epdform10k_123108.htm
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
þ ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE
SECURITIES EXCHANGE ACT OF 1934
For the
fiscal year ended December 31, 2008
OR
o TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE
SECURITIES EXCHANGE ACT OF 1934
For the
transition period from ___ to ___.
Commission
file number: 1-14323
ENTERPRISE
PRODUCTS PARTNERS L.P.
(Exact name of Registrant as
Specified in Its Charter)
Delaware
|
76-0568219
|
(State
or Other Jurisdiction of
|
(I.R.S.
Employer Identification No.)
|
Incorporation
or Organization)
|
|
|
|
|
|
1100
Louisiana, 10th Floor, Houston,
Texas 77002
|
|
|
(Address
of Principal Executive
Offices) (Zip
Code)
|
|
|
|
|
|
(713)
381-6500
|
|
|
(Registrant's
Telephone Number, Including Area Code)
|
|
Securities
registered pursuant to Section 12(b) of the Act:
Title of Each
Class
|
Name of Each Exchange
On Which Registered
|
Common
Units
|
|
Securities to be registered pursuant
to Section 12(g) of the Act: None.
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act.
Yes þ No
o
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act.
Yes o No
þ
Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days.
Yes þ
No o
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not
be contained, to the best of registrant’s knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. o
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting
company. See definitions of “large accelerated filer,” “accelerated
filer” and “smaller reporting company” in Rule 12b-2 of the Exchange
Act.
Large
accelerated filer þ
|
Accelerated
filer o
|
Non-accelerated
filer o
(Do not check if a smaller reporting company)
|
Smaller
reporting company o
|
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes o No
þ
The
aggregate market value of Enterprise Products Partners L.P.’s (or “EPD’s”)
common units held by non-affiliates at June 30, 2008 was approximately $8.44
billion based on the closing price of such equity securities in the daily
composite list for transactions on the New York Stock Exchange on June 30,
2008. This figure excludes common units beneficially owned by certain
affiliates, including Dan L. Duncan. There were 449,944,731
common units of EPD outstanding at March 2, 2009.
TABLE
OF CONTENTS
SIGNIFICANT
RELATIONSHIPS REFERENCED IN THIS
ANNUAL
REPORT
Unless the context requires otherwise,
references to “we,” “us,” “our,” or “Enterprise Products Partners” are intended
to mean the business and operations of Enterprise Products Partners L.P. and its
consolidated subsidiaries.
References to “EPO” mean Enterprise
Products Operating LLC as successor in interest by merger to Enterprise Products
Operating L.P., which is a wholly owned subsidiary of Enterprise Products
Partners through which Enterprise Products Partners conducts substantially all
of its business.
References
to “Duncan Energy Partners” mean Duncan Energy Partners L.P., which is a
consolidated subsidiary of EPO. Duncan Energy Partners is a publicly
traded Delaware limited partnership, the common units of which are listed on the
New York Stock Exchange (“NYSE”) under the ticker symbol “DEP.” References
to “DEP GP” mean DEP Holdings, LLC, which is the general partner of Duncan
Energy Partners and is wholly owned by EPO.
References
to “EPGP” mean Enterprise Products GP, LLC, which is our general
partner.
References to “Enterprise GP Holdings”
mean Enterprise GP Holdings L.P., a publicly traded affiliate, the units of
which are listed on the NYSE under the ticker symbol
“EPE.” Enterprise GP Holdings owns EPGP. References to
“EPE Holdings” mean EPE Holdings, LLC, which is the general partner of
Enterprise GP Holdings.
References
to “TEPPCO” mean TEPPCO Partners, L.P., a publicly traded affiliate, the common
units of which are listed on the NYSE under the ticker symbol
“TPP.” References to “TEPPCO GP” refer to Texas Eastern Products
Pipeline Company, LLC, which is the general partner of TEPPCO and is wholly
owned by Enterprise GP Holdings.
References
to “Energy Transfer Equity” mean the business and operations of Energy Transfer
Equity, L.P. and its consolidated subsidiaries, which include Energy Transfer
Partners, L.P. (“ETP”). Energy Transfer Equity is a publicly traded
Delaware limited partnership, the common units of which are listed on the NYSE
under the ticker symbol “ETE.” The general partner of Energy Transfer Equity is
LE GP, LLC (“LE GP”). On May 7, 2007, Enterprise GP Holdings
acquired non-controlling interests in both LE GP and Energy Transfer
Equity. Enterprise GP Holdings accounts for its investments in LE GP
and Energy Transfer Equity using the equity method of accounting.
References
to “Employee Partnerships” mean EPE Unit L.P. (“EPE Unit I”), EPE Unit II, L.P.
(“EPE Unit II”), EPE Unit III, L.P. (“EPE Unit III”), Enterprise Unit L.P.
(“Enterprise Unit”) and EPCO Unit L.P. (“EPCO Unit”), collectively, all of which
are private company affiliates of EPCO, Inc.
References
to “EPCO” mean EPCO, Inc. and its wholly owned private company affiliates, which
are related parties to all of the foregoing named entities.
We, EPO,
Duncan Energy Partners, DEP GP, EPGP, Enterprise GP Holdings, EPE Holdings,
TEPPCO and TEPPCO GP are affiliates under the common control of Dan L. Duncan,
the Group Co-Chairman and controlling shareholder of EPCO.
CAUTIONARY
STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This
annual report contains various forward-looking statements and information that
are based on our beliefs and those of our general partner, as well as
assumptions made by us and information currently available to
us. When used in this document, words such as “anticipate,”
“project,” “expect,” “plan,” “seek,” “goal,” “estimate,” “forecast,”
“intend,” “could,” “should,” “will,” “believe,” “may,” “potential” and similar
expressions and statements regarding our plans and objectives for future
operations, are intended to identify forward-looking
statements. Although we and our general partner believe that such
expectations reflected in such forward-looking statements are reasonable,
neither we nor our general partner can give any assurances that such
expectations will prove to be correct. Such statements are subject to
a variety of risks, uncertainties and assumptions as described in more detail in
Item 1A of this annual report. If one or more of these risks or
uncertainties materialize, or if underlying assumptions prove incorrect, our
actual results may vary materially from those anticipated, estimated, projected
or expected. You should not put undue reliance on any forward-looking
statements.
General
We are a
North American midstream energy company providing a wide range of services to
producers and consumers of natural gas, natural gas liquids (“NGLs”), crude oil
and certain petrochemicals. In addition, we are an industry leader in
the development of pipeline and other midstream energy infrastructure in the
continental United States and Gulf of Mexico. We conduct
substantially all of our business through EPO. Our principal
executive offices are located at 1100 Louisiana, 10th Floor,
Houston, Texas 77002, our telephone number is (713) 381-6500 and our
website is www.epplp.com.
We are a
publicly traded Delaware limited partnership formed in 1998, the common units of
which are listed on the NYSE under the ticker symbol “EPD.” We are
owned 98.0% by our limited partners and 2.0% by our general partner,
EPGP. Our general partner is owned by a publicly traded affiliate,
Enterprise GP Holdings, the common units of which are listed on the NYSE under
the ticker symbol “EPE.”
Business
Strategy
We operate an integrated network of
midstream energy assets that includes: natural gas gathering, treating,
processing, transportation and storage; NGL fractionation (or separation),
transportation, storage and import and export terminalling; crude oil
transportation; offshore production platform services; and petrochemical
transportation and services. Our business strategies are
to:
§
|
capitalize
on expected increases in natural gas, NGL and crude oil production
resulting from development activities in the Rocky Mountains, Midcontinent
and U.S. Gulf Coast regions, including the Gulf of Mexico and Barnett
Shale producing regions;
|
§
|
capitalize
on expected demand growth for natural gas, NGLs, crude oil and refined
products;
|
§
|
maintain
a diversified portfolio of midstream energy assets and expand this asset
base through growth capital projects and accretive acquisitions of
complementary midstream energy
assets;
|
§
|
share
capital costs and risks through joint ventures or alliances with strategic
partners, including those that will provide the raw materials for these
growth projects or purchase the project’s end products;
and
|
§
|
increase
fee-based cash flows by investing in pipelines and other fee-based
businesses.
|
As noted above, part of our business
strategy involves expansion through growth capital projects. We
expect that these projects will enhance our existing asset base and provide us
with additional growth opportunities in the future. For information
regarding our growth capital projects, see “Liquidity and Capital Resources -
Capital Spending” included under Item 7 of this annual report.
Financial
Information by Business Segment
For
information regarding our business segments, see Note 16 of the Notes to
Consolidated Financial Statements included under Item 8 of this annual
report. Such financial information is incorporated by reference into
this Item 1 and 2 discussion.
Recent
Developments
For
information regarding our recent developments, see “Recent Developments”
included under Item 7 of this annual report, which is incorporated by reference
into this Item 1 and 2 discussion.
Segment
Discussion
Our
midstream energy asset network links producers of natural gas, NGLs and crude
oil from some of the largest supply basins in the United States, Canada and the
Gulf of Mexico with domestic consumers and international markets. We
have four reportable business segments:
§
|
NGL
Pipelines & Services;
|
§
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Onshore
Natural Gas Pipelines &
Services;
|
§
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Offshore
Pipelines & Services; and
|
§
|
Petrochemical
Services.
|
Our business segments are generally
organized and managed according to the type of services rendered (or
technologies employed) and products produced and/or sold.
The
following sections present an overview of our business segments, including
information regarding the principal products produced, services rendered,
seasonality, competition and regulation. Our results of operations
and financial condition are subject to a variety of risks. For
information regarding our key risk factors, see Item 1A of this annual
report.
Our business activities are subject to
various federal, state and local laws and regulations governing a wide variety
of topics, including commercial, operational, environmental, safety and other
matters. For a discussion of the principal effects such laws and
regulations have on our business, see “Regulation” and “Environmental and Safety
Matters” included within this Item 1 and 2.
Our revenues are derived from a wide
customer base. During 2008 our largest customer was LyondellBasell
Industries (“LBI”) and its affiliates, which accounted for 9.6% of our
consolidated revenues. In 2007 and 2006, our largest customer was The
Dow Chemical Company and its affiliates, which accounted for 6.9% and 6.1%,
respectively, of our consolidated revenues.
On January 6, 2009, LBI announced that
its U.S. operations had voluntarily filed to reorganize under Chapter 11 of the
U.S. Bankruptcy Code. At the time of the bankruptcy filing, we had
approximately $17.3 million of credit exposure to LBI, which was reduced to
approximately $10.0 million through remedies provided under certain pipeline
tariffs. In addition, we are seeking to have LBI accept certain
contracts and have filed claims pursuant to current Bankruptcy Court Orders that
we expect will allow us to recover the majority of the remaining credit
exposure.
For 2008,
LBI accounted for 10.2%, or $1.6 billion, of revenues attributable to our NGL
Pipelines & Services business segment and 19.2%, or $516.2 million, of
revenues attributable to our Petrochemical Services business
segment.
As
generally used in the energy industry and in this document, the identified terms
have the following meanings:
/d
|
=
per day
|
BBtus
|
=
billion British thermal units
|
Bcf
|
=
billion cubic feet
|
MBPD
|
=
thousand barrels per day
|
MMBbls
|
=
million barrels
|
MMBtus
|
=
million British thermal units
|
MMcf
|
=
million cubic feet
|
The following discussion of our
business segments provides information regarding our principal plants, pipelines
and other assets. For information regarding our results of
operations, including significant measures of historical throughput, production
and processing rates, see Item 7 of this annual report.
NGL
Pipelines & Services
Our NGL
Pipelines & Services business segment includes our (i) natural gas
processing business and related NGL marketing activities, (ii) NGL pipelines
aggregating approximately 14,322 miles including our 7,808-mile Mid-America
Pipeline System, (iii) NGL and related product storage facilities and (iv) NGL
fractionation facilities located in Texas and Louisiana. This segment
also includes our import and export terminal operations.
NGL
products (ethane, propane, normal butane, isobutane and natural gasoline) are
used as raw materials by the petrochemical industry, as feedstocks by refiners
in the production of motor gasoline and by industrial and residential users as
fuel. Ethane is primarily used in the petrochemical industry as a
feedstock for ethylene production, one of the basic building blocks for a wide
range of plastics and other chemical products. Propane is used both as a
petrochemical feedstock in the production of ethylene and propylene and as a
heating, engine and industrial fuel. Normal butane is used as a
petrochemical feedstock in the production of ethylene and butadiene (a key
ingredient of synthetic rubber), as a blendstock for motor gasoline and to
derive isobutane through isomerization. Isobutane is fractionated
from mixed butane (a mixed stream of normal butane and isobutane) or produced
from normal butane through the process of isomerization, principally for use in
refinery alkylation to enhance the octane content of motor gasoline, in the
production of isooctane and other octane additives and in the production of
propylene oxide. Natural gasoline, a mixture of pentanes and heavier
hydrocarbons, is primarily used as a blendstock for motor gasoline or as a
petrochemical feedstock.
Natural
gas processing and related NGL marketing activities. At the core of
our natural gas processing business are 24 processing plants located in
Colorado, Louisiana, Mississippi, New Mexico, Texas
and Wyoming. Natural gas produced at the wellhead especially in
association with crude oil contains varying amounts of NGLs. This
“rich” natural gas in its raw form is usually not acceptable for transportation
in the nation’s major natural gas pipeline systems or for commercial use as a
fuel. Natural gas processing plants remove the NGLs from the natural
gas stream, enabling the natural gas to meet pipeline and commercial quality
specifications. In addition, on an energy equivalent basis, NGLs
generally have a greater economic value as a raw material for petrochemical and
motor gasoline production than their value as components of the natural gas
stream. After extraction, we typically transport the mixed NGLs to a
centralized facility for fractionation (or separation) into purity NGL products
such as ethane, propane, normal butane, isobutane and natural
gasoline. The purity NGL products can then be used in our NGL
marketing activities to meet contractual requirements or sold on spot and
forward markets.
When
operating and extraction costs of natural gas processing plants are higher than
the incremental value of the NGL products that would be extracted, the recovery
levels of certain NGL
products,
principally ethane, may be reduced or eliminated. This leads to a
reduction in NGL volumes available for transportation and
fractionation.
In our natural gas processing
activities, we enter into margin-band contracts, percent-of-liquids contracts,
percent-of-proceeds contracts, fee-based contracts, hybrid contracts (a
combination of percent-of-liquids and fee-based contract terms) and keepwhole
contracts. Under margin-band and keepwhole contracts, we take
ownership of mixed NGLs extracted from the producer’s natural gas stream and
recognize revenue when the extracted NGLs are delivered and sold to customers on
NGL marketing sales contracts. In the same way, revenue is recognized
under our percent-of-liquids contracts except that the volume of NGLs we earn
and sell is less than the total amount of NGLs extracted from the producers’
natural gas. Under a percent-of-liquids contract, the producer
retains title to the remaining percentage of mixed NGLs we extract and generally
bears the natural gas cost for shrinkage and plant fuel. Under a
percent-of-proceeds contract, we share in the proceeds generated from the sale
of the mixed NGLs we extract on the producer’s behalf. If a cash fee
for natural gas processing services is stipulated by the contract, we record
revenue when the natural gas has been processed and delivered to the
producer. The NGL volumes we earn and take title to in connection
with our processing activities are referred to as our equity NGL
production.
In
general, our percent-of-liquids, hybrid and keepwhole contracts give us the
right (but not the obligation) to process natural gas for a producer; thus, we
are protected from processing at an economic loss during times when the sum of
our costs exceeds the value of the mixed NGLs of which we would take
ownership. Generally, our natural gas processing agreements have
terms ranging from month-to-month to life of the producing
lease. Intermediate terms of one to ten years are also
common.
To the
extent that we are obligated under our margin-band and keepwhole gas processing
contracts to compensate the producer for the natural gas equivalent energy value
of mixed NGLs we extract from the natural gas stream, we are exposed to various
risks, primarily commodity price fluctuations. However, our margin band
contracts contain terms which limit our exposure to such risks. The
prices of natural gas and NGLs are subject to fluctuations in response to
changes in supply, market uncertainty and a variety of additional factors that
are beyond our control. Periodically, we attempt to mitigate these
risks through the use of commodity financial instruments. For
information regarding our use of commodity financial instruments, see “Commodity
Risk Hedging Program” included under Item 7A of this annual report.
Our NGL marketing activities generate
revenues from the sale and delivery of NGLs obtained through our processing
activities and purchases from third parties on the open market. These
sales contracts may also include forward product sales contracts. In
general, the sales prices referenced in these contracts are market-related and
can include pricing differentials for such factors as delivery
location.
NGL
pipelines, storage facilities and import/export terminals. Our NGL pipeline,
storage and terminalling operations include approximately 14,322 miles of NGL
pipelines, 157.2 MMBbls of working capacity of NGL and related product storage
and two import/export facilities.
Our NGL
pipelines transport mixed NGLs and other hydrocarbons from natural gas
processing facilities, refineries and import terminals to fractionation plants
and storage facilities; distribute and collect NGL products to and from
fractionation plants, petrochemical plants and refineries; and deliver propane
to customers along the Dixie Pipeline and certain sections of the Mid-America
Pipeline System. Revenue from our NGL pipeline transportation
agreements is generally based upon a fixed fee per gallon of liquids transported
multiplied by the volume delivered. Accordingly, the results of
operations for this business are generally dependent upon the volume of product
transported and the level of fees charged to customers (including those charged
to our NGL and petrochemical marketing activities, which are eliminated in
consolidation). The transportation fees charged under these
arrangements are either contractual or regulated by governmental agencies,
including the Federal Energy Regulatory Commission
(“FERC”). Typically, we do not take title to the products transported
by our NGL pipelines; rather, the shipper retains title and the associated
commodity price risk.
Our NGL and related product storage
facilities are integral parts of our operations. In general, our
underground storage wells are used to store our and our customers’ mixed NGLs,
NGL products and petrochemical products. Under our NGL and related
product storage agreements, we charge customers monthly storage reservation fees
to reserve storage capacity in our underground caverns. The customers
pay reservation fees based on the quantity of capacity reserved rather than the
actual quantity utilized. When a customer exceeds its reserved
capacity, we charge those customers an excess storage fee. In
addition, we charge our customers throughput fees based on volumes injected and
withdrawn from the storage facility. Accordingly, the profitability
of our storage operations is dependent upon the level of capacity reserved by
our customers, the volume of product injected and withdrawn from our underground
caverns and the level of fees charged.
We
operate NGL import and export facilities located on the Houston Ship Channel in
southeast Texas. Our import facility is primarily used to offload
volumes for delivery to our NGL storage and fractionation facilities near Mont
Belvieu, Texas. Our export facility includes an NGL products chiller and
related equipment used for loading refrigerated marine tankers for third-party
export customers. Revenues from our import and export services are
primarily based on fees per unit of volume loaded or unloaded and may also
include demand payments. Accordingly, the profitability of our import
and export activities primarily depends on the available quantities of NGLs to
be loaded and offloaded and the fees we charge for these services.
NGL
fractionation.
We own or have interests in eight NGL fractionation facilities located in
Texas and Louisiana. NGL fractionation facilities separate mixed NGL
streams into purity NGL products. The three primary sources of mixed NGLs
fractionated in the United States are (i) domestic natural gas processing
plants, (ii) domestic crude oil refineries and (iii) imports of butane and
propane mixtures. The mixed NGLs delivered from domestic natural gas
processing plants and crude oil refineries to our NGL fractionation facilities
are typically transported by NGL pipelines and, to a lesser extent, by railcar
and truck.
Mixed
NGLs extracted by domestic natural gas processing plants represent the largest
source of volumes processed by our NGL fractionators. Based upon industry
data, we believe that sufficient volumes of mixed NGLs, especially those
originating from Gulf Coast, Rocky Mountain and Midcontinent natural gas
processing plants, will be available for fractionation in commercially viable
quantities for the foreseeable future. Significant volumes of mixed NGLs are
contractually committed to our NGL fractionation facilities by joint owners and
third-party customers.
The majority of our NGL fractionation
facilities process mixed NGL streams for third-party customers and support our
NGL marketing activities under fee-based arrangements. These fees
(typically in cents per gallon) are subject to adjustment for changes in certain
fractionation expenses, including natural gas fuel costs. At our
Norco facility, we perform fractionation services for certain customers under
percent-of-liquids contracts. The results of operations of our NGL
fractionation business are dependent upon the volume of mixed NGLs fractionated
and either the level of fractionation fees charged (under fee-based contracts)
or the value of NGLs received (under percent-of-liquids arrangements). Our
fee-based customers generally retain title to the NGLs that we process for them;
however, we are exposed to fluctuations in NGL prices (i.e., commodity price
risk) to the extent we fractionate volumes for customers under
percent-of-liquids arrangements. Periodically, we attempt to mitigate these
risks through the use of commodity financial instruments. For
information regarding our use of commodity financial instruments, see “Commodity
Risk Hedging Program” included under Item 7A of this annual report.
Seasonality. Our natural gas processing
and NGL fractionation operations exhibit little to no seasonal
variation. Likewise, our NGL pipeline operations have not exhibited a
significant degree of seasonality overall. However, propane transportation
volumes are generally higher in the October through March timeframe in
connection with increased use of propane for heating in the upper Midwest and
southeastern United States. Our facilities located in the southern
United States may be affected by weather events such as hurricanes and tropical
storms originating in the Gulf of Mexico.
We
operate our NGL and related product storage facilities based on the needs and
requirements of our customers in the NGL, petrochemical, heating and other
related industries. We usually experience an increase in the demand
for storage services during the spring and summer months due to increased
feedstock storage requirements for motor gasoline production and a decrease
during the fall and winter months when propane inventories are being drawn for
heating needs. In general, our import volumes peak during the spring and
summer months and our export volumes are at their highest levels during the
winter months.
In
support of our commercial goals, our NGL marketing activities rely on
inventories of mixed NGLs and purity NGL products. These inventories
are the result of accumulated equity NGL production volumes, imports and other
spot and contract purchases. Our inventories of ethane, propane and
normal butane are typically higher on a seasonal basis from March through
November as each are normally in higher demand and at higher price levels during
winter months. Isobutane and natural gasoline inventories are
generally stable throughout the year. Generally, our inventory cycle
begins in late-February to mid-March (the seasonal low point), builds through
September, and remains level until early December before being drawn
through winter until the seasonal low is reached again.
Competition. Our
natural gas processing business and NGL marketing activities encounter
competition from fully integrated oil companies, intrastate pipeline companies,
major interstate pipeline companies and their non-regulated affiliates, and
independent processors. Each of our competitors has varying levels of
financial and personnel resources, and competition generally revolves around
price, service and location.
In the
markets served by our NGL pipelines, we compete with a number of intrastate and
interstate liquids pipelines companies (including those affiliated with major
oil, petrochemical and gas companies) and barge, rail and truck fleet
operations. In general, our NGL pipelines compete with these entities
in terms of transportation fees and service.
Our
competitors in the NGL and related product storage businesses are integrated
major oil companies, chemical companies and other storage and pipeline
companies. We compete with other storage service providers primarily in
terms of the fees charged, number of pipeline connections and operational
dependability. Our import and export operations also compete with those
operated by major oil and chemical companies primarily in terms of loading and
offloading volumes per hour.
We
compete with a number of NGL fractionators in Texas, Louisiana and
Kansas. Although competition for NGL fractionation services is
primarily based on the fractionation fee charged, the ability of an NGL
fractionator to receive mixed NGLs, store and distribute NGL products is also an
important competitive factor and is a function of the existence of the necessary
pipeline and storage infrastructure.
Properties. The following table
summarizes the significant natural gas processing assets of our NGL Pipelines
& Services business segment at February 2, 2009.
|
|
|
|
|
Net
Gas
|
|
Total
Gas
|
|
|
|
|
Our
|
|
Processing
|
|
Processing
|
|
|
|
|
Ownership
|
|
Capacity
|
|
Capacity
|
|
Description
of Asset
|
Location(s)
|
|
Interest
|
|
(Bcf/d)
(1)
|
|
(Bcf/d)
|
|
Natural
gas processing facilities:
|
|
|
|
|
|
|
|
|
Meeker
(2)
|
Colorado
|
|
100.0%
|
|
|
1.40 |
|
|
1.40 |
|
Pioneer
(3)
|
Wyoming
|
|
100.0%
|
|
|
1.30 |
|
|
1.30 |
|
Toca
|
Louisiana
|
|
67.4%
|
|
|
0.70 |
|
|
1.10 |
|
Chaco
|
New
Mexico
|
|
100.0%
|
|
|
0.65 |
|
|
0.65 |
|
North
Terrebonne
|
Louisiana
|
|
52.5%
|
|
|
0.63 |
|
|
1.30 |
|
Calumet
|
Louisiana
|
|
32.7%
|
|
|
0.51 |
|
|
1.60 |
|
Neptune
|
Louisiana
|
|
66.0%
|
|
|
0.43 |
|
|
0.65 |
|
Pascagoula
|
Mississippi
|
|
40.0%
|
|
|
0.40 |
|
|
1.50 |
|
Yscloskey
|
Louisiana
|
|
14.6%
|
|
|
0.34 |
|
|
1.85 |
|
Thompsonville
|
Texas
|
|
100.0%
|
|
|
0.30 |
|
|
0.30 |
|
Shoup
|
Texas
|
|
100.0%
|
|
|
0.29 |
|
|
0.29 |
|
Gilmore
|
Texas
|
|
100.0%
|
|
|
0.26 |
|
|
0.26 |
|
Armstrong
|
Texas
|
|
100.0%
|
|
|
0.25 |
|
|
0.25 |
|
Others
(10 facilities) (4)
|
Texas,
New Mexico, Louisiana
|
|
Various
(5)
|
|
|
1.19 |
|
|
2.85 |
|
Total
processing capacities
|
|
|
|
|
|
|
8.65 |
|
|
15.30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
The
approximate net natural gas processing capacity does not necessarily
correspond to our ownership interest in each facility. It is based on
a variety of factors such as volumes processed at the facility and
ownership interest in the facility.
(2)
We
commenced natural gas processing operations at our Meeker facility in
October 2007 and subsequently began the Meeker Phase II expansion project
to double the natural gas processing capacity to 1.4 Bcf/d at this
facility. The Meeker Phase II expansion is expected to be operational
during the first quarter of 2009.
(3)
We
acquired a silica gel natural gas processing facility from TEPPCO in March
2006 and subsequently increased the processing capacity from 0.3 Bcf/d to
0.6 Bcf/d. In addition, we constructed a new cryogenic processing
facility having 0.7 Bcf/d of processing capacity, which became operational
in February 2008.
(4)
Includes
our Venice, Sea Robin and Burns Point facilities located in Louisiana;
Indian Basin and Carlsbad facilities located in New Mexico; and San
Martin, Delmita, Sonora, Shilling and Indian Springs facilities located in
Texas. Our ownership in the Venice plant is through our 13.1% equity
method investment in Venice Energy Services Company, L.L.C.
(“VESCO”).
(5)
Our
ownership in these facilities ranges from 13.1% to
100.0%.
|
|
At the core of our natural gas
processing business are 24 processing plants located in Colorado, Louisiana,
Mississippi, New Mexico, Texas and Wyoming. Our natural gas
processing facilities can be characterized as two distinct types: (i) straddle
plants situated on mainline natural gas pipelines owned either by us or by third
parties or (ii) field plants that process natural gas from gathering
pipelines. We operate the Meeker, Pioneer, Toca, Chaco, North
Terrebonne, Calumet, Neptune, Burns Point and Carlsbad plants and all of the
Texas facilities. On a weighted-average basis, utilization rates
for these assets were 66.4%, 66.4%, and 56.0% during the years ended December
31, 2008, 2007 and 2006, respectively. These rates reflect the
periods in which we owned an interest in such facilities.
Our NGL marketing activities utilize a
fleet of approximately 730 railcars, the majority of which are
leased. These railcars are used to deliver feedstocks to our
facilities and to distribute NGLs throughout the United States and parts of
Canada. We have rail loading and unloading facilities in Alabama,
Arizona, California, Kansas, Louisiana, Minnesota, Mississippi, Nevada, North
Carolina and Texas. These facilities service both our rail shipments
and those of our customers.
The
following table summarizes the significant NGL pipelines and related storage
assets of our NGL Pipelines & Services business segment at February 2,
2009.
|
|
|
|
|
Useable
|
|
|
|
Our
|
|
Storage
|
|
|
|
Ownership
|
Length
|
Capacity
|
Description
of Asset
|
Location(s)
|
Interest
|
(Miles)
|
(MMBbls)
|
NGL
pipelines:
|
|
|
|
|
|
Mid-America
Pipeline System
|
Midwest
and Western U.S.
|
100.0%
|
7,808
|
|
|
Dixie
Pipeline
|
South
and Southeastern U.S.
|
100.0%
(1)
|
1,371
|
|
|
Seminole
Pipeline
|
Texas
|
90.0%
(2)
|
1,342
|
|
|
EPD
South Texas NGL System
|
Texas
|
100.0%
(3)
|
1,020
|
|
|
Louisiana
Pipeline System
|
Louisiana
|
Various
(4)
|
612
|
|
|
Skelly-Belvieu
Pipeline
|
Texas
|
49.0%
(5)
|
570
|
|
|
Promix
NGL Gathering System
|
Louisiana
|
50.0%
|
364
|
|
|
DEP
South Texas NGL Pipeline System
|
Texas
|
100.0%
(3)
|
297
|
|
|
Houston
Ship Channel
|
Texas
|
100.0%
|
252
|
|
|
Lou-Tex
NGL
|
Texas,
Louisiana
|
100.0%
|
205
|
|
|
Others
(6 systems) (6)
|
Various
|
Various
|
481
|
|
|
Total
miles
|
|
|
14,322
|
|
NGL
and related product storage facilities by state:
|
|
|
|
|
Texas
(7)
|
124.7
|
|
Louisiana
|
|
|
|
15.3
|
|
Kansas
|
|
|
|
7.5
|
|
Mississippi
|
|
|
|
5.7
|
|
Others
(Arizona, Georgia, Iowa, Kansas, Nebraska, North Carolina,
Oklahoma)
|
|
|
4.0
|
|
Total
capacity (8)
|
|
|
|
157.2
|
|
|
|
|
|
|
(1)
We
acquired the remaining 25.8% ownership interest in this system during
August 2008 and now own 100.0% of the Dixie Pipeline through our
subsidiary, Dixie Pipeline Company (“Dixie”).
(2)
We
hold a 90.0% interest in this system through a majority owned subsidiary,
Seminole Pipeline Company (“Seminole”).
(3)
Reflects
consolidated ownership of these systems by EPO (34.0%) and Duncan Energy
Partners (66.0%).
(4)
Of
the 612 total miles for this system, we own 100.0% of 559 miles and 52.5%
of the remaining 53 miles.
(5)
Our
ownership interest in this pipeline is held indirectly through our equity
method investment in Skelly-Belvieu Pipeline Company, L.L.C.
(“Skelly-Belvieu”), which we acquired in December
2008.
(6)
Includes
our Tri-States, Belle Rose, Wilprise, Chunchula and Bay Area pipelines
located in the coastal regions of Alabama, Louisiana, Mississippi and
Texas and our Meeker pipeline in Colorado. We acquired the
remaining 16.7% ownership interest in Belle Rose NGL Pipeline, L.L.C. and
an additional 16.7% interest in Tri-States NGL Pipeline, L.L.C. in October
2008.
(7)
The
amount shown for Texas includes 33 underground NGL and petrochemical
storage caverns with an aggregate useable storage capacity of
approximately 100 MMBbls that we own jointly with Duncan Energy
Partners. These caverns are located in Mont Belvieu,
Texas.
(8)
The
157.2 MMBbls of total useable storage capacity includes 22.4 MMBbls held
under long-term operating leases. The leased facilities are
located in Texas, Louisiana and
Kansas.
|
The maximum number of barrels that our
NGL pipelines can transport per day depends upon the operating balance achieved
at a given point in time between various segments of the
systems. Since the operating balance is dependent upon the mix of
products to be shipped and demand levels at various delivery points, the exact
capacities of our NGL pipelines cannot be determined. We measure the
utilization rates of such pipelines in terms of net throughput (i.e., on a net
basis in accordance with our consolidated ownership interest). Total
net throughput volumes for these pipelines were 1,747 MBPD, 1,583 MBPD and 1,450
MBPD during the years ended December 31, 2008, 2007 and 2006,
respectively.
The
following information highlights the general use of each of our principal NGL
pipelines. We operate our NGL pipelines with the exception of
Skelly-Belvieu Pipeline, Tri-States and a small portion of the Louisiana
Pipeline System.
§
|
The
Mid-America Pipeline System is a
regulated NGL pipeline system consisting of three primary segments: the
2,785-mile Rocky Mountain pipeline, the 2,771-mile Conway North
pipeline and the 2,252-mile Conway South pipeline. This system
covers thirteen 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. During 2007, the Rocky Mountain pipeline’s capacity was
increased by 50 MBPD. 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, which completed
an expansion in 2007, 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. We also own
fifteen unregulated propane terminals that are an integral part of the
Mid-America Pipeline System.
During
2008, approximately 52.0% of the volumes transported on the Mid-America Pipeline
System were mixed NGLs originating from natural gas processing plants located in
the Permian Basin in west Texas, the Hugoton Basin of southwestern Kansas, the
San Juan Basin of northwest New Mexico, the Piceance Basin of Colorado, the
Uintah Basin of Colorado and Utah and the Greater Green River Basin of
southwestern Wyoming. The remaining volumes are generally purity NGL
products originating from NGL fractionators in the mid-continent areas of
Kansas, Oklahoma, and Texas, as well as deliveries from Canada.
§
|
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, southern Louisiana and
Mississippi. This system operates in seven
states: Texas, Louisiana, Mississippi, Alabama, Georgia, South
Carolina and North Carolina.
|
§
|
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 southeastern
Texas. NGLs originating on the Mid-America Pipeline System are
the primary source of throughput for the Seminole
Pipeline.
|
§
|
The
EPD South Texas NGL System is a
network of NGL gathering and transportation pipelines located in south
Texas. The system includes approximately 380 miles of pipeline
used to gather and transport mixed NGLs from our south Texas natural gas
processing facilities to our south Texas NGL fractionation
facilities. The pipeline system also includes approximately 640
miles of pipelines that deliver NGLs from our south Texas fractionation
facilities to refineries and petrochemical plants located
between Corpus Christi and Houston, Texas and within the
Texas City-Houston area, as well as to common carrier NGL
pipelines.
|
We
contributed a 66.0% equity interest in Enterprise GC, LP (“Enterprise GC”), our
subsidiary that owns the EPD South Texas NGL Pipeline, to Duncan Energy Partners
effective December 8, 2008. We own, through our other subsidiaries,
the remaining 34.0% equity interest in Enterprise GC. For additional
information regarding this transaction, see “Other Items – Duncan Energy
Partners Transactions” included under Item 7 of this annual report.
§
|
The
Louisiana Pipeline
System is a network of NGL pipelines located in
Louisiana. This system transports NGLs originating in southern
Louisiana and in Texas to refineries and petrochemical companies
along the Mississippi River corridor in southern Louisiana. This
system also provides transportation services for our natural gas
processing plants, NGL fractionators and other facilities located in
Louisiana.
|
§
|
The
Skelly-Belvieu
Pipeline is a regulated pipeline that transports mixed NGLs from
Skellytown, Texas to markets in southeast Texas. Volumes
originating on the Mid-America Pipeline System and NGLs produced at local
refineries are the primary source of throughput for the Skelly-Belvieu
Pipeline.
|
§
|
The
Promix NGL Gathering
System is a NGL pipeline system that gathers mixed NGLs from
natural gas processing plants in Louisiana for delivery to an NGL
fractionator owned by K/D/S
|
Promix, L.L.C. (“Promix”). This gathering system is an
integral part of the Promix NGL fractionation facility. Our ownership
interest in this pipeline is held indirectly through our equity method
investment in Promix.
§
|
The
DEP South Texas NGL
Pipeline
System transports NGLs from our Shoup and Armstrong fractionation
facilities in south Texas to Mont Belvieu,
Texas.
|
§
|
The
Houston Ship
Channel pipeline system is a collection of pipelines
interconnecting our Mont Belvieu 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. This system is used to deliver NGL products to
third-party petrochemical plants and refineries as well as to deliver
feedstocks to our Mont Belvieu
facilities.
|
§
|
The
Lou-Tex NGL
pipeline system is used to provide transportation services for NGLs and
refinery grade propylene between the Louisiana and Texas markets. We also
use this pipeline to transport mixed NGLs from Mont Belvieu to our
Louisiana Pipeline System.
|
Our NGL and related product storage
facilities are integral parts of our pipeline and other
operations. In general, these underground storage facilities are used
to store NGLs and petrochemical products for us and our customers. We
operate these facilities, with the exception of certain Louisiana storage
locations operated for us by a third party.
Duncan Energy Partners, one of our
consolidated subsidiaries, owns a 66.0% equity interest in our subsidiary, Mont
Belvieu Caverns, LLC (“Mont Belvieu Caverns”). We own, through
our other subsidiaries, the remaining 34.0% equity interest in Mont Belvieu
Caverns. Mont Belvieu Caverns owns 33 underground NGL and
petrochemical storage caverns with an aggregate storage capacity of
approximately 100 MMBbls, a brine system with approximately 20 MMBbls of
above-ground brine storage pit capacity and two brine production
wells. These assets store and deliver NGLs (such as ethane and
propane) and certain refined and petrochemical products for industrial customers
located along the upper Texas Gulf Coast.
The following table summarizes the
significant NGL fractionation assets of our NGL Pipelines & Services
business segment at February 2, 2009.
|
|
|
|
Net
|
Total
|
|
|
|
Our
|
Plant
|
Plant
|
|
|
|
Ownership
|
Capacity
|
Capacity
|
Description
of Asset
|
Location(s)
|
Interest
|
(MBPD)
(1)
|
(MBPD)
|
NGL
fractionation facilities:
|
|
|
|
|
|
Mont
Belvieu
|
Texas
|
75.0%
|
178
|
230
|
|
Shoup
and Armstrong
|
Texas
|
100.0%
(2)
|
87
|
87
|
|
Hobbs
|
Texas
|
100.0%
|
75
|
75
|
|
Norco
|
Louisiana
|
100.0%
|
75
|
75
|
|
Promix
|
Louisiana
|
50.0%
|
73
|
145
|
|
BRF
|
Louisiana
|
32.2%
|
19
|
60
|
|
Tebone
|
Louisiana
|
52.5%
|
12
|
30
|
|
Total
plant capacities
|
|
|
519
|
702
|
|
|
|
|
|
|
(1)
The
approximate net NGL fractionation capacity does not necessarily correspond
to our ownership interest in each facility. It is based on a
variety of factors such as volumes processed at the facility and ownership
interest in the facility.
(2)
Reflects
consolidated ownership of these fractionators by EPO (34.0%) and Duncan
Energy Partners (66.0%).
|
The
following information highlights the general use of each of our principal NGL
fractionation facilities. We operate all of our NGL fractionation
facilities.
§
|
Our
Mont Belvieu NGL
fractionation facility is located at Mont Belvieu, Texas, which is a
key hub of the domestic and international 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.
|
§
|
Our
Shoup and Armstrong NGL
fractionation facilities fractionate mixed NGLs supplied by our south
Texas natural gas processing plants. In turn, the Shoup and
Armstrong facilities supply NGLs transported by the DEP South Texas NGL
Pipeline System.
|
We
contributed a 66.0% equity interest in Enterprise GC, our subsidiary that owns
the Shoup and Armstrong NGL fractionators, to Duncan Energy Partners effective
December 8, 2008. We own through our other subsidiaries the remaining
34.0% equity interest in Enterprise GC. For additional information
regarding this transaction, see “Other Items – Duncan Energy Partners
Transactions” included under Item 7 of this annual report.
§
|
Our
Hobbs NGL
fractionation facility is located in Gaines County, Texas, where it serves
petrochemical end users and refineries in West Texas, New Mexico and
California. In addition, the Hobbs facility can supply exports
to northern Mexico through existing third-party pipeline
infrastructure. 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 strategically
located at the interconnect of our Mid-America Pipeline System and
Seminole Pipeline, providing us 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.
|
§
|
Our
Norco NGL
fractionation facility receives mixed NGLs via pipeline from refineries
and natural gas processing plants located in southern Louisiana and along
the Mississippi and Alabama Gulf Coast, including our Yscloskey,
Pascagoula, Venice and Toca
facilities.
|
§
|
The
Promix NGL
fractionation facility receives mixed NGLs via pipeline from natural gas
processing plants located in southern Louisiana and along the Mississippi
Gulf Coast, including our Calumet, Neptune, Burns Point and Pascagoula
facilities. In addition to the 364-mile Promix NGL Gathering
System, Promix owns five NGL storage caverns and a barge loading facility
that are integral to its
operations.
|
§
|
The
BRF facility
fractionates mixed NGLs from natural gas processing plants located in
Alabama, Mississippi and southern
Louisiana.
|
On a weighted-average basis,
utilization rates for our NGL fractionators were 83.3%, 77.7% and 72.2% during
the years ended December 31, 2008, 2007 and 2006, respectively. These
rates reflect the periods in which we owned an interest in such
facilities. We own direct consolidated interests in all of our NGL
fractionation facilities with the exception of a 50.0% interest in the facility
owned by Promix and a 32.2% interest in the facility owned by Baton Rouge
Fractionators LLC (“BRF”).
Our NGL operations include import and
export facilities located on the Houston Ship Channel in southeast
Texas. We own an import and export facility located on land we lease
from Oiltanking Houston LP (“OTTI”). Our OTTI import facility can
offload NGLs from tanker vessels at rates up to 20,000 barrels per hour
depending on the product. Our OTTI export facility can load cargoes
of refrigerated propane and butane onto tanker vessels at rates up to 6,700
barrels per hour. In addition to our OTTI facilities, we own a barge
dock that can load or offload two barges of NGLs or refinery-grade propylene
simultaneously at rates up to 5,000 barrels per hour. Our average
combined NGL import and export volumes were 74 MBPD, 84 MBPD and 127 MBPD for
the years ended December 31, 2008, 2007 and 2006, respectively.
Onshore
Natural Gas Pipelines & Services
Our
Onshore Natural Gas Pipelines & Services business segment includes
approximately 18,346 miles of onshore natural gas pipeline systems that provide
for the gathering and transmission of natural gas in Alabama, Colorado,
Louisiana, Mississippi, New Mexico, Texas and Wyoming. We
own two salt dome natural gas storage facilities located in Mississippi and
lease natural gas storage facilities located in Texas and
Louisiana. This segment also includes our natural gas marketing
activities.
Onshore
natural gas pipelines and
related natural gas marketing. Our onshore natural gas
pipeline systems provide for the gathering and transmission of natural gas from
onshore developments, such as the San Juan, Barnett Shale, Permian, Piceance and
Greater Green River supply basins in the Western U.S., and from offshore
developments in the Gulf of Mexico through connections with offshore
pipelines. Typically, these systems receive natural gas from
producers, other pipelines or shippers through system interconnects and
redeliver the natural gas to processing facilities, local gas distribution
companies, industrial or municipal customers or to other onshore
pipelines.
Certain of our onshore natural gas
pipelines generate revenues from transportation agreements where shippers are
billed a fee per unit of volume transported (typically in MMBtus) multiplied by
the volume delivered. The transportation fees charged under these
arrangements are either contractual or regulated by governmental agencies,
including the FERC. Certain of our onshore natural gas pipelines may also
offer firm capacity reservation services whereby the shipper pays a
contractually stated fee based on the level of capacity reserved in our
pipelines whether or not the shipper actually ships the reserved quantity of
natural gas. Intrastate natural gas pipelines (such as our Acadian Gas and
Alabama Intrastate systems) may also purchase natural gas from producers and
suppliers and resell such natural gas to customers such as electric utility
companies, local natural gas distribution companies and industrial
customers.
We
entered the natural gas marketing business in 2001 when we acquired the Acadian
Gas System. In 2007, we initiated an expansion of this marketing
business to maximize the utilization of our portfolio of natural gas pipeline
and storage assets. Our natural gas marketing activities generate
revenues from the sale and delivery of natural gas obtained from (i) third party
well-head purchases, (ii) our natural gas processing plants and (iii) the open
market. In general, our natural gas sales contracts utilize
market-based pricing and can incorporate pricing differentials for factors such
as delivery location. We expect our natural gas marketing business to
continue to expand in the future. Our consolidated revenues from this
business were $3.10 billion, $1.48 billion and $1.10 billion for the years ended
December 31, 2008, 2007 and 2006, respectively.
We are
exposed to commodity price risk to the extent that we take title to natural gas
volumes through our natural gas marketing activities or through certain
contracts on our intrastate natural gas pipelines. In addition, our
San Juan, Carlsbad and Jonah Gathering Systems and certain segments of our
Texas Intrastate System provide aggregating and bundling services, in which we
purchase and resell natural gas for certain small producers. Also,
several of our gathering systems, while not providing marketing services, have
some exposure to risks related to commodity prices through transportation
arrangements with shippers. For example, revenues generated by
approximately 94.0% of the natural gas volumes gathered on our San Juan
Gathering System are calculated using a percentage of a regional price index for
natural gas. We use commodity financial instruments from time to time
to mitigate our exposure to risks related to commodity prices. For
information regarding our use of commodity financial instruments, see “Commodity
Risk Hedging Program” included under Item 7A of this annual report.
Underground
natural gas storage. We own two underground salt dome natural gas
storage facilities located near Hattiesburg, Mississippi that are ideally
situated to serve the domestic Northeast, Mid-Atlantic and Southeast natural gas
markets. On a combined basis, these facilities (our Petal Gas Storage
(“Petal”) and Hattiesburg Gas Storage (“Hattiesburg”) locations) are capable of
delivering in excess of 1.4 Bcf/d of natural gas into five interstate pipeline
systems. We also lease underground salt dome natural gas storage caverns
that serve markets in Texas and Louisiana.
The ability of salt dome storage
caverns to handle high levels of injections and withdrawals of natural gas
benefits customers who desire the ability to meet load swings and to cover major
supply interruption events, such as hurricanes and temporary losses of
production. High injection and withdrawal rates also allow
customers to take advantage of periods of volatile natural gas prices and
respond in situations where they have natural gas imbalance issues on pipelines
connected to the storage facilities. Our salt dome storage facilities
permit sustained periods of high natural gas deliveries, including the ability
to quickly switch from full injection to full withdrawal.
Under our natural gas storage
contracts, there are typically two components of revenues: (i) monthly
demand payments, which are associated with storage capacity reservation and paid
regardless of the customer’s usage, and (ii) storage fees per unit of volume
stored at our facilities.
Seasonality. Typically, our onshore
natural gas pipelines experience higher throughput rates during the summer
months as natural gas-fired power generation facilities increase output to meet
residential and commercial demand for electricity for air
conditioning. Higher throughput rates are also experienced in the
winter months as natural gas is needed to fuel residential and commercial
heating. Likewise, this seasonality also impacts the timing of
injections and withdrawals at our natural gas storage facilities.
Competition. Within their market areas,
our onshore natural gas pipelines compete with other onshore natural gas
pipelines on the basis of price (in terms of transportation fees and/or natural
gas selling prices), service and flexibility. Our competitive
position within the onshore market is enhanced by our longstanding relationships
with customers and the limited number of delivery pipelines connected (or
capable of being economically connected) to the customers we serve.
Competition
for natural gas storage is primarily based on location and the ability to
deliver natural gas in a timely and reliable manner. Our natural gas
storage facilities compete with other providers of natural gas storage,
including other salt dome storage facilities and depleted reservoir
facilities. We believe that the locations of our natural gas storage
facilities allow us to compete effectively with other companies who provide
natural gas storage services.
Properties. The
following table summarizes the significant assets of our Onshore Natural Gas
Pipelines & Services business segment at February 2, 2009.
|
|
|
|
|
Approx.
Net
|
|
|
|
|
Our
|
|
Capacity,
|
Gross
|
|
|
|
Ownership
|
Length
|
Natural
Gas
|
Capacity
|
Description
of Asset
|
Location(s)
|
Interest
|
(Miles)
|
(MMcf/d)
|
(Bcf)
|
Onshore
natural gas pipelines:
|
|
|
|
|
|
|
Texas
Intrastate System
|
Texas
|
100.0% (1)
|
7,860
|
5,535
|
|
|
Piceance
Basin Gathering System
|
Colorado
|
100.0%
|
79
|
1,600
|
|
|
White
River Hub
|
Colorado
|
50.0%
|
10
|
1,500
|
|
|
San
Juan Gathering System
|
New
Mexico, Colorado
|
100.0%
|
6,065
|
1,200
|
|
|
Acadian
Gas System
|
Louisiana
|
Various
(2)
|
1,042
|
1,149
|
|
|
Jonah
Gathering System
|
Wyoming
|
19.4%
|
714
|
455
|
|
|
Carlsbad
Gathering System
|
Texas,
New Mexico
|
100.0%
|
919
|
220
|
|
|
Alabama
Intrastate System
|
Alabama
|
100.0%
|
408
|
200
|
|
|
Encinal
Gathering System
|
Texas
|
100.0%
|
449
|
143
|
|
|
Other
(6 systems) (3)
|
Texas,
Mississippi
|
Various
(4)
|
800
|
460
|
|
|
Total
miles |
|
|
18,346
|
|
|
Natural
gas storage facilities:
|
|
|
|
|
|
|
Petal
|
Mississippi
|
100.0%
|
|
|
16.6
|
|
Hattiesburg
|
Mississippi
|
100.0%
|
|
|
2.1
|
|
Wilson
|
Texas
|
Leased
(5)
|
|
|
6.8
|
|
Acadian
|
Louisiana
|
Leased
(6)
|
|
|
1.7
|
|
Total
gross capacity
|
|
|
|
|
27.2
|
|
|
|
|
|
|
|
(1)
In
general, our consolidated ownership of this system is 100.0% through
interests held by EPO and Duncan Energy Partners. However, we
own and operate a consolidated 50.0% undivided interest in the 641-mile
Channel pipeline system, which is a component of the Texas Intrastate
System. The remaining 50.0% is owned by affiliates of Energy
Transfer Equity. In addition, we own less than a 100.0%
undivided interest in certain segments of the Enterprise Texas pipeline
system.
(2)
Reflects
consolidated ownership of Acadian Gas by EPO (34.0%) and Duncan Energy
Partners (66.0%). Also includes the 49.5% equity investment
that Acadian Gas has in the Evangeline pipeline.
(3)
Includes
the Delmita, Big Thicket, Indian Springs and Canales gathering systems
located in Texas and the Petal and Hattiesburg pipelines located in
Mississippi. The Delmita and Big Thicket gathering systems are
integral parts of our natural gas processing operations, the results of
operations and assets of which are accounted for under our NGL Pipelines
& Services business segment. We acquired the Canales
gathering system in connection with the Encinal acquisition in July
2006. The Petal and Hattiesburg pipelines are integral
components of our natural gas storage operations.
(4)
We
own 100.0% of these assets with the exception of the Indian Springs
system, in which we own an 80.0% undivided interest through a consolidated
subsidiary. Our 100.0% interest in Big Thicket reflects
consolidated ownership by EPO (34.0%) and Duncan Energy Partners
(66.0%).
(5)
We
hold this facility under an operating lease that expires in January
2028.
(6)
We
hold this facility under an operating lease that expires in December
2012.
|
On a weighted-average basis, aggregate
utilization rates for our onshore natural gas pipelines were approximately
65.5%, 63.5% and 70.9% during the years ended December 31, 2008, 2007 and 2006,
respectively. The utilization rate for 2008 excludes the White River Hub,
which commenced operations during December 2008 and continues to experience a
ramp-up in volumes. The utilization rate for 2007 excludes our
Piceance Creek Gathering System, which operated at an average utilization rate
of 24.3% during 2007 as volumes ramped-up on this system. Generally, our
utilization rates reflect the periods in which we owned an interest in such
assets, or, for recently constructed assets, since the dates such assets were
placed into service.
The following information highlights
the general use of each of our principal onshore natural gas pipelines and
storage facilities. We operate our onshore natural gas pipelines and
storage facilities with the exception of the White River Hub and small segments
of the Texas Intrastate System.
§
|
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
6,547-mile Enterprise Texas pipeline system, the 641-mile
Channel pipeline system, the 465-mile Waha gathering system and the
207-
|
mile TPC
Offshore gathering system. The leased Wilson natural gas storage
facility is an integral part of the Texas Intrastate System. The
Enterprise Texas pipeline system includes a 263-mile pipeline we lease from
an affiliate of ETP. 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.
The
178-mile Sherman Extension of our Texas Intrastate System is scheduled for final
completion in March 2009. The Sherman Extension is capable of
transporting up to 1.1 Bcf/d of natural gas from the prolific Barnett Shale
production basin in North Texas and provides producers with interconnects with
third party interstate pipelines having access to markets outside of
Texas. Customers, including EPO, have contracted for an aggregate 1.0
Bcf/d of the capacity of the Sherman Extension.
In late
2008, we began design of the 40-mile Trinity River Basin Extension, which is
expected to be completed in the fourth quarter of 2009. The Trinity
River Basin Extension will be capable of transporting up to 1.0 Bcf/d of natural
gas and will provide producers in the Barnett Shale production basin with
additional takeaway capacity. We are also constructing a new storage
cavern adjacent to the leased Wilson natural gas storage facility that is
expected to be completed in 2010. When completed, this new cavern is
expected to provide us with an additional 5.0 Bcf of useable natural gas storage
capacity.
We
contributed equity interests in our subsidiaries that own the Texas Intrastate
System to Duncan Energy Partners effective December 8, 2008. As a
result, Duncan Energy Partners owns a 51.0% voting equity interest in the entity
that owns the Enterprise Texas pipeline system, the Channel pipeline system
and the Wilson storage facility. Also, Duncan Energy Partners owns a
66.0% voting equity interest in the entity that owns the Waha gathering system
and the TPC Offshore gathering system. We own, through our other
subsidiaries, the remaining equity interests in these entities. For
additional information regarding this transaction, see “Other Items – Duncan
Energy Partners Transactions” included under Item 7 of this annual
report.
§
|
The
Piceance Basin
Gathering
System consists of the 48-mile Piceance Creek and the 31-mile
Great Divide gathering systems located in the Piceance Basin of
northwestern Colorado. We acquired the Piceance Creek gathering
system from EnCana Oil & Gas USA (“EnCana”) in December 2006 and
subsequently placed this asset in-service during January 2007. We
acquired the Great Divide gathering system from EnCana in December 2008.
The Great Divide gathering system gathers natural gas from the
southern portion of the Piceance basin, including EnCana’s Mamm Creek
field, to our Piceance Creek gathering system. The Piceance
Creek gathering system extends from a connection with the Great Divide
gathering system to the Meeker facility. For additional
information regarding our acquisition of the Great Divide system, see Note
12 of the Notes to Consolidated Financial Statements included under Item 8
of this annual report.
|
§
|
The
White River Hub
is a FERC-regulated interstate natural gas transmission system designed to
provide natural gas transportation and hub services. The White
River Hub connects to six interstate natural gas pipelines in northwest
Colorado and has a gross capacity of 3.0 Bcf/d of natural gas (1.5 Bcf/d
net to our interest). White River Hub began service in December
2008.
|
§
|
The
San Juan Gathering
System serves natural gas producers in the San Juan Basin of New
Mexico and Colorado. This system gathers natural gas from
approximately 10,813 producing wells in the San Juan Basin and
delivers the natural gas to natural gas processing facilities, including
our Chaco facility.
|
§
|
The
Acadian Gas
System purchases, transports, stores and sells natural gas in
Louisiana. The Acadian Gas System is comprised of the 577-mile
Cypress pipeline, the 438-mile Acadian pipeline and the 27-mile Evangeline
pipeline. The leased Acadian natural gas storage facility is an
integral part of the Acadian Gas
System.
|
§
|
The
Jonah Gathering
System is located in the Greater Green River Basin of southwestern
Wyoming. This system gathers natural gas from the Jonah and
Pinedale fields for delivery to regional natural gas processing plants,
including our Pioneer facility, and major interstate
pipelines. Our ownership in this gathering system is through
our 19.4% equity method investment in Jonah Gas Gathering Company, which
we acquired from TEPPCO in August 2006. We completed the Phase
V expansion of the Jonah Gathering System in June
2008.
|
§
|
The
Carlsbad Gathering System
gathers natural gas from wells in the Permian Basin region of Texas
and New Mexico and delivers natural gas into the El Paso Natural Gas,
Transwestern and Oasis pipelines.
|
§
|
The
Alabama Intrastate
System mainly gathers coal bed methane from wells in the
Black Warrior Basin in Alabama. This system is also
involved in the purchase, transportation and sale of natural
gas.
|
§
|
The
Encinal Gathering
System gathers natural gas from the Olmos and Wilcox formations in
south Texas and delivers into our Texas Intrastate System, which delivers
the natural gas to our south Texas facilities for
processing. We acquired this gathering system in connection
with the Encinal acquisition in July
2006.
|
§
|
The
Petal and Hattiesburg underground
storage facilities are strategically situated to serve the domestic
Northeast, Mid-Atlantic and Southeast natural gas markets and are capable
of delivering in excess of 1.4 Bcf/d of natural gas into five interstate
pipeline systems. We placed a new natural gas storage cavern at our
Petal facility into service during the third quarter of
2008. The new cavern has a total of 9.1 Bcf of storage capacity
which represents 5.9 Bcf of FERC certificated working gas capacity
and approximately 3.2 Bcf of base gas requirements needed to support
minimum pressures.
|
Offshore
Pipelines & Services
Our
Offshore Pipelines & Services business segment includes (i) approximately
1,544 miles of offshore natural gas pipelines strategically located to serve
production areas including some of the most active drilling and development
regions in the Gulf of Mexico, (ii) approximately 909 miles of offshore Gulf of
Mexico crude oil pipeline systems and (iii) six multi-purpose offshore hub
platforms located in the Gulf of Mexico with crude oil or natural gas processing
capabilities.
Offshore
natural gas pipelines. Our offshore
natural gas pipeline systems provide for the gathering and transmission of
natural gas from production developments located in the Gulf of Mexico,
primarily offshore Louisiana and Texas. Typically, these systems receive
natural gas from producers, other pipelines and shippers through system
interconnects and transport the natural gas to various downstream pipelines,
including major interstate transmission pipelines that access multiple markets
in the eastern half of the United States.
Our revenues from offshore natural gas
pipelines are derived from fee-based agreements and are typically based on
transportation fees per unit of volume transported (generally in MMBtus)
multiplied by the volume delivered. These transportation
agreements tend to be long-term in nature, often involving life-of-reserve
commitments with firm and interruptible components. We do not take
title to the natural gas volumes that are transported on our natural gas
pipeline systems; rather, the shipper retains title and the associated commodity
price risk.
Offshore
oil pipelines. We own interests in several offshore oil pipeline
systems, which are located in the vicinity of oil-producing areas in the Gulf of
Mexico. Typically, these systems receive crude oil from offshore
production developments, other pipelines or shippers through system
interconnects and deliver the crude oil to either onshore locations or to other
offshore interconnecting pipelines.
The majority of revenues from our
offshore crude oil pipelines are generated based upon a transportation fee per
unit of volume (typically in barrels) multiplied by the volume delivered to the
customer. A substantial portion of the revenues generated by our
offshore crude oil pipeline systems are attributable to long-term transportation
agreements with producers. The revenues we earn for our services are
dependent on the volume of crude oil to be delivered and the level of fees
charged to customers.
Offshore
platforms. We have ownership
interests in six multi-purpose offshore hub platforms located in the Gulf of
Mexico with crude oil and/or natural gas processing
capabilities. Offshore platforms are critical components of the
energy-related infrastructure in the Gulf of Mexico, supporting drilling and
producing operations, and therefore play a key role in the overall development
of offshore oil and natural gas reserves. Platforms are used to: (i)
interconnect with the offshore pipeline grid; (ii) provide an efficient means to
perform pipeline maintenance; (iii) locate compression, separation and
production handling and other facilities; (iv) conduct drilling operations
during the initial development phase of an oil and natural gas property; and (v)
process off-lease production.
Revenues
from offshore platform services generally consist of demand payments and
commodity charges. Demand fees represent charges to customers served
by our offshore platforms regardless of the volume the customer delivers to the
platform. Revenues from commodity charges are based on a fixed-fee
per unit of volume delivered to the platform (typically per MMcf of natural gas
or per barrel of crude oil) multiplied by the total volume of each product
delivered. Contracts for platform services often include both demand
payments and commodity charges, but demand payments generally expire after a
contractually fixed period of time and in some instances may be subject to
cancellation by customers. Our Independence Hub and Marco Polo
offshore platforms earn a significant amount of demand revenues. The
Independence Hub platform will earn $54.6 million of demand revenues annually
through March 2012. The Marco Polo platform will earn $2.1 million of
demand revenues monthly through March 2009.
Seasonality.
Our offshore operations exhibit little to no effects of seasonality; however,
they may be affected by weather events such as hurricanes and tropical storms in
the Gulf of Mexico.
Competition.
Within their market areas, our offshore natural gas and oil pipelines compete
with other pipelines (both regulated and unregulated systems) primarily on the
basis of price (in terms of transportation fees), available capacity and
connections to downstream markets. To a limited extent, our
competition includes other offshore pipeline systems, built, owned and operated
by producers to handle their own production and, as capacity is available,
production for others. We compete with other platform service
providers on the basis of proximity and access to existing reserves and pipeline
systems, as well as costs and rates. Furthermore, our competitors may
possess greater capital resources than we have available, which could enable
them to address business opportunities more quickly than us.
Properties. The
following table summarizes the significant assets of our Offshore Pipelines
& Services business segment at February 2, 2009, all of which are located in
the Gulf of Mexico primarily offshore Louisiana and Texas.
|
|
Our
|
|
Water
|
Approximate
Net Capacity
|
|
|
Ownership
|
Length
|
Depth
|
Natural
Gas
|
Crude
Oil
|
Description
of Asset
|
Interest
|
(Miles)
|
(Feet)
|
(MMcf/d)
|
(MPBD)
|
Offshore
natural gas pipelines:
|
|
|
|
|
|
|
High
Island Offshore System
|
100.0%
|
291
|
|
1,800
|
|
|
Viosca
Knoll Gathering System
|
100.0%
|
162
|
|
1,000
|
|
|
Independence
Trail
|
100.0%
|
134
|
|
1,000
|
|
|
Green
Canyon Laterals
|
Various
(1)
|
94
|
|
605
|
|
|
Phoenix
Gathering System
|
100.0%
|
77
|
|
450
|
|
|
Falcon
Natural Gas Pipeline
|
100.0%
|
14
|
|
400
|
|
|
Anaconda
Gathering System
|
100.0%
|
137
|
|
300
|
|
|
Manta
Ray Offshore Gathering System (2)
|
25.7%
|
250
|
|
206
|
|
|
Nautilus
System (2)
|
25.7%
|
101
|
|
154
|
|
|
VESCO
Gathering System (3)
|
13.1%
|
260
|
|
105
|
|
|
Nemo
Gathering System (4)
|
33.9%
|
24
|
|
102
|
|
|
Total
miles |
|
1,544
|
|
|
|
Offshore
crude oil pipelines:
|
|
|
|
|
|
|
Cameron
Highway Oil Pipeline (5)
|
50.0%
|
374
|
|
|
250
|
|
Poseidon
Oil Pipeline System (6)
|
36.0%
|
367
|
|
|
144
|
|
Allegheny
Oil Pipeline
|
100.0%
|
43
|
|
|
140
|
|
Marco
Polo Oil Pipeline
|
100.0%
|
37
|
|
|
120
|
|
Constitution
Oil Pipeline
|
100.0%
|
67
|
|
|
80
|
|
Typhoon
Oil Pipeline
|
100.0%
|
17
|
|
|
80
|
|
Tarantula
Oil Pipeline
|
100.0%
|
4
|
|
|
30
|
|
Total
miles |
|
909 |
|
|
|
Offshore
platforms:
|
|
|
|
|
|
|
Independence
Hub
|
80.0%
|
|
8,000
|
800
|
NA
|
|
Marco
Polo (7)
|
50.0%
|
|
4,300
|
150
|
60
|
|
Viosca
Knoll 817
|
100.0%
|
|
671
|
145
|
5
|
|
Garden
Banks 72
|
50.0%
|
|
518
|
38
|
18
|
|
East
Cameron 373
|
100.0%
|
|
441
|
195
|
3
|
|
Falcon
Nest
|
100.0%
|
|
389
|
400
|
3
|
|
|
|
|
|
|
|
(1)
Our
ownership interests in the Green Canyon Laterals ranges from 2.7% to
100.0%.
(2)
Our
ownership interest in these pipelines is held indirectly through our
equity method investment in Neptune Pipeline Company, L.L.C.
(“Neptune”).
(3)
Our
ownership interest in this system is held indirectly through our equity
method investment in VESCO.
(4)
Our
ownership interest in this pipeline is held indirectly through our equity
method investment in Nemo Gathering Company, LLC
(“Nemo”).
(5)
Our
50.0% joint control ownership interest in this pipeline is held indirectly
through our equity method investment in Cameron Highway Oil Pipeline
Company (“Cameron Highway”).
(6)
Our
ownership interest in this pipeline is held indirectly through our equity
method investment in Poseidon Oil Pipeline Company, LLC.
(“Poseidon”).
(7)
Our
50.0% joint control ownership interest in this platform is held indirectly
through our equity method investment in Deepwater Gateway, L.L.C.
(“Deepwater Gateway”).
|
We operate our offshore natural gas
pipelines, with the exception of the VESCO Gathering System, Manta Ray Offshore
Gathering System, Nautilus System, Nemo Gathering System and certain components
of the Green Canyon Laterals. On a weighted-average basis, aggregate
utilization rates for our offshore natural gas pipelines were approximately
22.0%, 24.1% and 25.9% during the years ended December 31, 2008, 2007 and 2006,
respectively. For recently constructed assets (e.g., Independence
Trail), utilization rates reflect the periods since the dates such assets were
placed into service.
The following information highlights
the general use of each of our principal Gulf of Mexico offshore natural gas
pipelines.
§
|
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. This system also includes the 86-mile East Breaks
System that connects HIOS to the Hoover-Diana deepwater platform located in
Alaminos Canyon Block 25.
§
|
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.
|
§
|
The
Independence
Trail natural gas pipeline transports natural gas from our
Independence Hub platform to the Tennessee Gas
Pipeline. 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. This pipeline includes one pipeline
junction platform at West Delta 68. We completed construction
of the Independence Trail natural gas pipeline in 2006 and, in July 2007,
the pipeline received its first production from deepwater wells connected
to the Independence Hub platform.
|
§
|
The
Green Canyon
Laterals consist of 15 pipeline laterals (which are extensions
of natural gas pipelines) that transport natural gas to downstream
pipelines, including HIOS.
|
§
|
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.
|
§
|
The
Falcon Natural Gas Pipeline delivers
natural gas processed at our Falcon Nest platform to a connection with the
Central Texas Gathering System located on the Brazos Addition Block 133
platform.
|
§
|
The
Anaconda Gathering
System connects our Marco Polo platform and the third-party owned
Constitution platform to the ANR pipeline system. The Anaconda
Gathering System includes our wholly owned Typhoon, Marco Polo and
Constitution natural gas pipelines. The Constitution
natural gas pipeline serves the Constitution and Ticonderoga fields
located in the central Gulf of
Mexico.
|
§
|
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.
|
§
|
The
Nautilus System
connects our Manta Ray Offshore Gathering System to our Neptune natural
gas processing plant on the Louisiana gulf
coast.
|
§
|
The
VESCO Gathering
System is a regulated natural gas pipeline system associated with
the Venice natural gas processing plant in Louisiana. This
pipeline is an integral part of the natural gas processing operations of
VESCO.
|
§
|
The
Nemo Gathering
System transports natural gas from Green Canyon developments
to an interconnect with our Manta Ray Offshore Gathering
System.
|
The following information highlights
the general use of each of our principal Gulf of Mexico offshore crude oil
pipelines, all of which we operate. On a weighted-average basis,
aggregate utilization rates for our offshore crude oil pipelines were
approximately 20.1%, 19.3% and 18.1% during the years ended December 31, 2008,
2007 and 2006, respectively.
§
|
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
pipeline includes one pipeline junction
platform.
|
§
|
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.
|
§
|
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.
|
§
|
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.
|
§
|
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.
|
In October 2006, we announced the
execution of definitive agreements with producers to construct, own and operate
an oil export pipeline (the “Shenzi Oil Pipeline”) that will provide firm
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 is expected to commence operations
during the second quarter of 2009. In August 2008, we, together
with TEPPCO and Oiltanking Holding Americas, Inc., announced the formation of
the Texas Offshore Port System, a joint venture to design, construct, operate
and own a Texas offshore crude oil port and related pipeline and storage system
that would facilitate delivery of waterborne crude oil cargoes to refining
centers located along the upper Texas Gulf Coast. For information
regarding these projects, see “Liquidity and Capital Resources – Significant
Ongoing Growth Capital Projects” included under Item 7 of this annual
report.
The following information highlights
the general use of each of our principal Gulf of Mexico offshore
platforms. We operate these offshore platforms with the exception of
the Independence Hub, Marco Polo and East Cameron 373 platforms.
On a weighted-average basis,
utilization rates with respect to natural gas processing capacity of our
offshore platforms were approximately 36.5%, 28.6% and 17.2% during the years
ended December 31, 2008, 2007 and 2006, respectively. Likewise, utilization
rates for our offshore platforms were approximately 16.9%, 26.1% and 19.2%,
respectively, in connection with platform crude oil processing
capacity. For recently constructed assets (e.g., Independence Hub),
these rates reflect the periods since the dates such assets were placed into
service. In addition to the offshore platforms we identified in the
preceding table, we own or have an ownership interest in fourteen pipeline
junction and service platforms. Our pipeline junction and service
platforms do not have processing capacity.
§
|
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. We
successfully installed the Independence Hub platform and began earning
demand revenues in March 2007. In July 2007, the Independence
Hub platform received first production from deepwater wells connected to
the platform.
|
§
|
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.
|
§
|
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.
|
§
|
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.
§
|
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.
|
§
|
The
Falcon Nest
platform, which is located in the Mustang Island Block 103 area of the
Gulf of Mexico, currently processes natural gas from the Falcon
field.
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Petrochemical
Services
Our
Petrochemical Services business segment primarily includes two propylene
fractionation facilities, an isomerization complex, and an octane additive
production facility. This segment also includes approximately 649
miles of petrochemical pipeline systems.
Propylene
fractionation.
Our propylene fractionation business consists primarily of two propylene
fractionation facilities located in Texas and Louisiana and propylene
pipeline systems aggregating approximately 579 miles. These
operations also include an export facility located on the Houston Ship Channel
and our petrochemical marketing activities.
In general, propylene fractionation
plants separate refinery grade propylene (a mixture of propane and propylene)
into either polymer grade propylene or chemical grade propylene along with
by-products of propane and mixed butane. Polymer grade and chemical grade
propylene can also be produced as a by-product of olefin (ethylene)
production. The demand for polymer grade propylene primarily relates
to the manufacture of polypropylene, which has a variety of end uses,
including packaging film, fiber for carpets and upholstery and molded plastic
parts for appliance, automotive, houseware and medical products. Chemical
grade propylene is a basic petrochemical used in the manufacturing of plastics,
synthetic fibers and foams.
Results
of operations for our polymer grade propylene plants are generally dependent
upon toll processing arrangements and petrochemical marketing
activities. These processing arrangements typically include a
base-processing fee per gallon (or other unit of measurement) subject to
adjustment for changes in natural gas, electricity and labor costs, which are
the primary costs of propylene fractionation and isomerization
operations. Our petrochemical marketing activities generate
revenues from the sale and delivery of products obtained through our processing
activities and purchases from third parties on the open market. In
general, we sell our petrochemical products at market-related prices, which may
include pricing differentials for such factors as delivery
location.
As part
of our petrochemical marketing activities, we have several long-term polymer
grade propylene sales agreements. To meet our petrochemical marketing
obligations, we have entered into several agreements to purchase refinery grade
propylene. To limit the exposure of our petrochemical marketing activities to
price risk, we attempt to match the timing and price of our feedstock purchases
with those of the sales of end products.
Isomerization. Our isomerization business
includes three butamer reactor units and eight associated deisobutanizer units
located in Mont Belvieu, Texas, which comprise the largest commercial
isomerization complex in the United States. In addition, this
business includes a 70-mile pipeline system used to transport high-purity
isobutane from Mont Belvieu, Texas to Port Neches, Texas.
Our commercial isomerization units
convert normal butane into mixed butane, which is subsequently fractionated into
isobutane, high purity isobutane and residual normal butane. The
primary uses of isobutane are currently for the production of propylene oxide,
isooctane and alkylate for motor gasoline. The demand for commercial
isomerization services depends upon the industry’s requirements for high purity
isobutane and isobutane in excess of naturally occurring isobutane produced from
NGL fractionation and refinery operations.
The results of operation of this
business are generally dependent upon the volume of normal and mixed butanes
processed and the level of toll processing fees charged to customers. Our
isomerization facility provides processing services to meet the needs of
third-party customers and our other businesses, including our NGL marketing
activities and octane additive production facility.
Octane
enhancement. We own and operate an octane additive production
facility located in Mont Belvieu, Texas designed to produce isooctane, which is
an additive used in reformulated motor gasoline blends to increase octane, and
isobutylene. The facility produces isooctane and isobutylene using
feedstock of high-purity isobutane, which is supplied by our isomerization
units. Prior to mid-2005, the facility produced methyl tertiary butyl
ether (“MTBE”). We modified the facility to produce isooctane and
isobutylene. Depending on the outcome of various factors, the
facility may be further modified in the future to produce alkylate, another
motor gasoline additive.
Seasonality. Overall, the propylene
fractionation business exhibits little seasonality. Our isomerization
operations experience slightly higher demand in the spring and summer months due
to the demand for isobutane-based fuel additives used in the production of motor
gasoline. Likewise, isooctane prices have been stronger during the
April to September period of each year, which corresponds with the summer
driving season.
Competition. We compete with numerous
producers of polymer grade propylene, which include many of the major refiners
and petrochemical companies located along the
Gulf Coast. Generally, the propylene fractionation business
competes in terms of the level of toll processing fees charged and access to
pipeline and storage infrastructure. Our petrochemical marketing
activities encounter competition from fully integrated oil companies and various
petrochemical companies. Our petrochemical marketing competitors have
varying levels of financial and personnel resources and competition generally
revolves around price, service, logistics and location.
With
respect to our isomerization operations, we compete primarily with facilities
located in Kansas, Louisiana and New Mexico. Competitive factors affecting
this business include the level of toll processing fees charged, the quality of
isobutane that can be produced and access to pipeline and storage
infrastructure. We compete with other octane additive manufacturing
companies primarily on the basis of price.
Properties. The following table
summarizes the significant assets of our Petrochemical Services segment at
February 2, 2009, all of which we operate.
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|
|
|
Net
|
Total
|
|
|
|
|
Our
|
Plant
|
Plant
|
|
|
|
|
Ownership
|
Capacity
|
Capacity
|
Length
|
Description
of Asset
|
Location(s)
|
Interest
|
(MBPD)
|
(MBPD)
|
(Miles)
|
Propylene
fractionation facilities:
|
|
|
|
|
|
Mont
Belvieu (six units)
|
Texas
|
Various
(1)
|
73
|
87
|
|
|
BRPC
|
Louisiana
|
30.0%
(2)
|
7
|
23
|
|
|
Total
capacity
|
|
|
80
|
110
|
|
Isomerization
facility:
|
|
|
|
|
|
|
Mont
Belvieu (3)
|
Texas
|
100.0%
|
116
|
116
|
|
Petrochemical
pipelines:
|
|
|
|
|
|
|
Lou-Tex
and Sabine Propylene
|
Texas,
Louisiana
|
100.0%
(4)
|
|
|
284
|
|
Texas
City RGP Gathering System
|
Texas
|
100.0%
|
|
|
86
|
|
Lake
Charles
|
Texas,
Louisiana
|
50.0%
|
|
|
81
|
|
Others
(5 systems) (5)
|
Texas
|
Various
(6)
|
|
|
198
|
|
Total
miles
|
|
|
|
|
649
|
Octane
additive production facilities:
|
|
|
|
|
|
Mont
Belvieu (7)
|
Texas
|
100.0%
|
12
|
12
|
|
|
|
|
|
|
|
|
(1)
We
own a 54.6% interest and lease the remaining 45.4% of a unit having 17
MBPD of plant capacity. We own a 66.7% interest in three
additional units having an aggregate 41 MBPD of total plant
capacity. We own 100.0% of the remaining two units, which have
14 MBPD and 15 MBPD of plant capacity, respectively.
(2)
Our
ownership interest in this facility is held indirectly through our equity
method investment in Baton Rouge Propylene Concentrator LLC
(“BRPC”).
(3)
On
a weighted-average basis, utilization rates for this facility were
approximately 74.1%, 77.6% and 69.8% during the years ended December 31,
2008, 2007 and 2006, respectively.
(4)
Reflects
consolidated ownership of these pipelines by EPO (34.0%) and Duncan Energy
Partners (66.0%).
(5)
Includes
our Texas City PGP Delivery System and Port Neches, La Porte, Port Arthur
and Bayport petrochemical pipelines.
(6)
We
own 100.0% of these pipelines with the exception of the 17-mile La Porte
pipeline, in which we hold an aggregate 50.0% indirect interest through
our equity method investments in La Porte Pipeline Company L.P. and La
Porte Pipeline GP, L.L.C.
(7)
On
a weighted-average basis, utilization rates for this facility were
approximately 58.3% during each of the years ended December 31, 2008, 2007
and 2006, respectively.
|
We produce polymer grade propylene at
our Mont Belvieu location and chemical grade propylene at our BRPC
facility. The primary purpose of the BRPC unit is to fractionate
refinery grade propylene produced by an affiliate of Exxon Mobil
Corporation into chemical grade propylene. The production of polymer
grade propylene from our Mont Belvieu facility is primarily used in our
petrochemical marketing activities. On a weighted-average basis,
aggregate utilization rates of our propylene fractionation facilities were
approximately 72.2%, 86.0% and 86.2% during the years ended December 31, 2008,
2007 and 2006, respectively. This business segment also includes an
above-ground polymer grade propylene storage and export facility located in
Seabrook, Texas. This facility can load vessels at rates up to 5,000
barrels per hour.
The
Lou-Tex Propylene pipeline is used to transport chemical grade propylene from
Sorrento, Louisiana to Mont Belvieu, Texas. The Sabine pipeline is
used to transport polymer grade propylene from Port Arthur, Texas to a pipeline
interconnect in Cameron Parish, Louisiana.
The
maximum number of barrels that our petrochemical pipelines can transport per day
depends upon the operating balance achieved at a given point in time between
various segments of the systems. Since the operating balance is
dependent upon the mix of products to be shipped and demand levels at various
delivery points, the exact capacities of our petrochemical pipelines cannot be
determined. We measure the utilization rates of such pipelines in
terms of net throughput (i.e., on a net basis in accordance with our ownership
interest). Total net throughput volumes for these pipelines were 108
MBPD, 105 MBPD and 97 MBPD during the years ended December 31, 2008, 2007 and
2006, respectively.
Title
to Properties
Our real property holdings fall into
two basic categories: (i) parcels that we and our unconsolidated affiliates own
in fee (e.g., we own the land upon which our Mont Belvieu NGL fractionator is
constructed) and (ii) parcels in which our interests and those of our
unconsolidated affiliates are derived from leases, easements, rights-of-way,
permits or licenses from landowners or governmental authorities permitting the
use of such land for our operations. The fee sites upon which our
significant facilities are located have been owned by us or our predecessors in
title for many years without any material challenge known to us relating to
title to the land upon which the assets are located, and we believe that we have
satisfactory title to such fee sites. We and our unconsolidated
affiliates have no knowledge of any challenge to the underlying fee title of any
material lease, easement, right-of-way, permit or license held by us or to our
rights pursuant to any material lease, easement, right-of-way, permit or
license, and we believe that we have satisfactory rights pursuant to all of our
material leases, easements, rights-of-way, permits and licenses.
Capital
Spending
We are committed to the long-term
growth and viability of Enterprise Products Partners. Part of our
business strategy involves expansion through business combinations, growth
capital projects and investments in joint ventures. We believe we are
positioned to continue to grow our system of assets through the construction of
new facilities and to capitalize on expected future production increases from
areas such as the Piceance Basin of western Colorado, the Greater Green River
Basin in Wyoming, the Barnett Shale in North Texas and the deepwater Gulf of
Mexico. For a discussion of our capital spending program, see
“Liquidity and Capital Resources - Capital Spending” included under Item 7 of
this annual report.
Weather-Related
Risks
In the
third quarter of 2008, our onshore and offshore facilities located along the
Gulf Coast of Texas and Louisiana were adversely impacted by Hurricanes Gustav
and Ike. The disruptions in natural gas, NGL and crude oil production
caused by these storms resulted in decreased volumes for some of our pipeline
systems, natural gas processing plants, NGL fractionators and offshore
platforms, which, in turn, caused a decrease in gross operating margin from
these operations. See Note 21 of the Notes to Consolidated Financial
Statements included under Item 8 of this annual report for more information
regarding significant risks and uncertainties.
Regulation
Interstate
Pipelines
Liquids
Pipelines. Certain of our crude oil and NGL pipeline systems
(collectively referred to as “liquids pipelines”) are interstate common carrier
pipelines subject to regulation by the FERC under the Interstate Commerce Act
(“ICA”) and the Energy Policy Act of 1992 (“Energy Policy Act”). The
ICA prescribes that interstate tariffs must be just and reasonable and must not
be unduly discriminatory or confer any undue preference upon any shipper. FERC
regulations require that interstate oil pipeline transportation rates and terms
of service be filed with the FERC and posted publicly.
The ICA
permits interested persons to challenge proposed new or changed rates or rules
and authorizes the FERC to investigate such changes and to suspend their
effectiveness for a period of up to seven months. If, upon completion
of an investigation, the FERC finds that the new or changed rate is unlawful, it
may require the carrier to refund the revenues in excess of the prior tariff
during the term of the investigation. The FERC may also investigate,
upon complaint or on its own motion, rates and related rules that are already in
effect and may order a carrier to change them prospectively. Upon an
appropriate showing, a shipper may obtain reparations for damages sustained for
a period of up to two years prior to the filing of its complaint.
The
Energy Policy Act deems just and reasonable (i.e., deems “grandfathered”)
liquids pipeline rates that (i) were in effect for the twelve months preceding
enactment and (ii) that had not been subject to complaint, protest or
investigation. Some, but not all, of our interstate liquids pipeline
rates are considered grandfathered under the Energy Policy
Act. Certain other rates for our interstate liquids pipeline services
are charged pursuant to a FERC-approved indexing methodology, which allows a
pipeline to charge rates up to a prescribed ceiling that changes annually based
on the change from year-to-year in the Producer Price Index for finished goods
(“PPI”). A rate increase within the indexed rate ceiling is presumed
to be just and reasonable unless a protesting party can demonstrate that the
rate increase is substantially in excess of the pipeline’s
costs. Effective March 21, 2006, the FERC concluded that for the
five-year period commencing July 1, 2006, liquids pipelines charging indexed
rates may adjust their indexed ceilings annually by the PPI plus
1.3%.
As an
alternative to using the indexing methodology, interstate liquids pipelines may
elect to support rate filings by using a cost-of-service methodology,
competitive market showings (“Market-Based Rates”) or agreements with all of the
pipeline’s shippers that the rate is acceptable.
Because
of the complexity of ratemaking, the lawfulness of any rate is never
assured. Prescribed rate methodologies for approving regulated tariff
rates may limit our ability to set rates based on our actual costs or may delay
the use of rates reflecting higher costs. Changes in the FERC’s
methodology for approving rates could adversely affect us. In
addition, challenges to our tariff rates could be filed with the FERC and
decisions by the FERC in approving our regulated rates could adversely affect
our cash flow. We believe the transportation rates currently charged
by our interstate common carrier liquids pipelines are in accordance with the
ICA. However, we cannot predict the rates we will be allowed to
charge in the future for transportation services by such pipelines.
The
Lou-Tex Propylene and Sabine Propylene pipelines are interstate common carrier
pipelines regulated under the ICA by the Surface Transportation Board
(“STB”). If the STB finds that a carrier’s rates are not just and
reasonable or are unduly discriminatory or preferential, it may prescribe a
reasonable rate. In determining a reasonable rate, the STB will
consider, among other factors, the effect of the rate on the volumes transported
by that carrier, the carrier’s revenue needs and the availability of other
economic transportation alternatives.
The STB
does not need to provide rate relief unless shippers lack effective competitive
alternatives. If the STB determines that effective competitive
alternatives are not available and a pipeline holds market power, then we may be
required to show that our rates are reasonable.
Mid-America
Pipeline Company, LLC (“Mid-America”) is currently involved in a rate case
before the FERC. The case primarily involves shipper protests of rate
increases on Mid-America's Conway North pipeline filed on March 31, 2005 and
March 31, 2006. A hearing before an Administrative Law Judge began on
October 2, 2007 and culminated with an initial decision on September 3,
2008. Briefs on Exceptions were filed October 31, 2008, with Briefs
Opposing Exceptions filed on January 8, 2009. The matter is presently
pending before the FERC, with a decision expected to be issued in the second
half of 2009. We are unable to predict the outcome of this
litigation.
Natural
Gas Pipelines. Our interstate natural gas pipelines and storage
facilities that provide services in interstate commerce are regulated by the
FERC under the Natural Gas Act of 1938 (“NGA”). Under the NGA, the
rates for service on these interstate facilities must be just and reasonable and
not unduly discriminatory. We operate these interstate facilities
pursuant to tariffs which set forth rates and terms and conditions of
service. These tariffs must be filed with and approved by the FERC
pursuant to its regulations and orders. Our tariff rates may be
lowered on a prospective basis only by the FERC if it finds, on its own
initiative or as a result of challenges to the rates by third parties, that they
are unjust, unreasonable or otherwise unlawful. Unless the FERC
grants specific authority to charge market-based rates, our rates are derived
and charged based on a cost-of-service methodology.
The
FERC’s authority over companies that provide natural gas pipeline transportation
or storage services in interstate commerce also includes: (i)
certification, construction, and operation of certain new
facilities;
(ii) the acquisition, extension, disposition or abandonment of such facilities;
(iii) the maintenance of accounts and records; (iv) the initiation, extension
and termination of regulated services; and (v) various other
matters. The FERC’s rules require interstate pipelines and their
affiliates to adhere to Standards of Conduct that, among other things, require
that transmission employees function independently of marketing
employees. The Energy Policy Act of 2005 amended the NGA to add an
anti-manipulation provision. Pursuant to that act, the FERC
established rules prohibiting energy market manipulation. A violation
of these rules may subject us to civil penalties, disgorgement of unjust
profits, or appropriate non-monetary remedies imposed by the FERC. In
addition, the Energy Policy Act of 2005 amended the NGA and the Natural Gas
Policy Act of 1978 (“NGPA”) to increase civil and criminal penalties for any
violation of the NGA, NGPA and any rules, regulations or orders of the FERC up
to $1.0 million per day per violation.
Offshore
Pipelines. Our offshore natural gas gathering pipelines and
crude oil pipeline systems are subject to federal regulation under the Outer
Continental Shelf Lands Act, which requires that all pipelines operating on or
across the outer continental shelf provide nondiscriminatory transportation
service.
Intrastate
Pipelines
Liquids
Pipelines.
Certain of our pipeline systems operate within a single state and provide
intrastate pipeline transportation services. These pipeline systems
are subject to various regulations and statutes mandated by state regulatory
authorities. Although the applicable state statutes and regulations
vary, they generally require that intrastate pipelines publish tariffs setting
forth all rates, rules and regulations applying to intrastate service, and
generally require that pipeline rates and practices be reasonable and
nondiscriminatory. Shippers may also challenge our intrastate tariff
rates and practices on our pipelines. Our intrastate liquids
pipelines are subject to regulation in many states, including Alabama, Colorado,
Louisiana, Mississippi, New Mexico and Texas.
Natural
Gas Pipelines. Our intrastate natural gas pipelines are subject to
regulation in many states, including Alabama, Colorado, Louisiana, Mississippi,
New Mexico and Texas. Certain of our intrastate natural gas pipelines
are also subject to limited regulation by the FERC under the NGPA because they
provide transportation and storage service pursuant to Section 311 of the NGPA
and Part 284 of the FERC’s regulations. Under Section 311 of the
NGPA, an intrastate pipeline company may transport gas for an interstate
pipeline or any local distribution company served by an interstate pipeline
without becoming subject to the FERC’s jurisdiction under the
NGA. However, such a pipeline is required to provide these services
on an open and nondiscriminatory basis, and to make certain rate and other
filings and reports are in compliance with the FERC’s
regulations. The rates for 311 services may be established by the
FERC or the respective state agency, but such rates may not exceed a fair and
equitable rate.
In
September 2007, the FERC also approved an uncontested settlement establishing
our maximum firm and interruptible transportation rates for NGPA Section 311
service on the Enterprise Texas Pipeline. In September 2008, we
submitted to the FERC a new proposed Section 311 rate for service on our Sherman
Extension pipeline, which rate is presently under review by the
FERC. We are required to file another rate petition on or before
April 2009 to justify our current rates or establish new rates for NGPA Section
311 service. The Texas Railroad Commission has the authority to
regulate the rates and terms of service for our intrastate transportation
service in Texas.
In
September 2007, the FERC approved an uncontested settlement establishing our
maximum firm and interruptible transportation rates for NGPA Section 311 service
on the Enterprise Alabama Intrastate Pipeline. We are required to
file another rate petition on or before May 2010 to justify our current rates or
establish new rates for NGPA Section 311 service. The Alabama Public
Service Commission has the authority to regulate the rates and terms of service
for our intrastate transportation service in Alabama.
Sales
of Natural Gas
We are engaged in natural gas marketing
activities. The resale of natural gas in interstate commerce is
subject to FERC jurisdiction. However, under current federal rules the
price at which we sell
natural
gas currently is not regulated, insofar as the interstate market is concerned
and, for the most part, is not subject to state regulation. Our
affiliates that engage in natural gas marketing are considered marketing
affiliates of our interstate natural gas pipelines. The FERC’s rules
require interstate pipelines and their marketing affiliates who sell natural gas
in interstate commerce subject to the FERC’s jurisdiction to adhere to standards
of conduct that, among other things, require that their transmission and
marketing employees function independently of each other. Pursuant to
the Energy Policy Act of 2005, the FERC has established rules prohibiting energy
market manipulation. A violation of these rules may subject us to
civil penalties, disgorgement of unjust profits, suspension, loss of
authorization to perform such sales or other appropriate non-monetary remedies
imposed by the FERC.
The FERC
is continually proposing and implementing new rules and regulations affecting
segments of the natural gas industry. For example, the FERC recently
established rules requiring certain non-interstate pipelines to post daily
scheduled volume information and design capacity for certain points, and has
also required the annual reporting of gas sales information, in order to
increase transparency in natural gas markets. In November 2008, the
FERC commenced an inquiry into whether to expand the contract reporting
requirements of Section 311 service providers. We cannot predict the
ultimate impact of these regulatory changes on our natural gas marketing
activities; however, we believe that any new regulations will also be applied to
other natural gas marketers with whom we compete.
Environmental
and Safety Matters
General
Our
operations are subject to multiple environmental obligations and potential
liabilities under a variety of federal, state and local laws and regulations.
These include, without limitation: the Comprehensive Environmental
Response, Compensation, and Liability Act; the Resource Conservation and
Recovery Act; the Clean Air Act; the Federal Water Pollution Control Act or the
Clean Water Act; the Oil Pollution Act; and analogous state and local laws and
regulations. Such laws and regulations affect many aspects of our present
and future operations, and generally require us to obtain and comply with a wide
variety of environmental registrations, licenses, permits, inspections and other
approvals, with respect to air emissions, water quality, wastewater discharges
and solid and hazardous waste management. Failure to comply with these
requirements may expose us to fines, penalties and/or interruptions in our
operations that could influence our financial position, results of
operations and cash flows. If an accidental leak, spill or release of
hazardous substances occurs at a facility that we own, operate or otherwise use,
or where we send materials for treatment or disposal, we could be held jointly
and severally liable for all resulting liabilities, including investigation,
remedial and clean-up costs. Likewise, we could be required to remove or
remediate previously disposed wastes or property contamination, including
groundwater contamination. Any or all of this could materially affect our
financial position, results of operations and cash flows.
We
believe our operations are in material compliance with applicable environmental
and safety laws and regulations, other than certain matters discussed under Item
3 of this annual report, and that compliance with existing environmental and
safety laws and regulations are not expected to have a material adverse effect
on our financial position, results of operations and cash
flows. Environmental and safety laws and regulations are subject to
change. The clear trend in environmental regulation is to place more
restrictions and limitations on activities that may be perceived to affect the
environment, and thus there can be no assurance as to the amount or timing of
future expenditures for environmental regulation compliance or remediation, and
actual future expenditures may be different from the amounts we currently
anticipate. Revised or additional regulations that result in increased
compliance costs or additional operating restrictions, particularly if those
costs are not fully recoverable from our customers, could have a material
adverse effect on our business, financial position, results of operations and
cash flows.
Water
The Federal Water Pollution Control Act
of 1972, as renamed and amended as the Clean Water Act (“CWA”), and analogous
state laws impose restrictions and strict controls regarding the discharge of
pollutants into navigable waters of the United States, as well as state
waters. Permits must be obtained to
discharge
pollutants into these waters. The CWA imposes substantial civil and
criminal penalties for non-compliance. The Environmental Protection
Agency (“EPA”) has promulgated regulations that require us to have permits in
order to discharge storm water runoff. The EPA has entered into
agreements with states in which we operate whereby the permits are administered
by the respective states.
The
primary federal law for oil spill liability is the Oil Pollution Act of 1990
(“OPA”), which addresses three principal areas of oil pollution - prevention,
containment and cleanup, and liability. The OPA subjects owners of
certain facilities to strict, joint and potentially unlimited liability for
containment and removal costs, natural resource damages and certain other
consequences of an oil spill, where such spill affects navigable waters, along
shorelines or in the exclusive economic zone of the United
States. Any unpermitted release of petroleum or other pollutants from
our operations could also result in fines or penalties. The OPA
applies to vessels, offshore platforms and onshore facilities, including
terminals, pipelines and transfer facilities. In order to handle,
store or transport oil, shore facilities are required to file oil spill response
plans with the United States Coast Guard, the United States Department of
Transportation Office of Pipeline Safety (“OPS”) or the EPA, as
appropriate.
Some states maintain groundwater
protection programs that require permits for discharges or commercial operations
that may impact groundwater conditions. Groundwater contamination
resulting from spills or releases of petroleum products is an inherent risk
within the midstream energy industry. To the extent that groundwater
contamination requiring remediation exists along our pipeline systems as a
result of past operations, we believe any such contamination could be controlled
or remedied without having a material adverse effect on our financial position,
results of operations and cash flows, but such costs are site specific and we
cannot predict that the effect will not be material in the
aggregate.
Air
Emissions
Our operations are subject to the
Federal Clean Air Act (the “Clean Air Act”) and comparable state laws and
regulations. These laws and regulations regulate emissions of air
pollutants from various industrial sources, including our facilities, and also
impose various monitoring and reporting requirements. Such laws and regulations
may require that we obtain pre-approval for the construction or modification of
certain projects or facilities expected to produce air emissions or result in
the increase of existing air emissions, obtain and strictly comply with air
permits containing various emissions and operational limitations, or utilize
specific emission control technologies to limit emissions.
Our
permits and related compliance obligations under the Clean Air Act, as well as
recent or soon to be adopted changes to state implementation plans for
controlling air emissions in regional, non-attainment areas, may require our
operations to incur capital expenditures to add to or modify existing air
emission control equipment and strategies. In addition, some of our
facilities are included within the categories of hazardous air pollutant
sources, which are subject to increasing regulation under the Clean Air Act and
many state laws. Our failure to comply with these requirements could
subject us to monetary penalties, injunctions, conditions or restrictions on
operations and enforcement actions. We may be required to incur certain
capital expenditures in the future for air pollution control equipment in
connection with obtaining and maintaining operating permits and approvals for
air emissions. We believe, however, that such requirements will not have a
material adverse effect on our operations, and the requirements are not expected
to be any more burdensome to us than to any other similarly situated
companies.
Some
recent scientific studies have suggested that emissions of certain gases,
commonly referred to as “greenhouse gases” and including carbon dioxide and
methane, may be contributing to the warming of the Earth’s atmosphere. In
response to such studies, the U.S. Congress is considering legislation to reduce
emissions of greenhouse gases. In addition, at least 17 states have
declined to wait on Congress to develop and implement climate control
legislation and have already taken legal measures to reduce emissions of
greenhouse gases. Also, as a result of the U.S. Supreme Court’s decision
on April 2, 2007 in Massachusetts, et al. v. EPA,
the EPA must consider whether it is required to regulate greenhouse gas
emissions from mobile sources (e.g., cars and trucks) even if Congress does not
adopt new legislation specifically addressing emissions of greenhouse
gases. The Supreme Court’s position in the Massachusetts case that
greenhouse gases fall under the federal Clean Air Act’s definition of “air
pollutant” may also
result in
future regulation of greenhouse gas emissions from stationary sources under
various Clean Air Act programs, including those that may be used in our
operations. It is not possible at this time to predict how legislation
that may be enacted to address greenhouse gas emissions would impact our
business. However, future laws and regulations could result in increased
compliance costs or additional operating restrictions, and could have a material
adverse effect on our business, financial position, demand for our operations,
results of operations, and cash flows.
Solid
Waste
In our normal operations, we generate
hazardous and non-hazardous solid wastes, including hazardous substances, that
are subject to the requirements of the federal Resource Conservation and
Recovery Act (“RCRA”) and comparable state laws, which impose detailed
requirements for the handling, storage treatment and disposal of hazardous and
solid waste. We also utilize waste minimization and recycling processes to
reduce the volumes of our waste. Amendments to RCRA required the EPA
to promulgate regulations banning the land disposal of all hazardous wastes
unless the waste meets certain treatment standards or the land-disposal method
meets certain waste containment criteria. In the past, although we
utilized operating and disposal practices that were standard in the industry at
the time, hydrocarbons and other materials may have been disposed of or
released. In the future we may be required to remove or remediate
these materials.
Environmental
Remediation
The Comprehensive Environmental
Response, Compensation and Liability Act (“CERCLA”), also known as “Superfund,”
imposes liability, without regard to fault or the legality of the original act,
on certain classes of persons who contributed to the release of a “hazardous
substance” into the environment. These persons include the owner or operator of
a facility where a release occurred, transporters that select the site of
disposal of hazardous substances and companies that disposed of or arranged for
the disposal of any hazardous substances found at a facility. Under CERCLA,
these persons may be subject to joint and several liability for the costs of
cleaning up the hazardous substances that have been released into the
environment, for damages to natural resources and for the costs of certain
health studies. CERCLA also authorizes the EPA and, in some
instances, third parties to take actions in response to threats to the public
health or the environment and to seek to recover the costs they incur from the
responsible classes of persons. It is not uncommon for neighboring
landowners and other third parties to file claims for personal injury and
property damage allegedly caused by hazardous substances or other pollutants
released into the environment. Despite the “petroleum exclusion” of
CERCLA that currently encompasses natural gas, we may nonetheless handle
“hazardous substances” subject to CERCLA in the course of our operations and our
pipeline systems may generate wastes that fall within CERCLA’s definition of a
“hazardous substance.” In the event a disposal facility previously
used by us requires clean up in the future, we may be responsible under CERCLA
for all or part of the costs required to clean up sites at which such wastes
have been disposed.
Pipeline
Safety Matters
We are subject to regulation by the
United States Department of Transportation (“DOT”) under the Accountable
Pipeline and Safety Partnership Act of 1996, sometimes referred to as the
Hazardous Liquid Pipeline Safety Act (“HLPSA”), and comparable state statutes
relating to the design, installation, testing, construction, operation,
replacement and management of our pipeline facilities. The HLPSA covers
petroleum and petroleum products. The HLPSA requires any entity that
owns or operates pipeline facilities to (i) comply with such regulations, (ii)
permit access to and copying of records, (iii) file certain reports and (iv)
provide information as required by the Secretary of
Transportation. We believe that we are in material compliance with
these HLPSA regulations.
We are also subject to the DOT
regulation requiring qualification of pipeline personnel. The
regulation requires pipeline operators to develop and maintain a written
qualification program for individuals performing covered tasks on pipeline
facilities. The intent of this regulation is to ensure a qualified
work force and to reduce the probability and consequence of incidents caused by
human error.
The
regulation establishes qualification requirements for individuals performing
covered tasks. We believe that we are in material compliance with
these DOT regulations.
In addition, we are subject to the DOT
Integrity Management regulations, which specify how companies should assess,
evaluate, validate and maintain the integrity of pipeline segments that, in the
event of a release, could impact High Consequence Areas
(“HCAs”). HCAs are defined to include populated areas, unusually
sensitive environmental areas and commercially navigable
waterways. The regulation requires the development and implementation
of an Integrity Management Program that utilizes internal pipeline inspection,
pressure testing, or other equally effective means to assess the integrity of
HCA pipeline segments. The regulation also requires periodic review
of HCA pipeline segments to ensure that adequate preventative and mitigative
measures exist and that companies take prompt action to address integrity issues
raised by the assessment and analysis. We have identified our HCA
pipeline segments and developed an appropriate Integrity Management
Program.
Risk
Management Plans
We are
subject to the EPA’s Risk Management Plan regulations at certain
facilities. These regulations are intended to work with the
Occupational Safety and Health Act (“OSHA”) Process Safety Management
regulations (see “Safety Matters” below) to minimize the offsite consequences of
catastrophic releases. The regulations required us to develop and
implement a risk management program that includes a five-year accident history,
an offsite consequence analysis process, a prevention program and an emergency
response program. We believe we are operating in material compliance
with our risk management program.
Safety
Matters
Certain of our facilities are also
subject to the requirements of the federal OSHA and comparable state
statutes. We believe we are in material compliance with OSHA and
state requirements, including general industry standards, record keeping
requirements and monitoring of occupational exposures.
We are subject to OSHA Process Safety
Management (“PSM”) regulations, which are designed to prevent or minimize the
consequences of catastrophic releases of toxic, reactive, flammable or explosive
chemicals. These regulations apply to any process which involves a
chemical at or above the specified thresholds or any process which involves
certain flammable liquid or gas. We believe we are in material
compliance with the OSHA PSM regulations.
The OSHA hazard communication standard,
the EPA community right-to-know regulations under Title III of the federal
Superfund Amendment and Reauthorization Act and comparable state statutes
require us to organize and disclose information about the hazardous materials
used in our operations. Certain parts of this information must be
reported to employees, state and local governmental authorities and local
citizens upon request.
Employees
Like many publicly traded partnerships,
we have no employees. All of our management, administrative and
operating functions are performed by employees of EPCO pursuant to an
administrative services agreement (the “ASA”). For additional
information regarding the ASA, see “EPCO Administrative Services Agreement”
under Item 13 of this annual report. As of December 31, 2008, there
were approximately 3,500 EPCO personnel who spend all or a portion of their time
engaged in our business. Approximately 2,100 of these individuals
devote all of their time performing management and operating duties for
us. The remaining approximate 1,400 personnel are part of EPCO’s
shared service organization and spend a portion of their time engaged in our
business.
Available
Information
As a
large accelerated filer, we electronically file certain documents with the U.S.
Securities and Exchange Commission (“SEC”). We file annual reports on
Form 10-K; quarterly reports on Form 10-Q; and current reports on Form 8-K (as
appropriate); along with any related amendments and supplements
thereto. Occasionally, we may also file registration statements and
related documents in connection with equity or debt offerings. You
may read and copy any materials we file with the SEC at the SEC’s Public
Reference Room at 100 F Street, NE, Washington, DC 20549. You
may obtain information regarding the Public Reference Room by calling the SEC at
(800) SEC-0330. In addition, the SEC maintains an Internet website at
www.sec.gov
that contains reports and other information regarding registrants that file
electronically with the SEC, including us.
We provide electronic access to our
periodic and current reports on our Internet website, www.epplp.com. These
reports are available as soon as reasonably practicable after we electronically
file such materials with, or furnish such materials to, the SEC. You
may also contact our investor relations department at (866) 230-0745 for paper
copies of these reports free of charge.
An
investment in our common units involves certain risks. If any of
these risks were to occur, our business, financial position, results of
operations and cash flows could be materially adversely affected. In
that case, the trading price of our common units could decline and you could
lose part or all of your investment.
The
following section lists some, but not all, of the key risk factors that may have
a direct impact on our business, financial position, results of operations and
cash flows.
Risks
Relating to Our Business
Changes
in demand for and production of hydrocarbon products may materially adversely
affect our financial position, results of operations and cash
flows.
We operate predominantly in the
midstream energy sector which includes gathering, transporting, processing,
fractionating and storing natural gas, NGLs and crude oil. As such,
our financial position, results of operations and cash flows may be materially
adversely affected by changes in the prices of these hydrocarbon products and by
changes in the relative price levels among these hydrocarbon
products. Changes in prices and relative price levels may impact
demand for hydrocarbon products, which in turn may impact production, demand and
volumes of product for which we provide services. We may also incur credit and
price risk to the extent counterparties do not perform in connection with our
marketing of natural gas, NGLs and propylene.
In the
past, the price of natural gas has been extremely volatile, and we expect this
volatility to continue. The New York Mercantile Exchange daily
settlement price for natural gas for the prompt month contract in 2006 ranged
from a high of $10.63 per MMBtu to a low of $4.20 per
MMBtu. In 2007, the same index ranged from a high of $8.64 per MMBtu
to a low of $5.38 per MMBtu. In 2008, the same index ranged from a
high of $13.58 per MMBtu to a low of $5.29 per MMBtu.
Generally, the prices of natural gas,
NGLs, crude oil and other hydrocarbon products are subject to fluctuations in
response to changes in supply, demand, market uncertainty and a variety of
additional factors that are impossible to control. Some of these
factors include:
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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;
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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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We are exposed to natural gas and NGL
commodity price risk under certain of our natural gas processing and gathering
and NGL fractionation contracts that provide for our fees to be calculated based
on a regional natural gas or NGL price index or to be paid in-kind by taking
title to natural gas or NGLs. A decrease in natural gas and NGL
prices can result in lower margins from these contracts, which may materially
adversely affect our financial position, results of operations and cash
flows.
Our
operating results in one or more geographic regions may also be affected by
uncertain or changing economic conditions within that region, such as the
challenges that are currently affecting economic conditions in the United
States. Volatility in commodity prices may also have an impact on
many of our customers, which in turn could have a negative impact on their
ability to meet their obligations to us.
A
decline in the volume of natural gas, NGLs and crude oil delivered to our
facilities could adversely affect our financial position, results of operations
and cash flows.
Our profitability could be materially
impacted by a decline in the volume of natural gas, NGLs and crude oil
transported, gathered or processed at our facilities. A material
decrease in natural gas or crude oil production or crude oil refining, as a
result of depressed commodity prices, a decrease in domestic and international
exploration and development activities or otherwise, could result in a decline
in the volume of natural gas, NGLs and crude oil handled by our
facilities.
The crude oil, natural gas and NGLs
currently transported, gathered or processed at our facilities originate from
existing domestic and international resource basins, which naturally deplete
over time. To offset this natural decline, our facilities will need
access to production from newly discovered properties that are either being
developed or expected to be developed. Exploration and development of new
oil and natural gas reserves is capital intensive, particularly offshore in the
Gulf of Mexico. Many economic and business factors are beyond our
control and can adversely affect the decision by producers to explore for and
develop new reserves. These factors could include relatively low oil
and natural gas prices, cost and availability of equipment and labor, regulatory
changes, capital budget limitations, the lack of available capital or the
probability of success in finding hydrocarbons. For example, a
sustained decline in the price of natural gas and crude oil could result in a
decrease in natural gas and crude oil exploration and development activities in
the regions where our facilities are located. This could result in a
decrease in volumes to our offshore platforms, natural gas processing plants,
natural gas, crude oil and NGL pipelines, and NGL fractionators, which would
have a material adverse affect on our financial position, results of operations
and cash flows. Additional reserves, if discovered, may not be
developed in the near future or at all.
In addition, imported liquefied natural
gas (“LNG”), is expected to be a significant component of future natural gas
supply to the United States. Much of this increase in LNG supplies is
expected to be imported through new LNG facilities to be developed over the next
decade. Twelve LNG projects have been approved by the FERC to be
constructed in the Gulf Coast region and an additional two LNG projects
have been proposed for the region. We cannot predict which, if any,
of these new projects will be
constructed. We
may not realize expected increases in future natural gas supply available to our
facilities and pipelines if (i) a significant number of these new projects fail
to be developed with their announced capacity, (ii) there are significant delays
in such development, (iii) they are built in locations where they are not
connected to our assets or (iv) they do not influence sources of supply on our
systems. If the expected increase in natural gas supply through
imported LNG is not realized, projected natural gas throughput on our pipelines
would decline, which could have a material adverse effect on our financial
position, results of operations and cash flows.
A
decrease in demand for NGL products by the petrochemical, refining or heating
industries could materially adversely affect our financial position,
results of operations and cash flows.
A decrease in demand for NGL products
by the petrochemical, refining or heating industries, whether because of general
economic conditions, reduced demand by consumers for the end products made with
NGL products, increased competition from petroleum-based products due to pricing
differences, adverse weather conditions, government regulations affecting prices
and production levels of natural gas or the content of motor gasoline or other
reasons, could materially adversely affect our financial position, results of
operations and cash flows. For example:
Ethane. Ethane is primarily
used in the petrochemical industry as feedstock for ethylene, one of the basic
building blocks for a wide range of plastics and other chemical
products. If natural gas prices increase significantly in relation to
NGL product prices or if the demand for ethylene falls (and, therefore, the
demand for ethane by NGL producers falls), it may be more profitable for natural
gas producers to leave the ethane in the natural gas stream to be burned as fuel
than to extract the ethane from the mixed NGL stream for sale as an ethylene
feedstock.
Propane. The demand for propane as a
heating fuel is significantly affected by weather
conditions. Unusually warm winters could cause the demand for propane
to decline significantly and could cause a significant decline in the volumes of
propane that we transport.
Isobutane. A reduction in demand for
motor gasoline additives may reduce demand for isobutane. During
periods in which the difference in market prices between isobutane and normal
butane is low or inventory values are high relative to current prices for normal
butane or isobutane, our operating margin from selling isobutane could be
reduced.
Propylene. Propylene is sold to
petrochemical companies for a variety of uses, principally for the production of
polypropylene. Propylene is subject to rapid and material price
fluctuations. Any downturn in the domestic or international economy
could cause reduced demand for, and an oversupply of propylene, which could
cause a reduction in the volumes of propylene that we transport.
We
face competition from third parties in our midstream businesses
Even if
crude oil and natural gas reserves exist in the areas accessed by our
facilities and are ultimately produced, we may not be chosen by the producers in
these areas to gather, transport, process, fractionate, store or otherwise
handle the hydrocarbons that are produced. We compete with others,
including producers of oil and natural gas, for any such production on the basis
of many factors, including but not limited to:
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geographic
proximity to the production;
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Our
future debt level may limit our flexibility to obtain additional financing and
pursue other business opportunities.
As of
December 31, 2008, we had approximately $9.05 billion of consolidated debt
outstanding including Duncan Energy Partners, which had approximately
$484.3 million of consolidated debt outstanding. The amount of our
future debt could have significant effects on our operations, including, among
other things:
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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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credit
rating agencies may view our 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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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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we
may be at a competitive disadvantage relative to similar companies that
have less debt; and
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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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Our public debt indentures currently do
not limit the amount of future indebtedness that we can create, incur, assume or
guarantee. Although EPO’s Multi-Year Revolving Credit Facility
restricts our ability to incur additional debt above certain levels, any debt we
may incur in compliance with these restrictions may still be
substantial. For information regarding EPO’s Multi-Year Revolving
Credit Facility, see Note 14 of the Notes to Consolidated Financial
Statements included under Item 8 of this annual report.
EPO’s Multi-Year Revolving Credit
Facility, its Japanese Yen Term Loan and each of its indentures for public debt
contain conventional financial covenants and other restrictions. For
example, we are prohibited from making distributions to our partners if such
distributions would cause an event of default or otherwise violate a covenant
under EPO’s Multi-Year Revolving Credit Facility. In addition, under
the terms of our junior subordinated notes, generally, if we elect to defer
interest payments thereon, we are restricted from making distributions with
respect to our equity securities. A breach of any of these
restrictions by us could permit our lenders or noteholders, as applicable, to
declare all amounts outstanding under these debt agreements to be immediately
due and payable and, in the case of EPO’s Multi-Year Revolving Credit Facility,
to terminate all commitments to extend further credit.
Our
ability to access capital markets to raise capital on favorable terms could be
affected by our debt level, the amount of our debt maturing in the next several
years and current maturities, and by prevailing market
conditions. Moreover, if the rating agencies were to downgrade our
credit ratings, then we could experience an increase in our borrowing costs,
difficulty assessing capital markets or a reduction in the market price of our
common units. Such a development could adversely affect our ability
to obtain financing for working capital, capital expenditures or acquisitions or
to refinance existing indebtedness. If we are unable to access the
capital markets on favorable terms in the future, we might be forced to seek
extensions for some of our short-term securities or to refinance some of our
debt obligations through bank credit, as opposed to long-term public debt
securities or equity securities. The price and terms upon which we
might receive such extensions or additional bank credit, if at all, could be
more onerous than those contained in existing debt agreements. Any
such arrangements could, in turn, increase the risk that our
leverage
may adversely affect our future financial and operating flexibility and thereby
impact our ability to pay cash distributions at expected levels.
We
may not be able to fully execute our growth strategy if we encounter illiquid
capital markets or increased competition for investment
opportunities.
Our strategy contemplates growth
through the development and acquisition of a wide range of midstream and other
energy infrastructure assets while maintaining a strong balance
sheet. This strategy includes constructing and acquiring additional
assets and businesses to enhance our ability to compete effectively and
diversifying our asset portfolio, thereby providing more stable cash
flow. We regularly consider and enter into discussions regarding, and
are currently contemplating and/or pursuing, potential joint ventures, stand
alone projects or other transactions that we believe will present opportunities
to realize synergies, expand our role in the energy infrastructure business and
increase our market position.
We will require substantial new capital
to finance the future development and acquisition of assets and
businesses. Any limitations on our access to capital will impair our
ability to execute this strategy. If the cost of such capital becomes
too expensive, our ability to develop or acquire accretive assets will be
limited. We may not be able to raise the necessary funds on
satisfactory terms, if at all. The primary factors that influence our
initial cost of equity include market conditions, fees we pay to underwriters
and other offering costs, which include amounts we pay for legal and accounting
services. The primary factors influencing our cost of borrowing
include interest rates, credit spreads, covenants, underwriting or loan
origination fees and similar charges we pay to lenders.
Recent
conditions in the financial markets have limited our ability to access equity
and credit markets. Generally, credit has become more expensive and
difficult to obtain, and the cost of equity capital has also become more
expensive. Some lenders are imposing more stringent credit terms and
there may be a general reduction in the amount of credit available in the
markets in which we conduct business. Tightening of the credit
markets may have a material adverse effect on us by, among other things,
decreasing our ability to finance expansion projects or business acquisitions on
favorable terms and by the imposition of increasingly restrictive borrowing
covenants. In addition, the distribution yields of new equity issued
may be at a higher yield than our historical levels, making additional equity
issuances more expensive.
We also
compete for the types of assets and businesses we have historically purchased or
acquired. Increased competition for a limited pool of assets could
result in our losing to other bidders more often or acquiring assets at less
attractive prices. Either occurrence would limit our ability to fully
execute our growth strategy. Our inability to execute our growth
strategy may materially adversely affect our ability to maintain or pay higher
distributions in the future.
Our
variable rate debt and future maturities of fixed-rate, long-term debt make us
vulnerable to increases in interest rates. Increases in interest
rates could materially adversely affect our business, financial position,
results of operation and cash flows.
As of December 31, 2008, we had
outstanding $9.05 billion of consolidated debt (excluding the value of interest
rate swaps and currency swaps). Of this amount, approximately $1.57
billion, or 17.3%, was subject to variable interest rates, either as short-term
or long-term variable rate debt obligations or as long-term fixed-rate debt
converted to variable rates through the use of interest rate
swaps. We have approximately $217.6 million in 4.93% fixed-rate debt
maturing in March 2009. We also have an additional $500.0 million of
4.625% fixed-rate Senior Notes maturing in October 2009, $54.0 million of 8.70%
fixed-rate debt maturing in March 2010, and $500.0 million of 4.95% fixed-rate
Senior Notes maturing in June 2010. The rate on our December 2008
issuance of $500.0 million of Senior Notes due January 2014 was
9.75%. Should interest rates continue at current levels or increase
significantly, the amount of cash required to service our debt would
increase. As a result, our financial position, results of operations
and cash flows, could be materially adversely affected.
An increase in interest rates may also
cause a corresponding decline in demand for equity investments, in general, and
in particular, for yield-based equity investments such as our common
units. Any such reduction in demand for our common units resulting
from other more attractive investment opportunities may cause the trading price
of our common units to decline.
Operating
cash flows from our capital projects may not be immediate.
We have announced and are engaged in
several construction projects involving existing and new facilities for which we
have expended or will expend significant capital, and our operating cash flow
from a particular project may not increase until a period of time after its
completion. For instance, if we build a new pipeline or platform or
expand an existing facility, the design, construction, development and
installation may occur over an extended period of time, and we may not receive
any material increase in operating cash flow from that project until a period of
time after it is placed in-service. If we experience any
unanticipated or extended delays in generating operating cash flow from these
projects, we may be required to reduce or reprioritize our capital budget, sell
non-core assets, access the capital markets or decrease or limit distributions
to unitholders in order to meet our capital requirements.
Our
growth strategy may adversely affect our results of operations if we do not
successfully integrate the businesses that we acquire or if we substantially
increase our indebtedness and contingent liabilities to make
acquisitions.
Our growth strategy includes making
accretive acquisitions. As a result, from time to time, we will evaluate
and acquire assets and businesses (either ourselves or Duncan Energy Partners
may do so) that we believe complement our existing operations. We may be
unable to integrate successfully businesses we acquire in the future. We
may incur substantial expenses or encounter delays or other problems in
connection with our growth strategy that could negatively impact our financial
position, results of operations and cash flows.
Moreover, acquisitions and business
expansions involve numerous risks, including but not limited to:
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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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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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If consummated, any acquisition or
investment would also likely result in the incurrence of indebtedness and
contingent liabilities and an increase in interest expense and depreciation,
accretion and amortization expenses. As a result, our capitalization and
results of operations may change significantly following an acquisition. A
substantial increase in our indebtedness and contingent liabilities could have a
material adverse effect on our financial position, results of operations and
cash flows. In addition, any anticipated benefits of a material
acquisition, such as expected cost savings, may not be fully realized, if at
all.
Acquisitions that
appear to be accretive may nevertheless reduce our cash from operations on a per
unit basis.
Even if
we make acquisitions that we believe will be accretive, these acquisitions may
nevertheless reduce our cash from operations on a per unit basis. Any
acquisition involves potential risks, including, among other
things:
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mistaken
assumptions about volumes, revenues and costs, including
synergies;
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an
inability to integrate successfully the businesses we
acquire;
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decrease
in our liquidity as a result of our using a significant portion of our
available cash or borrowing capacity to finance the
acquisition;
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a
significant increase in our interest expense or financial leverage if we
incur additional debt to finance the
acquisition;
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the
assumption of unknown liabilities for which we are not indemnified or for
which our indemnity is inadequate;
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an
inability to hire, train or retain qualified personnel to manage and
operate our growing business and
assets;
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limitations
on rights to indemnity from the
seller;
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mistaken
assumptions about the overall costs of equity or
debt;
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the
diversion of management’s and employees’ attention from other business
concerns;
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unforeseen
difficulties operating in new product areas or new geographic
areas; and
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customer
or key employee losses at the acquired
businesses.
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If we consummate any future
acquisitions, our capitalization and results of operations may change
significantly, and you will not have the opportunity to evaluate the economic,
financial and other relevant information that we will consider in determining
the application of these funds and other resources.
Our
actual construction, development and acquisition costs could exceed forecasted
amounts.
We have significant expenditures for
the development and construction of midstream energy infrastructure assets,
including construction and development projects with significant logistical,
technological and staffing challenges. We may not be able to complete our
projects at the costs we estimated at the time of each project’s initiation or
that we currently estimate. For example, material and labor costs
associated with our projects in the Rocky Mountains region increased over time
due to factors such as higher transportation costs and the availability of
construction personnel. Similarly, force majeure events such as hurricanes
along the Gulf Coast may cause delays, shortages of skilled labor and
additional expenses for these construction and development projects, as were
experienced with Hurricanes Gustav and Ike in 2008.
Our construction
of new assets is subject to regulatory, environmental, political, legal and
economic risks, which may result in delays, increased costs or decreased cash
flows.
One of the ways we intend to grow our
business is through the construction of new midstream energy
assets. The construction of new assets involves numerous operational,
regulatory, environmental, political and legal risks beyond our control and may
require the expenditure of significant amounts of capital. These
potential risks include, among other things, the following:
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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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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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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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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; 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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A
materialization of any of these risks could adversely affect our ability to
achieve growth in the level of our cash flows or realize benefits from expansion
opportunities or construction projects.
Substantially
all of the common units in us that are owned by EPCO and its affiliates are
pledged as security under EPCO's credit facility. Additionally, all
of the member interests in our general partner and all of the common units in us
that are owned by Enterprise GP Holdings are pledged under its credit
facility. Upon an event of default under either of these credit
facilities, a change in ownership or control of us could ultimately
result.
An affiliate of EPCO has pledged
substantially all of its common units in us as security under its credit
facility. EPCO’s credit facility contains customary and other events
of default relating to defaults of EPCO and certain of its subsidiaries,
including certain defaults by us and other affiliates of EPCO. An
event of default, followed by a foreclosure on EPCO’s pledged collateral, could
ultimately result in a change in ownership of us. In addition, the
100.0% membership interest in our general partner and the 13,670,925 of our
common units that are owned by Enterprise GP Holdings are pledged under
Enterprise GP Holdings’ credit facility. Enterprise GP Holdings’
credit facility contains customary and other events of default. Upon
an event of default, the lenders under Enterprise GP Holdings’ credit facility
could foreclose on Enterprise GP Holdings’ assets, which could ultimately result
in a change in control of our general partner and a change in the ownership of
our units held by Enterprise GP Holdings.
The
credit and risk profile of our general partner and its owners could adversely
affect our credit ratings and profile.
The credit and business risk profiles
of the general partner or owners of a general partner may be factors in credit
evaluations of a master limited partnership. This is because the
general partner can exercise significant influence over the business activities
of the partnership, including its cash distribution and acquisition strategy and
business risk profile. Another factor that may be considered is the
financial condition of the general partner and its owners, including the degree
of their financial leverage and their dependence on cash flow from the
partnership to service their indebtedness.
Entities controlling the owner of our
general partner have significant indebtedness outstanding and are dependent
principally on the cash distributions from their limited partner equity
interests in us,
Enterprise
GP Holdings and TEPPCO to service such indebtedness. Any
distributions by us, Enterprise GP Holdings and TEPPCO to such entities will be
made only after satisfying our then current obligations to
creditors. Although we have taken certain steps in our organizational
structure, financial reporting and contractual relationships to reflect the
separateness of us and our general partner from the entities that control our
general partner, our credit ratings and business risk profile could be adversely
affected if the ratings and risk profiles of EPCO or the entities that control
our general partner were viewed as substantially lower or more risky than
ours.
The
interruption of distributions to us from our subsidiaries and joint ventures may
affect our ability to satisfy our obligations and to make distributions to
our partners.
We are a holding company with no
business operations and our operating subsidiaries conduct all of our operations
and own all of our operating assets. Our only significant assets are
the ownership interests we own in our subsidiaries and joint
ventures. As a result, we depend upon the earnings and cash flow of
our subsidiaries and joint ventures and the distribution of that cash to us in
order to meet our obligations and to allow us to make distributions to our
partners. The ability of our subsidiaries and joint ventures to make
distributions to us may be restricted by, among other things, the provisions of
existing and future indebtedness, applicable state partnership and limited
liability company laws and other laws and regulations, including FERC policies.
For example, all cash flows from Evangeline are currently used to service its
debt.
As of December 31, 2008, we also owned
5,393,100 common units and 37,333,887 Class B units of Duncan Energy Partners
(these Class B units automatically converted to common units of Duncan Energy
Partners on February 1, 2009), representing approximately 74.1% of its
outstanding limited partner units, and owned minority equity interests in
subsidiaries of Duncan Energy Partners that held total assets of approximately
$4.6 billion as of December 31, 2008. With respect to three
subsidiaries of Duncan Energy Partners acquired from us on December 8, 2008 that
held approximately $3.5 billion of total assets as of December 31, 2008,
Duncan Energy Partners has effective priority rights to specified quarterly
distribution amounts ahead of distributions on our retained equity interests in
these subsidiaries.
In
addition, the charter documents governing our joint ventures typically allow
their respective joint venture management committees sole discretion regarding
the occurrence and amount of distributions. Some of the joint
ventures in which we participate have separate credit agreements that contain
various restrictive covenants. Among other things, those covenants
may limit or restrict the joint venture's ability to make distributions to us
under certain circumstances. Accordingly, our joint ventures may be
unable to make distributions to us at current levels if at all.
We
may be unable to cause our joint ventures to take or not to take certain actions
unless some or all of our joint venture participants agree.
We participate in several joint
ventures. Due to the nature of some of these arrangements, each
participant in these joint ventures has made substantial investments in the
joint venture and, accordingly, has required that the relevant charter documents
contain certain features designed to provide each participant with the
opportunity to participate in the management of the joint venture and to protect
its investment, as well as any other assets which may be substantially dependent
on or otherwise affected by the activities of that joint
venture. These participation and protective features customarily
include a corporate governance structure that requires at least a
majority-in-interest vote to authorize many basic activities and requires a
greater voting interest (sometimes up to 100.0%) to authorize more significant
activities. Examples of these more significant activities are large
expenditures or contractual commitments, the construction or acquisition of
assets, borrowing money or otherwise raising capital, transactions with
affiliates of a joint venture participant, litigation and transactions not in
the ordinary course of business, among others. Thus, without the
concurrence of joint venture participants with enough voting interests, we may
be unable to cause any of our joint ventures to take or not to take certain
actions, even though those actions may be in the best interest of us or the
particular joint venture.
Moreover, any joint venture owner may
sell, transfer or otherwise modify its ownership interest in a joint venture,
whether in a transaction involving third parties or the other joint venture
owners. Any such transaction could result in us being required to
partner with different or additional parties.
A
natural disaster, catastrophe or other event could result in severe personal
injury, property damage and environmental damage, which could curtail our
operations and otherwise materially adversely affect our cash flow and,
accordingly, affect the market price of our common units.
Some of our operations involve risks of
personal injury, property damage and environmental damage, which could curtail
our operations and otherwise materially adversely affect our cash
flow. For example, natural gas facilities operate at high pressures,
sometimes in excess of 1,100 pounds per square inch. We also operate
oil and natural gas facilities located underwater in the Gulf of Mexico, which
can involve complexities, such as extreme water pressure. Virtually
all of our operations are exposed to potential natural disasters, including
hurricanes, tornadoes, storms, floods and/or earthquakes. The
location of our assets and our customers’ assets in the U.S. Gulf Coast region
makes them particularly vulnerable to hurricane risk.
If one or more facilities that are
owned by us or that deliver oil, natural gas or other products to us are damaged
by severe weather or any other disaster, accident, catastrophe or event, our
operations could be significantly interrupted. Similar interruptions
could result from damage to production or other facilities that supply our
facilities or other stoppages arising from factors beyond our
control. These interruptions might involve significant damage to
people, property or the environment, and repairs might take from a week or less
for a minor incident to six months or more for a major
interruption. Additionally, some of the storage contracts that we are
a party to obligate us to indemnify our customers for any damage or injury
occurring during the period in which the customers’ natural gas is in our
possession. Any event that interrupts the revenues generated by our
operations, or which causes us to make significant expenditures not covered by
insurance, could reduce our cash available for paying distributions and,
accordingly, adversely affect the market price of our common units.
We believe that EPCO maintains adequate
insurance coverage on our behalf, although insurance will not cover many types
of interruptions that might occur and will not cover amounts up to applicable
deductibles. As a result of market conditions, premiums and
deductibles for certain insurance policies can increase substantially, and in
some instances, certain insurance may become unavailable or available only for
reduced amounts of coverage. For example, change in the insurance
markets subsequent to the hurricanes in 2005 and 2008 have made it more
difficult for us to obtain certain types of coverage. As a result,
EPCO may not be able to renew existing insurance policies on behalf of us or
procure other desirable insurance on commercially reasonable terms, if at
all. If we were to incur a significant liability for which we were
not fully insured, it could have a material adverse effect on our financial
position, results of operations and cash flows. In addition, the
proceeds of any such insurance may not be paid in a timely manner and may be
insufficient if such an event were to occur.
An
impairment of goodwill and intangible assets could reduce our
earnings.
At December 31, 2008, our balance sheet
reflected $706.9 million of goodwill and $855.4 million of intangible
assets. Goodwill is recorded when the purchase price of a business
exceeds the fair market value of the tangible and separately measurable
intangible net assets. Generally accepted accounting principles in
the United States (“GAAP”) require us to test goodwill for impairment on an
annual basis or when events or circumstances occur indicating that goodwill
might be impaired. Long-lived assets such as intangible assets with
finite useful lives are reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount may not be
recoverable. If we determine that any of our goodwill or intangible
assets were impaired, we would be required to take an immediate charge to
earnings with a correlative effect on partners’ equity and balance sheet
leverage as measured by debt to total capitalization.
The
use of derivative financial instruments could result in material financial
losses by us.
We historically have sought to limit a
portion of the adverse effects resulting from changes in energy commodity prices
and interest rates by using financial derivative instruments and other hedging
mechanisms from time to time. To the extent that we hedge our
commodity price and interest rate exposures, we will forego the benefits we
would otherwise experience if commodity prices or interest rates were to change
in our favor. In addition, even though monitored by management,
hedging activities can result in losses. Such losses could occur
under various circumstances, including if a counterparty does not perform its
obligations under the hedge arrangement, the hedge is imperfect, or hedging
policies and procedures are not followed.
Our
pipeline integrity program may impose significant costs and liabilities on
us.
The U.S. DOT issued final rules
(effective March 2001 with respect to hazardous liquid pipelines and
February 2004 with respect to natural gas pipelines) requiring pipeline
operators to develop integrity management programs to comprehensively evaluate
their pipelines, and take measures to protect pipeline segments located in what
the rules refer to as “high consequence areas.” The final rule
resulted from the enactment of the Pipeline Safety Improvement Act of
2002. At this time, we cannot predict the ultimate costs of
compliance with this rule because those costs will depend on the number and
extent of any repairs found to be necessary as a result of the pipeline
integrity testing that is required by the rule. We will continue our
pipeline integrity testing programs to assess and maintain the integrity of our
pipelines. The results of these tests could cause us to incur
significant and unanticipated capital and operating expenditures for repairs or
upgrades deemed necessary to ensure the continued safe and reliable operation of
our pipelines.
Environmental
costs and liabilities and changing environmental regulation, including climate
change regulation, could affect our results of operations, cash flows and
financial condition.
Our operations are subject to extensive
federal, state and local regulatory requirements relating to environmental
affairs, health and safety, waste management and chemical and petroleum
products. Further, we cannot ensure that existing environmental
regulations will not be revised or that new regulations, such as regulations
designed to reduce the emissions of greenhouse gases, will not be adopted or
become applicable to us. Governmental authorities have the power to
enforce compliance with applicable regulations and permits and to subject
violators to civil and criminal penalties, including substantial fines,
injunctions or both. Certain environmental laws, including CERCLA and
analogous state laws and regulations, impose strict, joint and several liability
for costs required to cleanup and restore sites where hazardous substances or
hydrocarbons have been disposed or otherwise released. Moreover,
third parties, including neighboring landowners, may also have the right to
pursue legal actions to enforce compliance or to recover for personal injury and
property damage allegedly caused by the release of hazardous substances,
hydrocarbons or other waste products into the environment.
We will make expenditures in connection
with environmental matters as part of normal capital expenditure programs.
However, future environmental law developments, such as stricter laws,
regulations, permits or enforcement policies, could significantly increase some
costs of our operations, including the handling, manufacture, use, emission or
disposal of substances and wastes.
Climate
change regulation is one area of potential future environmental law
development. Studies have suggested that emissions of certain gases,
commonly referred to as “greenhouse gases,” may be contributing to warming of
the Earth’s atmosphere. Methane, a primary component of natural gas,
and carbon dioxide, a byproduct of the burning of natural gas, are examples of
greenhouse gases. The U.S. Congress is considering legislation to
reduce emissions of greenhouse gases. In addition, at least nine
states in the Northeast and five states in the West have developed initiatives
to regulate emissions of greenhouse gases, primarily through the planned
development of greenhouse gas emission inventories and/or regional greenhouse
gas cap and trade programs. The EPA is separately considering whether
it will regulate greenhouse gases as “air pollutants” under the existing federal
Clean Air Act.
Passage
of climate control legislation or other regulatory initiatives by Congress or
various states of the U.S. or the adoption of regulations by the EPA or
analogous state agencies that regulate or restrict emissions of greenhouse
gases, including methane or carbon dioxide in areas in which we conduct
business, could result in changes to the consumption and demand for natural gas
and could have adverse effects on our business, financial position, results of
operations and prospects. These changes could increase the costs of
our operations, including costs to operate and maintain our facilities, install
new emission controls on our facilities, acquire allowances to authorize our
greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions
and administer and manage a greenhouse gas emissions program. While
we may be able to include some or all of such increased costs in the rates
charged by our pipelines or other facilities, such recovery of costs is
uncertain and may depend on events beyond our control, including the outcome of
future rate proceedings before the FERC and the provisions of any final
legislation.
Federal,
state or local regulatory measures could materially adversely affect our
business, results of operations, cash flows and financial
condition.
The FERC regulates our interstate
natural gas pipelines and natural gas storage facilities under the Natural Gas
Act, and interstate NGL and petrochemical pipelines under the
ICA. The STB regulates our interstate propylene
pipelines. State regulatory agencies regulate our intrastate natural
gas and NGL pipelines, intrastate storage facilities and gathering
lines.
Under the NGA, the FERC has authority
to regulate natural gas companies that provide natural gas pipeline
transportation services in interstate commerce. Its authority to
regulate those services is comprehensive and includes the rates charged for the
services, terms and condition of service and certification and construction of
new facilities. The FERC requires that our services are provided on a
non-discriminatory basis so that all shippers have open access to our pipelines
and storage. Pursuant to the FERC’s jurisdiction over interstate gas
pipeline rates, existing pipeline rates may be challenged by customer complaint
or by the FERC Staff and proposed rate increases may be challenged by
protest.
We have interests in natural gas
pipeline facilities offshore from Texas and Louisiana. These
facilities are subject to regulation by the FERC and other federal agencies,
including the Department of Interior, under the Outer Continental Shelf Lands
Act, and by the DOT’s OPS under the Natural Gas Pipeline Safety
Act.
Our intrastate NGL and natural gas
pipelines are subject to regulation in many states, including Alabama, Colorado,
Louisiana, Mississippi, New Mexico and Texas, and by the FERC pursuant to
Section 311 of the Natural Gas Policy Act. We also have natural gas
underground storage facilities in Louisiana, Mississippi and
Texas. Although state regulation is typically less onerous than at
the FERC, proposed and existing rates subject to state regulation and the
provision of services on a non-discriminatory basis are also subject to
challenge by protest and complaint, respectively.
For a general overview of federal,
state and local regulation applicable to our assets, see “Regulation”
included under Items 1 and 2 of this annual report. This regulatory
oversight can affect certain aspects of our business and the market for our
products and could materially adversely affect our cash flows.
We are subject to
strict regulations at many of our facilities regarding employee safety, and
failure to comply with these regulations could adversely affect our ability to
make distributions to unitholders.
The
workplaces associated with our facilities are subject to the requirements of the
federal Occupational Safety and Health Act, or OSHA, and comparable state
statutes that regulate the protection of the health and safety of workers. In
addition, the OSHA hazard communication standard requires that we maintain
information about hazardous materials used or produced in our operations and
that we provide this information to employees, state and local governmental
authorities and local residents. The failure to comply with OSHA requirements or
general industry standards, keep adequate records or monitor
occupational
exposure to regulated substances could have a material adverse effect on our
business, financial position, results of operations and ability to make
distributions to unitholders.
Terrorist
attacks aimed at our facilities could adversely affect our business, results of
operations, cash flows and financial condition.
Since the September 11, 2001 terrorist
attacks on the United States, the United States government has issued warnings
that energy assets, including our nation’s pipeline infrastructure, may be the
future target of terrorist organizations. Any terrorist attack on our
facilities or pipelines or those of our customers could have a material adverse
effect on our business.
We
depend on the leadership and involvement of Dan L. Duncan and other key
personnel for the success of our businesses.
We depend on the leadership,
involvement and services of Dan L. Duncan, the founder of EPCO and the chairman
of our general partner and other key personnel. Mr. Duncan has been
integral to our success and the success of EPCO due in part to his ability to
identify and develop business opportunities, make strategic decisions and
attract and retain key personnel. The loss of his leadership and
involvement or the services of certain key members of our senior management
team could have a material adverse effect on our business, financial position,
results of operations, cash flows and market price of our
securities.
EPCO’s
employees may be subjected to conflicts in managing our business and the
allocation of time and compensation costs between our business and the business
of EPCO and its other affiliates.
We have no officers or employees and
rely solely on officers of our general partner and employees of
EPCO. Certain of our officers are also officers of EPCO and other
affiliates of EPCO. These relationships may create conflicts of interest
regarding corporate opportunities and other matters, and the resolution of any
such conflicts may not always be in our or our unitholders’ best interests. In
addition, these overlapping officers allocate their time among us, EPCO and
other affiliates of EPCO. These officers face potential conflicts
regarding the allocation of their time, which may adversely affect our business,
results of operations and financial condition.
We have entered into an ASA that
governs business opportunities among entities controlled by EPCO, which includes
us and our general partner, Enterprise GP Holdings and its general partner,
Duncan Energy Partners and its general partner and TEPPCO and its general
partner. For information regarding how business opportunities are
handled within the EPCO group of companies, please read Item 13 of this annual
report.
We do not have an independent
compensation committee, and aspects of the compensation of our executive
officers and other key employees, including base salary, are not reviewed or
approved by our independent directors. The determination of executive officer
and key employee compensation could involve conflicts of interest resulting in
economically unfavorable arrangements for us.
The
global financial crisis may have impacts on our business and financial
condition that we currently cannot predict.
The
continued credit crisis and related turmoil in the global financial system has
had, and may continue to have, an impact on our business and financial
condition. We may face significant challenges if conditions in the
financial markets revert to those that existed in the fourth quarter of
2008. Our ability to access the capital markets may be severely
restricted at a time when we would like, or need, to do so, which could have an
adverse impact on our ability to meet capital commitments and achieve the
flexibility needed to react to changing economic and business
conditions. The credit crisis could have a negative impact on our
lenders or customers, causing them to fail to meet their obligations to
us. Additionally, demand for our services and products depends on
activity and expenditure levels in the energy industry, which are directly and
negatively impacted by depressed oil and gas prices. Also, a decrease
in demand for NGLs by the
petrochemical
and refining industries due to a decrease in demand for their products as a
result of general economic conditions would likely impact demand for our
services and products. Any of these factors could lead to reduced
usage of our pipelines and energy logistics services, which could have a
material negative impact on our revenues and prospects.
Risks
Relating to Our Partnership Structure
We
may issue additional securities without the approval of our common
unitholders.
At any time, we may issue an unlimited
number of limited partner interests of any type (to parties other than our
affiliates) without the approval of our unitholders. Our partnership
agreement does not give our common unitholders the right to approve the issuance
of equity securities including equity securities ranking senior to our common
units. The issuance of additional common units or other equity
securities of equal or senior rank will have the following effects:
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the
ownership interest of a unitholder immediately prior to the issuance will
decrease;
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the
amount of cash available for distributions on each common unit may
decrease;
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the
ratio of taxable income to distributions may
increase;
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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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We
may not have sufficient cash from operations to pay distributions at the current
level following establishment of cash reserves and payments of fees and
expenses, including payments to EPGP.
Because distributions on our common
units are dependent on the amount of cash we generate, distributions may
fluctuate based on our performance. We cannot guarantee that we will
continue to pay distributions at the current level each quarter. The
actual amount of cash that is available to be distributed each quarter will
depend upon numerous factors, some of which are beyond our control and the
control of EPGP. These factors include but are not limited to the
following:
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the
level of our operating costs;
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the
level of competition in our business
segments;
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prevailing
economic conditions;
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the
level of capital expenditures we
make;
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the
restrictions contained in our debt agreements and our debt service
requirements;
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fluctuations
in our working capital needs;
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the
cost of acquisitions, if any; and
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the
amount, if any, of cash reserves established by EPGP in its sole
discretion.
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In addition, you should be aware that
the amount of cash we have available for distribution depends primarily on our
cash flow, including cash flow from financial reserves and working capital
borrowings, not solely on profitability, which is affected by non-cash
items. As a result, we may make cash distributions during periods
when we record losses and we may not make distributions during periods when we
record net income.
We
do not have the same flexibility as other types of organizations to accumulate
cash and equity to protect against illiquidity in the future.
Unlike a corporation, our partnership
agreement requires us to make quarterly distributions to our unitholders of all
available cash reduced by any amounts of reserves for commitments and
contingencies, including capital and operating costs and debt service
requirements. The value of our units and other limited partner
interests may decrease in correlation with decreases in the amount we distribute
per unit. Accordingly, if we experience a liquidity problem in the
future, we may not be able to issue more equity to recapitalize.
Cost
reimbursements and fees due to EPCO and its affiliates, including our general
partner may be substantial and will reduce our cash available for distribution
to holders of our units.
Prior to making any distribution on our
units, we will reimburse EPCO and its affiliates, including officers and
directors of EPGP, for all expenses they incur on our behalf, including
allocated overhead. These amounts will include all costs incurred in
managing and operating us, including costs for rendering administrative staff
and support services to us, and overhead allocated to us by EPCO. The payment of
these amounts could adversely affect our ability to pay cash distributions to
holders of our units. EPCO has sole discretion to determine the
amount of these expenses. In addition, EPCO and its affiliates may
provide other services to us for which we will be charged fees as determined by
EPCO.
EPGP
and its affiliates have limited fiduciary responsibilities to, and conflicts of
interest with respect to, our partnership, which may permit it to favor its own
interests to your detriment.
The directors and officers of EPGP and
its affiliates have duties to manage EPGP in a manner that is beneficial to its
members. At the same time, EPGP has duties to manage our partnership
in a manner that is beneficial to us. Therefore, EPGP’s duties to us
may conflict with the duties of its officers and directors to its
members. Such conflicts may include, among others, the
following:
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neither
our partnership agreement nor any other agreement requires EPGP or EPCO to
pursue a business strategy that favors
us;
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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;
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under
our partnership agreement, EPGP determines which costs incurred by it and
its affiliates are reimbursable by
us;
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EPGP
is allowed to resolve any conflicts of interest involving us and EPGP and
its affiliates;
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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;
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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;
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affiliates
of EPGP, including TEPPCO, may compete with us in certain
circumstances;
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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;
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we
do not have any employees and we rely solely on employees of EPCO and its
affiliates;
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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;
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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;
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EPGP
intends to limit its liability regarding our contractual and other
obligations and, in some circumstances, may be entitled to be indemnified
by us;
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EPGP
controls the enforcement of obligations owed to us by our general partner
and its affiliates; and
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EPGP
decides whether to retain separate counsel, accountants or others to
perform services for us.
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We have
significant business relationships with entities controlled by Dan L. Duncan,
including EPCO and TEPPCO. For detailed information on these
relationships and related transactions with these entities, see Item 13 included
within this annual report.
Unitholders
have limited voting rights and are not entitled to elect our general partner or
its directors, which could lower the trading price of our common
units. In addition, even if unitholders are dissatisfied, they cannot
easily remove our general partner.
Unlike the holders of common stock in a
corporation, unitholders have only limited voting rights on matters affecting
our business and, therefore, limited ability to influence management’s decisions
regarding our business. Unitholders did not elect EPGP or its
directors and will have no right to elect our general partner or its directors
on an annual or other continuing basis. The Board of Directors of our
general partner, including the independent directors, is chosen by the owners of
the general partner and not by the unitholders.
Furthermore, if unitholders are
dissatisfied with the performance of our general partner, they currently have no
practical ability to remove EPGP or its officers or directors. EPGP
may not be removed except upon the vote of the holders of at least 60.0% of our
outstanding units voting together as a single class. Because
affiliates of EPGP currently own approximately 34.0% of our outstanding
common units, the removal of EPGP as our general partner is highly unlikely
without the consent of both EPGP and its affiliates. As a result of
this provision, the trading price of our common units may be lower than other
forms of equity ownership because of the absence or reduction of a takeover
premium in the trading price.
Our
partnership agreement restricts the voting rights of unitholders owning 20.0% or
more of our common units.
Unitholders’ voting rights are further
restricted by a provision in our partnership agreement stating that any units
held by a person that owns 20.0% or more of any class of our common units then
outstanding, other than our general partner and its affiliates, cannot be voted
on any matter. In addition, our partnership agreement contains
provisions limiting the ability of unitholders to call meetings or to acquire
information about our operations, as well as other provisions limiting our
unitholders’ ability to influence the manner or direction of our
management. As a result of this provision, the trading price of our common
units may be lower than other forms of equity ownership because of the absence
or reduction of a takeover premium in the trading price.
EPGP
has a limited call right that may require common unitholders to sell their units
at an undesirable time or price.
If at any time EPGP and its affiliates
own 85.0% or more of the common units then outstanding, EPGP will have the
right, but not the obligation, which it may assign to any of its affiliates or
to us, to acquire all, but not less than all, of the remaining common units held
by unaffiliated persons at a price not less than the then current market
price. As a result, common unitholders may be required to sell their
common units at an undesirable time or price and may therefore not receive any
return on their investment. They may also incur a tax liability upon
a sale of their units.
Our
common unitholders may not have limited liability if a court finds that limited
partner actions constitute control of our business.
Under Delaware law, common unitholders
could be held liable for our obligations to the same extent as a general partner
if a court determined that the right of limited partners to remove our general
partner or to take other action under our partnership agreement constituted
participation in the “control” of our business.
Under Delaware law, our general partner
generally has unlimited liability for our obligations, such as our debts and
environmental liabilities, except for those of our contractual obligations that
are expressly made without recourse to our general partner.
The
limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been
clearly established in some of the states in which we do business. You could
have unlimited liability for our obligations if a court or government agency
determined that:
§
|
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.
|
Unitholders may
have liability to repay distributions.
Under
certain circumstances, our unitholders may have to repay amounts wrongfully
returned or distributed to them. Under Section 17-607 of the Delaware
Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make a
distribution to our unitholders if the distribution would cause our liabilities
to exceed the fair value of our assets. Liabilities to partners on
account of their partnership interests and liabilities that are non-recourse to
the partnership are not counted for purposes of determining whether a
distribution is permitted. Delaware law provides that for a period of
three years from the date of an impermissible distribution, limited partners who
received the distribution and who knew at the time of the distribution that it
violated Delaware law will be liable to the limited partnership for the
distribution amount. A purchaser of common units who becomes a
limited partner is liable for the obligations of the transferring limited
partner to make contributions to the partnership that are known to such
purchaser of common units at the time it became a limited partner and for
unknown obligations if the liabilities could be determined from our partnership
agreement.
Our
general partner’s interest in us and the control of our general partner may be
transferred to a third party without unitholder consent.
Our general partner, in accordance with
our partnership agreement, may transfer its general partner interest without the
consent of unitholders. In addition, our general partner may transfer
its general partner interest to a third party in a merger or consolidation or in
a sale of all or substantially all of its assets without the consent of our
unitholders. Furthermore, there is no restriction in our partnership agreement
on the ability of Enterprise GP Holdings or its affiliates to transfer their
equity interests in our general partner
to a
third party. The new equity owner of our general partner would then
be in a position to replace the board of directors and officers of our general
partner with their own choices and to influence the decisions taken by the board
of directors and officers of our general partner.
Tax
Risks to Common Unitholders
Our tax treatment
depends on our status as a partnership for federal income tax purposes, as well
as our not being subject to a material amount of entity-level taxation by
individual states. If the Internal Revenue Service were to treat us as a
corporation or if we were to become subject to a material amount of entity-level
taxation for state tax purposes, then our cash
available for distribution to our common unitholders would be substantially
reduced.
The anticipated after-tax economic
benefit of an investment in our common units depends largely on our being
treated as a partnership for federal income tax purposes. We have not
requested, and do not plan to request, a ruling from the Internal Revenue
Service (“IRS”) on this matter.
If we were treated as a corporation for
federal income tax purposes, we would pay federal income tax on our taxable
income at the corporate tax rate, which is currently a maximum of
35.0%. Distributions to our unitholders would generally be taxed
again as corporate distributions, and no income, gains, losses or deductions
would flow through to our unitholders. Because a tax would be imposed
upon us as a corporation, the cash available for distributions to our common
unitholders would be substantially reduced. Thus, treatment of us as
a corporation would result in a material reduction in the after-tax return to
our common unitholders, likely causing a substantial reduction in the value of
our common units.
Current law may change, causing us to
be treated as a corporation for federal income tax purposes or otherwise
subjecting us to a material amount of entity level taxation. In
addition, because of widespread state budget deficits and other reasons, several
states (including Texas) are evaluating ways to enhance state-tax collections.
For example, with respect to tax reports due on or after January 1, 2008, our
operating subsidiaries are subject to the Revised Texas Franchise Tax on that
portion of their revenue generated in Texas. Specifically, the
Revised Texas Franchise Tax is imposed at a maximum effective rate of 0.7% of
the operating subsidiaries’ gross revenue that is apportioned to
Texas. If any additional state were to impose an entity-level tax
upon us or our operating subsidiaries, the cash available for distribution to
our common unitholders would be reduced.
The
tax treatment of publicly traded partnerships or an investment in our common
units could be subject to potential legislative, judicial or administrative
changes and differing interpretations, possibly on a retroactive
basis.
The
present U.S. federal income tax treatment of publicly traded partnerships,
including us, or an investment in our common units may be modified by
administrative, legislative or judicial interpretation at any
time. Any modification to the U.S. federal income tax laws and
interpretations thereof could make it more difficult or impossible to meet the
exception for us to be treated as a partnership for U.S. federal income tax
purposes that is not taxable as a corporation, or Qualifying Income Exception,
affect or cause us to change our business activities, affect the tax
considerations of an investment in us, change the character or treatment of
portions of our income and adversely affect an investment in our common
units. For example, in response to certain recent developments,
members of Congress are considering substantive changes to the definition of
qualifying income under Section 7704(d) of the Internal Revenue
Code. It is possible that these legislative efforts could result in
changes to the existing U.S. tax laws that affect publicly traded partnerships,
including us. Modifications to the U.S. federal income tax laws and
interpretations thereof may or may not be applied retroactively. We
are unable to predict whether any changes will ultimately be
enacted. Any such changes could negatively impact the value of an
investment in our common units.
We
prorate our items of income, gain, loss and deduction between transferors and
transferees of our common units each month based upon the ownership of our
common units on the first day of each month, instead of on the basis of the date
a particular common unit is transferred.
We
prorate our items of income, gain, loss and deduction between transferors and
transferees of our common units each month based upon the ownership of our
common units on the first day of each month, instead of on the basis of the date
a particular unit is transferred. The use of this proration method
may not be permitted under existing Treasury regulations, and, accordingly, our
counsel is unable to opine as to the validity of this method. If the
IRS were to successfully challenge this method or new Treasury regulations were
issued, we may be required to change the allocation of items of income, gain,
loss and deduction among our unitholders.
A
successful IRS contest of the federal income tax positions we take may adversely
impact the market for our common units, and the costs of any contests will be
borne by our unitholders and our general partner.
The IRS may adopt positions that differ
from the positions we take, even positions taken with advice of
counsel. It may be necessary to resort to administrative or court
proceedings to sustain some or all of the positions we take. A court
may not agree with some or all of the positions we take. Any contest
with the IRS may materially and adversely impact the market for our common units
and the price at which our common units trade. In addition, the costs
of any contest with the IRS, principally legal, accounting and related fees,
will be borne indirectly by our unitholders and our general
partner.
Even
if our common unitholders do not receive any cash distributions from us, they
will be required to pay taxes on their share of our taxable income.
Common unitholders will be required to
pay federal income taxes and, in some cases, state and local income taxes on
their share of our taxable income whether or not they receive any cash
distributions from us. Our common unitholders may not receive cash
distributions from us equal to their share of our taxable income or even equal
to the actual tax liability which results from their share of our taxable
income.
Tax gain or loss on the disposition
of our common units could be different than expected.
If a common unitholder sells its common
units, the unitholder will recognize a gain or loss equal to the difference
between the amount realized and the unitholder’s tax basis in those common
units. Prior distributions to a unitholder in excess of the total net
taxable income a unitholder is allocated for a common unit, which decreased the
unitholder’s tax basis in that common unit, will, in effect, become taxable
income to the unitholder if the common unit is sold at a price greater than the
unitholder’s tax basis in that common unit, even if the price the unitholder
receives is less than the unitholder’s original cost. A substantial
portion of the amount realized, whether or not representing gain, may be
ordinary income to a unitholder.
Tax-exempt
entities and non-U.S. persons face unique tax issues from owning common
units that may result in adverse tax consequences to them.
Investments in common units by
tax-exempt entities, such as individual retirement accounts (known as
IRAs), other retirement plans and non-U.S. persons, raise issues unique to
them. For example, virtually all of our income allocated to
unitholders who are organizations exempt from federal income tax, including
individual retirement accounts and other retirement plans, will be unrelated
business taxable income and will be taxable to them. Distributions to
non-U.S. persons will be reduced by withholding taxes at the highest applicable
effective tax rate, and non-U.S. persons will be required to file United States
federal income tax returns and pay tax on their share of our taxable
income.
We
will treat each purchaser of our common units as having the same tax benefits
without regard to the units purchased. The IRS may challenge this
treatment, which could adversely affect the value of our common
units.
Because we cannot match transferors and
transferees of common units, we adopt depreciation and amortization positions
that may not conform with all aspects of applicable Treasury
regulations. A successful IRS challenge to those positions could
adversely affect the amount of tax benefits available to a common
unitholder. It also could affect the timing of these tax benefits or
the amount of gain from a sale of common units and could have a negative impact
on the value of our common units or result in audit adjustments to the common
unitholder’s tax returns.
Our
common unitholders will likely be subject to state and local taxes and return
filing requirements in states where they do not live as a result of an
investment in our common units.
In addition to federal income taxes,
our common unitholders will likely be subject to other taxes, including state
and local income taxes, unincorporated business taxes and estate, inheritance or
intangible taxes that are imposed by the various jurisdictions in which we do
business or own property. Our common unitholders will likely be
required to file state and local income tax returns and pay state and local
income taxes in some or all of these various jurisdictions. Further,
they may be subject to penalties for failure to comply with those
requirements. We may own property or conduct business in other states
or foreign countries in the future. It is the responsibility of the
common unitholder to file all federal, state and local tax returns.
The
sale or exchange of 50.0% or more of our capital and profits interests during
any twelve-month period will result in the termination of our partnership for
federal income tax purposes.
We will
be considered to have terminated for federal income tax purposes if there is a
sale or exchange of 50.0% or more of the total interests in our capital and
profits within a twelve-month period. Our termination would, among
other things, result in the closing of our taxable year for all unitholders and
could result in a deferral of depreciation deductions allowable in computing our
taxable income.
We
have adopted certain valuation methodologies that may result in a shift of
income, gain, loss and deduction between EPGP and our
unitholders. The IRS may challenge this treatment, which could
adversely affect the value of our common units.
When we issue additional common units
or engage in certain other transactions, we determine the fair market value of
our assets and allocate any unrealized gain or loss attributable to our assets
to the capital accounts of our unitholders and EPGP. Our methodology
may be viewed as understating the value of our assets. In that case,
there may be a shift of income, gain, loss and deduction between certain
unitholders and EPGP, which may be unfavorable to such
unitholders. Moreover, subsequent purchasers of common units may have
a greater portion of their Internal Revenue code Section 743(b) adjustment
allocated to our tangible assets and a lesser portion allocated to our
intangible assets. The IRS may challenge our methods, or our
allocation of the Section 743(b) adjustment attributable to our tangible and
intangible assets, and allocations of income, gain, loss and deduction between
EPGP and certain of our unitholders.
A successful IRS challenge to these
methods or allocations could adversely affect the amount of taxable income or
loss being allocated to our unitholders. It also could affect the
amount of gain from a unitholder’s sale of common units and could have a
negative impact on the value of the common units or result in audit adjustments
to the unitholder’s tax returns.
None.
On
occasion, we or our unconsolidated affiliates are named as defendants in
litigation relating to our normal business activities, including regulatory and
environmental matters. Although we are insured against various
business risks to the extent we believe it is prudent, there is no assurance
that the nature and amount of such insurance will be adequate, in every case, to
indemnify us against liabilities arising from future legal proceedings as a
result of our ordinary business activities. We are unaware of any
significant litigation, pending or threatened, that could have a significant
adverse effect on our financial position, results of operations or cash
flows. For detailed information regarding our legal proceedings, see
Note 20 of the Notes to Consolidated Financial Statements included under Item 8
of this annual report.
None.
and Issuer Purchases of Equity
Securities.
Market
Information and Cash Distributions
Our common units are listed on
the NYSE under the ticker symbol “EPD.” As of February 2, 2009, there
were approximately 988 unitholders of record of our common units. The
following table presents the high and low sales prices for our common units
during the periods indicated (as reported by the NYSE Composite Transaction
Tape) and the amount, record date and payment date of the quarterly cash
distributions we paid on each of our common units.
|
|
|
|
|
|
|
|
Cash
Distribution History
|
|
|
Price
Ranges
|
|
|
Per
|
|
Record
|
Payment
|
|
|
High
|
|
|
Low
|
|
|
Unit
|
|
Date
|
Date
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
1st
Quarter
|
|
$ |
32.750 |
|
|
$ |
28.060 |
|
|
$ |
0.4750 |
|
Apr.
30, 2007
|
May
10, 2007
|
2nd
Quarter
|
|
$ |
33.350 |
|
|
$ |
30.220 |
|
|
$ |
0.4825 |
|
Jul.
31, 2007
|
Aug.
9, 2007
|
3rd
Quarter
|
|
$ |
33.700 |
|
|
$ |
26.136 |
|
|
$ |
0.4900 |
|
Oct.
31, 2007
|
Nov.
8, 2007
|
4th
Quarter
|
|
$ |
32.450 |
|
|
$ |
29.920 |
|
|
$ |
0.5000 |
|
Jan.
31, 2008
|
Feb.
7, 2008
|
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
|
The quarterly cash distributions shown
in the table above correspond to cash flows for the quarters
indicated. The actual cash distributions (i.e., the payments made to
our partners) occur within 45 days after the end of such quarter. We
expect to fund our quarterly cash distributions to partners primarily with cash
provided by operating activities. For additional information
regarding our cash flows from operating activities, see “Liquidity and
Capital Resources” included under Item 7 of this annual report. Although
the payment of cash distributions is not guaranteed, we expect to continue
to pay comparable cash distributions in the future.
In
January 2009, we sold 10,590,000 common units (including an over-allotment of
990,000 common units) to the public at an offering price of $22.20 per
unit. We used the net offering proceeds of $225.6 million to
temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving
Credit Facility, which may be reborrowed to fund capital expenditures and other
growth projects, and for general partnership purposes.
Recent
Sales of Unregistered Securities
There
were no sales of unregistered equity securities during 2008.
Common
Units Authorized for Issuance Under Equity Compensation Plan
See “Securities Authorized for Issuance
Under Equity Compensation Plans” under Item 12 of this annual report, which is
incorporated by reference into this Item 5.
Issuer
Purchases of Equity Securities
We have
not repurchased any of our common units since 2002. In December 1998,
we announced a common unit repurchase program whereby we, together with certain
affiliates, intended to repurchase up to 2,000,000 of our common units for the
purpose of granting options to management and key employees (amount adjusted for
the 2-for-1 unit split in May 2002). As of February 2, 2009, we and
our affiliates could repurchase up to 618,400 additional common units under this
repurchase program.
The
following table summarizes our repurchase activity during 2008 in connection
with other arrangements:
|
|
|
|
Maximum
|
|
|
|
Total
Number of
|
Number
of Units
|
|
|
Average
|
of
Units Purchased
|
That
May Yet
|
|
Total
Number of
|
Price
Paid
|
as
Part of Publicly
|
Be
Purchased
|
Period
|
Units
Purchased
|
per
Unit
|
Announced
Plans
|
Under
the Plans
|
May
2008
|
21,413
(1)
|
$30.37
|
--
|
--
|
August
2008
|
4,940
(2)
|
$29.19
|
--
|
--
|
September
2008
|
4,565
(3)
|
$25.77
|
--
|
--
|
October
2008
|
54,328
(4)
|
$18.39
|
--
|
--
|
(1)
Of
the 67,500 restricted unit awards that vested in May 2008 and converted to
common units, 21,413 of these units were sold back to the partnership by
employees to cover related withholding tax
requirements.
(2)
Of
the 28,650 restricted unit awards that vested in August 2008 and converted
to common units, 4,940 of these units were sold back to the partnership by
employees to cover related withholding tax
requirements.
(3)
Of
the 16,500 restricted unit awards that vested in September 2008 and
converted to common units, 4,565 of these units were sold back to the
partnership by employees to cover related withholding tax
requirements.
(4)
Of
the 165,958 restricted unit awards that vested in October 2008 and
converted to common units, 54,328 of these units were sold back to the
partnership by employees to cover related withholding tax
requirements.
|
The
following table presents selected historical consolidated financial data of our
partnership. This information has been derived from and should be
read in conjunction with the audited financial statements. In
addition, information regarding our results of operations and liquidity and
capital resources can be found under Item 7 of this annual report. As
presented in the table, amounts are in thousands (except per unit
data).
|
|
For
the Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
Operating results data:
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
21,905,656 |
|
|
$ |
16,950,125 |
|
|
$ |
13,990,969 |
|
|
$ |
12,256,959 |
|
|
$ |
8,321,202 |
|
Income
from continuing operations (2)
|
|
$ |
954,021 |
|
|
$ |
533,674 |
|
|
$ |
599,683 |
|
|
$ |
423,716 |
|
|
$ |
257,480 |
|
Income per
unit from continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
and Diluted
|
|
$ |
1.85 |
|
|
$ |
0.96 |
|
|
$ |
1.22 |
|
|
$ |
0.92 |
|
|
$ |
0.83 |
|
Other
financial data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions
per common unit (3)
|
|
$ |
2.0750 |
|
|
$ |
1.9475 |
|
|
$ |
1.825 |
|
|
$ |
1.698 |
|
|
$ |
1.540 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As
of December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
Financial position data:
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
assets
|
|
$ |
17,957,535 |
|
|
$ |
16,608,007 |
|
|
$ |
13,989,718 |
|
|
$ |
12,591,016 |
|
|
$ |
11,315,461 |
|
Long-term
and current maturities of debt (4)
|
|
$ |
9,108,410 |
|
|
$ |
6,906,145 |
|
|
$ |
5,295,590 |
|
|
$ |
4,833,781 |
|
|
$ |
4,281,236 |
|
Partners'
equity (5)
|
|
$ |
6,084,988 |
|
|
$ |
6,131,649 |
|
|
$ |
6,480,233 |
|
|
$ |
5,679,309 |
|
|
$ |
5,328,785 |
|
Total
units outstanding (excluding treasury) (5)
|
|
|
441,435 |
|
|
|
435,297 |
|
|
|
432,408 |
|
|
|
389,861 |
|
|
|
364,786 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
In
general, our historical operating results and financial position have been
affected by numerous acquisitions since 2002. Our most significant
transaction to date was the GulfTerra Merger, which was completed on
September 30, 2004. The aggregate value of the total consideration we
paid or issued to complete the GulfTerra Merger was approximately $4
billion. We accounted for the GulfTerra Merger and our other
acquisitions using purchase accounting; therefore, the operating results
of these acquired entities are included in our financial results
prospectively from their respective acquisition dates.
(2)
Amounts
presented for the years ended December 31, 2006, 2005 and 2004 are before
the cumulative effect of accounting changes.
(3)
Distributions
per common unit represent declared cash distributions with respect to the
four fiscal quarters of each period presented.
(4)
In
general, the balances of our long-term and current maturities of debt have
increased over time as a result of financing all or a portion of
acquisitions and other capital spending.
(5)
We
regularly issue common units through underwritten public offerings and,
less frequently, in connection with acquisitions or other
transactions. The September 2004 issuance of 104.5 million common
units in connection with the GulfTerra Merger being our largest. For
additional information regarding our partners’ equity and unit history,
see Note 15 of the Notes to Consolidated Financial Statements included
under Item 8 of this annual report.
|
|
For
the years ended December 31, 2008, 2007 and 2006.
The following information should be
read in conjunction with our consolidated financial statements and our
accompanying notes. Our discussion and analysis includes the
following:
§
|
Cautionary
Note Regarding Forward-Looking
Statements.
|
§
|
Significant
Relationships Referenced in this Discussion and
Analysis.
|
§
|
General
Outlook for 2009.
|
§
|
Recent
Developments – Discusses significant developments during the year ended
December 31, 2008.
|
§
|
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, related party transactions, recent
accounting pronouncements and other
matters.
|
As generally used in the energy
industry and in this discussion, the identified terms have the following
meanings:
/d
|
=
per day
|
BBtus
|
=
billion British thermal units
|
Bcf
|
=
billion cubic feet
|
MBPD
|
=
thousand barrels per day
|
MMBbls
|
=
million barrels
|
MMBtus
|
=
million British thermal units
|
MMcf
|
=
million cubic feet
|
Our
financial statements have been prepared in accordance with U.S. generally
accepted accounting principles (“GAAP”).
Cautionary
Note Regarding Forward-Looking Statements
This
discussion contains various forward-looking statements and information that are
based on our beliefs and those of our general partner, as well as assumptions
made by us and information currently available to us. When used in
this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,”
“goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “will,” “believe,”
“may,” “potential” and similar expressions and statements regarding our plans
and objectives for future operations, are intended to identify forward-looking
statements. Although we and our general partner believe that such
expectations reflected in such forward-looking statements are reasonable,
neither we nor our general partner can give any assurances that such
expectations will prove to be correct. Such statements are subject to
a variety of risks, uncertainties and assumptions as described in more detail in
Item 1A of this annual report. If one or more of these risks or
uncertainties materialize, or if underlying
assumptions
prove incorrect, our actual results may vary materially from those anticipated,
estimated, projected or expected. You should not put undue reliance
on any forward-looking statements.
Significant
Relationships Referenced in this Discussion and Analysis
Unless the context requires otherwise,
references to “we,” “us,” “our,” or “Enterprise Products Partners” are intended
to mean the business and operations of Enterprise Products Partners L.P. and its
consolidated subsidiaries.
References to “EPO” mean Enterprise
Products Operating LLC as successor in interest by merger to Enterprise Products
Operating L.P., which is a wholly owned subsidiary of Enterprise Products
Partners through which Enterprise Products Partners conducts substantially all
of its business.
References
to “Duncan Energy Partners” mean Duncan Energy Partners L.P., which is a
consolidated subsidiary of EPO. Duncan Energy Partners is a publicly
traded Delaware limited partnership, the common units of which are listed on the
New York Stock Exchange (“NYSE”) under the ticker symbol “DEP.” References
to “DEP GP” mean DEP Holdings, LLC, which is the general partner of Duncan
Energy Partners and is wholly owned by EPO.
References
to “EPGP” mean Enterprise Products GP, LLC, which is our general
partner.
References to “Enterprise GP Holdings”
mean Enterprise GP Holdings L.P., a publicly traded affiliate, the units of
which are listed on the NYSE under the ticker symbol
“EPE.” Enterprise GP Holdings owns EPGP. References to
“EPE Holdings” mean EPE Holdings, LLC, which is the general partner of
Enterprise GP Holdings.
References
to “TEPPCO” mean TEPPCO Partners, L.P., a publicly traded affiliate, the common
units of which are listed on the NYSE under the ticker symbol
“TPP.” References to “TEPPCO GP” refer to Texas Eastern Products
Pipeline Company, LLC, which is the general partner of TEPPCO and is wholly
owned by Enterprise GP Holdings.
References
to “Energy Transfer Equity” mean the business and operations of Energy Transfer
Equity, L.P. and its consolidated subsidiaries, which include Energy Transfer
Partners, L.P. (“ETP”). Energy Transfer Equity is a publicly traded
Delaware limited partnership, the common units of which are listed on the NYSE
under the ticker symbol “ETE.” The general partner of Energy Transfer
Equity is LE GP, LLC (“LE GP”). On May 7, 2007, Enterprise GP
Holdings acquired non-controlling interests in both LE GP and Energy Transfer
Equity. Enterprise GP Holdings accounts for its investments in LE GP
and Energy Transfer Equity using the equity method of accounting.
References
to “Employee Partnerships” mean EPE Unit L.P. (“EPE Unit I”), EPE Unit II, L.P.
(“EPE Unit II”), EPE Unit III, L.P. (“EPE Unit III”), Enterprise Unit L.P.
(“Enterprise Unit”) and EPCO Unit L.P. (“EPCO Unit”), collectively, all of which
are private company affiliates of EPCO, Inc.
References
to “EPCO” mean EPCO, Inc. and its wholly owned private company affiliates, which
are related parties to all of the foregoing named entities.
We, EPO,
Duncan Energy Partners, DEP GP, EPGP, Enterprise GP Holdings, EPE Holdings,
TEPPCO and TEPPCO GP are affiliates under the common control of Dan L. Duncan,
the Group Co-Chairman and controlling shareholder of EPCO.
Overview
of Business
We are a
North American midstream energy company providing a wide range of services to
producers and consumers of natural gas, natural gas liquids (“NGLs”), crude oil
and certain petrochemicals. In addition, we are an industry leader in
the development of pipeline and other midstream energy infrastructure in the
continental United States and Gulf of Mexico. We are a publicly
traded Delaware
limited
partnership formed in 1998, the common units of which are listed on the NYSE
under the ticker symbol “EPD.”
Our midstream energy asset network
links producers of natural gas, NGLs and crude oil from some of the largest
supply basins in the United States, Canada and the Gulf of Mexico with domestic
consumers and international markets. We have four reportable business
segments: NGL Pipelines & Services; Onshore Natural Gas Pipelines &
Services; Offshore Pipelines & Services; and Petrochemical
Services. Our business segments are generally organized and managed
according to the type of services rendered (or technologies employed) and
products produced and/or sold.
We
conduct substantially all of our business through EPO. We are owned
98.0% by our limited partners and 2.0% by our general partner,
EPGP. EPGP is owned 100.0% by Enterprise GP Holdings.
General
Outlook for 2009
The current global recession and
financial crisis have impacted energy companies generally. The
recession and related slowdown in economic activity has reduced demand for
energy and related products, which in turn has generally led to significant
decreases in the prices of crude oil, natural gas and NGLs. The
financial crisis has resulted in the effective insolvency, liquidation or
government intervention for a number of financial institutions, investment
companies, hedge funds and highly leveraged industrial
companies. This has had an adverse impact on the prices of debt and
equity securities that has generally increased the cost and limited the
availability of debt and equity capital.
Commercial
Outlook
In 2008,
there was significant volatility in the prices of refined products, crude oil,
natural gas and NGLs. For example, the price of West Texas
Intermediate crude oil ranged from a high near $147 per barrel in mid-2008 to
$35 per barrel in January 2009; while the price of natural gas at the Henry Hub
ranged from a high of over $13.00 per MMBtu in mid-2008 to $5.00 per MMBtu in
January 2009. On a composite basis, the average price of NGLs
declined from $1.68 per gallon for the third quarter of 2008 to $0.74 per gallon
for the fourth quarter of 2008. The decrease in energy commodity
prices combined with higher costs of capital have led many crude oil and natural
gas producers to reconsider their drilling budgets for 2009. As a
midstream energy company, we provide services for producers and consumers of
natural gas, NGLs, crude oil and certain petrochemicals. The products
that we process, sell or transport are principally used as fuel for residential,
agricultural and commercial heating; feedstocks in petrochemical manufacturing;
and in the production of motor gasoline.
The decrease
in energy commodity prices has caused many oil and natural gas producers, which
include many of our customers, to reduce their drilling budgets in
2009. This has resulted in a substantial reduction in the number of
drilling rigs operating in the United States as surveyed by Baker Hughes
Incorporated. The U.S. operating rig count decreased from a peak of
2,031 rigs in September 2008 to approximately 1,300 in February
2009. We expect oil and gas producers in our operating areas to
reduce their drilling activity to varying degrees, which may lead to lower crude
oil, natural gas and NGL production growth in the near term and, as a result,
lower transportation, processing and marketing volumes for us than would have
otherwise been the case.
In our
natural gas processing business, we hedged approximately 80% of our equity NGL
production margins for 2008 to mitigate the commodity price risk associated with
these volumes. We have hedged approximately 67% of our expected
equity NGL production margins for 2009. Since the hedges were
consummated at prices that are significantly higher than current levels, we are
expected to be partially insulated from lower natural gas processing margins in
2009.
The
recession has reduced demand for midstream energy services and products by
industrial customers. In the fourth quarter of 2008, the
petrochemical industry experienced a dramatic destocking of inventories, which
reduced demand for purity NGL products such as ethane, propane and normal
butane. We expect that petrochemical demand will strengthen in early
2009 and have starting seeing signs of such
demand
through February 2009 as petrochemical customers have begun to restock their
depleted inventories. This trend is also evidenced by slightly higher
operating rates of U.S. ethylene crackers, which averaged approximately 70% of
capacity in February 2009 as compared to 56% in December 2008. Four
additional ethylene crackers were expected to recommence operations in February
2009. The average utilization rate for ethylene crackers in 2008 was
approximately 80%. Based on currently available information, we
expect that the operating rates of U.S. ethylene crackers will approximate 80%
of capacity in 2009. We expect that crude oil prices will rebound
from recent lows in the second half of 2009. As a result, we believe the
petrochemical industry will continue to prefer NGL feedstocks over crude-based
alternatives such as naphtha. In general, when the price of crude oil
rises relative to that of natural gas, NGLs become more attractive as a source
of feedstocks for the petrochemical industry.
The reduction in near-term demand for
crude oil and NGLs has created a contango market (i.e., a market in which the
price of a commodity is higher in future months than the current spot price) for
these products, which, in turn, we are benefiting from through an increase in
revenues earned by our storage assets in Mont Belvieu, Texas.
Liquidity
Outlook
Debt and
equity capital markets have also experienced significant recent
volatility. The major U.S. and international equity market indices
experienced significant losses in 2008, including losses of approximately 38%
and 34% for the S&P 500 and Dow Jones Industrial Average,
respectively. Likewise, the Alerian MLP Index, which is a recognized
major index for publicly traded partnerships, lost approximately 42% of its
value. The contraction in credit available to and investor
redemptions of holdings in certain investment companies and hedge funds
exacerbated the selling pressure and volatility in both the debt and equity
capital markets. This has resulted in a higher cost of debt and
equity capital for the public and private sector. Near term demand
for equity securities through follow on offerings, including our common
units, may be reduced due to the recent problems encountered by investment
companies and hedge funds, both of which significantly participated in equity
offerings over the past few years.
While the
cost of capital has increased, we have demonstrated our ability to access the
debt and equity capital markets during this distressed period. In
December 2008, we issued $500.0 million of 9.75% senior notes. The
higher cost of capital is evident when you compare the interest rate of the
December 2008 senior notes offering to the $400.0 million of 5.65% senior notes
that we issued in March 2008. On a positive note, our indicative cost
of long-term borrowing has improved approximately 250 basis points in early 2009
in conjunction with the recent improvement in the debt capital markets. We
believe that we will be able to either access the capital markets or utilize
availability under our long-term multi-year revolving credit facility to
refinance our $717.6 million of debt obligations that mature in
2009. In January 2009, we issued approximately 10.6 million of our common
units at an effective annual distribution yield of 9.5%. Net offering
proceeds of $225.6 million were used to reduce borrowings and for general
partnership purposes.
The increase in the cost of capital has
caused us to prioritize our respective internal growth projects to select those
with higher rates of return. However, consistent with our business
strategies, we continuously evaluate possible acquisitions of assets that would
complement our current operations. Given the current state of the
credit markets, we believe competition for such assets has decreased, which may
result in opportunities for us to acquire assets at attractive prices that would
be accretive to our partners and expand our portfolio of midstream energy
assets.
Based on
information currently available, we estimate that our capital spending for
property, plant and equipment in 2009 will approximate $1.00 billion, which
includes $820.0 million for growth capital projects and $180.0 million
for sustaining capital expenditures. The 2009 forecast amounts for
growth capital projects include amounts that are expected to be spent on the
Texas Offshore Port System. See “Recent Developments – Texas Offshore
Port System” for additional information regarding this joint
venture.
We expect
four of our significant construction projects to be completed and the assets
placed into service during the first half of 2009. These projects
include (i) the expansion of the Meeker natural gas processing plant, which
began operations in February 2009, (ii) the Exxon Mobil central treating
facility, (iii) the Sherman Extension natural gas pipeline, and (iv) the Shenzi
Crude Oil Pipeline in the Gulf of Mexico. Substantially all of the
financing to fund these projects has been completed. In 2009, we
expect these projects to contribute significant new sources of revenue,
operating income and cash flow from operations.
Hurricanes
Gustav and Ike damaged a number of energy-related assets onshore and offshore
along the Texas and Louisiana Gulf Coast in the summer of 2008,
including certain of our offshore pipelines and platforms. Repairs
are being completed on our affected assets and they are expected to be
ready to return to service once third party production fields return to
operational status over the course of 2009.
A few of
our customers have experienced severe financial problems leading to a
significant impact on their creditworthiness. These financial
problems are rooted in various factors including the significant use of debt,
current financial crises, economic recession and changes in commodity
prices. We are working to implement, to the extent allowable under
applicable contracts, tariffs and regulations, prepayments and other security
requirements, such as letters of credit, to enhance our respective credit
position relating to amounts owed to us by certain customers. We
cannot provide assurance that one or more of our customers will not default on
their obligations to us or that such a default or defaults will not have a
material adverse effect on our consolidated financial position, results of
operations, or cash flows; however, we believe that we have provided adequate
allowances for such customers.
We expect
our proactive approach to funding capital spending and other partnership needs,
combined with sufficient trade credit to operate our businesses efficiently, and
available borrowing capacity under their credit facilities, to provide us with a
foundation to meet our anticipated liquidity and capital requirements in 2009.
We also believe that we will be able to access the capital markets in 2009
to maintain financial flexibility. Based on information currently
available to us, we believe that we will maintain our investment grade credit
ratings and meet our loan covenant obligations in 2009.
Recent
Developments
The
following information highlights our significant developments since January 1,
2008 through the date of this filing.
Enterprise
Products Partners Issues $225.6 million of Common Units
In
January 2009, Enterprise Products Partners sold 10,590,000 common units
representing limited partner interests (including an over-allotment of 990,000
common units) to the public at an offering price of $22.20 per
unit. Net offering proceeds of $225.6 million were used to reduce
borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility and for
general partnership purposes.
High Island
Offshore System Natural Gas Pipeline Resumes Operations
In
December 2008, repairs were completed on the High Island Offshore System
(“HIOS”) pipeline that was severed in September 2008 during Hurricane
Ike. Federal regulators, after approving our inspection and start-up
procedures, authorized the partnership to resume full service on
HIOS. The pipeline has the capacity to transport up to 1.8 Bcf/d of
natural gas.
Operations
Begin at White River Hub
In
December 2008, we and Questar Pipeline Company (“Questar”), a subsidiary of
Questar Corp., announced that service had begun on the White River Hub. Located
in Rio Blanco County, Colo., the White River Hub currently connects our
natural-gas processing plant at Meeker with four interstate natural gas
pipelines: Rockies Express Pipeline LLC; Questar; Northwest Pipeline GP
(including the Williams Willow Creek processing plant, which is currently under
construction); and TransColorado Gas
Transmission
Company. Two more interstate pipelines, the Wyoming Interstate
Company and Colorado Interstate Gas systems, are expected to be connected during
the first quarter of 2009.
Sale
of Interest in Companies to Duncan Energy Partners
In
December 2008, Duncan Energy Partners acquired controlling equity interests in
three midstream energy companies from affiliates of EPO in a transaction valued
at $730.0 million. Duncan Energy Partners acquired a 51.0% membership
interest in Enterprise Texas Pipeline LLC (“Enterprise Texas”); a 51.0%
general partnership interest in Enterprise Intrastate LP (“Enterprise
Intrastate”); and a 66.0% general partnership interest in Enterprise GC, LP
(“Enterprise GC”). In the aggregate, these companies own more than
8,000 miles of natural gas pipelines with 5.6 Bcf/d of capacity; a leased
natural gas storage facility with 6.8 Bcf of storage capacity; more than 1,000
miles of NGL pipelines; approximately 18 MMBbls of leased NGL storage capacity;
and two NGL fractionators with a combined fractionation capacity of 87
MBPD. All of these assets are located in Texas. As
consideration for this dropdown transaction, EPO received 37,333,887 Class B
units valued at $449.5 million and $280.5 million in cash from Duncan Energy
Partners. The Class B limited partner units automatically converted
to common units of Duncan Energy Partners on February 1, 2009. For
additional information regarding this transaction, see “Other Items – Duncan
Energy Partners Transactions” within this Item 7
EPO
Issues $500.0 Million of Senior Notes
In
December 2008, EPO sold $500.0 million in principal amount of 9.75% fixed-rate,
unsecured senior notes due January 2014 (“Senior Notes O”). Net
proceeds from this offering were used to temporarily reduce borrowings
outstanding under EPO’s Multi-Year Revolving Credit Facility and for general
partnership purposes. For additional information regarding this
issuance of debt, see Note 14 of the Notes to Consolidated Financial
Statements included under Item 8 of this annual report.
EPO
Executes $592.6 Million of Credit Facilities
In
November 2008, EPO executed two senior unsecured credit facilities that provide
the partnership with $592.6 million of incremental borrowing
capacity. The facilities are comprised of a $375.0 million credit
facility maturing in November 2009 and a 20.7 billion yen (approximately $217.6
million U.S. dollar equivalent) term loan maturing in March 2009. The
Japanese term loan has a funded cost of approximately 4.93%, including the cost
of related foreign exchange currency swaps. For additional
information regarding these issuances of debt, see Note 14 of the Notes to
Consolidated Financial Statements included under Item 8 of this annual
report.
Texas
Offshore Port System
In
August 2008, we, together with TEPPCO and Oiltanking Holding Americas, Inc.
(“Oiltanking”), announced the formation of the Texas Offshore Port System, a
joint venture to design, construct, operate and own a Texas offshore crude oil
port and a related onshore pipeline and storage system that would facilitate
delivery of waterborne crude oil to refining centers located along the upper
Texas Gulf Coast. Demand for such projects is being driven by planned and
expected refinery expansions along the Gulf Coast, expected increases in
shipping traffic and operating limitations of regional ship
channels.
The joint
venture’s primary project, referred to as “TOPS,” includes (i) an offshore port
(which will be located approximately 36 miles from Freeport, Texas), (ii)
an onshore storage facility with approximately 3.9 million barrels of crude
oil storage capacity, and (iii) an 85-mile crude oil pipeline system having a
transportation capacity of up to 1.8 million barrels per day, that will extend
from the offshore port to a storage facility near Texas City,
Texas. The joint venture’s complementary project, referred to as the
Port Arthur Crude Oil Express (or “PACE”) will transport crude oil from Texas
City, including crude oil from TOPS, and will consist of a 75-mile pipeline and
1.2 million barrels of crude oil storage capacity in the Port Arthur, Texas
area. Development of the TOPS and PACE projects is supported by
long-term contracts with affiliates of Motiva Enterprises LLC (“Motiva”) and
Exxon Mobil Corporation
(“Exxon
Mobil”), which have committed a combined 725 MBPD of crude oil to the
projects. The timing of the construction and related capital costs of the
TOPS and PACE projects will be affected by the acquisition of requisite
permits.
We,
TEPPCO and Oiltanking each own, through our respective subsidiaries, a one-third
interest in the joint venture. The aggregate cost of the TOPS and PACE
projects is expected to be approximately $1.8 billion (excluding
capitalized interest), with the majority of such capital expenditures currently
expected to occur in 2010 and 2011. We and TEPPCO have each guaranteed up
to approximately $700.0 million, which includes a contingency amount for
potential cost overruns, of the capital contribution obligations of our
respective subsidiary partners in the joint venture. As of December 31,
2008, our investment in the Texas Offshore Port System was $35.9
million.
Acquisition
of Remaining Interest in Dixie
In August
2008, we acquired the remaining 25.8% ownership interest in Dixie Pipeline
Company (“Dixie”) for $57.1 million. As a result of this transaction,
we own 100.0% of Dixie, which owns a 1,371-mile pipeline system that delivers
NGLs (primarily propane) to customers along the U.S. Gulf Coast and southeastern
United States.
Reorganization
of Commercial Management Team
In July 2008, Mr. A. J. Teague,
Executive Vice President, was elected as a Director to the Boards of both our
general partner and that of Duncan Energy Partners and as Chief Commercial
Officer responsible for managing all of the commercial activities of the two
partnerships. In connection with Mr. Teague’s appointment as Chief
Commercial Officer, certain members of our senior management team were realigned
to report to Mr. Teague. Mr. Teague will continue to report to
Michael A. Creel, President and Chief Executive Officer (“CEO”) of Enterprise
Products Partners.
Independence
Trail and Hub Resume Operations
In April 2008, production at the
Independence Hub natural gas platform was shut-in due to a leak in the
flex-joint assembly where the Independence Trail export pipeline connects to the
platform. In July 2008, repairs were completed and the Independence
Hub platform and Trail pipeline returned to operation. Our
Independence Trail export pipeline recorded $17.0 million of expense associated
with the flex-joint repairs. We have submitted a claim with our
insurance carriers regarding the flex-joint repair costs. To the
extent that we receive cash proceeds from this claim in the future, such amounts
would be recorded as income in the period of receipt.
EPO
Issues $1.10 Billion of Senior Notes
In April 2008, EPO sold $400.0 million
in principal amount of 5.65% fixed-rate, unsecured senior notes due April 2013
(“Senior Notes M”) and $700.0 million in principal amount of 6.50% fixed-rate,
unsecured senior notes due January 2019 (“Senior Notes N”). Net
proceeds from this offering were used to temporarily reduce borrowings
outstanding under EPO’s Multi-Year Revolving Credit Facility. For
additional information regarding this issuance of debt, see Note 14 of the Notes
to Consolidated Financial Statements included under Item 8 of this annual
report.
Duncan
Energy Partners’ Shelf Registration Statement
In March
2008, Duncan Energy Partners filed a universal shelf registration statement with
the SEC that authorized its issuance of up to $1.00 billion in debt and equity
securities. As of February 2, 2008, Duncan Energy Partners has issued
$0.5 million in equity securities under this registration
statement.
Pioneer
Cryogenic Natural Gas Processing Facility Commences Operations
In February 2008, we commenced
operations of the Pioneer cryogenic natural gas processing
facility. Located near the Opal Hub in southwestern Wyoming, this new
facility is designed to process up to 700 MMcf/d of natural gas and extract as
much as 30 MBPD of NGLs. We intend to maintain the operational
capability of our Pioneer silica gel natural gas processing plant, which is
located adjacent to the Pioneer cryogenic plant, as a back-up to provide
producers with additional assurance of our processing capability at the
complex. NGLs extracted at our Pioneer complex are transported on our
Mid-America Pipeline System and ultimately to our Hobbs and Mont Belvieu NGL
fractionators.
In late March 2008, operations at our
Pioneer cryogenic natural gas processing facility were temporarily suspended
following a release of natural gas and subsequent fire. No injuries
resulted from the incident, which was restricted to a small area within the
plant. The facility resumed operations in April 2008.
Results
of Operations
We have
four reportable business segments: NGL Pipelines & Services, Onshore Natural
Gas Pipelines & Services, Offshore Pipelines & Services and
Petrochemical Services. Our business segments are generally organized
and managed according to the type of services rendered (or technologies
employed) and products produced and/or sold.
We
evaluate segment performance based on the non-GAAP financial measure of gross
operating margin. Gross operating margin (either in total or by
individual segment) is an important performance measure of the core
profitability of our operations. This measure forms the basis of our
internal financial reporting and is used by senior management in deciding how to
allocate capital resources among business segments. We believe that
investors benefit from having access to the same financial measures that our
management uses in evaluating segment results. The GAAP financial
measure most directly comparable to total segment gross operating margin is
operating income. Our non-GAAP financial measure of total segment
gross operating margin should not be considered as an alternative to GAAP
operating income.
We define
total segment gross operating margin as consolidated operating income before (i)
depreciation, amortization and accretion expense; (ii) operating lease expenses
for which we do not have the payment obligation; (iii) gains and losses from
asset sales and related transactions; and (iv) general and administrative
costs. Gross operating margin is exclusive of other income and
expense transactions, provision for income taxes, minority interest,
extraordinary charges and the cumulative effect of change in accounting
principle. Gross operating margin by segment is calculated by
subtracting segment operating costs and expenses (net of the adjustments noted
above) from segment revenues, with both segment totals before the elimination of
intersegment and intrasegment transactions. Intercompany accounts and
transactions are eliminated in consolidation.
We
include equity in earnings of unconsolidated affiliates in our measurement of
segment gross operating margin and operating income. Our equity
investments with industry partners are a vital component of our business
strategy. They are a means by which we conduct our operations to
align our interests with those of our customers and/or
suppliers. This method of operation also enables us to achieve
favorable economies of scale relative to the level of investment and business
risk assumed versus what we could accomplish on a stand alone
basis. Many of these businesses perform supporting or complementary
roles to our other business operations.
Our consolidated gross operating margin
amounts include the gross operating margin amounts of Duncan Energy Partners on
a 100.0% basis. Volumetric data associated with the operations of
Duncan Energy Partners are also included on a 100.0% basis in our consolidated
statistical data.
For
additional information regarding our business segments, see Note 16 of the Notes
to Consolidated Financial Statements included under Item 8 of this annual
report.
Selected
Price and Volumetric Data
The
following table illustrates selected annual and quarterly industry index prices
for natural gas, crude oil and selected NGL and petrochemical products for the
periods presented.
|
|
|
|
|
|
|
|
Polymer
|
Refinery
|
|
Natural
|
|
|
|
Normal
|
|
Natural
|
Grade
|
Grade
|
|
Gas,
|
Crude
Oil,
|
Ethane,
|
Propane,
|
Butane,
|
Isobutane,
|
Gasoline,
|
Propylene,
|
Propylene,
|
|
$/MMBtu
|
$/barrel
|
$/gallon
|
$/gallon
|
$/gallon
|
$/gallon
|
$/gallon
|
$/pound
|
$/pound
|
|
(1)
|
(2)
|
(1)
|
(1)
|
(1)
|
(1)
|
(1)
|
(1)
|
(1)
|
2006
Averages
|
$7.24
|
$66.09
|
$0.66
|
$1.01
|
$1.20
|
$1.24
|
$1.44
|
$0.47
|
$0.41
|
2007
Averages
|
$6.86
|
$72.30
|
$0.79
|
$1.21
|
$1.42
|
$1.49
|
$1.68
|
$0.52
|
$0.47
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
1st
Quarter
|
$8.03
|
$97.91
|
$1.01
|
$1.47
|
$1.80
|
$1.87
|
$2.12
|
$0.61
|
$0.54
|
2nd
Quarter
|
$10.94
|
$123.88
|
$1.05
|
$1.70
|
$2.05
|
$2.08
|
$2.64
|
$0.70
|
$0.67
|
3rd
Quarter
|
$10.25
|
$118.01
|
$1.09
|
$1.68
|
$1.97
|
$1.99
|
$2.52
|
$0.78
|
$0.66
|
4th
Quarter
|
$6.95
|
$58.32
|
$0.42
|
$0.80
|
$0.90
|
$0.96
|
$1.09
|
$0.37
|
$0.22
|
2008
Averages
|
$9.04
|
$99.53
|
$0.89
|
$1.41
|
$1.68
|
$1.72
|
$2.09
|
$0.62
|
$0.52
|
|
|
|
(1)
Natural
gas, NGL, polymer grade propylene and refinery grade propylene prices
represent an average of various commercial index prices including Oil
Price Information Service (“OPIS”) and Chemical Market Associates, Inc.
(“CMAI”). Natural gas price is representative of Henry-Hub
I-FERC. NGL prices are representative of Mont Belvieu Non-TET
pricing. Refinery grade propylene represents a weighted-average
of CMAI spot prices. Polymer-grade propylene represents average
CMAI contract pricing.
(2)
Crude
oil price is representative of an index price for West Texas
Intermediate.
|
The
following table presents our significant average throughput, production and
processing volumetric data. These statistics are reported on a net
basis, taking into account our ownership interests in certain joint ventures and
reflect the periods in which we owned an interest in such
operations. These statistics include volumes for newly constructed
assets since the dates such assets were placed into service and for recently
purchased assets since the date of acquisition.
|
|
For
the Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
NGL
Pipelines & Services, net:
|
|
|
|
|
|
|
|
|
|
NGL
transportation volumes (MBPD)
|
|
|
1,819 |
|
|
|
1,666 |
|
|
|
1,577 |
|
NGL
fractionation volumes (MBPD)
|
|
|
429 |
|
|
|
394 |
|
|
|
312 |
|
Equity
NGL production (MBPD)
|
|
|
108 |
|
|
|
88 |
|
|
|
63 |
|
Fee-based
natural gas processing (MMcf/d)
|
|
|
2,524 |
|
|
|
2,565 |
|
|
|
2,218 |
|
Onshore
Natural Gas Pipelines & Services, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas transportation volumes (BBtus/d)
|
|
|
7,477 |
|
|
|
6,632 |
|
|
|
6,012 |
|
Offshore
Pipelines & Services, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas transportation volumes (BBtus/d)
|
|
|
1,408 |
|
|
|
1,641 |
|
|
|
1,520 |
|
Crude
oil transportation volumes (MBPD)
|
|
|
169 |
|
|
|
163 |
|
|
|
153 |
|
Platform
natural gas processing (MMcf/d)
|
|
|
632 |
|
|
|
494 |
|
|
|
159 |
|
Platform
crude oil processing (MBPD)
|
|
|
15 |
|
|
|
24 |
|
|
|
15 |
|
Petrochemical
Services, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
Butane
isomerization volumes (MBPD)
|
|
|
86 |
|
|
|
90 |
|
|
|
81 |
|
Propylene
fractionation volumes (MBPD)
|
|
|
58 |
|
|
|
68 |
|
|
|
56 |
|
Octane
additive production volumes (MBPD)
|
|
|
9 |
|
|
|
9 |
|
|
|
9 |
|
Petrochemical
transportation volumes (MBPD)
|
|
|
108 |
|
|
|
105 |
|
|
|
97 |
|
Total,
net:
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL,
crude oil and petrochemical transportation volumes (MBPD)
|
|
|
2,096 |
|
|
|
1,934 |
|
|
|
1,827 |
|
Natural
gas transportation volumes (BBtus/d)
|
|
|
8,885 |
|
|
|
8,273 |
|
|
|
7,532 |
|
Equivalent
transportation volumes (MBPD) (1)
|
|
|
4,434 |
|
|
|
4,111 |
|
|
|
3,809 |
|
(1) Reflects
equivalent energy volumes where 3.8 MMBtus of natural gas are equivalent
to one barrel of NGLs.
|
|
Comparison
of Results of Operations
The
following table summarizes the key components of our results of operations for
the periods indicated (dollars in thousands):
|
|
For
the Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Revenues
|
|
$ |
21,905,656 |
|
|
$ |
16,950,125 |
|
|
$ |
13,990,969 |
|
Operating
costs and expenses
|
|
|
20,460,964 |
|
|
|
16,009,051 |
|
|
|
13,089,091 |
|
General
and administrative costs
|
|
|
90,550 |
|
|
|
87,695 |
|
|
|
63,391 |
|
Equity
in earnings of unconsolidated affiliates
|
|
|
59,104 |
|
|
|
29,658 |
|
|
|
21,565 |
|
Operating
income
|
|
|
1,413,246 |
|
|
|
883,037 |
|
|
|
860,052 |
|
Interest
expense
|
|
|
400,686 |
|
|
|
311,764 |
|
|
|
238,023 |
|
Provision
for income taxes
|
|
|
26,401 |
|
|
|
15,257 |
|
|
|
21,323 |
|
Minority
interest
|
|
|
41,376 |
|
|
|
30,643 |
|
|
|
9,079 |
|
Net
income
|
|
|
954,021 |
|
|