through
2019.
|
§
|
Mississippi
natural gas storage contracts – These intangible assets represent the
value assigned by us to certain natural gas storage contracts associated
with our Petal and Hattiesburg, Mississippi storage
facilities. These facilities were acquired in connection with
the GulfTerra Merger. At December 31, 2009, the carrying value
of these intangible assets was $55.4 million. These intangible
assets are being amortized to earnings on a straight-line basis over the
remainder of their respective contract terms, which range from eight to 18
years (i.e. 2012 through 2022).
|
Onshore
|
Onshore
|
Petrochemical
|
||||||||||||||||||||||
NGL
|
Natural
Gas
|
Crude
Oil
|
Offshore
|
&
Refined
|
||||||||||||||||||||
Pipelines
|
Pipelines
|
Pipelines
|
Pipelines
|
Products
|
Consolidated
|
|||||||||||||||||||
&
Services
|
&
Services
|
&
Services
|
&
Services
|
Services
|
Totals
|
|||||||||||||||||||
Balance
at January 1, 2007
|
$ | 224.8 | $ | 284.9 | $ | 303.0 | $ | 82.1 | $ | 917.3 | $ | 1,812.1 | ||||||||||||
Goodwill
related to acquisitions
|
1.2 | -- | -- | -- | -- | 1.2 | ||||||||||||||||||
Balance
at December 31, 2007
|
226.0 | 284.9 | 303.0 | 82.1 | 917.3 | 1,813.3 | ||||||||||||||||||
Goodwill
related to acquisitions
|
115.2 | -- | -- | -- | 91.1 | 206.3 | ||||||||||||||||||
Balance
at December 31, 2008
|
341.2 | 284.9 | 303.0 | 82.1 | 1,008.4 | 2,019.6 | ||||||||||||||||||
Impairment
charges (1)
|
-- | -- | -- | -- | (1.3 | ) | (1.3 | ) | ||||||||||||||||
Balance
at December 31, 2009 (2)
|
$ | 341.2 | $ | 284.9 | $ | 303.0 | $ | 82.1 | $ | 1,007.1 | $ | 2,018.3 | ||||||||||||
(1)
See Note 6 for additional information regarding impairment charges
recorded during year ended December 31, 2009.
(2)
The total carrying amount of goodwill at December 31, 2009 is
reflected net of $1.3 million of accumulated impairment
charges.
|
December
31,
|
||||||||
2009
|
2008
|
|||||||
NGL
Pipelines & Services
|
||||||||
Acquisition
of ownership interests in TEPPCO
|
$ | 72.2 | $ | 72.2 | ||||
GulfTerra
Merger
|
23.8 | 23.8 | ||||||
Acquisition
of Encinal
|
95.3 | 95.3 | ||||||
Acquisition
of interest in Dixie
|
80.3 | 80.3 | ||||||
Acquisition
of Great Divide
|
44.9 | 44.9 | ||||||
Acquisition
of Indian Springs natural gas processing business
|
13.2 | 13.2 | ||||||
Other
|
11.5 | 11.5 | ||||||
Onshore
Natural Gas Pipelines & Services
|
||||||||
GulfTerra
Merger
|
279.9 | 279.9 | ||||||
Other
|
5.0 | 5.0 | ||||||
Onshore
Crude Oil Pipeline & Services
|
||||||||
Acquisition
of ownership interests in TEPPCO
|
288.8 | 288.8 | ||||||
Acquisition
of crude oil pipeline and services business
|
14.2 | 14.2 | ||||||
Offshore
Pipelines & Services
|
||||||||
GulfTerra
Merger
|
82.1 | 82.1 | ||||||
Petrochemical
& Refined Products Services
|
||||||||
Acquisition
of ownership interests in TEPPCO
|
842.3 | 842.3 | ||||||
Acquisition
of marine services businesses
|
90.4 | 90.4 | ||||||
Acquisition
of Mont Belvieu propylene fractionation business
|
73.7 | 73.7 | ||||||
Other
(1)
|
0.7 | 2.0 | ||||||
Total
|
$ | 2,018.3 | $ | 2,019.6 | ||||
(1)
Includes
a non-cash impairment charge of $1.3 million, see Note 6 for additional
information.
|
December
31,
|
||||||||
2009
|
2008
|
|||||||
EPO
senior debt obligations:
|
||||||||
Multi-Year
Revolving Credit Facility, variable-rate, due November
2012
|
$ | 195.5 | $ | 800.0 | ||||
Pascagoula
MBFC Loan, 8.70% fixed-rate, due March 2010
(1)
|
54.0 | 54.0 | ||||||
Petal
GO Zone Bonds, variable-rate, due August 2037
|
57.5 | 57.5 | ||||||
Yen
Term Loan, 4.93% fixed-rate, due March 2009
|
-- | 217.6 | ||||||
Senior
Notes B, 7.50% fixed-rate, due February 2011
|
450.0 | 450.0 | ||||||
Senior
Notes C, 6.375% fixed-rate, due February 2013
|
350.0 | 350.0 | ||||||
Senior
Notes D, 6.875% fixed-rate, due March 2033
|
500.0 | 500.0 | ||||||
Senior
Notes F, 4.625% fixed-rate, due October 2009
|
-- | 500.0 | ||||||
Senior
Notes G, 5.60% fixed-rate, due October 2014
|
650.0 | 650.0 | ||||||
Senior
Notes H, 6.65% fixed-rate, due October 2034
|
350.0 | 350.0 | ||||||
Senior
Notes I, 5.00% fixed-rate, due March 2015
|
250.0 | 250.0 | ||||||
Senior
Notes J, 5.75% fixed-rate, due March 2035
|
250.0 | 250.0 | ||||||
Senior
Notes K, 4.95% fixed-rate, due June 2010 (1)
|
500.0 | 500.0 | ||||||
Senior
Notes L, 6.30% fixed-rate, due September 2017
|
800.0 | 800.0 | ||||||
Senior
Notes M, 5.65% fixed-rate, due April 2013
|
400.0 | 400.0 | ||||||
Senior
Notes N, 6.50% fixed-rate, due January 2019
|
700.0 | 700.0 | ||||||
Senior
Notes O, 9.75% fixed-rate, due January 2014
|
500.0 | 500.0 | ||||||
Senior
Notes P, 4.60% fixed-rate, due August 2012
|
500.0 | -- | ||||||
Senior
Notes Q, 5.25% fixed-rate, due January 2020
|
500.0 | -- | ||||||
Senior
Notes R, 6.125% fixed-rate, due October 2039
|
600.0 | -- | ||||||
Senior
Notes S, 7.625% fixed-rate, due February 2012 (2)
|
490.5 | -- | ||||||
Senior
Notes T, 6.125% fixed-rate, due February 2013 (2)
|
182.5 | -- | ||||||
Senior
Notes U, 5.90% fixed-rate, due April 2013 (2)
|
237.6 | -- | ||||||
Senior
Notes V, 6.65% fixed-rate, due April 2018 (2)
|
349.7 | -- | ||||||
Senior
Notes W, 7.55% fixed-rate, due April 2038 (2)
|
399.6 | -- | ||||||
TEPPCO
senior debt obligations:
|
||||||||
TEPPCO
Revolving Credit Facility, variable-rate, due December
2012
|
-- | 516.7 | ||||||
TEPPCO
Senior Notes (2)
|
40.1 | 1,700.0 | ||||||
Duncan
Energy Partners’ debt obligations:
|
||||||||
DEP
Revolving Credit Facility, variable-rate, due February
2011
|
175.0 | 202.0 | ||||||
DEP
Term Loan, variable-rate, due December 2011
|
282.3 | 282.3 | ||||||
Total
principal amount of senior debt obligations
|
9,764.3 | 10,030.1 | ||||||
EPO
Junior Subordinated Notes A, fixed/variable-rate, due August
2066
|
550.0 | 550.0 | ||||||
EPO
Junior Subordinated Notes B, fixed/variable-rate, due January
2068
|
682.7 | 682.7 | ||||||
EPO
Junior Subordinated Notes C, fixed/variable-rate, due June 2067
(2)
|
285.8 | -- | ||||||
TEPPCO
Junior Subordinated Notes, fixed/variable-rate, due June 2067
(2)
|
14.2 | 300.0 | ||||||
Total
principal amount of senior and junior debt obligations
|
11,297.0 | 11,562.8 | ||||||
Other,
non-principal amounts:
|
||||||||
Change
in fair value of debt-related derivative instruments (see Note
6)
|
44.4 | 51.9 | ||||||
Unamortized
discounts, net of premiums
|
(18.7 | ) | (12.6 | ) | ||||
Unamortized
deferred net gains related to terminated interest rate swaps (see Note
6)
|
23.7 | 35.8 | ||||||
Total
other, non-principal amounts
|
49.4 | 75.1 | ||||||
Total
long-term debt
|
$ | 11,346.4 | $ | 11,637.9 | ||||
(1)
Long-term
and current maturities of debt reflect the classification of such
obligations at December 31, 2009 after taking into consideration
EPO’s ability to use available borrowing capacity under its Multi-Year
Revolving Credit Facility.
(2)
Substantially
all of TEPPCO debt obligations were exchanged for a corresponding series
of new EPO notes in October 2009 in connection with the TEPPCO
Merger.
|
TEPPCO
Notes
Exchanged
|
Corresponding
Series
of New
EPO
Notes
|
Aggregate
Principal
Amount
|
Principal
Amount
Exchanged
|
Principal
Amount
Remaining
|
|||||||||
TEPPCO
Senior Notes, 7.625%
fixed-rate,
due February 2012
|
Senior
Notes S, 7.625%
fixed-rate,
due February 2012
|
$ | 500.0 | $ | 490.5 | $ | 9.5 | ||||||
TEPPCO
Senior Notes, 6.125%
fixed-rate,
due February 2013
|
Senior
Notes T, 6.125%
fixed-rate,
due February 2013
|
200.0 | 182.5 | 17.5 | |||||||||
TEPPCO
Senior Notes, 5.90%
fixed-rate,
due April 2013
|
Senior
Notes U, 5.90%
fixed-rate,
due April 2013
|
250.0 | 237.6 | 12.4 | |||||||||
TEPPCO
Senior Notes, 6.65%
fixed-rate,
due April 2018
|
Senior
Notes V, 6.65%
fixed-rate,
due April 2018
|
350.0 | 349.7 | 0.3 | |||||||||
TEPPCO
Senior Notes, 7.55%
fixed-rate,
due April 2038
|
Senior
Notes W, 7.55%
fixed-rate,
due April 2038
|
400.0 | 399.6 | 0.4 | |||||||||
$ | 1,700.0 | $ | 1,659.9 | $ | 40.1 |
Range
of
|
Weighted-Average
|
|
Interest
Rates
|
Interest
Rate
|
|
Paid
|
Paid
|
|
EPO
Multi-Year Revolving Credit Facility
|
0.73%
to 3.25%
|
0.95%
|
TEPPCO
Revolving Credit Facility
|
0.75%
to 3.25%
|
0.88%
|
DEP
Revolving Credit Facility
|
0.81%
to 2.74%
|
1.48%
|
DEP
Term Loan
|
0.93%
to 2.93%
|
1.15%
|
Petal
GO Zone Bonds
|
0.21%
to 2.75%
|
0.60%
|
Scheduled
Maturities of Debt
|
||||||||||||||||||||||||||||
After
|
||||||||||||||||||||||||||||
Total
|
2010
(1)
|
2011
|
2012
|
2013
|
2014
|
2014
|
||||||||||||||||||||||
Revolving
Credit Facilities
|
$ | 370.5 | $ | -- | $ | 175.0 | $ | 195.5 | $ | -- | $ | -- | $ | -- | ||||||||||||||
Senior
Notes
|
9,000.0 | 500.0 | 450.0 | 1,000.0 | 1,200.0 | 1,150.0 | 4,700.0 | |||||||||||||||||||||
Term
Loans
|
282.3 | -- | 282.3 | -- | -- | -- | -- | |||||||||||||||||||||
Junior
Subordinated Notes
|
1,532.7 | -- | -- | -- | -- | -- | 1,532.7 | |||||||||||||||||||||
Other
|
111.5 | 54.0 | -- | -- | -- | -- | 57.5 | |||||||||||||||||||||
Total
|
$ | 11,297.0 | $ | 554.0 | $ | 907.3 | $ | 1,195.5 | $ | 1,200.0 | $ | 1,150.0 | $ | 6,290.2 | ||||||||||||||
(1)
Long-term
and current maturities of debt reflect the classification of such
obligations on our Consolidated Balance Sheet at December 31, 2009 after
taking into consideration EPO’s ability to use available borrowing
capacity under its Multi-Year Revolving Credit Facility.
|
Scheduled
Maturities of Debt
|
||||||||||||||||||||||||||||||||
Ownership
|
After
|
|||||||||||||||||||||||||||||||
Interest
|
Total
|
2010
|
2011
|
2012
|
2013
|
2014
|
2014
|
|||||||||||||||||||||||||
Poseidon
|
36% | $ | 92.0 | $ | -- | $ | 92.0 | $ | -- | $ | -- | $ | -- | $ | -- | |||||||||||||||||
Evangeline
|
49.5% | 10.7 | 3.2 | 7.5 | -- | -- | -- | -- | ||||||||||||||||||||||||
Centennial
|
50% | 120.0 | 9.1 | 9.0 | 8.9 | 8.6 | 8.6 | 75.8 | ||||||||||||||||||||||||
Total
|
$ | 222.7 | $ | 12.3 | $ | 108.5 | $ | 8.9 | $ | 8.6 | $ | 8.6 | $ | 75.8 |
Net
Cash Proceeds from Sale of Common Units
|
||||||||||||||||
Number
of
|
Contributed
|
Contributed
by
|
Total
|
|||||||||||||
Common
Units
|
by
Limited
|
General
|
Net
Cash
|
|||||||||||||
Issued
|
Partners
|
Partner
|
Proceeds
|
|||||||||||||
Fiscal
2007:
|
||||||||||||||||
DRIP
and EUPP
|
2,056,615 | $ | 60.4 | $ | 1.2 | $ | 61.6 | |||||||||
Total
2007
|
2,056,615 | $ | 60.4 | $ | 1.2 | $ | 61.6 | |||||||||
Fiscal
2008:
|
||||||||||||||||
DRIP
and EUPP
|
5,523,946 | $ | 139.3 | $ | 2.8 | $ | 142.1 | |||||||||
Total
2008
|
5,523,946 | $ | 139.3 | $ | 2.8 | $ | 142.1 | |||||||||
Fiscal
2009:
|
||||||||||||||||
January
underwritten offering
|
10,590,000 | $ | 225.6 | $ | 4.6 | $ | 230.2 | |||||||||
DRIP
and EUPP
|
12,089,920 | 290.8 | 5.9 | 296.7 | ||||||||||||
September
private placement
|
5,940,594 | 150.0 | 3.1 | 153.1 | ||||||||||||
September
underwritten offering
|
8,337,500 | 226.4 | 4.6 | 231.0 | ||||||||||||
Total
2009
|
36,958,014 | $ | 892.8 | $ | 18.2 | $ | 911.0 |
Restricted
|
||||||||||||||||
Common
|
Common
|
Class
B
|
Treasury
|
|||||||||||||
Units
|
Units
|
Units
|
Units
|
|||||||||||||
Balance,
December 31, 2006
|
431,303,193 | 1,105,237 | -- | -- | ||||||||||||
Common
units issued in connection with DRIP and EUPP
|
2,056,615 | -- | -- | -- | ||||||||||||
Common
units issued in connection with equity awards
|
244,071 | 738,040 | -- | -- | ||||||||||||
Forfeiture
or settlement of restricted units
|
-- | (149,853 | ) | -- | -- | |||||||||||
Conversion
of restricted units to common units
|
4,884 | (4,884 | ) | -- | -- | |||||||||||
Balance,
December 31, 2007
|
433,608,763 | 1,688,540 | -- | -- | ||||||||||||
Common
units issued in connection with DRIP and EUPP
|
5,523,946 | -- | -- | -- | ||||||||||||
Common
units issued in connection with equity awards
|
21,905 | -- | -- | -- | ||||||||||||
Restricted
units issued
|
-- | 766,200 | -- | -- | ||||||||||||
Forfeiture
or settlement of restricted units
|
-- | (88,777 | ) | -- | -- | |||||||||||
Conversion
of restricted units to common units
|
285,363 | (285,363 | ) | -- | -- | |||||||||||
Acquisition
of treasury units
|
(85,246 | ) | -- | -- | 85,246 | |||||||||||
Cancellation
of treasury units
|
-- | -- | -- | (85,246 | ) | |||||||||||
Balance,
December 31, 2008
|
439,354,731 | 2,080,600 | -- | -- | ||||||||||||
Common
units issued in connection with underwritten offerings
|
18,927,500 | -- | -- | -- | ||||||||||||
Common
units issued in connection with private placement
|
5,940,594 | -- | -- | -- | ||||||||||||
Common
units issued in connection with DRIP and EUPP
|
12,089,920 | -- | -- | -- | ||||||||||||
Common
units issued in connection with equity awards
|
59,638 | -- | -- | -- | ||||||||||||
Common
units issued in connection with the TEPPCO Merger
|
126,624,302 | -- | -- | -- | ||||||||||||
Class
B units issued in connection with the TEPPCO Merger
|
-- | -- | 4,520,431 | -- | ||||||||||||
Restricted
units issued
|
-- | 1,025,650 | -- | -- | ||||||||||||
Restricted
units issued in connection with the TEPPCO Merger
|
-- | 308,016 | -- | -- | ||||||||||||
Forfeiture
of restricted units
|
-- | (411,884 | ) | -- | -- | |||||||||||
Conversion
of restricted units to common units
|
281,500 | (281,500 | ) | -- | -- | |||||||||||
Acquisition
of treasury units
|
(75,357 | ) | -- | -- | 75,357 | |||||||||||
Cancellation
of treasury units
|
-- | -- | -- | (75,357 | ) | |||||||||||
Balance,
December 31, 2009
|
603,202,828 | 2,720,882 | 4,520,431 | -- |
Restricted
|
||||||||||||||||
Common
|
Common
|
Class
B
|
||||||||||||||
Units
|
Units
|
Units
|
Total
|
|||||||||||||
Balance,
December 31, 2006
|
$ | 6,320.5 | $ | 9.3 | $ | -- | $ | 6,329.8 | ||||||||
Net
income
|
416.3 | 1.4 | -- | 417.7 | ||||||||||||
Operating
lease expenses paid by EPCO
|
2.1 | -- | -- | 2.1 | ||||||||||||
Cash
distributions paid to partners
|
(831.2 | ) | (2.6 | ) | -- | (833.8 | ) | |||||||||
Unit
option reimbursements to EPCO
|
(3.0 | ) | -- | -- | (3.0 | ) | ||||||||||
Net
cash proceeds from issuance of common units
|
60.4 | -- | -- | 60.4 | ||||||||||||
Cash
proceeds from exercise of unit options
|
7.5 | -- | -- | 7.5 | ||||||||||||
Repurchase
of restricted units and options
|
(0.5 | ) | (1.0 | ) | -- | (1.5 | ) | |||||||||
Amortization
of equity awards
|
4.9 | 8.8 | -- | 13.7 | ||||||||||||
Balance,
December 31, 2007
|
5,977.0 | 15.9 | -- | 5,992.9 | ||||||||||||
Net
income
|
807.9 | 3.6 | -- | 811.5 | ||||||||||||
Operating
lease expenses paid by EPCO
|
2.0 | -- | -- | 2.0 | ||||||||||||
Cash
distributions paid to partners
|
(888.8 | ) | (3.9 | ) | -- | (892.7 | ) | |||||||||
Unit
option reimbursements to EPCO
|
(0.6 | ) | -- | -- | (0.6 | ) | ||||||||||
Acquisition
of treasury units
|
-- | (1.9 | ) | -- | (1.9 | ) | ||||||||||
Net
cash proceeds from issuance of common units
|
139.3 | -- | -- | 139.3 | ||||||||||||
Cash
proceeds from exercise of unit options
|
0.7 | -- | -- | 0.7 | ||||||||||||
Amortization
of equity awards
|
(0.6 | ) | 12.5 | -- | 11.9 | |||||||||||
Balance,
December 31, 2008
|
6,036.9 | 26.2 | -- | 6,063.1 | ||||||||||||
Net
income
|
847.8 | 4.4 | -- | 852.2 | ||||||||||||
Operating
lease expenses paid by EPCO
|
0.7 | -- | -- | 0.7 | ||||||||||||
Cash
distributions paid to partners
|
(1,064.1 | ) | (5.2 | ) | -- | (1,069.3 | ) | |||||||||
Unit
option reimbursements to EPCO
|
(2.4 | ) | -- | -- | (2.4 | ) | ||||||||||
Acquisition
of treasury units
|
-- | (2.1 | ) | -- | (2.1 | ) | ||||||||||
Common
units and Class B units issued in connection with the TEPPCO
Merger
|
2,455.6 | -- | 118.5 | 2,574.1 | ||||||||||||
Net
cash proceeds from issuance of common units
|
892.8 | -- | -- | 892.8 | ||||||||||||
Cash
proceeds from exercise of unit options
|
1.7 | -- | -- | 1.7 | ||||||||||||
Amortization
of equity awards
|
4.5 | 14.4 | -- | 18.9 | ||||||||||||
Balance,
December 31, 2009
|
$ | 9,173.5 | $ | 37.7 | $ | 118.5 | $ | 9,329.7 |
§
|
2%
of quarterly cash distributions up to $0.253 per
unit;
|
§
|
15%
of quarterly cash distributions from $0.253 per unit up to $0.3085 per
unit; and
|
§
|
25%
of quarterly cash distributions that exceed $0.3085 per
unit.
|
Distribution
|
Record
|
Payment
|
|
per
Unit
|
Date
|
Date
|
|
2008
|
|||
1st
Quarter
|
$0.5075
|
Apr.
30, 2008
|
May
7, 2008
|
2nd
Quarter
|
$0.5150
|
Jul.
31, 2008
|
Aug.
7, 2008
|
3rd
Quarter
|
$0.5225
|
Oct.
31, 2008
|
Nov.
12, 2008
|
4th
Quarter
|
$0.5300
|
Jan.
30, 2009
|
Feb.
9, 2009
|
2009
|
|||
1st
Quarter
|
$0.5375
|
Apr.
30, 2009
|
May
8, 2009
|
2nd
Quarter
|
$0.5450
|
Jul.
31, 2009
|
Aug.
7, 2009
|
3rd
Quarter
|
$0.5525
|
Oct.
30, 2009
|
Nov.
5, 2009
|
4th
Quarter
|
$0.5600
|
Jan.
29, 2010
|
Feb.
4, 2010
|
At
December 31,
|
||||||||
2009
|
2008
|
|||||||
Former
owners of TEPPCO (1)
|
$ | -- | $ | 2,827.6 | ||||
Limited
partners of Duncan Energy Partners:
|
||||||||
Third-party
owners of Duncan Energy Partners (2)
|
414.3 | 281.1 | ||||||
Related
party owners of Duncan Energy Partners
|
1.7 | -- | ||||||
Joint
venture partners (3)
|
117.4 | 148.0 | ||||||
AOCI
attributable to noncontrolling interest
|
(3.2 | ) | (50.3 | ) | ||||
Total
noncontrolling interest
|
$ | 530.2 | $ | 3,206.4 | ||||
(1)
Represents
former ownership interests in TEPPCO and TEPPCO GP (see Note 1, “Basis of
Financial Statement Presentation”). This amount excludes AOCI
attributable to former owners of TEPPCO.
(2)
Represents
non-affiliate public unitholders of Duncan Energy Partners. The
increase in noncontrolling interest between years is attributable to
Duncan Energy Partners’ equity offering in June 2009.
(3)
Represents
third-party ownership interests in joint ventures that we consolidate,
including Seminole, Tri-States Pipeline L.L.C., Independence Hub LLC and
Wilprise Pipeline Company LLC. The balance at December 31, 2008
included $35.6 million related to Oiltanking’s ownership interest in TOPS,
from which our subsidiaries dissociated in April 2009 (see Note
8).
|
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Cash
distributions paid to noncontrolling interests:
|
||||||||||||
Limited
partners of TEPPCO
|
$ | 274.5 | $ | 328.0 | $ | 294.4 | ||||||
Limited
partners of Duncan Energy Partners
|
33.7 | 24.8 | 15.8 | |||||||||
Joint
venture partners
|
31.8 | 31.1 | 16.6 | |||||||||
Total
cash distributions paid to noncontrolling interests
|
$ | 340.0 | $ | 383.9 | $ | 326.8 | ||||||
Cash
contributions from noncontrolling interests:
|
||||||||||||
Limited
partners of TEPPCO
|
$ | 3.5 | $ | 275.9 | $ | 1.7 | ||||||
Limited
partners of Duncan Energy Partners
|
137.4 | -- | 290.5 | |||||||||
Joint
venture partners
|
(2.2 | ) | 35.6 | 12.5 | ||||||||
Total
cash contributions from noncontrolling interests
|
$ | 138.7 | $ | 311.5 | $ | 304.7 |
For
Year Ended December 31,
|
|||||||||||||
2009
|
2008
|
2007
|
|||||||||||
Revenues
|
$ | 25,510.9 | $ | 35,469.6 | $ | 26,713.8 | |||||||
Less:
|
Operating
costs and expenses
|
(23,565.8 | ) | (33,618.9 | ) | (25,402.1 | ) | ||||||
Add:
|
Equity
in income of unconsolidated affiliates
|
51.2 | 34.9 | 10.5 | |||||||||
Depreciation,
amortization and accretion in operating costs and expenses
(1)
|
809.3 | 725.4 | 647.9 | ||||||||||
Impairment
charges in operating costs and expenses
|
33.5 | -- | -- | ||||||||||
Operating
lease expenses paid by EPCO
|
0.7 | 2.0 | 2.1 | ||||||||||
Gain
from asset sales and related transactions in operating
costs
and expenses (2)
|
-- | (4.0 | ) | (7.8 | ) | ||||||||
Total
segment gross operating margin
|
$ | 2,839.8 | $ | 2,609.0 | $ | 1,964.4 | |||||||
(1)
Amount
is a component of “Depreciation, amortization and accretion” as presented
on the Statements of Consolidated Cash Flows.
(2)
Amount
is a component of “Gain from asset sales and related transactions” as
presented on the Statements of Consolidated Cash Flows.
|
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Total
segment gross operating margin
|
$ | 2,839.8 | $ | 2,609.0 | $ | 1,964.4 | ||||||
Adjustments
to reconcile total segment gross operating margin
|
||||||||||||
to
operating income:
|
||||||||||||
Depreciation,
amortization and accretion in operating costs and expenses
|
(809.3 | ) | (725.4 | ) | (647.9 | ) | ||||||
Impairment
charges in operating costs and expenses
|
(33.5 | ) | -- | -- | ||||||||
Operating
lease expenses paid by EPCO
|
(0.7 | ) | (2.0 | ) | (2.1 | ) | ||||||
Gain
from asset sales and related transactions in operating
costs
and expenses
|
-- | 4.0 | 7.8 | |||||||||
General
and administrative costs
|
(172.3 | ) | (137.2 | ) | (127.2 | ) | ||||||
Operating
income
|
1,824.0 | 1,748.4 | 1,195.0 | |||||||||
Other
expense, net
|
(643.6 | ) | (528.5 | ) | (341.3 | ) | ||||||
Income
before provision for income taxes
|
$ | 1,180.4 | $ | 1,219.9 | $ | 853.7 |
Reportable
Segments
|
||||||||||||||||||||||||||||
Onshore
|
Onshore
|
Petrochemical
|
||||||||||||||||||||||||||
NGL
|
Natural
Gas
|
Crude
Oil
|
Offshore
|
&
Refined
|
Adjustments
|
|||||||||||||||||||||||
Pipelines
|
Pipelines
|
Pipelines
|
Pipelines
|
Products
|
and
|
Consolidated
|
||||||||||||||||||||||
&
Services
|
&
Services
|
&
Services
|
&
Services
|
Services
|
Eliminations
|
Totals
|
||||||||||||||||||||||
Revenues
from third parties:
|
||||||||||||||||||||||||||||
Year
ended December 31, 2009
|
$ | 11,928.3 | $ | 2,938.7 | $ | 7,191.2 | $ | 332.9 | $ | 2,520.8 | $ | -- | $ | 24,911.9 | ||||||||||||||
Year
ended December 31, 2008
|
14,715.8 | 3,407.2 | 12,763.8 | 260.3 | 3,307.1 | -- | 34,454.2 | |||||||||||||||||||||
Year
ended December 31, 2007
|
12,149.2 | 2,044.0 | 9,103.7 | 222.6 | 2,609.1 | -- | 26,128.6 | |||||||||||||||||||||
Revenues
from related parties:
|
||||||||||||||||||||||||||||
Year
ended December 31, 2009
|
380.7 | 211.2 | (0.2 | ) | 7.0 | 0.3 | -- | 599.0 | ||||||||||||||||||||
Year
ended December 31, 2008
|
598.0 | 409.2 | -- | 8.1 | 0.1 | -- | 1,015.4 | |||||||||||||||||||||
Year
ended December 31, 2007
|
301.5 | 281.9 | 0.1 | 1.2 | 0.5 | -- | 585.2 | |||||||||||||||||||||
Intersegment
and intrasegment revenues:
|
||||||||||||||||||||||||||||
Year
ended December 31, 2009
|
6,865.5 | 515.3 | 47.6 | 1.3 | 612.3 | (8,042.0 | ) | -- | ||||||||||||||||||||
Year
ended December 31, 2008
|
8,091.7 | 881.6 | 75.1 | 1.4 | 663.3 | (9,713.1 | ) | -- | ||||||||||||||||||||
Year
ended December 31, 2007
|
5,436.3 | 205.5 | 48.6 | 2.0 | 522.6 | (6,215.0 | ) | -- | ||||||||||||||||||||
Total
revenues:
|
||||||||||||||||||||||||||||
Year
ended December 31, 2009
|
19,174.5 | 3,665.2 | 7,238.6 | 341.2 | 3,133.4 | (8,042.0 | ) | 25,510.9 | ||||||||||||||||||||
Year
ended December 31, 2008
|
23,405.5 | 4,698.0 | 12,838.9 | 269.8 | 3,970.5 | (9,713.1 | ) | 35,469.6 | ||||||||||||||||||||
Year
ended December 31, 2007
|
17,887.0 | 2,531.4 | 9,152.4 | 225.8 | 3,132.2 | (6,215.0 | ) | 26,713.8 | ||||||||||||||||||||
Equity
in income of
unconsolidated
affiliates:
|
||||||||||||||||||||||||||||
Year
ended December 31, 2009
|
11.3 | 4.9 | 9.3 | 36.9 | (11.2 | ) | -- | 51.2 | ||||||||||||||||||||
Year
ended December 31, 2008
|
1.4 | 1.6 | 11.7 | 33.7 | (13.5 | ) | -- | 34.9 | ||||||||||||||||||||
Year
ended December 31, 2007
|
7.1 | 0.2 | 2.6 | 12.6 | (12.0 | ) | -- | 10.5 | ||||||||||||||||||||
Gross
operating margin:
|
||||||||||||||||||||||||||||
Year
ended December 31, 2009
|
1,628.7 | 501.5 | 164.4 | 180.5 | 364.7 | -- | 2,839.8 | |||||||||||||||||||||
Year
ended December 31, 2008
|
1,325.0 | 589.9 | 132.2 | 187.0 | 374.9 | -- | 2,609.0 | |||||||||||||||||||||
Year
ended December 31, 2007
|
848.0 | 493.2 | 109.6 | 171.6 | 342.0 | -- | 1,964.4 | |||||||||||||||||||||
Segment
assets:
|
||||||||||||||||||||||||||||
At
December 31, 2009
|
7,191.2 | 6,918.7 | 865.3 | 2,121.4 | 3,359.0 | 1,207.3 | 21,662.9 | |||||||||||||||||||||
At
December 31, 2008
|
6,459.3 | 6,118.8 | 883.0 | 2,061.8 | 3,308.9 | 2,015.4 | 20,847.2 | |||||||||||||||||||||
At
December 31, 2007
|
5,488.5 | 5,502.3 | 858.8 | 2,152.3 | 2,631.9 | 1,588.3 | 18,222.1 | |||||||||||||||||||||
Property,
plant and equipment (see Note 8):
|
||||||||||||||||||||||||||||
At
December 31, 2009
|
6,392.8 | 6,074.6 | 377.3 | 1,480.9 | 2,156.3 | 1,207.3 | 17,689.2 | |||||||||||||||||||||
At
December 31, 2008
|
5,622.4 | 5,223.6 | 386.9 | 1,394.5 | 2,090.0 | 2,015.4 | 16,732.8 | |||||||||||||||||||||
At
December 31, 2007
|
4,770.4 | 4,577.4 | 363.7 | 1,452.6 | 1,556.7 | 1,588.3 | 14,309.1 | |||||||||||||||||||||
Investments
in unconsolidated affiliates
(see Note 9):
|
||||||||||||||||||||||||||||
At
December 31, 2009
|
141.6 | 32.0 | 178.5 | 456.9 | 81.6 | -- | 890.6 | |||||||||||||||||||||
At
December 31, 2008
|
144.3 | 25.9 | 186.2 | 469.0 | 86.5 | -- | 911.9 | |||||||||||||||||||||
At
December 31, 2007
|
117.0 | 3.5 | 184.8 | 484.6 | 95.7 | -- | 885.6 | |||||||||||||||||||||
Intangible
assets, net (see Note 11):
|
||||||||||||||||||||||||||||
At
December 31, 2009
|
315.6 | 527.2 | 6.5 | 101.5 | 114.0 | -- | 1,064.8 | |||||||||||||||||||||
At
December 31, 2008
|
351.4 | 584.4 | 6.9 | 116.2 | 124.0 | -- | 1,182.9 | |||||||||||||||||||||
At
December 31, 2007
|
375.1 | 636.5 | 7.3 | 133.0 | 62.2 | -- | 1,214.1 | |||||||||||||||||||||
Goodwill
(see Note 11):
|
||||||||||||||||||||||||||||
At
December 31, 2009
|
341.2 | 284.9 | 303.0 | 82.1 | 1,007.1 | -- | 2,018.3 | |||||||||||||||||||||
At
December 31, 2008
|
341.2 | 284.9 | 303.0 | 82.1 | 1,008.4 | -- | 2,019.6 | |||||||||||||||||||||
At
December 31, 2007
|
226.0 | 284.9 | 303.0 | 82.1 | 917.3 | -- | 1,813.3 |
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
NGL
Pipelines & Services:
|
||||||||||||
Sales
of NGLs
|
$ | 11,598.9 | $ | 14,573.5 | $ | 11,701.3 | ||||||
Sales
of other petroleum and related products
|
1.8 | 2.4 | 3.0 | |||||||||
Midstream
services
|
708.3 | 737.9 | 746.4 | |||||||||
Total
|
12,309.0 | 15,313.8 | 12,450.7 | |||||||||
Onshore
Natural Gas Pipelines & Services:
|
||||||||||||
Sales
of natural gas
|
2,410.5 | 3,083.1 | 1,676.7 | |||||||||
Midstream
services
|
739.4 | 733.3 | 649.2 | |||||||||
Total
|
3,149.9 | 3,816.4 | 2,325.9 | |||||||||
Onshore
Crude Oil Pipelines & Services:
|
||||||||||||
Sales
of crude oil
|
7,110.6 | 12,696.2 | 9,048.5 | |||||||||
Midstream
services
|
80.4 | 67.6 | 55.3 | |||||||||
Total
|
7,191.0 | 12,763.8 | 9,103.8 | |||||||||
Offshore
Pipelines & Services:
|
||||||||||||
Sales
of natural gas
|
1.2 | 2.8 | 3.2 | |||||||||
Sales
of crude oil
|
5.3 | 11.1 | 12.1 | |||||||||
Midstream
services
|
333.4 | 254.5 | 208.5 | |||||||||
Total
|
339.9 | 268.4 | 223.8 | |||||||||
Petrochemical
& Refined Products Services:
|
||||||||||||
Sales
of other petroleum and related products
|
1,991.8 | 2,757.6 | 2,207.2 | |||||||||
Midstream
services
|
529.3 | 549.6 | 402.4 | |||||||||
Total
|
2,521.1 | 3,307.2 | 2,609.6 | |||||||||
Total
consolidated revenues
|
$ | 25,510.9 | $ | 35,469.6 | $ | 26,713.8 | ||||||
Consolidated
costs and expenses
|
||||||||||||
Operating
costs and expenses:
|
||||||||||||
Cost
of sales for our marketing activities
|
$ | 18,656.7 | $ | 28,250.2 | $ | 21,142.5 | ||||||
Depreciation,
amortization and accretion
|
809.3 | 725.4 | 647.9 | |||||||||
Gain
on sale of assets and related transactions
|
-- | (4.0 | ) | (7.8 | ) | |||||||
Non-cash
impairment charges
|
33.5 | -- | -- | |||||||||
Other
operating costs and expenses
|
4,066.3 | 4,647.3 | 3,619.5 | |||||||||
General
and administrative costs
|
172.3 | 137.2 | 127.2 | |||||||||
Total
consolidated costs and expenses
|
$ | 23,738.1 | $ | 33,756.1 | $ | 25,529.3 |
For
Year Ended December 31,
|
||||||||
2008
|
2007
|
|||||||
Total
revenues, as previously reported
|
$ | 21,905.6 | $ | 16,950.1 | ||||
Revenues
from TEPPCO
|
13,532.9 | 9,658.1 | ||||||
Revenues
from Jonah (1)
|
232.8 | 204.1 | ||||||
Eliminations
(2)
|
(201.7 | ) | (98.5 | ) | ||||
Total
revenues, as currently reported
|
$ | 35,469.6 | $ | 26,713.8 | ||||
Total
segment gross operating margin, as previously reported
|
$ | 2,057.4 | $ | 1,492.1 | ||||
Gross
operating margin from TEPPCO
|
501.0 | 434.8 | ||||||
Gross
operating margin from Jonah
|
157.6 | 125.4 | ||||||
Eliminations
(3)
|
(107.0 | ) | (87.9 | ) | ||||
Total
segment gross operating margin, as currently reported
|
$ | 2,609.0 | $ | 1,964.4 | ||||
(1)
Prior
to the TEPPCO Merger, we and TEPPCO were joint venture partners in
Jonah. As a result of the TEPPCO Merger, Jonah became a consolidated
subsidiary.
(2)
Represents
the eliminations of revenues between Enterprise Products Partners, TEPPCO
and Jonah.
(3)
Represents
equity earnings from Jonah recorded by Enterprise Products Partners and
TEPPCO prior to the merger.
|
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Revenues
– related parties:
|
||||||||||||
EPCO
and affiliates
|
$ | -- | $ | -- | $ | 0.2 | ||||||
Energy
Transfer Equity and subsidiaries
|
423.1 | 618.5 | 294.5 | |||||||||
Unconsolidated
affiliates
|
175.9 | 396.9 | 290.5 | |||||||||
Total
revenue – related parties
|
$ | 599.0 | $ | 1,015.4 | $ | 585.2 | ||||||
Costs
and expenses – related parties:
|
||||||||||||
EPCO
and affiliates
|
$ | 590.3 | $ | 554.2 | $ | 470.3 | ||||||
Energy
Transfer Equity and subsidiaries
|
443.8 | 192.2 | 35.2 | |||||||||
Cenac
and affiliates
|
40.9 | 48.3 | -- | |||||||||
Unconsolidated
affiliates
|
38.2 | 56.1 | 41.0 | |||||||||
Total
costs and expenses – related parties
|
$ | 1,113.2 | $ | 850.8 | $ | 546.5 | ||||||
Other
expense – related parties:
|
||||||||||||
EPCO
and affiliates
|
$ | 4.1 | $ | 0.3 | $ | 0.2 |
December
31,
|
||||||||
2009
|
2008
|
|||||||
Accounts
receivable - related parties:
|
||||||||
EPCO
and affiliates
|
$ | -- | $ | 0.2 | ||||
Energy
Transfer Equity and subsidiaries
|
28.2 | 35.0 | ||||||
Other
|
10.2 | 0.1 | ||||||
Total
accounts receivable – related parties
|
$ | 38.4 | $ | 35.3 | ||||
Accounts
payable - related parties:
|
||||||||
EPCO
and affiliates
|
$ | 26.8 | $ | 14.1 | ||||
Energy
Transfer Equity and subsidiaries
|
33.4 | 0.1 | ||||||
Other
|
9.6 | 3.2 | ||||||
Total
accounts payable – related parties
|
$ | 69.8 | $ | 17.4 |
§
|
EPCO
and its privately held affiliates;
|
§
|
EPGP,
our sole general partner;
|
§
|
Enterprise
GP Holdings, which owns and controls our general partner;
and
|
§
|
the
Employee Partnerships (see Note 5).
|
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
General
partner distributions
|
$ | 21.8 | $ | 18.2 | $ | 17.0 | ||||||
Incentive
distributions
|
161.3 | 125.9 | 107.4 | |||||||||
Total
distributions
|
$ | 183.1 | $ | 144.1 | $ | 124.4 |
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Enterprise
Products Partners
|
$ | 314.5 | $ | 281.1 | $ | 263.4 | ||||||
Enterprise
GP Holdings
|
205.2 | 158.7 | 125.5 | |||||||||
Total
distributions
|
$ | 519.7 | $ | 439.8 | $ | 388.9 |
§
|
EPCO
will provide selling, general and administrative services, and management
and operating services, as may be necessary to manage and operate our
businesses, properties and assets (all in accordance with prudent industry
practices). EPCO will employ or otherwise retain the services
of such personnel as may be necessary to provide such
services.
|
§
|
We
are required to reimburse EPCO for its services in an amount equal to the
sum of all costs and expenses incurred by EPCO which are directly or
indirectly related to our business or activities (including expenses
reasonably allocated to us by EPCO). In addition, we have
agreed to pay all sales, use, excise, value added or similar taxes, if
any, that may be applicable from time to time in respect of the services
provided to us by EPCO.
|
§
|
EPCO
will allow us to participate as a named insured in its overall insurance
program, with the associated premiums and other costs being allocated to
us.
|
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Operating
costs and expenses
|
$ | 495.3 | $ | 463.2 | $ | 387.7 | ||||||
General
and administrative expenses
|
95.0 | 91.0 | 82.6 | |||||||||
Total
costs and expenses
|
$ | 590.3 | $ | 554.2 | $ | 470.3 |
§
|
We
sell natural gas to Evangeline, which, in turn, uses the natural gas to
satisfy supply commitments it has with a major Louisiana
utility. Revenues from Evangeline were $155.5 million, $362.9
million and $268.0 million for the years ended December 31, 2009, 2008 and
2007, respectively.
|
§
|
We
pay Promix for the transportation, storage and fractionation of
NGLs. In addition, we sell natural gas to Promix for its plant
fuel requirements. Revenues from Promix were $11.0 million,
$24.5 million and $17.3 million for the years ended December 31, 2009,
2008 and 2007, respectively. Expenses with Promix were $26.0
million, $38.7 million and $30.4 million for the years ended December 31,
2009, 2008 and 2007, respectively.
|
§
|
For
the years ended December 31, 2008 and 2007, we paid $1.7 million and $3.8
million, respectively, to Centennial in connection with a pipeline
capacity lease. In addition, we paid $6.7 million, $6.6 million
and $5.3 million to Centennial for the years ended December 31, 2009, 2008
and 2007 for other pipeline transportation services,
respectively.
|
§
|
For
the years ended December 31, 2009, 2008 and 2007, we paid Seaway $3.4
million, $6.0 million and $4.7 million, respectively, for transportation
and tank rentals in connection with our crude oil marketing
activities.
|
§
|
We
perform management services for certain of our unconsolidated
affiliates. We charged such affiliates $10.7 million, $11.2
million and $11.0 million for the years ended December 31, 2009, 2008 and
2007, respectively.
|
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Current:
|
||||||||||||
Federal
|
$ | 7.9 | $ | 4.9 | $ | 4.7 | ||||||
State
|
11.9 | 23.9 | 5.1 | |||||||||
Foreign
|
1.0 | 0.4 | 0.1 | |||||||||
Total
current
|
20.8 | 29.2 | 9.9 | |||||||||
Deferred:
|
||||||||||||
Federal
|
4.8 | 0.8 | 2.7 | |||||||||
State
|
(0.3 | ) | 1.0 | 3.1 | ||||||||
Total
deferred
|
4.5 | 1.8 | 5.8 | |||||||||
Total
provision for income taxes
|
$ | 25.3 | $ | 31.0 | $ | 15.7 |
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Pre
Tax Net Book Income (“NBI”)
|
$ | 1,180.4 | $ | 1,219.9 | $ | 853.7 | ||||||
Texas
Margin Tax
|
$ | 10.1 | $ | 23.9 | $ | 7.7 | ||||||
State
income taxes (net of federal benefit)
|
1.3 | 0.5 | 0.3 | |||||||||
Federal
income taxes computed by applying the federal
|
||||||||||||
statutory
rate to NBI of corporate entities
|
8.3 | 6.3 | 5.3 | |||||||||
Valuation
allowance
|
(1.7 | ) | (1.4 | ) | 2.3 | |||||||
Expiration
of tax net operating loss
|
1.7 | -- | -- | |||||||||
Other
permanent differences
|
5.6 | 1.7 | 0.1 | |||||||||
Provision
for income taxes
|
$ | 25.3 | $ | 31.0 | $ | 15.7 | ||||||
Effective
income tax rate
|
2.1 | % | 2.5 | % | 1.8 | % |
At
December 31,
|
||||||||
2009
|
2008
|
|||||||
Deferred
tax assets:
|
||||||||
Net
operating loss carryovers (1)
|
$ | 24.6 | $ | 26.3 | ||||
Property,
plant and equipment
|
-- | 0.8 | ||||||
Employee
benefit plans
|
2.8 | 2.6 | ||||||
Deferred
revenue
|
1.1 | 1.0 | ||||||
Reserve
for legal fees and damages
|
-- | 0.3 | ||||||
Equity
investment in partnerships
|
1.0 | 0.6 | ||||||
AROs
|
0.1 | 0.1 | ||||||
Accruals
|
1.3 | 0.9 | ||||||
Total
deferred tax assets
|
30.9 | 32.6 | ||||||
Valuation
allowance (2)
|
2.2 | 3.9 | ||||||
Net
deferred tax assets
|
28.7 | 28.7 | ||||||
Deferred
tax liabilities:
|
||||||||
Property,
plant and equipment
|
97.4 | 92.9 | ||||||
Other
|
-- | 0.1 | ||||||
Total
deferred tax liabilities
|
97.4 | 93.0 | ||||||
Total
net deferred tax liabilities
|
$ | (68.7 | ) | $ | (64.3 | ) | ||
Current
portion of total net deferred tax assets
|
$ | 1.9 | $ | 1.4 | ||||
Long-term
portion of total net deferred tax liabilities
|
$ | (70.6 | ) | $ | (65.7 | ) | ||
(1)
These
losses expire in various years between 2010 and 2028 and are subject to
limitations on their utilization.
(2)
We
record a valuation allowance to reduce our deferred tax assets to the
amount of future benefit that is more likely than not to be
realized.
|
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
BASIC
EARNINGS PER UNIT
|
||||||||||||
Numerator
|
||||||||||||
Net
income attributable to Enterprise Products
Partners
L.P.
|
$ | 1,030.9 | $ | 954.0 | $ | 533.6 | ||||||
Net
income available to EPGP for EPU purposes
|
(186.4 | ) | (147.7 | ) | (120.4 | ) | ||||||
Net
income available to limited partners
|
$ | 844.5 | $ | 806.3 | $ | 413.2 | ||||||
Denominator
|
||||||||||||
Common
units
|
484.3 | 435.4 | 432.5 | |||||||||
Time-vested
restricted units
|
2.5 | 2.0 | 1.5 | |||||||||
Total
|
486.8 | 437.4 | 434.0 | |||||||||
Basic
earnings per unit
|
||||||||||||
Net
income per unit before EPGP earnings allocation
|
$ | 2.11 | $ | 2.18 | $ | 1.23 | ||||||
Net
income available to EPGP
|
(0.38 | ) | (0.34 | ) | (0.28 | ) | ||||||
Net
income available to limited partners
|
$ | 1.73 | $ | 1.84 | $ | 0.95 | ||||||
DILUTED
EARNINGS PER UNIT
|
||||||||||||
Numerator
|
||||||||||||
Net
income attributable to Enterprise Products
Partners
L.P.
|
$ | 1,030.9 | $ | 954.0 | $ | 533.6 | ||||||
Net
income available to EPGP for EPU purposes
|
(186.4 | ) | (147.7 | ) | (120.4 | ) | ||||||
Net
income available to limited partners
|
$ | 844.5 | $ | 806.3 | $ | 413.2 | ||||||
Denominator
|
||||||||||||
Common
units
|
484.3 | 435.4 | 432.5 | |||||||||
Time-vested
restricted units
|
2.5 | 2.0 | 1.5 | |||||||||
Class
B units
|
0.8 | -- | -- | |||||||||
Incremental
option units
|
0.2 | 0.2 | 0.4 | |||||||||
Total
|
487.8 | 437.6 | 434.4 | |||||||||
Diluted
earnings per unit
|
||||||||||||
Net
income per unit before EPGP earnings allocation
|
$ | 2.11 | $ | 2.18 | $ | 1.23 | ||||||
Net
income available to EPGP
|
(0.38 | ) | (0.34 | ) | (0.28 | ) | ||||||
Net
income available to limited partners
|
$ | 1.73 | $ | 1.84 | $ | 0.95 |
Payment
or Settlement due by Period
|
||||||||||||||||||||||||||||
Contractual
Obligations
|
Total
|
2010
|
2011
|
2012
|
2013
|
2014
|
Thereafter
|
|||||||||||||||||||||
Scheduled
maturities of long-term debt
|
$ | 11,297.0 | $ | 554.0 | $ | 907.3 | $ | 1,195.5 | $ | 1,200.0 | $ | 1,150.0 | $ | 6,290.2 | ||||||||||||||
Estimated
cash interest payments
|
$ | 12,372.2 | $ | 667.4 | $ | 618.3 | $ | 571.9 | $ | 502.9 | $ | 436.5 | $ | 9,575.2 | ||||||||||||||
Operating
lease obligations
|
$ | 343.9 | $ | 37.6 | $ | 35.3 | $ | 32.7 | $ | 27.3 | $ | 21.5 | $ | 189.5 | ||||||||||||||
Purchase
obligations:
|
||||||||||||||||||||||||||||
Product
purchase commitments:
|
||||||||||||||||||||||||||||
Estimated
payment obligations:
|
||||||||||||||||||||||||||||
Natural
gas
|
$ | 5,697.6 | $ | 1,308.9 | $ | 685.5 | $ | 696.3 | $ | 487.5 | $ | 471.8 | $ | 2,047.6 | ||||||||||||||
NGLs
|
$ | 2,943.0 | $ | 997.0 | $ | 339.3 | $ | 329.8 | $ | 329.7 | $ | 329.7 | $ | 617.5 | ||||||||||||||
Crude
oil
|
$ | 237.3 | $ | 237.3 | $ | -- | $ | -- | $ | -- | $ | -- | $ | -- | ||||||||||||||
Petrochemicals
& refined products
|
$ | 2,642.2 | $ | 1,486.6 | $ | 586.0 | $ | 238.5 | $ | 113.9 | $ | 72.4 | $ | 144.8 | ||||||||||||||
Other
|
$ | 114.1 | $ | 21.2 | $ | 12.2 | $ | 11.9 | $ | 11.8 | $ | 11.0 | $ | 46.0 | ||||||||||||||
Underlying
major volume commitments:
|
||||||||||||||||||||||||||||
Natural
gas (in BBtus) (1)
|
969,180 | 221,530 | 114,304 | 116,146 | 83,854 | 81,154 | 352,192 | |||||||||||||||||||||
NGLs
(in MBbls) (2)
|
49,300 | 19,048 | 5,337 | 5,159 | 5,158 | 5,158 | 9,440 | |||||||||||||||||||||
Crude
oil (in MBbls) (2)
|
2,985 | 2,985 | -- | -- | -- | -- | -- | |||||||||||||||||||||
Petrochemicals
& refined products (in MBbls)
|
35,034 | 19,523 | 7,856 | 3,266 | 1,509 | 960 | 1,920 | |||||||||||||||||||||
Service
payment commitments
|
$ | 575.6 | $ | 72.0 | $ | 57.0 | $ | 56.7 | $ | 55.1 | $ | 55.0 | $ | 279.8 | ||||||||||||||
Capital
expenditure commitments
|
$ | 497.5 | $ | 497.5 | $ | -- | $ | -- | $ | -- | $ | -- | $ | -- | ||||||||||||||
(1)
Volume
is measured in billion British thermal units (“BBtus”).
(2)
Volume
is measured in thousands of barrels (“MBbls”).
|
§
|
We
have long and short-term product purchase obligations for natural gas,
NGLs, crude oil, refined products and certain petrochemicals with
third-party suppliers. The prices that we are obligated to pay
under these contracts approximate market prices at the time we take
delivery of the volumes. The preceding table shows our volume
commitments and estimated payment obligations under these contracts for
the periods indicated. Our estimated future payment obligations
are based on the contractual price under each contract for purchases made
at December 31, 2009 applied to all future volume
commitments. Actual future payment obligations may vary
depending on prices at the time of delivery. At December 31,
2009, we do not have any significant product purchase commitments with
fixed or minimum pricing provisions with remaining terms in excess of one
year.
|
§
|
We
have long and short-term commitments to pay third-party providers for
services. Our contractual service payment commitments primarily
represent our obligations under firm pipeline transportation contracts on
pipelines owned by third parties. Payment obligations vary by
contract, but generally represent a price per unit of volume multiplied by
a firm transportation volume commitment. The preceding table
shows our estimated future payment obligations under these service
contracts.
|
§
|
We
have short-term payment obligations relating to our capital projects and
those of our unconsolidated affiliates. These commitments
represent unconditional payment obligations to vendors for services
rendered or products purchased. The preceding table presents
our share of such commitments for the periods
indicated.
|
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Business
interruption proceeds:
|
||||||||||||
Hurricanes
Katrina and Rita in 2005
|
$ | -- | $ | 1.1 | $ | 33.9 | ||||||
Hurricanes
Gustav and Ike in 2008
|
33.2 | -- | -- | |||||||||
Other
|
-- | -- | 1.4 | |||||||||
Total
proceeds
|
33.2 | 1.1 | 35.3 | |||||||||
Property
damage proceeds:
|
||||||||||||
Hurricanes
Katrina and Rita in 2005
|
38.6 | 12.1 | 103.7 | |||||||||
Hurricanes
Gustav and Ike in 2008
|
15.1 | -- | -- | |||||||||
Other
|
0.7 | -- | 1.5 | |||||||||
Total
proceeds
|
54.4 | 12.1 | 105.2 | |||||||||
Total
|
$ | 87.6 | $ | 13.2 | $ | 140.5 |
For
Year Ended December 31,
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
Decrease
(increase) in:
|
||||||||||||
Accounts
and notes receivable – trade
|
$ | (1,069.1 | ) | $ | 1,333.9 | $ | (1,175.8 | ) | ||||
Accounts
receivable – related party
|
7.2 | 3.6 | (37.0 | ) | ||||||||
Inventories
|
(317.4 | ) | 14.9 | (20.4 | ) | |||||||
Prepaid
and other current assets
|
71.2 | (26.9 | ) | 36.6 | ||||||||
Other
assets
|
15.0 | (11.7 | ) | (6.7 | ) | |||||||
Increase
(decrease) in:
|
||||||||||||
Accounts
payable – trade
|
(51.7 | ) | (9.1 | ) | 193.8 | |||||||
Accounts
payable – related party
|
44.3 | 1.2 | (2.2 | ) | ||||||||
Accrued
product payables
|
1,552.9 | (1,722.0 | ) | 2,195.2 | ||||||||
Accrued
expenses
|
42.4 | 3.4 | (809.3 | ) | ||||||||
Accrued
interest
|
33.7 | 21.8 | 39.9 | |||||||||
Other
current liabilities
|
(105.5 | ) | (27.7 | ) | 44.5 | |||||||
Other
liabilities
|
22.9 | 7.5 | (23.7 | ) | ||||||||
Net
effect of changes in operating accounts
|
$ | 245.9 | $ | (411.1 | ) | $ | 434.9 | |||||
Cash
payments for interest, net of $53.1, $90.7 and
|
||||||||||||
$86.5
capitalized in 2009, 2008 and 2007, respectively
|
$ | 651.5 | $ | 569.7 | $ | 429.5 | ||||||
Cash
payments for federal and state income taxes
|
$ | 29.5 | $ | 6.8 | $ | 5.8 |
First
|
Second
|
Third
|
Fourth
|
|||||||||||||
Quarter
|
Quarter
|
Quarter
|
Quarter
|
|||||||||||||
For
the Year Ended December 31, 2009:
|
||||||||||||||||
Revenues
|
$ | 4,886.9 | $ | 5,434.3 | $ | 6,789.4 | $ | 8,400.3 | ||||||||
Operating
income
|
482.8 | 373.3 | 356.3 | 611.6 | ||||||||||||
Net
income
|
315.5 | 212.5 | 187.8 | 439.3 | ||||||||||||
Net
income attributable to Enterprise Products Partners L.P.
|
225.3 | 186.6 | 212.9 | 406.1 | ||||||||||||
Earnings
per unit:
|
||||||||||||||||
Basic
|
$ | 0.41 | $ | 0.32 | $ | 0.36 | $ | 0.60 | ||||||||
Diluted
|
$ | 0.41 | $ | 0.32 | $ | 0.36 | $ | 0.60 | ||||||||
For
the Year Ended December 31, 2008:
|
||||||||||||||||
Revenues
|
$ | 8,506.4 | $ | 10,538.6 | $ | 10,499.1 | $ | 5,925.5 | ||||||||
Operating
income
|
469.7 | 454.6 | 401.0 | 423.1 | ||||||||||||
Net
income
|
336.0 | 320.0 | 258.1 | 274.8 | ||||||||||||
Net
income attributable to Enterprise Products Partners L.P.
|
259.6 | 263.3 | 203.1 | 228.0 | ||||||||||||
Earnings
per unit:
|
||||||||||||||||
Basic
|
$ | 0.51 | $ | 0.52 | $ | 0.38 | $ | 0.43 | ||||||||
Diluted
|
$ | 0.51 | $ | 0.52 | $ | 0.38 | $ | 0.43 |
EPO
and Subsidiaries
|
||||||||||||||||||||||||||||
Subsidiary
Issuer (EPO)
|
Other
Subsidiaries
(Non-guarantor)
|
EPO
and Subsidiaries Eliminations and Adjustments
|
Consolidated
EPO
and Subsidiaries
|
Parent
Company (Guarantor)
|
Eliminations
and Adjustments
|
Consolidated
Total
|
||||||||||||||||||||||
ASSETS
|
||||||||||||||||||||||||||||
Current
assets:
|
||||||||||||||||||||||||||||
Cash
and cash equivalents
|
$ | 14.4 | $ | 46.3 | $ | (6.2 | ) | $ | 54.5 | $ | -- | $ | 0.2 | $ | 54.7 | |||||||||||||
Restricted
Cash
|
63.1 | 0.5 | -- | 63.6 | -- | -- | 63.6 | |||||||||||||||||||||
Accounts
and notes receivable, net
|
509.6 | 2,674.0 | (45.7 | ) | 3,137.9 | (0.3 | ) | (0.2 | ) | 3,137.4 | ||||||||||||||||||
Inventories
|
595.4 | 120.3 | (3.8 | ) | 711.9 | -- | -- | 711.9 | ||||||||||||||||||||
Prepaid
and other current assets
|
185.4 | 100.6 | (6.7 | ) | 279.3 | -- | -- | 279.3 | ||||||||||||||||||||
Total
current assets
|
1,367.9 | 2,941.7 | (62.4 | ) | 4,247.2 | (0.3 | ) | -- | 4,246.9 | |||||||||||||||||||
Property,
plant and equipment, net
|
1,436.1 | 16,242.0 | 11.1 | 17,689.2 | -- | -- | 17,689.2 | |||||||||||||||||||||
Investments
in unconsolidated affiliates
|
18,981.2 | 5,912.7 | (24,003.3 | ) | 890.6 | 9,512.4 | (9,512.4 | ) | 890.6 | |||||||||||||||||||
Intangible
assets, net
|
170.0 | 910.3 | (15.5 | ) | 1,064.8 | -- | -- | 1,064.8 | ||||||||||||||||||||
Goodwill
|
473.7 | 1,544.6 | -- | 2,018.3 | -- | -- | 2,018.3 | |||||||||||||||||||||
Other
assets
|
287.2 | 131.1 | (177.4 | ) | 240.9 | -- | 0.9 | 241.8 | ||||||||||||||||||||
Total
assets
|
$ | 22,716.1 | $ | 27,682.4 | $ | (24,247.5 | ) | $ | 26,151.0 | $ | 9,512.1 | $ | (9,511.5 | ) | $ | 26,151.6 | ||||||||||||
LIABILITIES
AND EQUITY
|
||||||||||||||||||||||||||||
Current
liabilities:
|
||||||||||||||||||||||||||||
Accounts
payable
|
$ | 146.3 | $ | 551.5 | $ | (217.4 | ) | $ | 480.4 | $ | -- | $ | -- | $ | 480.4 | |||||||||||||
Accrued
product payables
|
1,842.6 | 1,557.3 | (6.9 | ) | 3,393.0 | -- | -- | 3,393.0 | ||||||||||||||||||||
Other
current liabilities
|
403.7 | 274.2 | (15.3 | ) | 662.6 | -- | -- | 662.6 | ||||||||||||||||||||
Total
current liabilities
|
2,392.6 | 2,383.0 | (239.6 | ) | 4,536.0 | -- | -- | 4,536.0 | ||||||||||||||||||||
Long-term
debt
|
10,777.6 | 568.8 | -- | 11,346.4 | -- | -- | 11,346.4 | |||||||||||||||||||||
Commitments
and contingencies
|
||||||||||||||||||||||||||||
Other
long-term liabilities
|
17.9 | 209.0 | -- | 226.9 | -- | -- | 226.9 | |||||||||||||||||||||
Equity:
|
||||||||||||||||||||||||||||
Controlling
interests
|
9,528.0 | 21,058.3 | (21,084.5 | ) | 9,501.8 | 9,512.1 | (9,501.8 | ) | 9,512.1 | |||||||||||||||||||
Noncontrolling
interests
|
-- | 3,463.3 | (2,923.4 | ) | 539.9 | -- | (9.7 | ) | 530.2 | |||||||||||||||||||
Total
equity
|
9,528.0 | 24,521.6 | (24,007.9 | ) | 10,041.7 | 9,512.1 | (9,511.5 | ) | 10,042.3 | |||||||||||||||||||
Total
liabilities and equity
|
$ | 22,716.1 | $ | 27,682.4 | $ | (24,247.5 | ) | $ | 26,151.0 | $ | 9,512.1 | $ | (9,511.5 | ) | $ | 26,151.6 |
EPO
and Subsidiaries
|
||||||||||||||||||||||||||||
Subsidiary
Issuer (EPO)
|
Other
Subsidiaries
(Non-guarantor)
|
EPO
and Subsidiaries Eliminations and Adjustments
|
Consolidated
EPO
and Subsidiaries
|
Parent
Company (Guarantor)
|
Eliminations
and Adjustments
|
Consolidated
Total
|
||||||||||||||||||||||
ASSETS
|
||||||||||||||||||||||||||||
Current
assets:
|
||||||||||||||||||||||||||||
Cash
and cash equivalents
|
$ | 1.0 | $ | 69.7 | $ | (9.4 | ) | $ | 61.3 | $ | 0.2 | $ | 0.2 | $ | 61.7 | |||||||||||||
Restricted
Cash
|
203.8 | -- | -- | 203.8 | -- | -- | 203.8 | |||||||||||||||||||||
Accounts
and notes receivable, net
|
1,230.9 | 930.1 | (84.9 | ) | 2,076.1 | (7.7 | ) | (4.6 | ) | 2,063.8 | ||||||||||||||||||
Inventories
|
288.8 | 129.3 | (13.1 | ) | 405.0 | -- | -- | 405.0 | ||||||||||||||||||||
Prepaid
and other current assets
|
107.4 | 254.4 | 6.6 | 368.4 | -- | -- | 368.4 | |||||||||||||||||||||
Total
current assets
|
1,831.9 | 1,383.5 | (100.8 | ) | 3,114.6 | (7.5 | ) | (4.4 | ) | 3,102.7 | ||||||||||||||||||
Property,
plant and equipment, net
|
1,249.7 | 15,457.7 | 25.4 | 16,732.8 | -- | -- | 16,732.8 | |||||||||||||||||||||
Investments
in unconsolidated affiliates
|
13,389.3 | 5,297.4 | (17,774.8 | ) | 911.9 | 6,097.5 | (6,097.5 | ) | 911.9 | |||||||||||||||||||
Intangible
assets, net
|
182.4 | 1,016.7 | (16.2 | ) | 1,182.9 | -- | -- | 1,182.9 | ||||||||||||||||||||
Goodwill
|
473.7 | 342.6 | 1,203.3 | 2,019.6 | -- | -- | 2,019.6 | |||||||||||||||||||||
Other
assets
|
308.3 | 159.0 | (206.2 | ) | 261.1 | -- | 0.6 | 261.7 | ||||||||||||||||||||
Total
assets
|
$ | 17,435.3 | $ | 23,656.9 | $ | (16,869.3 | ) | $ | 24,222.9 | $ | 6,090.0 | $ | (6,101.3 | ) | $ | 24,211.6 | ||||||||||||
LIABILITIES
AND EQUITY
|
||||||||||||||||||||||||||||
Current
liabilities:
|
||||||||||||||||||||||||||||
Accounts
payable
|
$ | 1,532.1 | $ | (841.2 | ) | $ | (285.1 | ) | $ | 405.8 | $ | 0.5 | $ | -- | $ | 406.3 | ||||||||||||
Accrued
product payables
|
844.8 | 1,014.2 | (13.3 | ) | 1,845.7 | -- | -- | 1,845.7 | ||||||||||||||||||||
Other
current liabilities
|
262.4 | 601.5 | (14.7 | ) | 849.2 | -- | -- | 849.2 | ||||||||||||||||||||
Total
current liabilities
|
2,639.3 | 774.5 | (313.1 | ) | 3,100.7 | 0.5 | -- | 3,101.2 | ||||||||||||||||||||
Long-term
debt
|
8,567.0 | 3,070.9 | -- | 11,637.9 | -- | -- | 11,637.9 | |||||||||||||||||||||
Commitments
and contingencies
|
||||||||||||||||||||||||||||
Other
long-term liabilities
|
17.2 | 159.4 | -- | 176.6 | -- | -- | 176.6 | |||||||||||||||||||||
Equity:
|
||||||||||||||||||||||||||||
Controlling
interests
|
6,211.8 | 16,476.0 | (16,597.1 | ) | 6,090.7 | 6,089.5 | (6,090.7 | ) | 6,089.5 | |||||||||||||||||||
Noncontrolling
interests
|
-- | 3,176.1 | 40.9 | 3,217.0 | -- | (10.6 | ) | 3,206.4 | ||||||||||||||||||||
Total
equity
|
6,211.8 | 19,652.1 | (16,556.2 | ) | 9,307.7 | 6,089.5 | (6,101.3 | ) | 9,295.9 | |||||||||||||||||||
Total
liabilities and equity
|
$ | 17,435.3 | $ | 23,656.9 | $ | (16,869.3 | ) | $ | 24,222.9 | $ | 6,090.0 | $ | (6,101.3 | ) | $ | 24,211.6 |
EPO
and Subsidiaries
|
||||||||||||||||||||||||||||
Subsidiary
Issuer (EPO)
|
Other
Subsidiaries
(Non-guarantor)
|
EPO
and Subsidiaries Eliminations and Adjustments
|
Consolidated
EPO
and Subsidiaries
|
Parent
Company (Guarantor)
|
Eliminations
and Adjustments
|
Consolidated
Total
|
||||||||||||||||||||||
Revenues
|
$ | 18,986.8 | $ | 14,496.0 | $ | (7,971.9 | ) | $ | 25,510.9 | $ | -- | $ | -- | $ | 25,510.9 | |||||||||||||
Costs
and expenses:
|
||||||||||||||||||||||||||||
Operating
costs and expenses
|
18,647.9 | 12,821.8 | (7,903.9 | ) | 23,565.8 | -- | -- | 23,565.8 | ||||||||||||||||||||
General
and administrative costs
|
14.1 | 149.2 | -- | 163.3 | 9.0 | -- | 172.3 | |||||||||||||||||||||
Total
costs and expenses
|
18,662.0 | 12,971.0 | (7,903.9 | ) | 23,729.1 | 9.0 | -- | 23,738.1 | ||||||||||||||||||||
Equity
in income of unconsolidated affiliates
|
1,225.8 | 117.5 | (1,292.1 | ) | 51.2 | 1,039.9 | (1,039.9 | ) | 51.2 | |||||||||||||||||||
Operating
income
|
1,550.6 | 1,642.5 | (1,360.1 | ) | 1,833.0 | 1,030.9 | (1,039.9 | ) | 1,824.0 | |||||||||||||||||||
Other
income (expense):
|
||||||||||||||||||||||||||||
Interest
expense
|
(514.1 | ) | (140.4 | ) | 12.7 | (641.8 | ) | -- | -- | (641.8 | ) | |||||||||||||||||
Other,
net
|
8.5 | 2.4 | (12.7 | ) | (1.8 | ) | -- | -- | (1.8 | ) | ||||||||||||||||||
Total
other expense, net
|
(505.6 | ) | (138.0 | ) | -- | (643.6 | ) | -- | -- | (643.6 | ) | |||||||||||||||||
Income
before provision for income taxes
|
1,045.0 | 1,504.5 | (1,360.1 | ) | 1,189.4 | 1,030.9 | (1,039.9 | ) | 1,180.4 | |||||||||||||||||||
Provision
for income taxes
|
(7.8 | ) | (17.4 | ) | -- | (25.2 | ) | -- | (0.1 | ) | (25.3 | ) | ||||||||||||||||
Net
income
|
1,037.2 | 1,487.1 | (1,360.1 | ) | 1,164.2 | 1,030.9 | (1,040.0 | ) | 1,155.1 | |||||||||||||||||||
Net
income attributable to noncontrolling interest
|
-- | 21.6 | (146.2 | ) | (124.6 | ) | -- | 0.4 | (124.2 | ) | ||||||||||||||||||
Net
income attributable to entity
|
$ | 1,037.2 | $ | 1,508.7 | $ | (1,506.3 | ) | $ | 1,039.6 | $ | 1,030.9 | $ | (1,039.6 | ) | $ | 1,030.9 |
EPO
and Subsidiaries
|
||||||||||||||||||||||||||||
Subsidiary
Issuer (EPO)
|
Other
Subsidiaries
(Non-guarantor)
|
EPO
and Subsidiaries Eliminations and Adjustments
|
Consolidated
EPO
and Subsidiaries
|
Parent
Company (Guarantor)
|
Eliminations
and Adjustments
|
Consolidated
Total
|
||||||||||||||||||||||
Revenues
|
$ | 23,348.2 | $ | 21,729.0 | $ | (9,607.6 | ) | $ | 35,469.6 | $ | -- | $ | -- | $ | 35,469.6 | |||||||||||||
Costs
and expenses:
|
||||||||||||||||||||||||||||
Operating
costs and expenses
|
23,140.2 | 20,078.6 | (9,599.9 | ) | 33,618.9 | -- | -- | 33,618.9 | ||||||||||||||||||||
General
and administrative costs
|
12.6 | 122.1 | -- | 134.7 | 2.5 | -- | 137.2 | |||||||||||||||||||||
Total
costs and expenses
|
23,152.8 | 20,200.7 | (9,599.9 | ) | 33,753.6 | 2.5 | -- | 33,756.1 | ||||||||||||||||||||
Equity
in income of unconsolidated affiliates
|
1,140.5 | 158.5 | (1,264.1 | ) | 34.9 | 956.5 | (956.5 | ) | 34.9 | |||||||||||||||||||
Operating
income
|
1,335.9 | 1,686.8 | (1,271.8 | ) | 1,750.9 | 954.0 | (956.5 | ) | 1,748.4 | |||||||||||||||||||
Other
income (expense):
|
||||||||||||||||||||||||||||
Interest
expense
|
(386.6 | ) | (166.2 | ) | 12.1 | (540.7 | ) | -- | -- | (540.7 | ) | |||||||||||||||||
Other,
net
|
21.1 | 0.4 | (9.3 | ) | 12.2 | -- | -- | 12.2 | ||||||||||||||||||||
Total
other expense, net
|
(365.5 | ) | (165.8 | ) | 2.8 | (528.5 | ) | -- | -- | (528.5 | ) | |||||||||||||||||
Income
before provision for income taxes
|
970.4 | 1,521.0 | (1,269.0 | ) | 1,222.4 | 954.0 | (956.5 | ) | 1,219.9 | |||||||||||||||||||
Provision
for income taxes
|
(14.2 | ) | (16.8 | ) | -- | (31.0 | ) | -- | -- | (31.0 | ) | |||||||||||||||||
Net
income
|
956.2 | 1,504.2 | (1,269.0 | ) | 1,191.4 | 954.0 | (956.5 | ) | 1,188.9 | |||||||||||||||||||
Net
income attributable to noncontrolling interest
|
-- | (221.1 | ) | (14.0 | ) | (235.1 | ) | -- | 0.2 | (234.9 | ) | |||||||||||||||||
Net
income attributable to entity
|
$ | 956.2 | $ | 1,283.1 | $ | (1,283.0 | ) | $ | 956.3 | $ | 954.0 | $ | (956.3 | ) | $ | 954.0 |
EPO
and Subsidiaries
|
||||||||||||||||||||||||||||
Subsidiary
Issuer (EPO)
|
Other
Subsidiaries
(Non-guarantor)
|
EPO
and Subsidiaries Eliminations and Adjustments
|
Consolidated
EPO
and Subsidiaries
|
Parent
Company (Guarantor)
|
Eliminations
and Adjustments
|
Consolidated
Total
|
||||||||||||||||||||||
Revenues
|
$ | 16,308.8 | $ | 16,541.8 | $ | (6,136.8 | ) | $ | 26,713.8 | $ | -- | $ | -- | $ | 26,713.8 | |||||||||||||
Costs
and expenses:
|
||||||||||||||||||||||||||||
Operating
costs and expenses
|
16,257.6 | 15,270.5 | (6,126.0 | ) | 25,402.1 | -- | -- | 25,402.1 | ||||||||||||||||||||
General
and administrative costs
|
26.5 | 98.2 | -- | 124.7 | 2.5 | -- | 127.2 | |||||||||||||||||||||
Total
costs and expenses
|
16,284.1 | 15,368.7 | (6,126.0 | ) | 25,526.8 | 2.5 | -- | 25,529.3 | ||||||||||||||||||||
Equity
in income of unconsolidated affiliates
|
800.4 | 108.5 | (898.4 | ) | 10.5 | 534.3 | (534.3 | ) | 10.5 | |||||||||||||||||||
Operating
income
|
825.1 | 1,281.6 | (909.2 | ) | 1,197.5 | 531.8 | (534.3 | ) | 1,195.0 | |||||||||||||||||||
Other
income (expense):
|
||||||||||||||||||||||||||||
Interest
expense
|
(300.4 | ) | (124.7 | ) | 12.1 | (413.0 | ) | -- | -- | (413.0 | ) | |||||||||||||||||
Other,
net
|
14.6 | 67.0 | (11.7 | ) | 69.9 | 1.8 | -- | 71.7 | ||||||||||||||||||||
Total
other expense, net
|
(285.8 | ) | (57.7 | ) | 0.4 | (343.1 | ) | 1.8 | -- | (341.3 | ) | |||||||||||||||||
Income
before provision for income taxes
|
539.3 | 1,223.9 | (908.8 | ) | 854.4 | 533.6 | (534.3 | ) | 853.7 | |||||||||||||||||||
Provision
for income taxes
|
(5.0 | ) | (10.7 | ) | -- | (15.7 | ) | -- | -- | (15.7 | ) | |||||||||||||||||
Net
income
|
534.3 | 1,213.2 | (908.8 | ) | 838.7 | 533.6 | (534.3 | ) | 838.0 | |||||||||||||||||||
Net
income attributable to noncontrolling interest
|
-- | (305.6 | ) | 1.1 | (304.5 | ) | -- | 0.1 | (304.4 | ) | ||||||||||||||||||
Net
income attributable to entity
|
$ | 534.3 | $ | 907.6 | $ | (907.7 | ) | $ | 534.2 | $ | 533.6 | $ | (534.2 | ) | $ | 533.6 |
EPO
and Subsidiaries
|
||||||||||||||||||||||||||||
Subsidiary
Issuer (EPO)
|
Other
Subsidiaries
(Non-guarantor)
|
EPO
and Subsidiaries Eliminations and Adjustments
|
Consolidated
EPO
and Subsidiaries
|
Parent
Company (Guarantor)
|
Eliminations
and Adjustments
|
Consolidated
Total
|
||||||||||||||||||||||
Operating
activities:
|
||||||||||||||||||||||||||||
Net
income
|
$ | 1,037.2 | $ | 1,487.1 | $ | (1,360.1 | ) | $ | 1,164.2 | $ | 1,030.9 | $ | (1,040.0 | ) | $ | 1,155.1 | ||||||||||||
Adjustments
to reconcile net income to cash provided
by
operating activities:
|
||||||||||||||||||||||||||||
Depreciation,
accretion and amortization
|
86.3 | 748.7 | (1.6 | ) | 833.4 | -- | -- | 833.4 | ||||||||||||||||||||
Non-cash
impairment charges
|
-- | 33.5 | -- | 33.5 | -- | -- | 33.5 | |||||||||||||||||||||
Equity
in income of unconsolidated affiliates
|
(1,225.8 | ) | (117.5 | ) | 1,292.1 | (51.2 | ) | (1,039.9 | ) | 1,039.9 | (51.2 | ) | ||||||||||||||||
Distributions
received from unconsolidated affiliates
|
258.6 | 79.8 | (251.8 | ) | 86.6 | 1,265.0 | (1,265.0 | ) | 86.6 | |||||||||||||||||||
Operating
lease expenses paid by EPCO
|
0.7 | -- | -- | 0.7 | -- | -- | 0.7 | |||||||||||||||||||||
Loss
on forfeiture of investment in TOPS
|
-- | 68.4 | -- | 68.4 | -- | -- | 68.4 | |||||||||||||||||||||
Gain
from asset sales and related transactions
|
-- | 0.3 | (0.3 | ) | -- | -- | -- | -- | ||||||||||||||||||||
Deferred
income tax expense
|
(0.9 | ) | 5.8 | -- | 4.9 | -- | (0.4 | ) | 4.5 | |||||||||||||||||||
Changes
in fair market value of derivative instruments
|
5.8 | (5.4 | ) | -- | 0.4 | -- | -- | 0.4 | ||||||||||||||||||||
Effect
of pension settlement recognition
|
-- | (0.1 | ) | -- | (0.1 | ) | -- | -- | (0.1 | ) | ||||||||||||||||||
Net
effect of changes in operating accounts
|
1,314.9 | (856.7 | ) | (208.8 | ) | 249.4 | (3.7 | ) | 0.2 | 245.9 | ||||||||||||||||||
Cash
provided by operating activities
|
1,476.8 | 1,443.9 | (530.5 | ) | 2,390.2 | 1,252.3 | (1,265.3 | ) | 2,377.2 | |||||||||||||||||||
Investing
activities:
|
||||||||||||||||||||||||||||
Capital
expenditures, net of contributions in aid of
construction
costs
|
(209.9 | ) | (1,356.6 | ) | -- | (1,566.5 | ) | -- | -- | (1,566.5 | ) | |||||||||||||||||
Decrease
(increase) in restricted cash
|
140.7 | (0.5 | ) | -- | 140.2 | -- | -- | 140.2 | ||||||||||||||||||||
Cash
used for business combinations
|
(23.7 | ) | (93.9 | ) | 10.3 | (107.3 | ) | -- | -- | (107.3 | ) | |||||||||||||||||
Acquisition
of intangible assets
|
-- | (1.4 | ) | -- | (1.4 | ) | -- | -- | (1.4 | ) | ||||||||||||||||||
Investments
in unconsolidated affiliates
|
(1,266.0 | ) | (18.1 | ) | 1,265.3 | (18.8 | ) | (908.3 | ) | 908.3 | (18.8 | ) | ||||||||||||||||
Proceeds
from asset sales and related transactions
|
-- | 3.6 | -- | 3.6 | -- | -- | 3.6 | |||||||||||||||||||||
Other
investing activities
|
-- | 3.3 | -- | 3.3 | -- | -- | 3.3 | |||||||||||||||||||||
Cash
provided by (used in) investing activities
|
(1,358.9 | ) | (1,463.6 | ) | 1,275.6 | (1,546.9 | ) | (908.3 | ) | 908.3 | (1,546.9 | ) | ||||||||||||||||
Financing
activities:
|
||||||||||||||||||||||||||||
Borrowings
under debt agreements
|
6,105.0 | 1,271.6 | -- | 7,376.6 | -- | -- | 7,376.6 | |||||||||||||||||||||
Repayments
of debt
|
(5,838.2 | ) | (1,815.3 | ) | -- | (7,653.5 | ) | -- | -- | (7,653.5 | ) | |||||||||||||||||
Cash
distributions paid to partners
|
(1,265.1 | ) | (448.1 | ) | 448.1 | (1,265.1 | ) | (1,254.8 | ) | 1,265.1 | (1,254.8 | ) | ||||||||||||||||
Cash
distributions paid to noncontrolling interest
|
-- | (303.8 | ) | (36.4 | ) | (340.2 | ) | -- | 0.2 | (340.0 | ) | |||||||||||||||||
Net
cash proceeds from issuance of common units
|
-- | -- | -- | -- | 912.7 | -- | 912.7 | |||||||||||||||||||||
Cash
contributions from members
|
908.3 | 1,288.8 | (1,288.8 | ) | 908.3 | -- | (908.3 | ) | -- | |||||||||||||||||||
Cash
contributions from noncontrolling interest
|
-- | 3.5 | 135.2 | 138.7 | -- | -- | 138.7 | |||||||||||||||||||||
Other
financing activities
|
(14.5 | ) | (0.2 | ) | -- | (14.7 | ) | (2.1 | ) | -- | (16.8 | ) | ||||||||||||||||
Cash
provided by (used in) financing activities
|
(104.5 | ) | (3.5 | ) | (741.9 | ) | (849.9 | ) | (344.2 | ) | 357.0 | (837.1 | ) | |||||||||||||||
Effect
of exchange rate changes on cash
|
-- | (0.2 | ) | -- | (0.2 | ) | -- | -- | (0.2 | ) | ||||||||||||||||||
Net
change in cash and cash equivalents
|
13.4 | (23.2 | ) | 3.2 | (6.6 | ) | (0.2 | ) | -- | (6.8 | ) | |||||||||||||||||
Cash
and cash equivalents, January 1
|
1.0 | 69.7 | (9.4 | ) | 61.3 | 0.2 | 0.2 | 61.7 | ||||||||||||||||||||
Cash
and cash equivalents, December 31
|
$ | 14.4 | $ | 46.3 | $ | (6.2 | ) | $ | 54.5 | $ | -- | $ | 0.2 | $ | 54.7 |
EPO
and Subsidiaries
|
||||||||||||||||||||||||||||
Subsidiary
Issuer (EPO)
|
Other
Subsidiaries
(Non-guarantor)
|
EPO
and Subsidiaries Eliminations and Adjustments
|
Consolidated
EPO
and Subsidiaries
|
Parent
Company (Guarantor)
|
Eliminations
and Adjustments
|
Consolidated
Total
|
||||||||||||||||||||||
Operating
activities:
|
||||||||||||||||||||||||||||
Net
income
|
$ | 956.2 | $ | 1,504.2 | $ | (1,269.0 | ) | $ | 1,191.4 | $ | 954.0 | $ | (956.5 | ) | $ | 1,188.9 | ||||||||||||
Adjustments
to reconcile net income to cash provided
by
operating activities:
|
||||||||||||||||||||||||||||
Depreciation,
accretion and amortization
|
68.4 | 669.3 | 0.1 | 737.8 | -- | -- | 737.8 | |||||||||||||||||||||
Equity
in income of unconsolidated affiliates
|
(1,140.5 | ) | (158.5 | ) | 1,264.1 | (34.9 | ) | (956.5 | ) | 956.5 | (34.9 | ) | ||||||||||||||||
Distributions
received from unconsolidated affiliates
|
346.6 | (265.8 | ) | -- | 80.8 | 1,036.8 | (1,036.8 | ) | 80.8 | |||||||||||||||||||
Operating
lease expenses paid by EPCO
|
2.0 | -- | -- | 2.0 | -- | -- | 2.0 | |||||||||||||||||||||
Gain
from asset sales and related transactions
|
-- | (4.0 | ) | -- | (4.0 | ) | -- | -- | (4.0 | ) | ||||||||||||||||||
Loss
(gain) on early extinguishment of debt
|
(7.1 | ) | 8.7 | -- | 1.6 | -- | -- | 1.6 | ||||||||||||||||||||
Deferred
income tax expense
|
(0.4 | ) | 6.6 | -- | 6.2 | -- | -- | 6.2 | ||||||||||||||||||||
Changes
in fair market value of derivative instruments
|
3.8 | (3.9 | ) | -- | (0.1 | ) | -- | -- | (0.1 | ) | ||||||||||||||||||
Effect
of pension settlement recognition
|
(1.2 | ) | 1.1 | -- | (0.1 | ) | -- | -- | (0.1 | ) | ||||||||||||||||||
Net
effect of changes in operating accounts
|
(352.1 | ) | (66.5 | ) | 3.3 | (415.3 | ) | 3.2 | 1.0 | (411.1 | ) | |||||||||||||||||
Cash
provided by (used in) operating activities
|
(124.3 | ) | 1,691.2 | (1.5 | ) | 1,565.4 | 1,037.5 | (1,035.8 | ) | 1,567.1 | ||||||||||||||||||
Investing
activities:
|
||||||||||||||||||||||||||||
Capital
expenditures, net of contributions in aid of
construction
costs
|
(42.2 | ) | (2,470.2 | ) | -- | (2,512.4 | ) | -- | -- | (2,512.4 | ) | |||||||||||||||||
Increase
in restricted cash
|
(132.8 | ) | -- | -- | (132.8 | ) | -- | -- | (132.8 | ) | ||||||||||||||||||
Cash
used for business combinations
|
(77.0 | ) | (476.5 | ) | -- | (553.5 | ) | -- | -- | (553.5 | ) | |||||||||||||||||
Acquisition
of intangible assets
|
(5.1 | ) | (0.7 | ) | -- | (5.8 | ) | -- | -- | (5.8 | ) | |||||||||||||||||
Investments
in unconsolidated affiliates
|
(584.1 | ) | 512.7 | 6.7 | (64.7 | ) | (141.0 | ) | 141.0 | (64.7 | ) | |||||||||||||||||
Proceeds
from asset sales and related transactions
|
0.3 | 22.0 | -- | 22.3 | -- | -- | 22.3 | |||||||||||||||||||||
Cash
provided by (used in) investing activities
|
(840.9 | ) | (2,412.7 | ) | 6.7 | (3,246.9 | ) | (141.0 | ) | 141.0 | (3,246.9 | ) | ||||||||||||||||
Financing
activities:
|
||||||||||||||||||||||||||||
Borrowings
under debt agreements
|
8,284.6 | 4,903.4 | -- | 13,188.0 | -- | -- | 13,188.0 | |||||||||||||||||||||
Repayments
of debt
|
(6,403.5 | ) | (4,030.8 | ) | -- | (10,434.3 | ) | -- | -- | (10,434.3 | ) | |||||||||||||||||
Cash
distributions paid to partners
|
(1,036.8 | ) | -- | -- | (1,036.8 | ) | (1,037.4 | ) | 1,036.8 | (1,037.4 | ) | |||||||||||||||||
Cash
distributions paid to noncontrolling interest
|
-- | (384.8 | ) | -- | (384.8 | ) | -- | 0.9 | (383.9 | ) | ||||||||||||||||||
Net
cash proceeds from issuance of common units
|
-- | -- | -- | -- | 142.8 | -- | 142.8 | |||||||||||||||||||||
Cash
contributions from members
|
141.0 | -- | -- | 141.0 | -- | (141.0 | ) | -- | ||||||||||||||||||||
Cash
contributions from noncontrolling interest
|
-- | 313.3 | -- | 313.3 | -- | (1.8 | ) | 311.5 | ||||||||||||||||||||
Other
financing activities
|
(30.3 | ) | (63.8 | ) | -- | (94.1 | ) | (1.9 | ) | -- | (96.0 | ) | ||||||||||||||||
Cash
provided by (used in) financing activities
|
955.0 | 737.3 | -- | 1,692.3 | (896.5 | ) | 894.9 | 1,690.7 | ||||||||||||||||||||
Effect
of exchange rate changes on cash
|
-- | (0.5 | ) | -- | (0.5 | ) | -- | -- | (0.5 | ) | ||||||||||||||||||
Net
change in cash and cash equivalents
|
(10.2 | ) | 15.8 | 5.2 | 10.8 | -- | 0.1 | 10.9 | ||||||||||||||||||||
Cash
and cash equivalents, January 1
|
11.2 | 54.4 | (14.6 | ) | 51.0 | 0.2 | 0.1 | 51.3 | ||||||||||||||||||||
Cash
and cash equivalents, December 31
|
$ | 1.0 | $ | 69.7 | $ | (9.4 | ) | $ | 61.3 | $ | 0.2 | $ | 0.2 | $ | 61.7 |
EPO
and Subsidiaries
|
||||||||||||||||||||||||||||
Subsidiary
Issuer (EPO)
|
Other
Subsidiaries
(Non-guarantor)
|
EPO
and Subsidiaries Eliminations and Adjustments
|
Consolidated
EPO
and Subsidiaries
|
Parent
Company (Guarantor)
|
Eliminations
and Adjustments
|
Consolidated
Total
|
||||||||||||||||||||||
Operating
activities:
|
||||||||||||||||||||||||||||
Net
income
|
$ | 534.3 | $ | 1,213.2 | $ | (908.8 | ) | $ | 838.7 | $ | 533.6 | $ | (534.3 | ) | $ | 838.0 | ||||||||||||
Adjustments
to reconcile net income to cash provided
by
operating activities:
|
||||||||||||||||||||||||||||
Depreciation,
accretion and amortization
|
62.2 | 595.9 | 0.3 | 658.4 | -- | -- | 658.4 | |||||||||||||||||||||
Equity
in income of unconsolidated affiliates
|
(800.4 | ) | (108.5 | ) | 898.4 | (10.5 | ) | (534.3 | ) | 534.3 | (10.5 | ) | ||||||||||||||||
Distributions
received from unconsolidated affiliates
|
924.6 | (837.6 | ) | -- | 87.0 | 946.9 | (946.9 | ) | 87.0 | |||||||||||||||||||
Operating
lease expenses paid by EPCO
|
2.1 | -- | -- | 2.1 | -- | -- | 2.1 | |||||||||||||||||||||
Loss
(gain) from asset sales and related transactions
|
5.8 | (73.2 | ) | -- | (67.4 | ) | -- | -- | (67.4 | ) | ||||||||||||||||||
Loss
on early extinguishment of debt
|
-- | 1.6 | -- | 1.6 | -- | -- | 1.6 | |||||||||||||||||||||
Deferred
income tax expense
|
2.4 | 5.2 | -- | 7.6 | -- | -- | 7.6 | |||||||||||||||||||||
Changes
in fair market value of derivative instruments
|
0.4 | 0.9 | -- | 1.3 | -- | -- | 1.3 | |||||||||||||||||||||
Effect
of pension settlement recognition
|
0.4 | 0.2 | -- | 0.6 | -- | -- | 0.6 | |||||||||||||||||||||
Net
effect of changes in operating accounts
|
(830.0 | ) | 1,244.5 | 8.0 | 422.5 | 9.8 | 2.6 | 434.9 | ||||||||||||||||||||
Cash
provided by operating activities
|
(98.2 | ) | 2,042.2 | (2.1 | ) | 1,941.9 | 956.0 | (944.3 | ) | 1,953.6 | ||||||||||||||||||
Investing
activities:
|
||||||||||||||||||||||||||||
Capital
expenditures, net of contributions in aid of
construction
costs
|
(170.7 | ) | (2,535.7 | ) | -- | (2,706.4 | ) | -- | -- | (2,706.4 | ) | |||||||||||||||||
Decrease
(increase) in restricted cash
|
(66.3 | ) | 19.0 | -- | (47.3 | ) | -- | -- | (47.3 | ) | ||||||||||||||||||
Cash
used for business combinations
|
(0.3 | ) | (35.6 | ) | -- | (35.9 | ) | -- | -- | (35.9 | ) | |||||||||||||||||
Acquisition
of intangible assets
|
(11.2 | ) | (3.3 | ) | -- | (14.5 | ) | -- | -- | (14.5 | ) | |||||||||||||||||
Investments
in unconsolidated affiliates
|
(114.7 | ) | (125.6 | ) | 3.5 | (236.8 | ) | (67.6 | ) | 67.6 | (236.8 | ) | ||||||||||||||||
Proceeds
from asset sales and related transactions
|
0.1 | 169.0 | -- | 169.1 | -- | -- | 169.1 | |||||||||||||||||||||
Cash
provided by (used in) investing activities
|
(363.1 | ) | (2,512.2 | ) | 3.5 | (2,871.8 | ) | (67.6 | ) | 67.6 | (2,871.8 | ) | ||||||||||||||||
Financing
activities:
|
||||||||||||||||||||||||||||
Borrowings
under debt agreements
|
5,643.5 | 1,986.3 | -- | 7,629.8 | -- | -- | 7,629.8 | |||||||||||||||||||||
Repayments
of debt
|
(4,329.0 | ) | (1,462.0 | ) | (8.9 | ) | (5,799.9 | ) | -- | -- | (5,799.9 | ) | ||||||||||||||||
Cash
distributions paid to partners
|
(946.9 | ) | -- | -- | (946.9 | ) | (957.7 | ) | 946.9 | (957.7 | ) | |||||||||||||||||
Cash
distributions paid to noncontrolling interest
|
-- | (326.8 | ) | -- | (326.8 | ) | -- | -- | (326.8 | ) | ||||||||||||||||||
Net
cash proceeds from issuance of common units
|
-- | -- | -- | -- | 69.2 | -- | 69.2 | |||||||||||||||||||||
Cash
contributions from members
|
67.6 | -- | -- | 67.6 | -- | (67.6 | ) | -- | ||||||||||||||||||||
Cash
contributions from noncontrolling interest
|
-- | 306.9 | -- | 306.9 | (2.2 | ) | 304.7 | |||||||||||||||||||||
Other
financing activities
|
31.7 | (4.7 | ) | -- | 27.0 | -- | -- | 27.0 | ||||||||||||||||||||
Cash
provided by (used in) financing activities
|
466.9 | 499.7 | (8.9 | ) | 957.7 | (888.5 | ) | 877.1 | 946.3 | |||||||||||||||||||
Effect
of exchange rate changes on cash
|
-- | 0.4 | -- | 0.4 | -- | -- | 0.4 | |||||||||||||||||||||
Net
change in cash and cash equivalents
|
5.6 | 29.7 | (7.5 | ) | 27.8 | (0.1 | ) | 0.4 | 28.1 | |||||||||||||||||||
Cash
and cash equivalents, January 1
|
5.6 | 24.3 | (7.1 | ) | 22.8 | 0.3 | (0.3 | ) | 22.8 | |||||||||||||||||||
Cash
and cash equivalents, December 31
|
$ | 11.2 | $ | 54.4 | $ | (14.6 | ) | $ | 51.0 | $ | 0.2 | $ | 0.1 | $ | 51.3 |
U.S. Bank National Association | ||||||
As
Trustee
|
||||||
By:
|
/s/ Steven A.
Finklea
|
|||||
Name:
|
Steven A. Finklea, CCTS
|
|||||
Title:
|
Vice President
|
The Bank of New York Mellon Trust Company, N.A. | ||||||
As
Trustee
|
||||||
By: | /s/ Kash Asghar | |||||
Name: Kash Asghar | ||||||
Title: Senior Associate |
For
the Year Ended December 31,
|
|||||||||||||||||||||
2009
|
2008
|
2007
|
2006
|
2005
|
|||||||||||||||||
Consolidated
income
|
$ | 1,155.1 | $ | 1,188.9 | $ | 838.0 | $ | 787.6 | $ | 577.4 | |||||||||||
Add:
|
Provision
for taxes
|
25.3 | 31.0 | 15.7 | 22.0 | 8.3 | |||||||||||||||
Less:
|
Equity
in earnings from unconsolidated affiliates
|
(51.2 | ) | (34.9 | ) | (10.5 | ) | (25.2 | ) | (34.6 | ) | ||||||||||
Consolidated
pre-tax income before equity in earnings from unconsolidated
affiliates
|
1,129.2 | 1,185.0 | 843.2 | 784.4 | 551.1 | ||||||||||||||||
Add:
|
Fixed
charges
|
715.1 | 650.3 | 520.0 | 412.2 | 360.8 | |||||||||||||||
Amortization
of capitalized interest
|
15.3 | 13.4 | 11.6 | 9.8 | 2.0 | ||||||||||||||||
Distributed
income of equity investees
|
86.6 | 80.8 | 87.0 | 76.5 | 93.1 | ||||||||||||||||
Subtotal
|
1,946.2 | 1,929.5 | 1,461.8 | 1,282.9 | 1,007.0 | ||||||||||||||||
Less:
|
Capitalized
interest
|
(53.1 | ) | (90.7 | ) | (86.5 | ) | (66.4 | ) | (28.8 | ) | ||||||||||
Net
income attributable to noncontrolling interest
|
(26.4 | ) | (23.0 | ) | (14.8 | ) | (4.0 | ) | (4.5 | ) | |||||||||||
Total
earnings
|
$ | 1,866.7 | $ | 1,815.8 | $ | 1,360.5 | $ | 1,212.5 | $ | 973.7 | |||||||||||
Fixed
charges:
|
|||||||||||||||||||||
Interest
expense
|
$ | 641.8 | $ | 540.7 | $ | 413.0 | $ | 324.2 | $ | 312.4 | |||||||||||
Capitalized
interest
|
53.1 | 90.7 | 86.5 | 66.4 | 28.8 | ||||||||||||||||
Interest
portion of rental expense
|
20.2 | 18.9 | 20.5 | 21.6 | 19.6 | ||||||||||||||||
Total
|
$ | 715.1 | $ | 650.3 | $ | 520.0 | $ | 412.2 | $ | 360.8 | |||||||||||
Ratio
of earnings to fixed charges
|
2.6x | 2.8x | 2.6x | 2.9x | 2.7x |
·
|
consolidated
pre-tax income from continuing operations before adjustment for income or
loss from equity investees;
|
·
|
fixed
charges;
|
·
|
amortization
of capitalized interest;
|
·
|
distributed
income of equity investees; and
|
·
|
our
share of pre-tax losses of equity investees for which charges arising from
guarantees are included in fixed
charges.
|
·
|
interest
capitalized;
|
·
|
preference
security dividend requirements of consolidated subsidiaries;
and
|
·
|
the
noncontrolling interest in pre-tax income of subsidiaries that have not
incurred fixed charges.
|
1.
|
I
have reviewed this annual report on Form 10-K of Enterprise Products
Partners L.P.;
|
2.
|
Based
on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
|
3.
|
Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
report;
|
4.
|
The
registrant’s other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and
have:
|
a)
|
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
|
b)
|
Designed
such internal control over financial reporting, or caused such internal
control over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
|
c)
|
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation;
and
|
d)
|
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
|
5.
|
The
registrant’s other certifying officer and I have disclosed, based on our
most recent evaluation of internal control over financial reporting, to
the registrant’s auditors and the audit committee of the registrant’s
board of directors (or persons performing the equivalent
functions):
|
a)
|
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information;
and
|
b)
|
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
|
/s/
Michael A. Creel
|
||
Name:
|
Michael
A. Creel
|
|
Title:
|
Chief
Executive Officer of Enterprise Products GP, LLC,
the
General Partner of Enterprise Products Partners L.P.
|
1.
|
I
have reviewed this annual report on Form 10-K of Enterprise Products
Partners L.P.;
|
2.
|
Based
on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
|
3.
|
Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
report;
|
4.
|
The
registrant’s other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and
have:
|
a)
|
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
|
b)
|
Designed
such internal control over financial reporting, or caused such internal
control over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
|
c)
|
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation;
and
|
d)
|
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
|
5.
|
The
registrant’s other certifying officer and I have disclosed, based on our
most recent evaluation of internal control over financial reporting, to
the registrant’s auditors and the audit committee of the registrant’s
board of directors (or persons performing the equivalent
functions):
|
a)
|
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information;
and
|
b)
|
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
|
/s/ W.
Randall Fowler
|
||
Name:
|
W.
Randall Fowler
|
|
Title:
|
Chief
Financial Officer of Enterprise Products GP, LLC,
the
General Partner of Enterprise Products Partners L.P.
|
(1)
|
The
Report fully complies with the requirements of Section 13(a) of the
Securities Exchange Act of 1934;
and
|
(2)
|
The
information contained in the Report fairly presents, in all material
respects, the financial condition and results of operations of the
Registrant.
|
/s/
Michael A. Creel
|
|
Name:
|
Michael
A. Creel
|
Title:
|
Chief
Executive Officer of Enterprise Products GP, LLC,
|
the
General Partner of Enterprise Products Partners
L.P.
|
(1)
|
The
Report fully complies with the requirements of Section 13(a) of the
Securities Exchange Act of 1934;
and
|
(2)
|
The
information contained in the Report fairly presents, in all material
respects, the financial condition and results of operations of the
Registrant.
|
/s/ W. Randall
Fowler
|
|
Name:
|
W.
Randall Fowler
|
Title:
|
Chief
Financial Officer of Enterprise Products GP, LLC
|
the
General Partner of Enterprise Products Partners
L.P.
|