e10vk
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2005
OR
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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)
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Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
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76-0568219
(I.R.S. Employer Identification No.) |
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2727 North Loop West, Houston, Texas
(Address of Principal Executive Offices)
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77008
(Zip Code) |
(713) 880-6500
(Registrants Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
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Title of Each Class
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Name of Each Exchange On Which Registered |
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Common Units
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New York Stock Exchange |
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 is
not contained herein, and will not be contained, to the best of registrants 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,
or a non-accelerated filer. See definition of accelerated filer and large accelerated filer in
Rule 12b-2 of the Exchange Act.
Large accelerated filer þ Accelerated filer o Non-accelerated filer 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 the common units of Enterprise Products Partners L.P. (EPD) held by
non-affiliates at June 30, 2005, 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, 2005, was approximately
$6.3 billion. This figure excludes common units beneficially owned by certain affiliates,
including (i) Dan L. Duncan, (ii) certain trusts established for the benefit of Mr. Duncans family
and (iii) directors of Enterprise Products GP, LLC (our general partner). There were 390,303,358
common units of EPD outstanding at February 15, 2006.
ENTERPRISE PRODUCTS PARTNERS L.P.
TABLE OF CONTENTS
PART I
Item 1. Business.
GENERAL
Enterprise Products Partners L.P. is a North American midstream energy company that provides a
wide range of services to producers and consumers of natural gas, natural gas liquids (NGLs), and
crude oil, and is an industry leader in the development of pipeline and other midstream
infrastructure in the continental United States and Gulf of Mexico. Unless the context requires
otherwise, references to we, us, our, or Enterprise Products Partners are intended to mean
the consolidated business and operations of Enterprise Products Partners L.P. and its subsidiaries.
We are a publicly traded Delaware limited partnership, the common units of which are listed on
the New York Stock Exchange (NYSE) under the ticker symbol EPD. We were formed in April 1998
to own and operate certain NGL related businesses of EPCO, Inc. (EPCO). Our principal executive
offices are located at 2727 North Loop West, Houston, Texas 77008 and our telephone number is (713)
880-6500.
We conduct substantially all of our business through our wholly owned subsidiary, Enterprise
Products Operating L.P. (our Operating Partnership). We are owned 98% by our limited partners
and 2% by Enterprise Products GP, LLC (our general partner, referred to as Enterprise Products
GP). Enterprise Products GP is owned 100% by Enterprise GP Holdings L.P. (Enterprise GP
Holdings), a publicly traded affiliate, the common units of which are listed on the NYSE under the
ticker symbol EPE. The general partner of Enterprise GP Holdings is EPE Holdings, LLC (EPE
Holdings), a wholly owned subsidiary of EPCO. We, Enterprise Products GP, Enterprise GP Holdings
and EPE Holdings are affiliates and under common control of Dan L. Duncan, the Chairman and
controlling shareholder of EPCO.
In September 2004, we completed the GulfTerra Merger transactions, whereby, among other
transactions, GulfTerra Energy Partners, L.P. (GulfTerra) merged with one of our wholly owned
subsidiaries. As a result of the GulfTerra Merger, GulfTerra and its subsidiaries and GulfTerras
general partner (GulfTerra GP) became our wholly owned subsidiaries. The GulfTerra Merger greatly
expanded our asset base to include numerous natural gas and crude oil pipelines, offshore platforms
and other midstream energy assets. Additionally, the GulfTerra Merger included the purchase of
various midstream assets from El Paso Corporation (El
Paso) that are located in South Texas.
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. From time-to-time, 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 SECs 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 1-800-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.
We provide electronic access to our periodic and current reports on our Internet website,
www.epplp.com. These reports are available on our website 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 (713) 880-6521 for paper copies of
these reports free of charge.
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As generally used in the energy industry and in this document, the identified terms have the
following meanings:
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/d
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= per day |
BBtus
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= billion British Thermal units |
Bcf
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= billion cubic feet |
MBPD
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= thousand barrels per day |
Mdth
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= thousand dekatherms |
MMBbls
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= million barrels |
MMBtus
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= million British thermal units |
MMcf
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= million cubic feet |
Mcf
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= thousand cubic feet |
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 Enterprise Products GP, 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, goal, forecast, intend, could, believe, may and similar
expressions and statements regarding our plans and objectives for future operations, are intended
to identify forward-looking statements. Although we and Enterprise Products GP believe that such
expectations reflected in such forward-looking statements are reasonable, neither we nor Enterprise
Products GP 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.
BUSINESS STRATEGY
We operate an integrated midstream asset network within the United States that includes
natural gas gathering, processing, transportation and storage; NGL fractionation (or separation),
transportation, storage and import and export terminaling; crude oil transportation and offshore
production platform services. Our business strategy is to:
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capitalize on expected increases in natural gas, NGL and crude oil production resulting
from development activities in the Rocky Mountain region and Gulf of Mexico; |
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maintain a balanced and diversified portfolio of midstream energy assets and expand
this asset base through growth capital projects and accretive acquisitions of
complementary midstream energy assets; |
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share capital costs and risks through joint ventures or alliances with strategic
partners that will provide the raw materials for these projects or purchase the projects
end products; and |
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increase fee-based cash flows by investing in pipelines and other fee-based businesses
and de-emphasize commodity-based activities. |
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, please read
Capital Spending included under Item 7 of this annual report.
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RECENT DEVELOPMENTS
For information regarding significant events affecting us during 2005, please read Recent
Developments included under Item 7 of this annual report, which is incorporated by reference into
this Item 1.
SEGMENT DISCUSSION
Our midstream 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: (i) NGL
Pipelines & Services; (ii) Onshore Natural Gas Pipelines & Services; (iii) Offshore Pipelines &
Services; and (iv) Petrochemical Services. Our business segments are generally organized and
managed along our asset base according to the type of services rendered (or technology 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, please read Item 1A of this annual report. For
listings and descriptions of our principal plant, pipeline and other properties by segment, please
read Item 2 of this annual report.
For information regarding our general revenue recognition policies and other segment-related
matters, please read Notes 4 and 17 of the Notes to Consolidated Financial Statements included
under Item 8 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 and other
matters. For a discussion of the principal effects of regulation on each of our business segments,
please read Regulation and Environmental within each of the following segment disclosures.
For a general discussion of environmental matters, please read Other Matters Other
Environmental included within this Item 1.
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 12,810 miles and
related storage facilities including our Mid-America Pipeline System, Seminole Pipeline and Dixie
Pipeline systems and (iii) 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, 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.
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Natural gas processing and related NGL marketing activities. At the core of our
natural gas processing business are twenty-four processing plants located in Texas, Louisiana,
Mississippi and New Mexico. Natural gas produced at the wellhead and 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 nations 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 transmission pipeline and commercial quality specifications. In addition,
on an energy equivalent basis, NGLs generally have a greater economic value as a raw material for
petrochemicals and motor gasoline 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 gas processing plants are higher than the incremental
value of the NGL products that would be received by NGL extraction, 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
(mixed percent-of-liquids and fee-based) and keepwhole contracts. Under margin-band and keepwhole
contracts, we take ownership of mixed NGLs extracted from the producers 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 extract 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. Under a percent-of-proceeds contract, we
share in the proceeds generated from the producers sale of the mixed NGLs we extract on their
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
extract and retain 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 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.
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.
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NGL pipelines, storage facilities and import/export terminals. Our NGL pipeline,
storage and terminalling operations include approximately 12,810 miles of NGL pipelines, 150
million barrels of underground NGL and related product storage working capacity and two
import/export facilities.
Our NGL pipelines transport mixed NGLs and other hydrocarbons to fractionation plants;
distribute and collect NGL products to and from 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 in 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
collect a fee based on the number of days a customer has volumes in storage multiplied by a storage
rate for each product. Accordingly, the profitability of our storage operations is primarily
dependent upon the volume of material stored 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 to be delivered to our NGL
storage and processing 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 charges. Accordingly, the
profitability of our import and export activities primarily depends upon 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 nine 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.
Recoveries of mixed NGLs by 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 and Rocky Mountain 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). We are exposed to fluctuations in NGL prices to the
extent we fractionate volumes for customers under percent-of-liquids
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arrangements. Our tolling (or
fee-based) customers generally retain title to the NGLs that we process for them.
Regulation and Environmental. Our Mid-America, Seminole, Dixie, Chunchula, Lou-Tex NGL
pipelines and certain pipelines in which we own equity interests, along with certain pipelines of
the Louisiana Pipeline System, are interstate common carrier liquids pipelines subject to
regulation by the FERC under the Interstate Commerce Act
(ICA). As interstate common carriers, these liquids pipelines must provide service to any shipper
who requests transportation services, provided that products tendered for transportation satisfy
the conditions and specifications contained in the applicable tariff. We are required to maintain
tariffs on file with the FERC that set forth the rates we charge for providing transportation
services on our interstate common carrier liquids pipelines as well as the rules and regulations
governing these services.
We believe that the rates charged for transportation services on our interstate common carrier
liquids pipelines we own or have an interest in are just and reasonable under the ICA. However, we
cannot predict what rates we will be allowed to charge in the future for service on our interstate
common carrier liquids pipelines. Furthermore, because rates charged for transportation services
must be competitive with those charged by other transporters, the rates set forth in our tariffs
will be determined based on competitive factors in addition to regulatory considerations.
Intrastate movements of products on the Seminole, Mid-America, Belle Rose and certain
pipelines of the Louisiana Pipeline System are subject to various other state laws and regulations
that affect the rates we charge and the terms of service. 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.
Our NGL pipelines and services are subject to various safety and environmental statutes,
including: the Hazardous Materials Transportation Act, the Hazardous Liquid Pipeline Safety Act,
the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation
and Liability Act, the Clean Air Act, the Federal Water Pollution Control Act, the Oil Pollution
Act of 1990, the Endangered Species Act, the Occupational Safety and Health Act, the Emergency
Planning, Pipeline Safety Improvement Act of 2002 and Community Right-to-Know Act and similar state
statutes. We have ongoing programs designed to keep our gas processing plants, NGL pipelines and
NGL fractionation, NGL storage and related product storage operations in compliance with
environmental and safety requirements, and we believe that our facilities are in material
compliance with the applicable requirements.
The U.S. Department of Transportation issued final rules (effective March 2001 with respect to
hazardous liquids pipelines, which include NGL and petrochemical pipelines, and February 2004 with
respect to natural gas pipelines) requiring pipeline operators to develop integrity management
programs to comprehensively evaluate their pipelines, and to take measures (including repairs) to
protect pipeline segments located in what the rules refer to as high consequence areas. We have
ongoing programs designed to keep our pipelines in compliance with environmental and safety
requirements, and we believe that our facilities are in material compliance with the applicable
requirements. For information regarding the costs of our pipeline integrity management program,
please read Item 7 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 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
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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 in summer months 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. Our inventory cycle begins in late-February to mid-March
(the seasonal low point); builds through September; 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 area 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 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.
Onshore Natural Gas Pipelines & Services
Our Onshore Natural Gas Pipelines & Services business segment includes approximately 17,200
miles of onshore natural gas pipeline systems that provide for the gathering and transmission of
natural gas in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas. In addition, we
own two salt dome natural gas storage facilities located in Mississippi and lease natural gas
storage facilities located in Texas and Louisiana.
Onshore natural gas pipelines. 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 and Permian supply basins in the Western U.S., or 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 customers or
to other onshore pipelines.
Certain of our onshore natural gas pipelines generate revenue 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. Intrastate natural gas
pipelines (such as our Acadian Gas and Alabama Intrastate systems) may also purchase natural gas
from producers and suppliers
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and resell such natural gas to customers such as electric utility
companies, local natural gas distribution companies and industrial customers.
Our Acadian Gas and Alabama Intrastate pipelines are exposed to commodity price risk to the
extent they take title to natural gas volumes through certain of their contracts. In addition, our
San Juan Gathering and Permian Basin pipeline systems 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, approximately 94%
of the fee-based gathering arrangements of 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.
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. These facilities (our Petal Gas Storage
(Petal) and 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. The high
injection and withdrawal rates of such facilities also allow customers to take advantage of
favorable natural gas prices and to quickly respond in situations where they have natural gas
imbalance issues on pipelines connected to the storage facility. Our salt dome storage facilities
permit sustained periods of high natural gas deliveries, 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)
fixed monthly demand payments, which are associated with storage capacity reservation and paid
regardless of the customers usage of the storage facilities, and (ii) storage fees per unit of
volume stored at the facilities.
Regulation and Environmental. Certain of our interstate natural gas pipelines and the
Petal natural gas storage facility are regulated by the FERC, which approves rates, terms and other
conditions under which these systems can provide services to customers. Pursuant to the FERCs
jurisdiction over interstate gas pipeline rates, existing pipeline rates may be challenged by
customer complaint or by the FERC staff and any proposed rate increase by our offshore natural gas
pipelines may be challenged by protest. The FERCs authority over companies that provide natural
gas pipeline transportation or storage services also includes certification and construction of new
facilities; the acquisition, extension, disposition or abandonment of facilities; the maintenance
of accounts and records; the initiation, extension and discontinuation of covered services; and
various other matters. As noted, our regulated natural gas pipelines have tariffs established
through FERC filings that have a variety of terms and conditions, each of which affect the
operations and profitability of each system. Generally, changes to these fees or terms are subject
to approval by the FERC. In addition, our intrastate natural gas pipelines and natural gas storage
facilities are subject to a variety of state and local regulations, including those that affect the
rates we charge and terms of service.
Our onshore natural gas pipelines and storage facilities are subject to various safety and
environmental statutes, including: the Natural Gas Act, the Natural Gas Policy Act, the Hazardous
Materials Transportation Act, the Hazardous Liquid Pipeline Safety Act, the Resource Conservation
and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act, the
Clean Air Act, the Federal Water Pollution Control Act, the Oil Pollution Act of 1990, the
Endangered Species Act, the Occupational Safety and Health Act, the Emergency Planning, Pipeline
Safety Improvement Act of 2002 and Community Right-to-Know Act and similar state statutes. Our
onshore natural gas pipelines and storage facilities are also subject to pipeline integrity
programs as described under NGL Pipelines & Services Regulation and Environmental.
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At December 31, 2005 and 2004, we had a reserve of approximately $21 million for environmental
remediation costs expected to be incurred by GulfTerra over time associated with mercury meters.
Remediation activities were started during 2005 and are expected to take four years to complete.
Seasonality. Typically, our onshore natural gas pipelines experience higher
throughput rates during the summer months as gas-fired power generation facilities increase output
for residential and commercial demand for electricity for air conditioning. Likewise, seasonality
impacts the timing of injections and withdrawals at our natural gas storage facilities. In the
winter months, natural gas is needed as fuel for residential and commercial heating, and during the
summer months, natural gas is needed by power generation facilities due to the demand for
electricity for air conditioning.
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.
Offshore Pipelines & Services
Our Offshore Pipelines & Services business segment includes (i) approximately 1,190 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 870
miles of offshore Gulf of Mexico crude oil pipeline systems and (iii) seven multi-purpose offshore
hub platforms located in the Gulf of Mexico.
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 (typically 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 they 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 oil to either onshore locations or to other offshore
interconnecting pipelines.
The majority of revenues from our offshore crude oil pipelines are derived from purchase and
sale arrangements whereby we purchase oil from shippers at various receipt points along our crude
oil pipelines for an index-based price (less a price differential) and sell the oil back to the
shippers at various redelivery points at the same index-based price. Net revenue recognized from
such arrangements is based on a price differential per unit of volume (typically in barrels)
multiplied by the volume delivered. In addition, certain of our offshore crude oil pipelines
generate revenues based upon a gathering fee per unit of volume
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(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 production
from reserves committed under long-term contracts for the productive life of the relevant field or
contracts for the purchase and sale of crude oil with terms from two to twelve months. The
revenues we earn for our services are dependent on the volume of crude oil to be delivered and the
amount and term of the reserve commitment by the customer.
Offshore platforms. We have ownership interests in seven multi-purpose offshore hub
platforms located in the Gulf of Mexico. Offshore platforms are critical components of the
offshore 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, 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 fees and commodity
charges. Demand fees represent fixed-fees charged to customers who use 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 fees and commodity charges, but demand
fees generally expire after a contractually fixed period of time.
Regulation and Environmental. Certain of our offshore natural gas pipelines
(primarily our High Island Offshore System) are regulated by the FERC. The jurisdiction of the
FERC over these operations is similar to the FERCs jurisdiction over our interstate
natural gas pipelines and the Petal natural gas storage facility as described under Onshore
Natural Gas Pipelines & Services Regulation and Environmental.
Our offshore pipeline systems are also subject to federal regulation under the Outer
Continental Shelf Lands Act (OCSLA), which calls for nondiscriminatory transportation on
pipelines operating in the outer continental shelf region of the Gulf of Mexico. Each of our oil
pipeline systems has continuing programs of inspection and compliance designed to keep all of our
facilities in compliance with pipeline safety and pollution control requirements. We believe that
our oil pipeline systems are in material compliance with the applicable requirements of these
regulations.
Our offshore pipelines and platforms are subject to various safety and environmental statutes,
including: the OCSLA, the Hazardous Liquid Pipeline Safety Act, the Resource Conservation and
Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act, the Clean
Air Act, the Federal Water Pollution Control Act, the Oil Pollution Act of 1990, the Endangered
Species Act, the Occupational Safety and Health Act, the Emergency Planning and Community
Right-to-Know Act and similar state statutes. We have ongoing programs designed to keep our oil and
natural gas pipelines and offshore platform operations in compliance with environmental and safety
requirements, and we believe that our facilities are in material compliance with the applicable
requirements.
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 area, 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.
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Petrochemical Services
Our Petrochemical Services business segment includes four propylene fractionation facilities,
an isomerization complex, and an octane additive production facility. This segment also includes
approximately 690 miles of petrochemical pipeline systems.
Propylene fractionation. Our propylene fractionation business consists primarily of
four propylene fractionation facilities located in Texas and Louisiana, and approximately 620 miles
of various propylene pipeline systems. 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 propylene can also be produced from chemical
grade propylene feedstock. Chemical grade propylene is also a by-product of olefin (ethylene)
production. The demand for polymer grade propylene is attributable 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 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, the sales prices referenced in
these contracts are market-related and can 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 normal butane, isobutane and high purity isobutane. The principal
uses of isobutane are for alkylate used in the production of motor gasoline, propylene oxide and in
the production of methyl tertiary butyl ether (MTBE) and isooctane. The demand for commercial
isomerization services depends upon the industrys 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 both isooctane and MTBE, which are motor gasoline
additives that increase octane and are used in reformulated motor gasoline blends. This facility
produces isooctane using feedstocks of high-purity isobutane and MTBE using feedstocks of
high-purity isobutane and methanol.
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The facilitys high-purity isobutane feedstock requirements are met using production from our
isomerization units.
The production of MTBE was primarily driven by oxygenated fuel programs enacted under the
federal Clean Air Act Amendments of 1990, which mandated the use of reformulated gasoline in
certain areas of the United States. In recent years, MTBE has been detected in water supplies.
The major source of ground water contamination appears to be leaks from underground storage tanks.
As a result of environmental concerns, several states enacted legislation to ban or significantly
limit the use of MTBE in motor gasoline within their jurisdictions. In addition, the Energy Policy
Act of 2005 eliminates the requirement of oxygenates in reformulated motor gasoline.
As a result of such developments, we modified the facility to produce isooctane in addition to
MTBE. These modifications were completed in mid-2005. We expect isooctane to be in demand by
refiners to replace the amount of octane that is lost as a result of MTBE being eliminated as a
motor gasoline blendstock. Depending on the outcome of various factors, the facility may be
further modified in the future to produce alkylate, another motor gasoline additive.
Regulation and Environmental. Our interstate Lou-Tex Propylene pipeline is a common
carrier pipeline regulated by the Surface Transportation Board (STB). In general, our
petrochemical services operations are subject to various safety and environmental statutes,
including: the Hazardous Liquid Pipeline Safety Act, the Resource Conservation and Recovery Act,
the Comprehensive Environmental Response, Compensation and Liability Act, the Clean Air Act, the
Federal Water Pollution Control Act, the Endangered Species Act, the Occupational Safety and Health
Act, the Emergency Planning and Community Right-to-Know Act, and similar state statutes. Our
petrochemical pipelines are also subject to pipeline integrity programs as described under NGL
Pipelines & Services Regulation and Environmental. We have ongoing programs designed to keep our
storage operations in compliance with environmental and safety regulations, and we believe that our
facilities are in material compliance with the applicable requirements.
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 and MTBE 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 on 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.
In the isomerization market, 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 also compete with other octane additive manufacturing companies primarily on the
basis of price.
OTHER MATTERS
Other Environmental
We are subject to extensive federal, state and local laws and regulations governing
environmental quality and pollution control. These environmental laws and regulations may, in
certain instances, require us to remedy the effects on the environment of the disposal or release
of specified substances at current and former operating sites. We may incur significant costs and
liabilities in order to comply with existing environmental laws and regulations. It is also
possible that other developments, such as claims for
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damages to property, employees, other persons and the environment resulting from current or past
operations, could result in substantial costs and liabilities in the future. It is possible that
new information or future developments, such as increasingly strict environmental laws, could
require us to reassess our potential exposure related to environmental matters. As this
information becomes available, or other relevant developments occur, we will make expense accruals
accordingly. For a summary of our significant environmental-related costs, please read Note 2 of
the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
Pipelines. Several federal and state environmental statutes and regulations may
pertain specifically to the operations of our pipelines. Among these, the Hazardous Materials
Transportation Act regulates materials capable of posing an unreasonable risk to health, safety and
property when transported in commerce, and the Natural Gas Pipeline Safety Act and the Hazardous
Liquid Pipeline Safety Act authorize the development and enforcement of regulations governing
pipeline transportation of natural gas and NGLs. Although federal jurisdiction is exclusive over
regulated pipelines, the statutes allow states to impose additional requirements for intrastate
lines if compatible with federal programs. New Mexico, Texas and Louisiana have developed
regulatory programs that parallel the federal program for the transportation of natural gas and
NGLs by pipelines.
Solid Waste. The operations of our pipelines and plants may generate both hazardous
and nonhazardous solid wastes that are subject to the requirements of the Resource Conservation and
Recovery Act and its regulations, and other federal and state statutes and regulations. Further, it
is possible that some wastes that are currently classified as nonhazardous, via exemption or
otherwise, perhaps including wastes currently generated during pipeline operations, may, in the
future, be designated as hazardous wastes, which would then be subject to more rigorous and
costly treatment, storage, transportation, and disposal requirements. Such changes in the
regulations may result in additional expenditures or operating expenses for us.
Hazardous Substances. The Comprehensive Environmental Response, Compensation and
Liability Act (CERCLA), and comparable state statutes, also known as Superfund laws, impose
liability, without regard to fault or the legality of the original conduct, on certain classes of
persons that cause or contribute to the release of a hazardous substance into the environment.
These persons include the current owner or operator of a site, the past owner or operator of a
site, and companies that transport, dispose of, or arrange for the disposal of the hazardous
substances found at the site. CERCLA also authorizes the Environmental Protection Agency or state
agency, and in some cases, third parties, to take actions in response to threats to the public
health or the environment and to seek to recover from the responsible classes of persons the costs
they incur. Despite the petroleum exclusion of CERCLA Section 101(14) that currently encompasses
crude oil, refined petroleum products, natural gas and NGLs, we may nonetheless handle hazardous
substances, within the meaning of CERCLA or similar state statutes, in the course of our ordinary
operations.
Air. Our operations may be subject to the Clean Air Act and other federal and state
statutes and regulations that impose certain pollution control requirements with respect to air
emissions from operations, particularly in instances where a company constructs a new facility or
modifies an existing facility. We may be required to incur certain capital expenditures in the next
several years for air pollution control equipment in connection with maintaining or obtaining
operating permits and approvals addressing other air emission-related issues. However, we do not
believe these requirements will have a material adverse affect on our operations.
Water. The Federal Water Pollution Control Act imposes strict controls against the
unauthorized discharge of pollutants, including produced waters and other oil and natural gas
wastes, into navigable waters. It provides for civil and criminal penalties for any unauthorized
discharges of oil and other substances and, along with the Oil Pollution Act of 1990 (OPA),
imposes substantial potential liability for the costs of oil or hazardous substance removal,
remediation and damages. Similarly, the OPA imposes liability for the discharge of oil into or upon
navigable waters or adjoining shorelines. State laws for the control of water pollution also
provide varying civil and criminal penalties and liabilities in the case of an unauthorized
discharge of pollutants into state waters.
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Communication of Hazards. The Occupational Safety and Health Act, the Emergency
Planning and Community Right-to-Know Act and comparable state statutes require those entities that
operate facilities for us to organize and disseminate information to employees, state and local
organizations, and the public about the hazardous materials used in our operations and our
emergency planning.
Employees
At December 31, 2005, there were approximately 2,600 persons directly involved in the
management, administration and operations of Enterprise Products Partners, approximately 2,365 of
which are employees of EPCO that provide services to us under an administrative services agreement.
The remaining 235 individuals primarily represent third-party contract personnel. For additional
information regarding our relationship with EPCO, please read Item 13 of this annual report.
Significant Customers
Our revenues are derived from a wide customer base. During 2005, our largest customer, The
Dow Chemical Company, accounted for 6.8% of our consolidated revenues. During 2004 and 2003, our
largest customer, Shell Oil Company and affiliates (Shell), accounted for 6.5% and 5.5% of our
consolidated revenues, respectively.
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Item 1A. Risk Factors.
An investment in our common units involves certain risks. If any of these risks were to
occur, our business, results of operations, cash flows and financial condition 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.
Among the key risk factors that may have a direct impact on our business, results of
operations, cash flows and financial condition are:
Risks Related to Our Business
Changes in the prices of hydrocarbon products may materially adversely affect our results of
operations, cash flows and financial condition.
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
results of operations, cash flows and financial condition 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. 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. These factors
include:
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the level of domestic production; |
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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; and |
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conservation and the extent of governmental regulation of production and the overall
economic environment. |
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 results of operations, cash flows and
financial position.
A decline in the volume of natural gas, NGLs and crude oil delivered to our facilities could
adversely affect our results of operations, cash flows and financial condition.
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 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 available to our facilities will be derived from reserves
produced from existing wells, which reserves naturally decline over time. To offset this natural
decline, our facilities will need access to additional reserves. Additionally, some of our
facilities will be dependent
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on reserves that are expected to be produced from newly discovered properties that are currently
being 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 results of operations, cash flows and financial position. Additional reserves, if
discovered, may not be developed in the near future or at all.
A decrease in demand for NGL products by the petrochemical, refining or heating industries
could materially adversely affect our results of operations, cash flows and financial position.
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 results of operations, cash flows and financial position. For example:
Ethane. If natural gas prices increase significantly in relation to ethane prices, 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.
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. A downturn in the domestic or international economy could cause reduced demand for
propylene, which could cause a reduction in the volumes of propylene that we produce and expose our
investment in inventories of propane/propylene mix to pricing risk due to requirements for
short-term price discounts in the spot or short-term propylene markets.
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We face competition from third parties in our midstream businesses.
Even if 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:
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geographic proximity to the production; |
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costs of connection; |
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available capacity; |
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rates; and |
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access to markets. |
Our future debt level may limit our future financial and operating flexibility.
As of December 31, 2005, we had approximately $4.8 billion 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 significant portion of our cash flow 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 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; |
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our ability to obtain additional financing for working capital, capital expenditures,
acquisitions and general partnership purposes may be limited; |
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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. |
Our public debt indentures currently do not limit the amount of future indebtedness that we
can create, incur, assume or guarantee. Although our 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 our
Multi-Year Revolving Credit Facility, please read Note 14 of the Notes to Consolidated Financial
Statements included under Item 8 of this annual report.
Our Multi-Year Revolving Credit Facility and each of our indentures for our 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 our Multi-Year Revolving Credit Facility. A breach of any of
these restrictions by us could permit our lenders or noteholders, as applicable, to declare all
amounts outstanding under these debt agreements to be immediately due and payable and, in the case
of our Multi-Year Revolving Credit Facility, to terminate all commitments to extend further credit.
For additional information regarding our Multi-Year Revolving Credit Facility, please read Note 14
of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
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Our ability to access capital markets to raise capital on favorable terms will 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 rates.
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.
In addition, we are experiencing increased competition 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 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 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 results of operations, cash flows and financial condition.
Moreover, acquisitions and business expansions involve numerous risks, including:
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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. |
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,
depletion 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 results of operations, cash
flows and financial condition. In addition, any anticipated benefits of a material acquisition,
such as expected cost savings, may not be fully realized, if at all.
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 that we believe complement our existing
operations. We may incur substantial expenses or encounter delays or other problems in connection
with our growth strategy that could negatively impact our results of operations, cash flows and
financial condition.
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 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 results of operations, cash flows and
financial condition.
Our operating cash flows from our capital projects may not be immediate.
We are engaged in several construction projects involving existing and new facilities for
which significant capital has been or will be expended, 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 actual construction, development and acquisition costs could exceed forecasted amounts.
We will have significant expenditures for the development and construction of energy
infrastructure assets, including some construction and development projects with significant
technological challenges. We may not be able to complete our projects at the costs estimated at
the time of each projects initiation.
Substantially
all of the common units in us that are owned by EPCO and its affiliates are pledged as
security under EPCOs 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.
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An affiliate of
EPCO has pledged substantially all of its common units in us as security under
its credit facility. EPCOs 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 EPCOs pledged collateral, could ultimately result in a change in ownership of us. In addition, the 100% membership interest in our general partner and the 13,454,498
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 general partner and
limited partner equity interests in us to service such indebtedness. Any distributions by us to
such entities will be made only after satisfying our then current obligations to our creditors.
Although we have taken certain steps in our organizational structure, financial reporting and
contractual relationships to reflect the separateness of us and Enterprise Products GP from the
entities that control Enterprise Products GP, our credit ratings and business risk profile could be
adversely affected if the ratings and risk profiles of 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. Our only significant assets are the
equity 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.
In addition, the charter documents governing our joint ventures typically vest in the joint
venture management committee 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
ventures 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%) to authorize more significant
20
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.
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 behalf of us, although insurance
will not cover many types of interruptions that might occur. 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. 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 and results of operations. 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, 2005, our balance sheet reflected $494 million of goodwill and $913.6 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 (otherwise known as 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
21
with a correlative effect on
partners equity and balance sheet leverage as measured by debt to total capitalization.
Increases in interest rates could materially adversely affect our business, results of
operations,
cash flows and financial condition.
In addition to our exposure to commodity prices, we have significant exposure to increases in
interest rates. As of December 31, 2005, we had approximately $4.8 billion of consolidated debt,
of which approximately $3.3 billion was at fixed interest rates and approximately $1.5 billion was
at variable interest rates, after giving effect to existing interest swap arrangements. From time
to time, we may enter into additional interest rate swap arrangements, which could increase our
exposure to variable interest rates. As a result, our results of operations, cash flows and
financial condition, could be materially adversely affected by significant increases in interest
rates.
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.
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 oil and natural gas 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. Department of Transportation 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 could materially
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. 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. Third parties may also have the right to pursue legal
actions to enforce compliance.
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,
22
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.
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 interstate 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 Natural Gas Act, 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 FERCs 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 Department of
Transportations Office of Pipeline Safety 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 our intrastate
natural gas pipelines are subject to regulation 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, please
read the regulation and environmental information included under Item 1 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.
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 nations 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 and our subsidiaries businesses.
We depend on the leadership, involvement and services of Dan L. Duncan, the founder of EPCO
and the Chairman of our general partner. 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 any members of our senior management team could have a material
adverse effect on our business, results of operations, cash flows and financial condition.
23
Some
of our executive officers and directors face potential conflicts of
interest in managing our
business.
Certain
of our executive officers and directors are also officers and/or directors of
EPCO, the general partner of Enterprise GP Holdings, the general
partner of TEPPCO and other affiliates of EPCO. These
relationships may create conflicts of interest regarding corporate
opportunities and other matters. The resolution of any such conflicts
may not always be in our or our unitholders best interests. In
addition, these overlapping executive officers and directors allocate their time among EPCO, Enterprise GP
Holdings, TEPPCO and other affiliates of EPCO. These officers and
directors face
potential conflicts regarding the allocation of their time, which may adversely affect our
business, results of operations and financial condition. Please read
Item 10 of this annual report for more detailed information on
which of our officers and directors serve as officers and/or
directors of EPCO, the general partner of Enterprise GP Holdings, the
general partner of TEPPCO and other affiliates of EPCO.
Risks Related to Our Common Units as a Result of Our Partnership Structure
We may issue additional securities without the approval of our common unitholders.
Subject to NYSE rules, 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 proportionate ownership interest of a common unit will decrease; |
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the amount of cash available for distributions on each 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 unit may be diminished; and |
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the market price of our common units may decline. |
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
Enterprise Products GP.
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 Enterprise Products GP. 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 Enterprise Products GP in its sole discretion. |
In addition, you should be aware that our ability to pay the minimum quarterly distribution
each quarter 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 direct 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 Enterprise Products GP 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 Enterprise Products GP and
its affiliates, including officers and directors of Enterprise Products GP, for expenses they incur
on our behalf. The reimbursement of expenses could adversely affect our ability to pay cash
distributions to holders of our units. Enterprise Products GP has sole discretion to determine the
amount of these expenses. In addition, Enterprise Products GP and its affiliates may provide other
services to us for which we will be charged fees as determined by Enterprise Products GP.
Enterprise
Products GP 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 Enterprise Products GP and its affiliates have duties to manage
Enterprise Products GP in a manner that is beneficial to its members. At the same time, Enterprise
Products GP has duties to manage our partnership in a manner that is beneficial to us. Therefore,
Enterprise Products GPs 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 Enterprise Products GP or EPCO to pursue a business strategy
that favors us; |
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decisions of Enterprise Products GP 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 Enterprise Products GP; |
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under our partnership agreement, Enterprise Products GP determines which costs incurred
by it and its affiliates are reimbursable by us; |
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Enterprise Products GP is allowed to resolve any conflicts of
interest involving us and Enterprise Products GP and its affiliates; |
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Enterprise Products GP is allowed to resolve any conflicts of
interest involving us and Enterprise Products GP and its affiliates; |
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Enterprise Products GP 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 Enterprise Products GP 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 Enterprise Products GP, including TEPPCO, may compete with us in certain circumstances; |
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Enterprise Products GP 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, Enterprise Products GP 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 Enterprise
Products GP 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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Enterprise
Products GP 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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Enterprise
Products GP controls the enforcement of obligations owed to us by our
general partner and its affiliates; and |
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Enterprise
Products GP decides whether to retain separate counsel, accountants
or others to perform services for us. |
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,
please read Item 13 included within this annual report.
Even if unitholders are dissatisfied, they cannot easily remove Enterprise Products GP.
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 managements
decisions regarding our business. Unitholders did not elect Enterprise Products GP or its
directors and will have no right to elect our general partner or its directors on an annual or
other continuing basis.
Furthermore, if unitholders are dissatisfied with the
performance of our general partner, they
currently have no practical ability to remove Enterprise Products GP
or the officers or directors of Enterprise Products GP. Enterprise Products GP may
not be removed except upon the vote of the holders of at least 60% of our outstanding units voting
together as a single class. Because affiliates of Enterprise Products GP currently own
approximately 35.6% of our outstanding common units, the removal of Enterprise Products GP as our
general partner is not practicable without the consent of both Enterprise Products GP and its
affiliates.
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Unitholders voting rights are further restricted by a provision in our partnership agreement
stating that any units held by a person that owns 20% or more of any class of our 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 these provisions, 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.
Enterprise Products GP has a limited call right that may require common unitholders to sell
their units at an undesirable time or price.
If at any time Enterprise Products GP and its affiliates own 85% or more of the common units
then outstanding, Enterprise Products GP 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.
In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides
that, under some circumstances, a limited partner may be liable to us for the amount of a
distribution for a period of three years from the date of the distribution.
A large number of our outstanding common units may be sold in the market, which may depress
the market price of our common units.
Shell
owns 29,407,549 of our common units, representing approximately 7.5% of our outstanding
common units at February 15, 2006, and has publicly announced its intention to reduce its holdings
of our common units on an orderly schedule over a period of years, taking into account market
conditions. All of the common units held
by Shell are registered for resale under our effective registration
statement on Form S-3.
Sales of a substantial number of our common units in the public market could cause the market
price of our common units to decline. As of February 22, 2006,
we had 390,308,358 common units
outstanding. Sales of a substantial number of these common units in the trading markets, whether
in a single transaction or series of transactions, or the possibility that these sales may occur,
could reduce the market price of our outstanding common units. In addition, these sales, or the
possibility that these sales may occur, could make it more difficult for us to sell our common
units in the future.
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Tax Risks to Common Unitholders
If we were to become subject to entity level taxation for federal or 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%,
and we likely would pay state taxes as well. Distributions to our unitholders would generally be
taxed again as corporate distributions, and no income, gains, losses or deductions would flow
though 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. Therefore,
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 entity level taxation. For example, because of widespread
state budget deficits, several states are evaluating ways to subject partnerships to entity level
taxation through the imposition of state income, franchise or other forms of taxation. If any
state were to impose a tax upon us as an entity, the cash available for distribution to our common
unitholders would be reduced.
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 even if they do not 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 unitholders 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 unitholders 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 unitholders tax basis in that common unit, even if the price the unitholder
receives is less than the unitholders original cost. A substantial portion of the amount
realized, whether or not representing gain, may be ordinary income to a unitholder.
Tax-exempt entities, regulated investment companies and foreign persons face unique tax issues
from owning common units that may result in adverse tax consequences to them.
28
Investments in common units by tax-exempt entities, such as individual retirement accounts
(known as IRAs), regulated investment companies (known as mutual
funds), and foreign persons raises 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. Recent
legislation treats net income derived from the ownership of certain publicly traded partnerships
(including us) as qualifying income to a regulated investment company. 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 unitholders 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 by 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 United States federal, state
and local tax returns.
The sale or exchange of 50% 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% 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.
Item 1B. Unresolved Staff Comments.
None.
Item 2. Properties.
The following sections provide information regarding our principal plants, pipelines and other
assets by segment. For information regarding our significant historical throughput, production
and processing rates, please read Item 7 of this annual report.
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
29
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.
NGL Pipelines & Services
The following table summarizes the significant NGL pipelines and related storage assets of our
NGL Pipelines & Services business segment at February 1, 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Useable |
|
|
|
|
Our |
|
|
|
|
|
Storage |
|
|
|
|
Ownership |
|
Length |
|
Capacity |
Description of Asset |
|
Location(s) |
|
Interest |
|
(Miles) |
|
(MMBbls) |
|
NGL pipelines: (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-America Pipeline System |
|
Midwest and Western U.S.(2) |
|
|
100 |
% |
|
|
7,226 |
|
|
|
|
|
Dixie Pipeline |
|
South and Southeastern U.S. |
|
|
65.9 |
% (3) |
|
|
1,301 |
|
|
|
|
|
Seminole Pipeline |
|
Texas |
|
|
90 |
% (4) |
|
|
1,281 |
|
|
|
|
|
Texas NGL System (5) |
|
Texas |
|
|
100 |
% |
|
|
1,039 |
|
|
|
|
|
Louisiana Pipeline System |
|
Louisiana |
|
|
Various(6) |
|
|
655 |
|
|
|
|
|
Promix NGL Gathering System |
|
Louisiana |
|
|
50 |
% (7) |
|
|
410 |
|
|
|
|
|
Houston Ship Channel |
|
Texas |
|
|
100 |
% |
|
|
266 |
|
|
|
|
|
Lou-Tex NGL |
|
Texas, Louisiana |
|
|
100 |
% |
|
|
204 |
|
|
|
|
|
Others (5 systems) (8) |
|
Alabama, Louisiana, Mississippi |
|
|
Various |
|
|
427 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total miles |
|
|
|
|
|
|
|
|
12,809 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL and related product storage facilities by state: |
|
|
|
|
|
|
|
|
|
|
|
|
Texas |
|
|
|
|
|
|
|
|
|
|
|
|
114.9 |
|
Louisiana |
|
|
|
|
|
|
|
|
|
|
|
|
13.0 |
|
Mississippi |
|
|
|
|
|
|
|
|
|
|
|
|
10.9 |
|
Others (Arizona, Georgia, Iowa, Kansas, Nebraska, Oklahoma, Utah) |
|
|
|
|
|
|
|
|
|
|
9.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capacity (9) |
|
|
|
|
|
|
|
|
|
|
|
|
148.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The maximum number of barrels that these systems can transport per day depends upon the operating balance achieved at a given time between various segments of the systems. Because the
balance is dependent upon the mix of products to be shipped and the demand levels at the various delivery points, the exact capacities of the systems cannot be stated. We measure the utilization
rates of our NGL pipelines in terms of throughput (on a net basis in accordance with our ownership interest). Total net volumes for our NGL pipelines during 2005, 2004 and 2003 were 1,360 MBPD,
1,343 MBPD and 1,196 MBPD, respectively. |
|
(2) |
|
This system crosses thirteen states: Wyoming, Utah, Colorado, New Mexico, Texas, Oklahoma, Kansas, Missouri, Nebraska, Iowa, Illinois, Minnesota and Wisconsin. |
|
(3) |
|
We hold a 65.9% interest in this system through a majority owned subsidiary, Dixie Pipeline Company (Dixie). |
|
(4) |
|
We hold a 90% interest in this system through a majority owned subsidiary, Seminole Pipeline Company (Seminole). |
|
(5) |
|
Acquired in connection with the GulfTerra Merger in September 2004. |
|
(6) |
|
Of the 655 total miles for this system, we own 100% of 559 miles; 44.3% of 53 miles; and 32.2% of the remaining 43 miles. |
|
(7) |
|
Our ownership interest in this pipeline is held indirectly through our equity method investment in K/D/S Promix LLC (Promix). |
|
(8) |
|
Includes our Tri-States, Belle Rose, Wilprise and Chunchula pipelines located in the coastal regions of Alabama, Louisiana and Mississippi and a pipeline held by Venice Energy Services
Company, LLC (VESCO), an equity investment of ours. |
|
(9) |
|
The 148.4 MMBbls of total useable storage capacity includes 21.3 MMBbls held under operating leases. |
The following information highlights the general use of each of our principal NGL
pipelines. We operate our NGL pipelines with the exception of 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 2,548-mile Rocky Mountain pipeline, the 2,740-mile Conway North
pipeline and |
30
|
|
|
the 1,938-mile Conway South pipeline. The Rocky Mountain pipeline transports
mixed NGLs from the Rocky Mountain Overthrust and San Juan Basin areas to the Hobbs hub
located on the Texas-New Mexico border. The Conway North segment links the NGL hub at
Conway, Kansas to refineries, petrochemical plants and propane markets in the upper
Midwest. In addition, the Conway North segment has access to NGL supplies from Canadas
Western Sedimentary Basin through third-party connections. The Conway South pipeline
connects the Conway hub with Kansas refineries and transports NGLs from Conway, Kansas to
the Hobbs hub (with interconnections with our Seminole pipeline at the Hobbs hub). We also own fifteen
unregulated propane terminals that are an integral part of the Mid-America Pipeline System. |
|
|
|
|
Approximately 60% of the volumes transported on the Mid-America system are 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, and the 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 propane pipeline extending from southeast Texas and
Louisiana to markets in the southeastern United States. Propane supplies transported on
this system primarily originate from southeast Texas, southern Louisiana and Mississippi. |
|
|
§ |
|
The Seminole Pipeline is a regulated pipeline that transports NGLs from the Hobbs hub
and the Permian Basin area to southeastern Texas. The primary source of throughput for
the Seminole pipeline is the Mid-America Pipeline System. |
|
|
§ |
|
The Texas NGL System is a network of NGL gathering and transportation pipelines located
in south Texas. The system includes 379 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 660 miles of
pipelines that deliver NGLs from our South Texas fractionation facilities to refineries
and petrochemical plants located from Corpus Christi to Houston and within the Texas
City-Houston area, as well as to common carrier NGL pipelines. |
|
|
§ |
|
The Louisiana Pipeline System is a network of nine NGL pipelines located in Louisiana.
This system transports NGLs originating in southern Louisiana and 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 Promix NGL Gathering System is a NGL pipeline system that gathers mixed NGLs from
natural gas processing plants in Louisiana for delivery to the Promix NGL fractionator.
This gathering system is an integral part of the Promix NGL fractionation facility. |
|
|
§ |
|
The Houston Ship Channel pipeline system is a collection of pipelines extending from
our Houston Ship Channel import/export facility and Morgans Point facility to Mont
Belvieu, Texas. 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 certain of our Louisiana gas processing plants to
our Mont Belvieu NGL fractionation facility. |
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 our and our
customers NGLs
31
and petrochemicals. Our underground storage facilities include locations in
Arizona, Kansas and Utah that were acquired in July 2005 from Ferrellgas L.P. We operate these
facilities, with the exception of certain storage locations operated for us by a third party in
Louisiana and Mississippi.
The following table summarizes the significant natural gas processing and NGL fractionation
assets of our NGL Pipelines & Services business segment at February 1, 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Gas |
|
Total Gas |
|
Net |
|
Total |
|
|
|
|
Our |
|
Processing |
|
Processing |
|
Plant |
|
Plant |
|
|
|
|
Ownership |
|
Capacity |
|
Capacity |
|
Capacity |
|
Capacity |
Description of Asset |
|
Location(s) |
|
Interest |
|
(Bcf/d) (2) |
|
(Bcf/d) |
|
(MBPD) |
|
(MBPD) |
|
Natural gas processing facilities: (1, 3,4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Toca |
|
Louisiana |
|
|
60.3 |
% |
|
|
0.66 |
|
|
|
1.10 |
|
|
|
|
|
|
|
|
|
Chaco (4) |
|
New Mexico |
|
|
100 |
% |
|
|
0.65 |
|
|
|
0.65 |
|
|
|
|
|
|
|
|
|
North Terrebonne |
|
Louisiana |
|
|
44.3 |
% |
|
|
0.58 |
|
|
|
1.30 |
|
|
|
|
|
|
|
|
|
Yscloskey |
|
Louisiana |
|
|
31.1 |
% |
|
|
0.54 |
|
|
|
1.85 |
|
|
|
|
|
|
|
|
|
Calumet |
|
Louisiana |
|
|
31.5 |
% |
|
|
0.50 |
|
|
|
1.60 |
|
|
|
|
|
|
|
|
|
Neptune |
|
Louisiana |
|
|
66 |
% |
|
|
0.43 |
|
|
|
0.65 |
|
|
|
|
|
|
|
|
|
Pascagoula |
|
Mississippi |
|
|
40 |
% |
|
|
0.40 |
|
|
|
1.50 |
|
|
|
|
|
|
|
|
|
Thompsonville (4) |
|
Texas |
|
|
100 |
% |
|
|
0.30 |
|
|
|
0.30 |
|
|
|
|
|
|
|
|
|
Shoup (4) |
|
Texas |
|
|
100 |
% |
|
|
0.29 |
|
|
|
0.29 |
|
|
|
|
|
|
|
|
|
Gilmore (4) |
|
Texas |
|
|
100 |
% |
|
|
0.26 |
|
|
|
0.26 |
|
|
|
|
|
|
|
|
|
Armstrong (4) |
|
Texas |
|
|
100 |
% |
|
|
0.25 |
|
|
|
0.25 |
|
|
|
|
|
|
|
|
|
Matagorda (4) |
|
Texas |
|
|
100 |
% |
|
|
0.25 |
|
|
|
0.25 |
|
|
|
|
|
|
|
|
|
Others (12 facilities)(4,5) |
|
Texas, New Mexico, Louisiana |
|
|
Various(6) |
|
|
1.24 |
|
|
|
5.38 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total processing capacities |
|
|
|
|
|
|
|
|
6.35 |
|
|
|
15.38 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL fractionation facilities: (7,8) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mont Belvieu |
|
Texas |
|
|
75 |
% |
|
|
|
|
|
|
|
|
|
|
158 |
|
|
|
210 |
|
Norco |
|
Louisiana |
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
75 |
|
|
|
75 |
|
Promix |
|
Louisiana |
|
|
50 |
% |
|
|
|
|
|
|
|
|
|
|
73 |
|
|
|
145 |
|
Shoup |
|
Texas |
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
69 |
|
|
|
69 |
|
BRF |
|
Louisiana |
|
|
32.2 |
% |
|
|
|
|
|
|
|
|
|
|
19 |
|
|
|
60 |
|
Others (4 facilities) (9) |
|
Texas, Louisiana |
|
|
Various |
|
|
|
|
|
|
|
|
|
|
45 |
|
|
|
93 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total plant capacities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
439 |
|
|
|
652 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
We own direct consolidated interests in all of our natural gas processing facilities with the exception of our 13.1% interest in a facility held through our equity method investment in VESCO. |
|
(2) |
|
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. |
|
(3) |
|
On a weighted-average basis, utilization rates for these assets (based on the periods that we held an ownership interest) were approximately 53%, 61% and 63% during 2005, 2004 and 2003, respectively. |
|
(4) |
|
As a result of the GulfTerra Merger, we acquired ownership interest in eleven natural gas processing facilities having net gas processing capacity of 2.66 Bcf/d and gross gas processing capacity of 2.8 Bcf/d. |
|
(5) |
|
Includes our Venice, Blue Water, Sea Robin, Patterson II, Iowa and Burns Point facilities located in Louisiana; Indian Basin facility located in New Mexico; and San Martin, Delmita, Shilling, Sonora and Indian Springs facilities located in
Texas. We acquired the Indians Springs facility in January 2005. |
|
(6) |
|
Our ownership in these facilities ranges from 1.9% to 100%. |
|
(7) |
|
On a weighted-average basis, utilization rates for these assets (based on the periods that we held an ownership interest) were approximately 70% during each of the years 2005, 2004 and 2003. |
|
(8) |
|
We own direct consolidated interests in all of our NGL fractionation facilities with the exception of a 50% interest in a facility held through our equity method investment in Promix; a 32.2% interest in a facility owned by Baton Rouge
Fractionators LLC (BRF); and a 13.1% interest in a facility owned by VESCO. |
|
(9) |
|
Includes our Tebone and VESCO NGL facilities located in Louisiana and our Armstrong and Delmita facilities located in Texas. |
At the core of our natural gas processing business are twenty-four processing plants
located in Texas, Louisiana, Mississippi and New Mexico. 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 in
connection with gathering pipelines. We operate the Toca, Chaco, North Terrebonne, Calumet and
Neptune plants and all of the Texas facilities.
32
Our NGL marketing activities utilize a fleet of approximately 600 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. We have rail loading and unloading facilities in
Arizona, Kansas, Louisiana, Mississippi and Texas. These facilities service both our rail
shipments and those of our customers.
The following information highlights the general use of each of our principal NGL
fractionation facilities. We operate all of our NGL fractionation facilities, with the exception
of the facility owned by VESCO.
|
§ |
|
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 Mountain Overthrust, East Texas and
the Gulf Coast. |
|
|
§ |
|
The Norco NGL fractionation facility receives mixed NGLs via pipeline from refineries
and natural gas processing plants, including our Yscloskey and Toca natural gas processing
plants. |
|
|
§ |
|
The Promix NGL fractionation facility receives mixed NGLs from natural gas processing
plants on the Mississippi and Alabama Gulf Coast through a connection with our Belle Rose
and Tri-States NGL pipelines. In addition to the 410-mile Promix NGL pipeline, Promix
owns five NGL storage caverns and a barge loading facility that are integral to its
operations. |
|
|
§ |
|
Our Shoup NGL fractionation facility fractionates mixed NGLs supplied by our South
Texas natural gas processing facilities. |
|
|
§ |
|
The BRF facility processes mixed NGLs from production fields in Alabama, Mississippi
and southern Louisiana as well as offshore Gulf of Mexico areas. |
Our NGL operations include import and export facilities located on the Houston Ship Channel in
southeast Texas. We lease an import facility that can offload NGLs from tanker vessels at a rate
of 10,000 barrels per hour. In addition, we own an export facility that can load cargoes of
refrigerated propane and butane onto tanker vessels at rates of up to 5,000 barrels per hour. In
addition, 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 119 MBPD, 91 MBPD and 79 MBPD for 2005, 2004 and 2003, respectively.
33
Onshore Natural Gas Pipelines & Services
The following table summarizes the significant assets of our Onshore Natural Gas Pipelines &
Services business segment at February 1, 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Approximate |
|
|
|
|
|
|
Our |
|
|
|
|
|
Capacity, |
|
Gross |
|
|
|
|
Ownership |
|
Length |
|
Natural Gas |
|
Capacity |
Description of Asset |
|
Location(s) |
|
Interest |
|
(Miles) |
|
(MMcf/d) |
|
(Bcf) |
|
Onshore natural gas pipelines:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas Intrastate System(2) |
|
Texas |
|
|
100 |
%(3) |
|
|
8,222 |
|
|
|
4,975 |
|
|
|
|
|
San Juan Gathering System(2) |
|
New Mexico, Colorado |
|
|
100 |
% |
|
|
5,404 |
|
|
|
1,100 |
|
|
|
|
|
Permian Basin System(2) |
|
Texas, New Mexico |
|
|
100 |
% |
|
|
1,477 |
|
|
|
490 |
|
|
|
|
|
Acadian Gas System |
|
Louisiana |
|
|
100 |
%(4) |
|
|
1,027 |
|
|
|
954 |
|
|
|
|
|
Alabama Intrastate System(2) |
|
Alabama |
|
|
100 |
% |
|
|
402 |
|
|
|
200 |
|
|
|
|
|
Other (4 systems)(5) |
|
Texas, Mississippi |
|
|
Various(6) |
|
|
684 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total miles |
|
|
|
|
|
|
|
|
17,216 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas storage facilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petal(2) |
|
Mississippi |
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
11.9 |
|
Hattiesburg(2) |
|
Mississippi |
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
4.0 |
|
Wilson(2) |
|
Texas |
|
|
Leased(7) |
|
|
|
|
|
|
|
|
|
|
6.4 |
|
Acadian |
|
Louisiana |
|
|
Leased(8) |
|
|
|
|
|
|
|
|
|
|
3.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross capacity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
On a weighted-average basis, utilization rates for these assets (based on the periods that we held an ownership interest) were approximately 73%, 75% and 63% during 2005, 2004 and 2003, respectively. |
|
(2) |
|
Acquired in connection with the GulfTerra Merger in September 2004. |
|
(3) |
|
We own a 50% undivided interest in the 733-mile Channel pipeline system, which is a component of the Texas Intrastate System. |
|
(4) |
|
We own 100% of 1,000 miles of the Acadian Gas System and 49.5% of the related 27-mile Evangeline natural gas pipeline. |
|
(5) |
|
Includes the Delmita, Big Thicket and Indian Springs gathering systems located in Texas and the Petal pipeline 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 Indian Springs gathering system in January
2005. |
|
(6) |
|
We own 100% of these assets with the exception the Indian Springs system, in which we indirectly own an 80% equity interest in this system through a majority owned subsidiary. |
|
(7) |
|
Facility held under an operating lease that expires in January 2008, which contains certain renewal options. |
|
(8) |
|
Facility held under an operating lease that expires in December 2012. |
The following information highlights the general use of each of our principal onshore
natural gas pipelines and storage facilities, all of which we operate.
|
§ |
|
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 consumers. This 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 Ship Channel industrial
market. The Texas Intrastate System is comprised of the 7,292-mile GulfTerra Texas
Intrastate pipeline system, the 197-mile TPC Offshore gathering system and the 733-mile
Channel pipeline system. The Wilson natural gas storage facility is an integral part of
the Texas Intrastate System. |
|
|
§ |
|
The San Juan Gathering System serves natural gas producers in the San Juan Basin of New
Mexico and Colorado. This system gathers natural gas production from over 10,450 wells in
the San Juan Basin and delivers the natural gas to natural gas processing facilities,
including our Chaco facility. |
|
|
§ |
|
The Permian Basin 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 Permian Basin System is comprised of the 674-mile Waha system
and 803-mile Carlsbad system. |
34
|
§ |
|
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, 423-mile
Acadian pipeline and the 27-mile Evangeline pipeline. The Acadian natural gas storage
facility is an integral part of the Acadian Gas System. |
|
|
§ |
|
The Alabama Intrastate System 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. |
|
|
§ |
|
Our 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. |
35
Offshore Pipelines & Services
The following table summarizes the significant assets of our Offshore Pipelines & Services
business segment at February 1, 2006, 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:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Manta Ray Offshore Gathering System |
|
25.7%(2) |
|
|
250 |
|
|
|
|
|
|
|
206 |
|
|
|
|
|
High Island Offshore System(3) |
|
100% |
|
|
204 |
|
|
|
|
|
|
|
1,800 |
|
|
|
|
|
Viosca Knoll Gathering System(3) |
|
100% |
|
|
162 |
|
|
|
|
|
|
|
1,000 |
|
|
|
|
|
Green Canyon Laterals(3) |
|
Various(4) |
|
|
136 |
|
|
|
|
|
|
|
649 |
|
|
|
|
|
Anaconda Gathering System(3) |
|
100% |
|
|
136 |
|
|
|
|
|
|
|
550 |
|
|
|
|
|
Nautilus System |
|
25.7%(2) |
|
|
101 |
|
|
|
|
|
|
|
154 |
|
|
|
|
|
East Breaks System(3) |
|
100% |
|
|
85 |
|
|
|
|
|
|
|
400 |
|
|
|
|
|
Phoenix Gathering System(3) |
|
100% |
|
|
78 |
|
|
|
|
|
|
|
450 |
|
|
|
|
|
Nemo Gathering System |
|
33.9%(5) |
|
|
24 |
|
|
|
|
|
|
|
102 |
|
|
|
|
|
Falcon Gas Pipeline(3) |
|
100% |
|
|
14 |
|
|
|
|
|
|
|
400 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total miles |
|
|
|
|
1,190 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Offshore crude oil pipelines:(6) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cameron Highway Oil Pipeline(3) |
|
50%(7) |
|
|
378 |
|
|
|
|
|
|
|
|
|
|
|
250 |
|
Poseidon Oil Pipeline System(3) |
|
36%(8) |
|
|
324 |
|
|
|
|
|
|
|
|
|
|
|
144 |
|
Constitution Oil Pipeline |
|
100% |
|
|
70 |
|
|
|
|
|
|
|
|
|
|
|
80 |
|
Allegheny Oil Pipeline(3) |
|
100% |
|
|
43 |
|
|
|
|
|
|
|
|
|
|
|
140 |
|
Marco Polo Oil Pipeline(3) |
|
100% |
|
|
36 |
|
|
|
|
|
|
|
|
|
|
|
120 |
|
Typhoon Oil Pipeline(3) |
|
100% |
|
|
16 |
|
|
|
|
|
|
|
|
|
|
|
80 |
|
Tarantula Oil Pipeline(3) |
|
100% |
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total miles |
|
|
|
|
871 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Offshore platforms: (3,9) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ship Shoal 332A(10) |
|
62% |
|
|
|
|
|
|
438 |
|
|
|
|
|
|
|
|
|
Ship Shoal 332B(10) |
|
50%(7) |
|
|
|
|
|
|
438 |
|
|
|
|
|
|
|
|
|
Marco Polo |
|
50%(11) |
|
|
|
|
|
|
4,300 |
|
|
|
150 |
|
|
|
60 |
|
Viosca Knoll 817 |
|
100% |
|
|
|
|
|
|
671 |
|
|
|
140 |
|
|
|
5 |
|
Garden Banks 72 |
|
50% |
|
|
|
|
|
|
518 |
|
|
|
40 |
|
|
|
18 |
|
East Cameron 373 |
|
100% |
|
|
|
|
|
|
441 |
|
|
|
195 |
|
|
|
3 |
|
Falcon Nest |
|
100% |
|
|
|
|
|
|
389 |
|
|
|
400 |
|
|
|
3 |
|
|
|
|
(1) |
|
On a weighted-average basis, utilization rates for these assets (based on the periods that we held an ownership interest) were approximately 30%, 32% and 41% during 2005, 2004 and 2003, respectively. |
|
(2) |
|
Our ownership interest in this pipeline is held indirectly through our equity method investment in Neptune Pipeline Company, LLC. |
|
(3) |
|
Acquired in connection with the GulfTerra Merger in September 2004. Data shown for the Anaconda Gathering System includes our recently completed 30-mile Constitution Gas Pipeline, which has a net capacity of
approximately 200 MMcf/d. |
|
(4) |
|
Our ownership interests in the Green Canyon Laterals ranges from 2.7% to 100%. |
|
(5) |
|
Our ownership interest in this pipeline is held indirectly through our equity method investment in Nemo Gathering Company, LLC. |
|
(6) |
|
On a weighted-average basis, utilization rates for these assets (based on the periods that we held an ownership interest) were approximately 17% and 27% during 2005 and 2004, respectively. |
|
(7) |
|
Our ownership interest in this asset is held indirectly through our equity method investment in Cameron Highway Oil Pipeline Company (Cameron Highway). |
|
(8) |
|
Our ownership interest in this asset is held indirectly through our equity method investment in Poseidon Oil Pipeline Company, LLC. |
|
(9) |
|
On a weighted-average basis, utilization rates during 2005 and 2004 for these assets (based on the periods that we held an ownership interest) were approximately 26% and 32% in connection with natural gas capacity and
approximately 9% and 14% for crude oil capacity, respectively. |
|
(10) |
|
These platforms serve as pipeline junctions; therefore, we do not have processing capacities to report for these assets. |
|
(11) |
|
Our ownership interest in this platform is held indirectly through our equity method investment in Deepwater Gateway, LLC. |
36
The following information highlights the general use of each of our principal Gulf of
Mexico offshore natural gas pipelines. We operate our offshore natural gas pipelines, with the
exception of the Manta Ray Offshore Gathering System, Nautilus System, Nemo Gathering System and
certain components of the Green Canyon Laterals.
|
§ |
|
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 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 Viosca Knoll Gathering System transports natural gas from producing fields located
in the Main Pass, Mississippi Canyon and Viosca Knoll areas to several major interstate
pipelines, including the Tennessee Gas, Columbia Gulf, Southern Natural, Transco, Dauphin
Island Gathering System and Destin Pipelines. |
|
|
§ |
|
The Green Canyon Laterals consist of 28 pipeline laterals (which are extensions of
natural gas pipelines) that transport natural gas to downstream pipelines, including the
HIOS. |
|
|
§ |
|
The Anaconda Gathering System connects our Marco Polo platform and Constitution Gas
Pipeline to the ANR pipeline system. The Anaconda Gathering System includes our
wholly-owned Constitution Gas Pipeline, which was completed in late 2005 and serves the
Constitution and Ticonderoga fields located in the central Gulf of
Mexico. We initiated flows into our Constitution Gas Pipeline during the first quarter of 2006. |
|
|
§ |
|
The Nautilus System connects our Manta Ray Offshore Gathering System to our Neptune
natural gas processing plant. |
|
|
§ |
|
The East Breaks System connects the Hoover-Diana deepwater platform located in Alaminos
Canyon Block 25 to the 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 Nemo Gathering System transports natural gas from Green Canyon developments to an
interconnect with our Manta Ray Offshore Gathering System. |
|
|
§ |
|
The Falcon 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 following information highlights the general use of each of our principal Gulf of Mexico
offshore crude oil pipelines, all of which we operate.
|
§ |
|
The Cameron Highway Oil Pipeline, which commenced operations during the first quarter
of 2005, 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. |
|
|
§ |
|
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. |
37
|
§ |
|
The Constitution Oil Pipeline was completed in late 2005 and serves the Constitution
and Ticonderoga fields located in the central Gulf of Mexico. Initial
throughput volumes were received during the first quarter of 2006. The Constitution Oil Pipeline connects with our
Cameron Highway Oil Pipeline and Poseidon Oil Pipeline System at a 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 gathers crude oil from our Marco Polo platform to an
interconnect with our Allegheny Oil Pipeline in Green Canyon Block 164. |
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 Marco Polo
platform and East Cameron 373.
|
§ |
|
The Ship Shoal 332A platform is a junction platform, which serves as a location for
crude oil and natural gas to enter our system of assets. Crude oil and natural gas
produced in the deepwater Gulf of Mexico is transported to the Ship Shoal 332A platform
via several third-party pipelines. Crude oil enters our Poseidon Oil Pipeline System and
Allegheny Oil Pipelines at the Ship Shoal 332 A platform, and natural gas enters our Manta
Ray Offshore Gathering System. |
|
|
§ |
|
The Ship Shoal 332B platform is a junction platform for crude oil pipelines. Crude oil
produced in the deepwater Gulf of Mexico is transported to the Ship Shoal 332B platform on
our Poseidon Oil Pipeline System and Constitution Oil Pipeline and third-party pipelines.
The crude oil is then shipped off this platform via our Cameron Highway Oil Pipeline. |
|
|
§ |
|
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 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 currently processes natural gas from the Falcon field. |
38
Petrochemical Services
The following table summarizes the significant assets of our Petrochemical Services segment at
February 1, 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
Our |
|
|
Plant |
|
|
Plant |
|
|
|
|
|
|
|
|
|
|
Ownership |
|
|
Capacity |
|
|
Capacity |
|
|
Length |
|
Description of Asset |
|
Location(s) |
|
|
Interest |
|
|
(MBPD) |
|
|
(MBPD) |
|
|
(Miles) |
|
|
Propylene fractionation facilities:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mont Belvieu (3 plants) |
|
Texas
|
|
Various(2) |
|
|
58 |
|
|
|
72 |
|
|
|
|
|
BRPC |
|
Louisiana
|
|
|
30 |
%(3) |
|
|
7 |
|
|
|
23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capacity |
|
|
|
|
|
|
|
|
|
|
65 |
|
|
|
95 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Isomerization facility: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mont Belvieu(4) |
|
Texas
|
|
|
100 |
% |
|
|
116 |
|
|
|
116 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petrochemical pipelines:(5) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lou-Tex Propylene |
|
Texas, Louisiana
|
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
291 |
|
Lake Charles |
|
Texas, Louisiana
|
|
|
50 |
%(6) |
|
|
|
|
|
|
|
|
|
|
88 |
|
Others (7 systems)(7) |
|
Texas, Louisiana
|
|
Various(8) |
|
|
|
|
|
|
|
|
|
|
311 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total miles |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
690 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Octane additive production facilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mont Belvieu |
|
Texas
|
|
|
100 |
% |
|
(Dual Use)(9)
|
|
|
|
|
|
|
|
(1) |
|
On a weighted-average basis, utilization rates for these assets (based on the periods that we held an ownership interest) were approximately 83%, 86% and 88% during 2005, 2004 and 2003,
respectively. |
|
(2) |
|
We own a 54.6% interest and lease the remaining 45.4% of a facility having 17 MBPD of plant capacity. We own a 66.7% interest in a second facility having 41 MBPD of total plant capacity. We
own 100% of the remaining facility, which has 14 MBPD of plant capacity. |
|
(3) |
|
Our ownership interest in this facility is held indirectly through our equity method investment in Baton Rouge Propylene Concentrator, LLC (BRPC). |
|
(4) |
|
On a weighted-average basis, utilization rates for this facility were approximately 70% for 2005 and 66% for each of 2004 and 2003. |
|
(5) |
|
The maximum number of barrels that these systems can transport per day depends upon the operating balance achieved at a given time between various segments of the systems. Because the balance is
dependent upon the mix of products to be shipped and the demand levels at the various delivery points, the exact capacities of the systems cannot be stated. We measure the utilization rates of our
petrochemical pipelines in terms of throughput (on a net basis in accordance with our ownership interest). Total net volumes for our petrochemical pipelines during 2005, 2004 and 2003 were 64 MBPD,
71 MBPD and 68 MBPD, respectively. |
|
(6) |
|
Of the 88 total miles for this pipeline, we own 50% of 82 miles and 100% of the remainder. |
|
(7) |
|
Includes our Port Neches, Bay Area, Texas City, La Porte, Morgans Point and other petrochemical pipelines located in Texas and our Sabine Propylene pipeline located in Texas and Louisiana. |
|
(8) |
|
We own 100% of these pipelines with the exception of (i) the 17-mile La Porte pipeline, in which we hold an aggregate 50% indirect interest through our equity method investments in La Porte
Pipeline Company, L.P. and La Porte GP, LLC and (ii) the 16-mile Bay Area pipeline, in which we own an undivided 66% interest. |
|
(9) |
|
This facility is capable of producing either isooctane or MTBE as conditions warrant. At full capacity, the facility can produce approximately 12 MBPD of isooctane or 15.5 MBPD of MTBE. On a
weighted-average basis, utilization rates for these assets (based on the periods that we held an ownership interest and the products produced) were approximately 29%, 83% and 62% during 2005, 2004
and 2003, respectively. The facility was capable of producing only MTBE prior to mid-2005. |
We produce polymer grade propylene at our Mont Belvieu facilities 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 ExxonMobil Corporation into chemical grade propylene.
The production of polymer grade propylene from our Mont Belvieu plants is primarily used in our
petrochemical marketing activities.
The Lou-Tex Propylene pipeline is used to transport propylene from Sorrento, Louisiana to Mont
Belvieu, Texas. Currently, this pipeline is used to transport chemical grade propylene. 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.
We operate all of the assets in our Petrochemical Services business segment.
39
Item 3. Legal Proceedings.
On occasion, we are named as a defendant in litigation relating to our normal business
operations, 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 activity.
We are not aware of any significant litigation, pending or threatened, that may have a significant
adverse effect on our financial position or results of operations.
A number of lawsuits have been filed by municipalities and other water suppliers against a
number of manufacturers of reformulated gasoline containing MTBE, although generally such suits
have not named manufacturers of MTBE as defendants, and there have been no such lawsuits filed
against our subsidiary that owns the facility. It is possible, however, that MTBE manufacturers
such as our subsidiary could ultimately be added as defendants in such lawsuits or in new lawsuits.
In connection with our purchase of additional equity interests in the owner of the octane-additive
production facility in 2003 from an affiliate of Devon Energy Corporation (Devon) and in 2004
from an affiliate of Sunoco, Inc. (Sun), Devon and Sun indemnified us for any related liability
(including liabilities described above) that are in respect of periods prior to the date we
purchased such interests. There are no dollar limits or deductibles associated with the
indemnities we received from Sun and Devon with respect to potential claims linked to the period of
time they held ownership interests in the facility.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
40
PART II
Item 5. Market for Registrants Common Equity, Related Unitholder Matters 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 15,
2006, there were an estimated 920 unitholders of record of our common units. The following table
sets forth 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 |
2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1st Quarter
|
|
$ |
24.720 |
|
|
$ |
21.750 |
|
|
$ |
0.3725 |
|
|
Apr. 30, 2004
|
|
May 12, 2004 |
2nd Quarter
|
|
$ |
23.840 |
|
|
$ |
20.000 |
|
|
$ |
0.3725 |
|
|
Jul. 30, 2004
|
|
Aug. 6, 2004 |
3rd Quarter
|
|
$ |
23.700 |
|
|
$ |
20.190 |
|
|
$ |
0.3950 |
|
|
Oct. 29, 2004
|
|
Nov. 5, 2004 |
4th Quarter
|
|
$ |
25.990 |
|
|
$ |
22.730 |
|
|
$ |
0.4000 |
|
|
Jan. 31, 2005
|
|
Feb. 14, 2005 |
2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1st Quarter
|
|
$ |
28.350 |
|
|
$ |
23.150 |
|
|
$ |
0.4100 |
|
|
Apr. 29, 2005
|
|
May 10, 2005 |
2nd Quarter
|
|
$ |
27.090 |
|
|
$ |
24.770 |
|
|
$ |
0.4200 |
|
|
Jul. 29, 2005
|
|
Aug. 10, 2005 |
3rd Quarter
|
|
$ |
27.660 |
|
|
$ |
23.500 |
|
|
$ |
0.4300 |
|
|
Oct. 31, 2005
|
|
Nov. 8, 2005 |
4th Quarter
|
|
$ |
26.020 |
|
|
$ |
23.380 |
|
|
$ |
0.4375 |
|
|
Jan. 31, 2006
|
|
Feb. 9, 2006 |
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, please read Liquidity and Capital
Resources included under Item 7 of this annual report. Although the payment of cash dividends is
not guaranteed, we expect to continue to pay comparable cash distributions in the future.
Recent Sales of Unregistered Securities
There were no sales of unregistered equity securities during 2005.
Common Units Authorized for Issuance Under Equity Compensation Plan
Please read the information included under Item 12 of this annual report, which is
incorporated by reference into this Item 5.
Issuer Purchases of Equity Securities
We did not repurchase any of our common units during 2005. 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 15, 2006, we
and our affiliates are authorized to repurchase up to 618,400 additional common units under this
repurchase program.
41
Item 6. Selected Financial Data.
The following table presents selected historical financial data of Enterprise Products
Partners. This information has been derived from our audited financial statements for the periods
indicated and should be read in conjunction with the audited financial statements included under
Item 8 of this annual report. 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 (except per unit data) are in thousands.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
2002 |
|
|
2001 |
|
Operating results data:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
12,256,959 |
|
|
$ |
8,321,202 |
|
|
$ |
5,346,431 |
|
|
$ |
3,584,783 |
|
|
$ |
3,154,369 |
|
Income from continuing operations(2) |
|
$ |
423,716 |
|
|
$ |
257,480 |
|
|
$ |
104,546 |
|
|
$ |
95,500 |
|
|
$ |
242,178 |
|
Income per unit from continuing operations:(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.92 |
|
|
$ |
0.83 |
|
|
$ |
0.42 |
|
|
$ |
0.55 |
|
|
$ |
1.70 |
|
Diluted |
|
$ |
0.92 |
|
|
$ |
0.83 |
|
|
$ |
0.41 |
|
|
$ |
0.48 |
|
|
$ |
1.39 |
|
Other financial data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions per common unit(4) |
|
$ |
1.698 |
|
|
$ |
1.540 |
|
|
$ |
1.470 |
|
|
$ |
1.360 |
|
|
$ |
1.194 |
|
Commodity hedging income (loss)(5) |
|
$ |
1,095 |
|
|
$ |
448 |
|
|
$ |
(619 |
) |
|
$ |
(51,344 |
) |
|
$ |
101,290 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
2002 |
|
|
2001 |
|
Financial position data:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
12,591,016 |
|
|
$ |
11,315,461 |
|
|
$ |
4,802,814 |
|
|
$ |
4,230,272 |
|
|
$ |
2,424,692 |
|
Long-term and current maturities of debt(6) |
|
$ |
4,833,781 |
|
|
$ |
4,281,236 |
|
|
$ |
2,139,548 |
|
|
$ |
2,246,463 |
|
|
$ |
855,278 |
|
Partners equity(7) |
|
$ |
5,679,309 |
|
|
$ |
5,328,785 |
|
|
$ |
1,705,953 |
|
|
$ |
1,200,904 |
|
|
$ |
1,146,922 |
|
Total units outstanding (excluding treasury)(7) |
|
|
389,861 |
|
|
|
364,786 |
|
|
|
217,780 |
|
|
|
183,810 |
|
|
|
174,542 |
|
|
|
|
(1) |
|
In general, our historical operating results and financial position have been affected by numerous acquisitions since 2001. 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. The GulfTerra Merger and our other
acquisitions were accounted for using purchase accounting; therefore, the operating results of these acquired entities are included in our financial results prospectively from their respective purchase dates.
For additional information regarding such transactions, please read Note 12 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report. |
|
(2) |
|
Amounts presented for 2005 and 2004 are prior to the cumulative effect of accounting changes. |
|
(3) |
|
Earnings per unit and unit count data prior to 2002 have been adjusted to reflect the May 2002 two-for-one split of each class of our partnership units. |
|
(4) |
|
Distributions per common unit represent declared cash distributions with respect to the four fiscal quarters of each period presented. |
|
(5) |
|
Income from continuing operations includes our gain or loss from commodity hedging activities. A variety of factors influence whether or not a particular hedging strategy is successful. As a result of
incurring significant losses from commodity hedging transactions in early 2002 due to a rapid increase in natural gas prices, we exited those commodity hedging strategies that created the losses. Since that
time, we have utilized only a limited number of commodity financial instruments. For additional information regarding our use of financial instruments, please read Item 7A of this annual report. |
|
(6) |
|
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 growth capital spending. |
|
(7) |
|
We regularly issue common units through public offerings and, less frequently, in connection with acquisitions or other transactions. The increase in partners equity since 2001 has been the result of
such transactions, with the September 2004 issuance of 104.5 million of common units in connection with the GulfTerra Merger being our largest. For additional information regarding our partners equity and
unit history, please read Note 15 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report. |
42
Item 7. Managements Discussion and Analysis of Financial Condition and Results of
Operations.
For the years ended December 31, 2005, 2004 and 2003.
Enterprise Products Partners L.P. is a North American midstream energy company that provides a
wide range of services to producers and consumers of natural gas, natural gas liquids (NGLs), and
crude oil, and is an industry leader in the development of pipeline and other midstream assets in
the continental United States and Gulf of Mexico. Unless the context requires otherwise,
references to we, us, our, or Enterprise Products Partners are intended to mean the
consolidated business and operations of Enterprise Products Partners L.P. and its subsidiaries.
We conduct substantially all of our business through our wholly owned subsidiary, Enterprise
Products Operating L.P. (our Operating Partnership). We are owned 98% by our limited partners
and 2% by Enterprise Products GP, LLC (our general partner, referred to as Enterprise Products
GP). Enterprise Products GP is owned 100% by Enterprise GP Holdings L.P. (Enterprise GP
Holdings), a publicly traded affiliate listed on the New York Stock Exchange (NYSE) under the
ticker symbol EPE. We, Enterprise Products GP and Enterprise GP Holdings are affiliates and
under common control of Dan L. Duncan, the Chairman and the controlling shareholder of EPCO, Inc.
(EPCO).
This annual report contains various forward-looking statements and information based on our
beliefs and those of Enterprise Products GP, as well as assumptions made by us and information
currently available to us. Please read the section titled Cautionary Statement Regarding
Forward-Looking Information included under Item 1 of this annual report.
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 |
|
Mdth
|
|
= thousand dekatherms |
|
MMBbls
|
|
= million barrels |
|
MMBtus
|
|
= million British thermal units |
|
MMcf
|
|
= million cubic feet |
|
Mcf
|
|
= thousand cubic feet |
RECENT DEVELOPMENTS
The year 2005 was a challenging year for Enterprise Products Partners. The Gulf Coast region
experienced two major hurricanes (Katrina and Rita) that affected our employees, suppliers,
customers and industry. Our thoughts remain with those displaced by these storms and we are
well-positioned to assist the Gulf Coast energy industry in the rebuilding effort. Although
certain of our facilities incurred structural damage as a result of the storms and other operations
were interrupted, by year-end the majority of our operated facilities were at pre-hurricane
production, transportation or processing levels. In particular, our Toca natural gas processing
facility, which is located in coastal Louisiana and was heavily damaged in Hurricane Katrina, has
recently returned to operations. For information regarding our insurance claims related to these
storms, please read Note 22 of the Notes to Consolidated Financial Statements included under Item 8
of this annual report.
Our growth capital spending for 2005 was a record of $743.8 million, which includes $338.6
million for our Independence Hub offshore platform and related Independence Trail Pipeline and
$90.1 million for our Constitution Oil and Constitution Gas Pipelines. In addition, we recently
announced two new natural gas processing projects in the Rockies. We expect that these projects
will enhance our existing asset base and provide us with additional growth opportunities in the
future. In addition to our growth capital projects, we completed $326.6 million in acquisitions
during 2005, the largest of which was the $145.5 million purchase of underground NGL storage
facilities and propane terminals from Ferrellgas L.P.
43
(Ferrellgas). For additional information regarding our growth capital spending and acquisitions,
please read Capital Spending included within this Item 7.
During 2005, we completed the integration of our legacy operations with those of GulfTerra
Energy Partners L.P. (GulfTerra). In September 2004, we completed the GulfTerra Merger
transaction, whereby GulfTerra merged with one of our wholly owned subsidiaries. As a result of
the GulfTerra Merger, GulfTerra and its subsidiaries and GulfTerras general partner (GulfTerra
GP) became our wholly owned subsidiaries. The GulfTerra Merger greatly expanded our asset base to
include numerous natural gas and crude oil pipelines, offshore platforms and other midstream energy
assets. Additionally, the GulfTerra Merger included the purchase of various midstream assets from
El Paso that are located in South Texas. For additional information regarding the GulfTerra
Merger, please read Note 12 of the Notes to Consolidated Financial Statements included under Item 8
of this annual report.
Our Cameron Highway Oil Pipeline began deliveries of Gulf of Mexico crude oil production
during the first quarter of 2005 to major refining markets along the Texas Gulf Coast. The
Cameron Highway Oil Pipeline can transport up to 500 MBPD of deepwater Gulf of Mexico crude oil
production. We own a 50% interest in this system through our equity method investment in Cameron
Highway Oil Pipeline Company (Cameron Highway).
We completed construction of the Constitution Oil and Constitution Gas Pipelines in 2005. We
own and operate these pipelines, which provide production gathering services for the Constitution
and Ticonderoga fields in the Gulf of Mexico. Initial throughput is expected on the Constitution
pipelines during the first quarter of 2006.
In May 2003, GulfTerra commenced a project relating to its San Juan Basin assets. The San
Juan Optimization Project was substantially complete in 2005 at an approximate cost of $31 million.
This project resulted in a 10% increase of capacity on our San Juan Gathering System and will
increase market opportunities through a new interconnect with the Transwestern Pipeline. We
connected a record 336 natural gas wells to the San Juan Gathering System during 2005.
In February 2005, we sold 17,250,000 common units (including an over-allotment amount of
2,250,000 common units which closed in March 2005), which generated net proceeds of approximately
$456.7 million. In addition, our Operating Partnership sold $500 million of senior notes in
February 2005. In March 2005, we filed a universal shelf registration statement with the SEC registering the
issuance of up to $4 billion of additional partnership equity and/or public debt obligations. In
June 2005, our Operating Partnership sold $500 million of senior notes under this registration
statement. In December 2005, we sold 4,000,000 common units under this registration statement,
which generated net proceeds of $98.7 million. For additional information regarding our debt
obligations and capital structure, please see Notes 14 and 15 of the Notes to Consolidated
Financial Statements included under Item 8 of this annual report.
In October 2005, our Operating Partnership amended its revolving credit facility to increase
total bank commitments from $750 million to $1.25 billion (which may be further increased to $1.4
billion upon our request, subject to certain conditions). The increase in borrowing capacity under
our Multi-Year Revolving Credit Facility further enables us to meet future funding requirements of
our growth capital projects. For additional information regarding our debt obligations, please see
Note 14 of the Notes to Consolidated Financial Statements included under Item 8 of this annual
report.
The ownership of our general partner underwent a number of changes during 2005. In January
2005, affiliates of EPCO acquired a 9.9% membership interest in Enterprise Products GP and
13,454,498 of our common units from El Paso for approximately $425 million in cash. As a result of
these transactions, EPCO and its affiliates owned 100% of the membership interests of Enterprise
Products GP. In August 2005, EPCO and its affiliates contributed their membership interests in
Enterprise Products GP to Enterprise GP Holdings. Affiliates of EPCO currently own 86.5% of
Enterprise GP Holdings. For additional information regarding these transactions between related
parties, please read Item 13 of this annual report.
44
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. In recent years, major oil and gas companies have sold
non-strategic assets in the midstream energy sector in which we operate. We forecast that this
trend will continue, and expect independent oil and natural gas companies to consider similar
divestitures. Management continues to analyze potential acquisitions, joint ventures and similar
transactions with businesses that operate in complementary markets or geographic regions.
We believe that we are positioned to continue to grow through construction of new facilities
and acquisitions that will expand our system of assets and through growth capital projects. We
estimate our consolidated capital spending during 2006 will
approximate $1.8 billion, which
includes estimated expenditures of approximately $1.7 billion for growth capital projects and
acquisitions and approximately $78 million for sustaining capital expenditures.
Our forecast of consolidated capital expenditures is based upon our strategic operating and
growth plans, which are also dependent upon our ability to generate capital from operating cash
flows or otherwise obtain the capital necessary to accomplish our objectives. Our forecast may
change due to factors beyond our control, such as weather related issues, changes in supplier
prices or adverse economic conditions. Further, our forecast may change as a result of decisions
made at a later date, which may include acquisitions or decisions to take on additional partners.
Our success in raising capital, including the formation of joint ventures to share costs and
risks, continues to be the principal factor that determines how much we can spend. We believe our
access to capital resources is sufficient to meet the demands of our current and future operating
growth needs, and although we currently intend to make the forecasted expenditures discussed above,
we may adjust the timing and amounts of projected expenditures in response to changes in capital
markets.
45
The following table summarizes our capital spending by activity for the periods indicated
(dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For Year Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
|
|
Capital spending for business combinations and asset purchases: |
|
|
|
|
|
|
|
|
|
|
|
|
GulfTerra Merger: |
|
|
|
|
|
|
|
|
|
|
|
|
Cash payments to El Paso, including amounts paid to acquire
certain South Texas midstream assets |
|
|
|
|
|
$ |
655,277 |
|
|
|
|
|
Transaction fees and other direct costs |
|
|
|
|
|
|
24,032 |
|
|
|
|
|
Cash received from GulfTerra |
|
|
|
|
|
|
(40,313 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash payments |
|
|
|
|
|
|
638,996 |
|
|
|
|
|
Value of non-cash consideration issued or granted |
|
|
|
|
|
|
2,910,771 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total GulfTerra Merger consideration |
|
|
|
|
|
|
3,549,767 |
|
|
|
|
|
Indirect interests in the Indian Springs natural gas gathering and
processing assets |
|
$ |
74,854 |
|
|
|
|
|
|
|
|
|
Additional ownership interests in Dixie Pipeline Company (Dixie) |
|
|
68,608 |
|
|
|
|
|
|
|
|
|
NGL underground storage and terminalling assets purchased
from Ferrellgas |
|
|
145,522 |
|
|
|
|
|
|
|
|
|
Other business combinations and asset purchases |
|
|
37,618 |
|
|
|
85,851 |
|
|
$ |
37,348 |
|
|
|
|
Total |
|
|
326,602 |
|
|
|
3,635,618 |
|
|
|
37,348 |
|
|
|
|
Capital spending for property, plant and equipment: |
|
|
|
|
|
|
|
|
|
|
|
|
Growth capital projects, net |
|
|
743,827 |
|
|
|
114,419 |
|
|
|
125,600 |
|
Sustaining capital projects |
|
|
73,622 |
|
|
|
32,509 |
|
|
|
20,313 |
|
|
|
|
Total |
|
|
817,449 |
|
|
|
146,928 |
|
|
|
145,913 |
|
|
|
|
Capital spending attributable to unconsolidated affiliates: |
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of 50% interest in GulfTerra GP in connection with
the initial step of the GulfTerra Merger |
|
|
|
|
|
|
|
|
|
|
425,000 |
|
Other investments in and advances to unconsolidated affiliates |
|
|
88,044 |
|
|
|
64,412 |
|
|
|
46,927 |
|
|
|
|
Total |
|
|
88,044 |
|
|
|
64,412 |
|
|
|
471,927 |
|
|
|
|
Total capital spending |
|
$ |
1,232,095 |
|
|
$ |
3,846,958 |
|
|
$ |
655,188 |
|
|
|
|
As shown in the preceding table, capital spending for growth capital projects is
presented net of contributions in aid of construction costs of $47 million, $8.9 million and $0.9
million during 2005, 2004 and 2003, respectively. On certain of our capital projects, third
parties may be obligated to reimburse us for all or a portion of project expenditures. The
majority of such arrangements are associated with projects related to pipeline construction and
production well tie-ins.
Our significant capital spending transactions during 2005 include the following:
§ |
|
We paid El Paso $74.9 million for indirect majority ownership interests in the 89-mile
Indian Springs Gathering System and the Indian Springs natural gas processing facility,
both of which are located in East Texas. |
|
§ |
|
We paid $68.6 million for an additional 46% interest in Dixie from affiliates of
ConocoPhillips and ChevronTexaco. As a result of these acquisitions, Dixie is now a
majority-owned consolidated subsidiary of ours. |
|
§ |
|
We purchased three NGL underground storage facilities and four propane terminals from
Ferrellgas for $145.5 million in cash. The underground storage facilities are located in
Kansas, Arizona and Utah and have a combined capacity of 6.1 MMBbls. Approximately 70% of
the aggregate storage capacity is leased to third party customers under fee-based
contracts. The four propane terminals are located in Minnesota and North Carolina. The
Minnesota facilities are connected to our Mid-America Pipeline System, and the North
Carolina terminals are connected by rail to our facilities on the Gulf Coast. As part of
the transaction, Ferrellgas has contracted with us to maintain a certain level of storage
volume and terminal throughput for five years with the option to extend for an additional
five years. |
46
Significant Recently Announced Growth Capital Projects
Jonah
Expansion. In February 2006, we and TEPPCO Partners, L.P.
(TEPPCO), affiliate of
EPCO, entered into a letter of intent related to the formation of a joint venture to expand
TEPPCOs Jonah Gas Gathering System (the Jonah system), located in the Green River Basin in
southwestern Wyoming. The proposed expansion of the Jonah system would increase the natural gas gathering
and transportation capacity of the Jonah system from 1.5 Bcf/d to 2.0 Bcf/d.
The letter of intent stipulates that we will be responsible for all activities related to the
construction of the expansion of the Jonah system, including advancing of all expenditures
necessary to plan, engineer and construct the expansion project. We estimate that total funds
needed for this project will approximate $200 million and that the expansion assets will be placed
in service in late 2006.
The amounts we advance to complete the expansion of the Jonah system will constitute a
subscription for an equity interest in the proposed joint venture. TEPPCO has the option to return
to us up to 100% of the amounts we advance (i.e., the subscription amounts). If TEPPCO returns any
portion of the subscription to us, the relative interests of us and TEPPCO in the new joint venture
would be adjusted accordingly. The proposed joint venture arrangement will terminate without
liability to either party if TEPPCO returns 100% of the advances we make in connection with the
expansion project, including carrying costs and expenses.
The general partner of TEPPCO and 2,500,000 common units of TEPPCO are owned by an affiliate
of Mr. Duncan, Chairman of the board of directors of our general partner.
Piceance
Basin Gas Processing Project. In January 2006, we announced
the execution of a minimum
15-year natural gas processing agreement with an affiliate of the
EnCana Corporation (EnCana).
Under that agreement, we will have the right to process up to 1.3 Bcf/d of EnCanas natural gas
production from the Piceance Basin area of western Colorado. To accommodate this production, we
have begun construction of the Meeker natural gas processing facility in Rio Blanco County,
Colorado. In addition, we will construct a 50-mile NGL pipeline that will connect our Meeker
facility with our Mid-America Pipeline System. Phase I, which includes construction of the plant
and pipeline, will provide us with 750 MMcf/d of natural gas processing capacity and the ability to
recover up to 35 MBPD of NGLs. Phase II, which includes the expansion of the plant, will expand
natural gas processing capacity at the facility to 1.3 Bcf/d and increase NGL extraction rates to
up to 70 MBPD. We expect Phase I and Phase II to be operational by mid-2007 and late-2008,
respectively. Phase I is expected to cost $284 million.
Wyoming Gas Processing Projects. In January 2006, we announced our intent to purchase from
TEPPCO the Pioneer natural gas processing plant located in Opal, Wyoming and the rights to process
natural gas originating from the Jonah and Pinedale fields in the Greater Green River Basin in
Wyoming. Upon execution of definitive agreements, the receipt of all necessary regulatory approval
and approvals from the boards of directors of TEPPCO and our general partner, we would purchase the
Pioneer plant for $36 million and commence construction to increase its processing capacity from
275 MMcf/d to 550 MMcf/d at an additional expected cost of $21 million. We expect this expansion to
be completed in mid-2006.
We have also announced our intent to build a new gas processing plant with a capacity of 650
MMcf/d adjacent to the Pioneer plant. We expect to place the new facility in service during 2007.
The Pioneer expansion and the new natural gas processing plant will serve growing natural gas
production in the Jonah and Pinedale fields. The cost of this new processing facility is expected
to be $228 million.
Natural Gas Storage Expansion. In December 2005, we completed the conversion of an existing
brine well located at our Petal, Mississippi storage facility to a 2.4 Bcf natural gas storage
cavern at a cost of $15 million. Due to strong demand for natural gas storage, we have commenced
the development of an additional storage cavern at the Petal facility that is expected to add 5 Bcf
of storage capacity. This cavern is expected to cost $75 million and be placed in service during
the first quarter of 2008.
47
Expansion of Mont Belvieu NGL and Petrochemical Storage Services. In November 2005, we
announced an expansion of our NGL and petrochemical storage services at our complex in Mont
Belvieu, Texas to improve our ability to receive and deliver NGLs and petrochemicals. The Mont
Belvieu expansion projects include the drilling of two new brine production wells and the
construction of two above-ground brine storage pits. The increased brine storage capability will
further enable us to enhance product storage services and movement to transportation and
distribution pipelines that serve the Gulf Coast region, as well as our import and export
facilities on the Houston Ship Channel. As a result of these projects, we will also more than
double our above-ground brine storage capabilities to 19 MMBbls and will increase our capacity to
produce brine. These projects are expected to be placed in service in 2006 and 2007
and are expected to cost $77 million.
Hobbs NGL Fractionator. In June 2005, we announced plans to construct a new NGL
fractionator, designed to handle up to 75 MBPD of mixed NGLs, located at the interconnection of our
Mid-America Pipeline System and our Seminole Pipeline near Hobbs, New Mexico. Additionally, we
will construct a purity ethane storage well near the new fractionator and reconfigure the
interconnection between our Mid-America Pipeline System and the Seminole Pipeline. These projects
are expected to cost $175 million and be placed in service by mid-2007. Our Hobbs NGL fractionator
will process the increase in mixed NGLs resulting from our Phase I expansion of the Mid-America
Pipeline System.
Mid-America Pipeline System Phase I Expansion. In January 2005, we announced an
expansion of the Rocky Mountain segment of our Mid-America Pipeline System to accommodate an
expected increase in mixed NGLs originating from producing basins in Wyoming, Utah, Colorado and
New Mexico. The expansion project will be completed in stages and will increase throughput volumes
on the segment by a total of 50 MBPD. We expect final completion of the Phase I expansion during
the second quarter of 2007 at a cost of $187 million. We expect to receive the necessary
regulatory approval and begin construction on our Phase I expansion project in the first quarter of
2006.
Expansion of Mont Belvieu NGL Fractionator. In January 2005, we began a project to
expand the processing capacity of our Mont Belvieu NGL fractionator from 210 MBPD to 225 MBPD and
to reduce energy costs. This expansion project will enable us to accommodate a portion of an
expected increase in NGL production from the Rocky Mountains. The project is expected to cost
approximately $41 million and be completed in mid-2006.
Independence Hub Platform and Independence Trail Pipeline System. In November 2004,
we entered into an agreement with the Atwater Valley Producers Group for the dedication, processing
and gathering of natural gas and condensate production from several natural gas fields in the
Atwater Valley, DeSoto Canyon, Lloyd Ridge and Mississippi Canyon areas (collectively, the anchor
fields) of the deepwater Gulf of Mexico. First production is expected in 2007.
We are constructing and will own the Independence Hub platform, which will be located in
Mississippi Canyon Block 920, at a water depth of 8,000 feet. The Independence Hub is a 105-foot
deep-draft, semi-submersible platform with a two-level production deck, which will process 1 Bcf/d
of natural gas. The platform, which is estimated to cost $420 million, will be operated by
Anadarko, and is designed to process production from its anchor fields and has excess payload
capacity to support ten additional pipeline risers. In December 2004, we entered into an agreement
with Cal Dive International Inc. (Cal Dive) to sell them a 20% indirect interest in the
Independence Hub platform.
Additionally, we will construct, own, and operate the 134-mile Independence Trail natural gas
pipeline system, which will have a throughput capacity of 1 Bcf/d of natural gas. The pipeline
system, which is estimated to cost $268 million, will transport production from the Independence
Hub platform to the Tennessee Gas Pipeline.
Pipeline Integrity Costs
Our NGL, petrochemical and natural gas pipelines are subject to pipeline safety programs
administered by the U.S. Department of Transportation, through its Office of Pipeline Safety. This
federal
48
agency has issued safety regulations containing requirements for the development of
integrity management programs for hazardous liquid pipelines (which include NGL and petrochemical
pipelines) and natural gas pipelines. In general, these regulations require companies to assess
the condition of their pipelines in certain high consequence areas (as defined by the regulation)
and to perform any necessary repairs. In connection with the regulations for hazardous liquid
pipelines, we developed a pipeline integrity management program in 2002. In connection with the regulations for natural gas pipelines, we
developed a pipeline integrity management program in 2004.
During 2005, we spent approximately $42.2 million to comply with these programs, of which $25
million was recorded as an operating expense, and the remaining $17.2 million was capitalized. We
spent approximately $22.4 million to comply with these programs during 2004, of which $14.9 million
was recorded as an operating expense and the remaining $7.5 million was capitalized.
We expect our net cash outlay for pipeline integrity program expenditures to approximate $63.2
million during 2006. Our forecast is net of certain costs we expect to recover from El Paso. In
April 2002, GulfTerra acquired several midstream assets located in Texas and New Mexico from El
Paso. These assets include the Texas Intrastate System and the Permian Basin System. El Paso
agreed to indemnify GulfTerra for any pipeline integrity costs it incurred (whether paid or
payable) during 2005, 2006 and 2007 with respect to such assets, to the extent that such annual
costs exceed $3.3 million; however, the aggregate amount reimbursable by El Paso for these periods
is capped at $50.2 million. During 2006, we expect to recover $13.8 million from El Paso related
to our 2005 expenditures, which leaves a remainder of $36.4 million reimbursable by El Paso for
2006 and 2007 pipeline integrity costs.
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
technology employed) and products produced and/or sold.
We evaluate segment performance based on the non-generally accepted accounting principle
(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 financial measure calculated using accounting principles generally
accepted in the United States of America (GAAP) 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 (or consolidated) segment gross operating margin as operating income before:
(i) depreciation and amortization expense; (ii) operating lease expenses for which we do not have
the payment obligation; (iii) gains and losses on the sale of assets; and (iv) general and
administrative expenses. Gross operating margin is exclusive of other income and expense
transactions, provision for income taxes, minority interest, extraordinary charges and the
cumulative effect of changes in accounting principles. 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.
For additional information regarding our business segments, please read Note 17 of the Notes
to Consolidated Financial Statements included under Item 8 of this annual report.
We have historically included equity earnings from 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
49
align our interests with those of our customers, which may be suppliers
of raw materials or consumers of finished products. 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 integrated midstream energy asset system (including the midstream energy assets of
our equity method investees) provides services to producers and consumers of natural gas, NGLs and
petrochemicals. Our asset system has multiple entry points. In general, hydrocarbons can enter
our asset system in a number of ways, including an offshore natural gas or crude oil pipeline, an
offshore platform, a natural gas processing plant, an NGL gathering pipeline, an NGL fractionator,
an NGL storage facility, an NGL transportation or distribution pipeline or an onshore natural gas
pipeline. At each link along this asset system, we earn revenues based on volume or an ownership
of products such as NGLs.
Many of our equity investments are present within our integrated midstream asset system. For
example, we have ownership interests in several offshore natural gas and crude oil pipelines.
Other examples include our use of the Promix NGL fractionator to process NGLs extracted by our gas
plants. The NGLs received from Promix then can be sold in our NGL marketing activities. Given the
integral nature of our equity investees to our operations, we believe treatment of earnings from
our equity method investees as a component of gross operating margin and operating income is
appropriate.
For additional information regarding our investments in and advances to unconsolidated
affiliates, please read Note 11 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 average quarterly industry index prices for natural
gas, crude oil and selected NGL and petrochemical products since the beginning of 2003:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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) |
|
2003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1st Quarter |
|
$ |
6.58 |
|
|
$ |
34.12 |
|
|
$ |
0.43 |
|
|
$ |
0.65 |
|
|
$ |
0.76 |
|
|
$ |
0.80 |
|
|
$ |
0.85 |
|
|
$ |
0.24 |
|
|
$ |
0.21 |
|
2nd Quarter |
|
$ |
5.40 |
|
|
$ |
29.04 |
|
|
$ |
0.39 |
|
|
$ |
0.53 |
|
|
$ |
0.58 |
|
|
$ |
0.62 |
|
|
$ |
0.65 |
|
|
$ |
0.25 |
|
|
$ |
0.19 |
|
3rd Quarter |
|
$ |
4.97 |
|
|
$ |
30.21 |
|
|
$ |
0.37 |
|
|
$ |
0.56 |
|
|
$ |
0.67 |
|
|
$ |
0.68 |
|
|
$ |
0.73 |
|
|
$ |
0.21 |
|
|
$ |
0.15 |
|
4th Quarter |
|
$ |
4.58 |
|
|
$ |
31.18 |
|
|
$ |
0.40 |
|
|
$ |
0.58 |
|
|
$ |
0.73 |
|
|
$ |
0.71 |
|
|
$ |
0.75 |
|
|
$ |
0.22 |
|
|
$ |
0.16 |
|
|
|
|
Average for Year |
|
$ |
5.38 |
|
|
$ |
31.14 |
|
|
$ |
0.40 |
|
|
$ |
0.58 |
|
|
$ |
0.68 |
|
|
$ |
0.70 |
|
|
$ |
0.74 |
|
|
$ |
0.23 |
|
|
$ |
0.18 |
|
|
|
|
2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1st Quarter |
|
$ |
5.69 |
|
|
$ |
35.25 |
|
|
$ |
0.43 |
|
|
$ |
0.66 |
|
|
$ |
0.76 |
|
|
$ |
0.76 |
|
|
$ |
0.87 |
|
|
$ |
0.29 |
|
|
$ |
0.26 |
|
2nd Quarter |
|
$ |
6.00 |
|
|
$ |
38.34 |
|
|
$ |
0.45 |
|
|
$ |
0.65 |
|
|
$ |
0.79 |
|
|
$ |
0.79 |
|
|
$ |
0.92 |
|
|
$ |
0.32 |
|
|
$ |
0.26 |
|
3rd Quarter |
|
$ |
5.75 |
|
|
$ |
43.90 |
|
|
$ |
0.52 |
|
|
$ |
0.79 |
|
|
$ |
0.92 |
|
|
$ |
0.92 |
|
|
$ |
1.05 |
|
|
$ |
0.32 |
|
|
$ |
0.27 |
|
4th Quarter |
|
$ |
7.07 |
|
|
$ |
48.31 |
|
|
$ |
0.60 |
|
|
$ |
0.85 |
|
|
$ |
1.03 |
|
|
$ |
1.04 |
|
|
$ |
1.15 |
|
|
$ |
0.40 |
|
|
$ |
0.35 |
|
|
|
|
Average for Year |
|
$ |
6.13 |
|
|
$ |
41.45 |
|
|
$ |
0.50 |
|
|
$ |
0.74 |
|
|
$ |
0.88 |
|
|
$ |
0.88 |
|
|
$ |
1.00 |
|
|
$ |
0.33 |
|
|
$ |
0.29 |
|
|
|
|
2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1st Quarter |
|
$ |
6.27 |
|
|
$ |
49.68 |
|
|
$ |
0.52 |
|
|
$ |
0.79 |
|
|
$ |
0.98 |
|
|
$ |
1.00 |
|
|
$ |
1.14 |
|
|
$ |
0.45 |
|
|
$ |
0.39 |
|
2nd Quarter |
|
$ |
6.74 |
|
|
$ |
53.09 |
|
|
$ |
0.52 |
|
|
$ |
0.82 |
|
|
$ |
0.98 |
|
|
$ |
1.01 |
|
|
$ |
1.16 |
|
|
$ |
0.37 |
|
|
$ |
0.30 |
|
3rd Quarter |
|
$ |
8.53 |
|
|
$ |
63.08 |
|
|
$ |
0.69 |
|
|
$ |
0.97 |
|
|
$ |
1.14 |
|
|
$ |
1.26 |
|
|
$ |
1.36 |
|
|
$ |
0.37 |
|
|
$ |
0.33 |
|
4th Quarter |
|
$ |
13.00 |
|
|
$ |
60.03 |
|
|
$ |
0.76 |
|
|
$ |
1.06 |
|
|
$ |
1.27 |
|
|
$ |
1.34 |
|
|
$ |
1.36 |
|
|
$ |
0.50 |
|
|
$ |
0.44 |
|
|
|
|
Average for Year |
|
$ |
8.64 |
|
|
$ |
56.47 |
|
|
$ |
0.62 |
|
|
$ |
0.91 |
|
|
$ |
1.09 |
|
|
$ |
1.15 |
|
|
$ |
1.26 |
|
|
$ |
0.42 |
|
|
$ |
0.37 |
|
|
|
|
|
|
|
(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 an 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. |
50
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, and reflect the periods in which we owned an interest in such operations. In
general, the increase in volumes since 2003 is due to the assets we acquired in connection with the
GulfTerra Merger, which was completed on September 30, 2004.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For Year Ended December 31, |
|
|
2005 |
|
2004 |
|
2003 |
|
|
|
NGL Pipelines & Services, net: |
|
|
|
|
|
|
|
|
|
|
|
|
NGL transportation volumes (MBPD) |
|
|
1,478 |
|
|
|
1,411 |
|
|
|
1,275 |
|
NGL fractionation volumes (MBPD) |
|
|
292 |
|
|
|
307 |
|
|
|
227 |
|
Equity NGL production (MBPD) |
|
|
85 |
|
|
|
95 |
|
|
|
43 |
|
Fee-based natural gas processing (MMcf/d) |
|
|
1,767 |
|
|
|
1,692 |
|
|
|
194 |
|
Onshore Natural Gas Pipelines & Services, net: |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas transportation volumes (BBtus/d) |
|
|
5,916 |
|
|
|
5,638 |
|
|
|
600 |
|
Offshore Pipelines & Services, net: |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas transportation volumes (BBtus/d) |
|
|
1,780 |
|
|
|
2,081 |
|
|
|
433 |
|
Crude oil transportation volumes (MBPD) |
|
|
127 |
|
|
|
138 |
|
|
|
|
|
Platform gas processing (BBtus/d) |
|
|
252 |
|
|
|
306 |
|
|
|
|
|
Platform oil processing (MBPD) |
|
|
7 |
|
|
|
14 |
|
|
|
|
|
Petrochemical Services, net: |
|
|
|
|
|
|
|
|
|
|
|
|
Butane isomerization volumes (MBPD) |
|
|
81 |
|
|
|
76 |
|
|
|
77 |
|
Propylene fractionation volumes (MBPD) |
|
|
55 |
|
|
|
57 |
|
|
|
57 |
|
Octane additive production volumes (MBPD) |
|
|
6 |
|
|
|
10 |
|
|
|
4 |
|
Petrochemical transportation volumes (MBPD) |
|
|
64 |
|
|
|
71 |
|
|
|
68 |
|
Total, net: |
|
|
|
|
|
|
|
|
|
|
|
|
NGL, crude oil and petrochemical transportation volumes (MBPD) |
|
|
1,669 |
|
|
|
1,620 |
|
|
|
1,343 |
|
Natural gas transportation volumes (BBtus/d) |
|
|
7,696 |
|
|
|
7,719 |
|
|
|
1,033 |
|
Equivalent transportation volumes (MBPD) (1) |
|
|
3,694 |
|
|
|
3,651 |
|
|
|
1,615 |
|
|
|
|
(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 most significant recent event affecting our results of operations was the GulfTerra Merger
and related transactions. Since the closing date of the GulfTerra Merger was September 30, 2004,
our Statements of Consolidated Operations do not include any earnings from GulfTerra prior to
October 1, 2004. The effective closing date of our purchase of the South Texas midstream assets
was September 1, 2004. As a result, our Statements of Consolidated Operations for 2004 include
four months of earnings from the South Texas midstream assets. The results of operations from our
other 2005, 2004 and 2003 business combinations and asset purchases are also included in our
earnings from the date of their respective acquisitions.
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, |
|
|
2005 |
|
2004 |
|
2003 |
|
|
|
Revenues |
|
$ |
12,256,959 |
|
|
$ |
8,321,202 |
|
|
$ |
5,346,431 |
|
Operating costs and expenses |
|
|
11,546,225 |
|
|
|
7,904,336 |
|
|
|
5,046,777 |
|
General and administrative costs |
|
|
62,266 |
|
|
|
46,659 |
|
|
|
37,590 |
|
Equity in income (loss) of unconsolidated affiliates |
|
|
14,548 |
|
|
|
52,787 |
|
|
|
(13,960 |
) |
Operating income |
|
|
663,016 |
|
|
|
422,994 |
|
|
|
248,104 |
|
Interest expense |
|
|
230,549 |
|
|
|
155,740 |
|
|
|
140,806 |
|
Net income |
|
|
419,508 |
|
|
|
268,261 |
|
|
|
104,546 |
|
51
Revenues from the sale and marketing of NGL products within the NGL Pipelines & Services
business segment accounted for 67% of total consolidated revenues for each of 2005 and 2004 and
68% of total consolidated revenues for 2003. Revenues from the sale of petrochemical products
within the Petrochemical Services segment accounted for 11%, 13% and 12% of total consolidated
revenues for 2005, 2004 and 2003, respectively. Revenues from the transportation, sale and storage
of natural gas using onshore assets accounted for 13%, 10% and 11% of total consolidated revenues
for 2005, 2004 and 2003, respectively.
Our gross operating margin by segment and in total is as follows for the periods indicated
(dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2005 |
|
2004 |
|
2003 |
|
|
|
Gross operating margin by segment: |
|
|
|
|
|
|
|
|
|
|
|
|
NGL Pipelines & Services |
|
$ |
579,706 |
|
|
$ |
374,196 |
|
|
$ |
310,677 |
|
Onshore Natural Gas Pipelines & Services |
|
|
353,076 |
|
|
|
90,977 |
|
|
|
18,345 |
|
Offshore Pipeline & Services |
|
|
77,505 |
|
|
|
36,478 |
|
|
|
5,561 |
|
Petrochemical Services |
|
|
126,060 |
|
|
|
121,515 |
|
|
|
75,885 |
|
Other, non-segment |
|
|
|
|
|
|
32,025 |
|
|
|
(53 |
) |
|
|
|
Total segment gross operating margin |
|
$ |
1,136,347 |
|
|
$ |
655,191 |
|
|
$ |
410,415 |
|
|
|
|
For a reconciliation of non-GAAP gross operating margin to GAAP operating income and
further to GAAP income before provision for taxes, minority interest and cumulative effect of
changes in accounting principles, please read Other Items included within this Item 7.
Comparison of Year Ended December 31, 2005 with Year Ended December 31, 2004
Revenues for 2005 increased $3.9 billion over those recorded during 2004. The trend in
consolidated revenues can be attributed to (i) a $2.2 billion increase in revenues from our NGL and
petrochemical marketing activities resulting from an increase in sales volumes and energy commodity
prices in 2005 relative to 2004; (ii) the addition of $1.5 billion in revenues from acquired or
consolidated businesses, particularly those generated by the GulfTerra and South Texas midstream
assets and (iii) a $0.2 billion increase in revenues from the sale of natural gas attributable to
higher natural gas prices year-to-year.
Consolidated costs and expenses increased $3.7 billion year-to-year primarily due to (i)
higher energy commodity prices, which resulted in a $2.2 billion increase in the cost of sales of
natural gas, NGLs and petrochemical products and (ii) the addition of $1.4 billion in costs and
expenses attributable to acquired or consolidated businesses. General and administrative costs
increased $15.6 million period-to-period as a result of our expanded business activities.
Changes in our revenues and costs and expenses period-to-period are explained in part by
changes in energy commodity prices. The weighted-average indicative market price for NGLs was 91
cents per gallon (CPG) during 2005 versus 73 CPG during 2004 a year-to-year increase of 25%.
Our determination of the weighted-average indicative market price for NGLs is based on U.S. Gulf
Coast prices for such products at Mont Belvieu, which is the primary industry hub for domestic NGL
production. The market price of natural gas (as measured at Henry Hub) averaged $8.64 per MMBtu
during 2005 versus $6.13 per MMBtu during 2004. Polymer grade propylene index prices increased 27%
year-to-year and refinery grade propylene index prices increased 28% year-to-year. For historical
pricing information of natural gas, crude oil and NGLs, please see the table on page 50.
Equity earnings from unconsolidated affiliates decreased $38.2 million year-to-year. Equity
earnings for 2005 include a full year of our share of earnings from investments we acquired in
connection with the GulfTerra Merger, including an $11.5 million charge associated with the
refinancing of Cameron Highways project debt. Fiscal 2004 includes $32 million of equity earnings
from GulfTerra GP, which we consolidated in September 2004 as a result of completing the GulfTerra
Merger. Collectively, the
52
aforementioned changes in revenues, costs and expenses and equity earnings contributed to a
$240 million increase in operating income year-to-year.
Interest expense increased $74.8 million year-to-year primarily due to debt we incurred in
2004 as a result of the GulfTerra Merger and the issuance of additional senior notes in 2005. Our
average debt principal outstanding was $4.6 billion in 2005 compared to $2.8 billion in 2004.
As a result of items noted in the previous paragraphs, net income increased $151.2 million
year-to-year to $419.5 million in 2005 compared to $268.3 million in 2004. Net income for both
years includes the recognition of non-cash amounts related to the cumulative effects of changes in
accounting principles. We recorded a $4.2 million charge in 2005 and a $10.8 million benefit in
2004 related to such changes. For additional information regarding the cumulative effect of
changes in accounting principles we recorded in 2005 and 2004, please read Note 8 of the Notes to
Consolidated Financial Statements included under Item 8 of this annual report.
Due to our geographic and business diversification, Hurricanes Katrina (August 2005) and Rita
(September 2005) had varying effects across our business segments. The hurricanes impacted supply
and demand for natural gas, NGLs, crude oil and motor gasoline. In general, this resulted in an
increase in energy commodity prices, which was exacerbated in certain regions due to local supply
and demand imbalances. The disruptions in natural gas, NGL and crude oil production along the U.S.
Gulf Coast resulted in decreased volumes for some of our pipeline systems, natural gas processing
plants and NGL fractionators, which in turn caused a decrease in our gross operating margin from
certain operations. In addition, operating costs at certain of our plants and pipelines were
negatively impacted due to the higher fuel costs. These adverse effects were mitigated by
increases in gross operating margin from certain of other operations, which benefited from
increased demand for NGLs and octane additives, regional demand for natural gas and the general
increase in commodity prices.
We estimate that Hurricanes Katrina and Rita reduced our gross operating margin in 2005 by
approximately $48 million as a result of decreased transportation and processing volumes and higher
hurricane-related expenses and insurance premium costs. Our 2005 results of operations reflect a
$4.8 million cash receipt related to the settlement of certain business interruption insurance
claims from Hurricane Ivan in September 2004.
We are at varying stages of the insurance claims process with respect to these hurricanes and
expect to receive additional insurance recoveries in 2006 and 2007. For additional information
regarding our insurance claims related to these storm events, please read Results of Operations
Significant Risks and Uncertainties Hurricanes included within this Item 7.
The following information highlights significant year-to-year variances in gross operating
margin by business segment:
NGL Pipelines & Services. Gross operating margin from this business segment was
$579.7 million for 2005 versus $374.2 million for 2004. The $205.5 million increase in gross
operating margin consists of the following: (i) a $186.9 million increase from natural gas
processing and related NGL marketing activities, (ii) a $21.3 million increase from NGL
fractionation and (iii) a $2.7 million decrease from NGL pipelines and related storage services.
The $186.9 million year-to-year increase in gross operating margin from natural gas processing
and related NGL marketing activities includes $122.3 million from natural gas plants acquired in
connection with the GulfTerra Merger and $66.9 million from NGL marketing activities. Our
marketing activities benefited from higher sales volumes and commodity prices during 2005 compared
to 2004.
The $21.3 million year-to-year increase in gross operating margin from NGL fractionation
includes (i) $14.9 million of improved results from our Mont Belvieu facility, (ii) $14 million
from assets acquired in connection with the GulfTerra Merger and (iii) a $9 million decrease from
our Louisiana NGL
53
fractionators, particularly Norco, which suffered a loss of processing volumes due to
Hurricane Katrina. Our Norco NGL fractionator is expected to return to normal operating rates
during 2006.
The $2.7 million year-to-year decrease in gross operating margin from NGL pipelines and
related storage services was due to a variety of reasons, including (i) a net $11.2 million
decrease from our Mid-America Pipeline System and Seminole Pipeline primarily due to higher fuel
costs and pipeline integrity expenses, (ii) a $4.9 million decrease from our Louisiana Pipeline
System primarily due to hurricane effects, (iii) a net $6.9 million increase from our import and
export facilities and related Houston Ship Channel pipeline attributable to increased volumes, and
(iv) a net $8.9 million increase due to acquired assets and consolidation of former equity method
investees.
Onshore Natural Gas Pipelines & Services. Gross operating margin from this business
segment was $353.1 million for 2005 compared to $91 million for 2004. The $262.1 million increase
in gross operating margin is primarily due to onshore natural gas pipelines and storage assets
acquired in connection with the GulfTerra Merger. Gross operating margin from this segment is
largely attributable to contributions from our San Juan Gathering System, Texas Intrastate System
and Permian Basin System, which together generated gross operating margins in 2005 of $290.4
million. Our Petal and Hattiesburg natural gas storage facilities generated $38.7 million of gross
operating margin in 2005. The San Juan Gathering System, Texas
Intrastate System, Permian Basin System and Petal and
Hattiesburg natural gas storage facilities were acquired in connection with the GulfTerra Merger.
Offshore Pipelines & Services. Gross operating margin from this business segment was
$77.5 million for 2005 compared to $36.5 million for 2004. The $41 million increase in gross
operating margin is primarily due to offshore Gulf of Mexico assets acquired in connection with the
GulfTerra Merger. The year-to-year change in gross operating margin consists of the following:
(i) a $20.1 million increase from offshore natural gas pipelines, (ii) a $26.4 million increase
from offshore platforms and (iii) a $5.5 million decrease from offshore crude oil pipelines, which
includes an $11.5 million charge related to the refinancing of Cameron Highways project debt in
2005.
Petrochemical Services. Gross operating margin from this business segment was $126.1
million for 2005 compared to $121.5 million during 2004. The $4.6 million increase in gross
operating margin is primarily due to improved results from isomerization services and octane
additive production activities, both of which benefited from increased demand for motor gasoline in
2005.
Other. Gross operating margin from this segment pertains to equity earnings we
recorded from GulfTerra GP prior to its consolidation with our financial results in September 2004.
Comparison of Year Ended December 31, 2004 with Year Ended December 31, 2003
Revenues for 2004 increased $3 billion over those recorded during 2003. The increase in
consolidated revenues can be attributed to (i) a $2.1 billion increase in revenues from our NGL and
petrochemical marketing activities primarily resulting from an increase in sales volumes and energy
commodity prices in 2004 relative to 2003 and (ii) the addition of $0.8 billion in revenues from
acquired assets and business combinations, particularly those resulting from the GulfTerra Merger
in September 2004.
Consolidated costs and expenses increased $2.9 billion year-to-year primarily due to (i)
higher energy commodity prices, which resulted in a $2 billion increase in the cost of sales of our
NGL and petrochemical marketing activities; (ii) the addition of $0.6 billion in costs and expenses
attributable to acquired or consolidated businesses during 2004; and (iii) a $0.2 billion increase
in the costs of our natural gas processing business primarily due to an increase in volumes.
General and administrative costs increased $9.1 million year-to-year as a result of expanded
business activities.
As noted previously, changes in our revenues and costs and expenses year-to-year are explained
in part by changes in energy commodity prices. The weighted-average indicative market price for
NGLs was 73 CPG during 2004 versus 57 CPG during 2003 a year-to-year increase of 28%. The market
price of
54
natural gas averaged $6.13 per MMBtu during 2004 versus $5.38 per MMBtu during 2003. Polymer
grade propylene index prices increased 44% year-to-year and refinery grade propylene index prices
increased 61% year-to-year.
Equity earnings from unconsolidated affiliates increased $66.7 million year-to-year. Fiscal
2004 includes $32 million of equity earnings from GulfTerra GP, which we acquired in December 2003.
Fiscal 2003 includes a $22.5 million non-cash asset impairment charge related to our octane
additive production facility. Collectively, the aforementioned changes in revenues, costs and
expenses and equity earnings contributed to a $174.9 million increase in operating income
year-to-year.
Interest expense increased $14.9 million year-to-year primarily due to debt we incurred in
2004 as a result of the GulfTerra Merger. Our average debt principal outstanding was $2.8 billion
during 2004 compared to $2 billion during 2003.
As a result of the items noted in previous paragraphs, net income increased $163.8 million to
$268.3 million for 2004 compared to $104.5 million for 2003. Net income for 2004 includes a $10.8
million benefit associated with the cumulative effect of changes in accounting principles.
The following information highlights the significant year-to-year variances in gross operating
margin by business segment:
NGL Pipelines & Services. Gross operating margin from this business segment was
$374.2 million for 2004 versus $310.7 million for 2003. The $63.5 million increase in gross
operating margin includes (i) a $82 million increase from our natural gas processing business,
which includes $61.2 million from assets acquired in connection with the GulfTerra Merger, (ii) a
$20.9 million decrease from our NGL pipelines and related storage services resulting from an
increase in pipeline integrity expenses and a decrease in transportation volumes on certain of our
pipelines and (iii) a $6.8 million increase from our NGL fractionation business, which includes
$5.8 million associated with the South Texas NGL fractionators we acquired in connection with the
GulfTerra Merger.
Onshore Natural Gas Pipelines & Services. Gross operating margin from this business
segment was $91 million for 2004 compared to $18.3 million for 2003. The $72.7 million increase in
gross operating margin for this segment is also attributable to assets acquired in connection with
the GulfTerra Merger.
Offshore Pipelines & Services. Gross operating margin from this business segment was
$36.5 million for 2004 compared to $5.6 million for 2003. The $30.9 million increase from this
segment is primarily due to offshore Gulf of Mexico assets acquired in connection with the
GulfTerra Merger.
Petrochemical Services. Gross operating margin from this business segment was $121.5
million in 2004 compared to $75.9 million in 2003. Gross operating margin from our octane additive
production business increased $34.4 million year-to-year primarily due to our consolidation of the
results of operations of Belvieu Environmental Fuels (BEF). We acquired a controlling ownership
interest in BEF, which owns our octane additive production facility, in September 2003. In
addition, the results of operations for 2003 include the recognition by us of our share (or $22.5
million) of a $67.5 million non-cash asset impairment charge recorded by BEF prior to its
consolidation. Gross operating margin from propylene fractionation increased $10.1 million
year-to-year primarily due to higher petrochemical marketing sales volumes, which benefited from
the effects of higher polymer grade propylene prices in 2004 relative to 2003.
55
Significant Risks and Uncertainties Hurricanes
The following is a discussion of the general status of insurance claims related to recent
hurricanes that affected our assets. To the extent we include any estimate or range of estimates
regarding the dollar value of damages, please be aware that a change in our estimates may occur as
additional information becomes available to us.
Hurricane Ivan insurance claims. Our final purchase price allocation for the
GulfTerra Merger includes a $26.2 million receivable for insurance claims related to expenditures
to repair property damage to certain GulfTerra assets caused by Hurricane Ivan, which struck the
eastern U.S. Gulf Coast region in September 2004 prior to the GulfTerra Merger. These expenditures
represent our costs to restore the damaged facilities to operation. Since this loss event
occurred prior to completion of the GulfTerra Merger, the claim was filed under the insurance
program of GulfTerra and El Paso. Since year end 2005, we received cash reimbursements from insurance carriers totaling
$24.1 million related to these property damage claims, and we expect to
recover the remaining $2.1 million by mid-2006. If the final recovery of funds is different
than the amount previously expended, we will recognize an income impact at that time.
In addition, we have submitted business interruption insurance claims for our estimated losses
caused by Hurricane Ivan. During the fourth quarter of 2005, we received $4.8 million from such
claims. In addition, we estimate an additional $15 million to $16 million will be received
during the first quarter of 2006. To the extent we receive cash proceeds from such business
interruption claims, they will be recorded as a gain in our statements of consolidated operations
and comprehensive income in the period in which funds are received.
Hurricanes Katrina and Rita insurance claims. Hurricanes Katrina and Rita affected
certain of our Gulf Coast assets in August and September of 2005, respectively. Inspection,
evaluation of property damage to our facilities and repairs are a continuing effort. We expensed
$5 million during the third quarter of 2005 related to property damage insurance deductibles for
these storms. To the extent that insurance proceeds from property damage claims do not cover our
actual cash expenditures (in excess of the insurance deductibles we have expensed), such shortfall
will be expensed when realized. We recorded $15.5 million of estimated recoveries from property
damage claims based on amounts expended through December 31, 2005. In addition, we expect to file
business interruption claims for losses related to these hurricanes. To the extent we receive cash
proceeds from such business interruption claims, they will be recorded as a gain in our statements
of consolidated operations and comprehensive income in the period of receipt.
56
General Outlook for 2006
We expect our results of operations to be affected by the following key trends and events
during 2006.
|
§ |
|
We believe that drilling activity in the major producing areas where we operate,
including the Rocky Mountains, San Juan Basin and deepwater Gulf of Mexico, will result in
increased demand for our midstream energy services. As a result, we expect higher
transportation and processing volumes for our assets due to increased natural gas and
crude oil production from both the Rocky Mountains and deepwater Gulf of Mexico.
Hurricanes Katrina and Rita reduced natural gas and crude oil production in the Gulf of
Mexico during the latter half of 2005. Barring any other major storms or similar
disruptions, we believe that Gulf of Mexico production will return to pre-hurricane levels
by mid-2006. |
|
|
§ |
|
We are currently in a major asset construction phase that began in 2005. With several
major projects underway and announced to begin this year, fiscal 2006 will be a transition
year as we continue to invest in multiple projects that will further diversify our
portfolio of midstream assets. We believe that completion of these projects will generate
additional cash flows beginning in 2006. Our significant growth capital projects are
supported by long-term agreements with producers in significant supply basins, which
include the Piceance Basin in Colorado, the Jonah and Pinedale fields in the Greater Green
River Basin in Wyoming and the deepwater Gulf of Mexico. |
|
|
§ |
|
We believe that our natural gas and NGL facilities located in central Louisiana and our
Marco Polo Oil Pipeline, Marco Polo platform and Cameron Highway Oil Pipeline located in
the Gulf of Mexico are poised to benefit as production volumes increase from developments
in the Southern Green Canyon area of the deepwater Gulf of Mexico.
Volumes on our Cameron Highway Oil Pipeline were adversely affected
during the fourth quarter of 2005 due to disruption of production
caused by Hurricanes Katrina and Rita, and these volumes are expected
to continue to be adversely affected during the first quarter of
2006. However, we currently expect significant increases in Cameron
Highway Oil Pipeline volumes during the remainder of 2006 as
production increases, including production at the Mad Dog field and
initial production from the Ticonderoga, K2 North and Timon fields. |
|
|
§ |
|
We believe that the strength of the domestic and global economy will continue to drive
increased demand for all forms of energy despite higher commodity prices. Our largest NGL
consuming customers in the ethylene industry continue to see strong demand for their
products, which enables them to raise prices to mitigate higher fuel and feedstock costs.
With the unusually high price of crude oil relative to natural gas, ethane and propane are
the preferred feedstocks for the ethylene industry. |
LIQUIDITY AND CAPITAL RESOURCES
Our primary cash requirements, in addition to normal operating expenses and debt service, are
for capital expenditures, business acquisitions and distributions to our partners. We expect to
fund our short-term needs for such items as operating expenses and sustaining capital expenditures
with operating cash flows and short-term revolving credit arrangements. Capital expenditures for
long-term needs resulting from internal growth projects and business acquisitions are expected to
be funded by a variety of sources (either separately or in combination) including cash flows from
operating activities, borrowings under commercial bank credit facilities, the issuance of
additional equity and debt securities. We expect to fund cash distributions to partners primarily
with operating cash flows. Our debt service requirements are expected to be funded by operating
cash flows and/or refinancing arrangements.
At December 31, 2005, we had $42.1 million of unrestricted cash on hand and approximately $727
million of available credit under our Operating Partnerships Multi-Year Revolving Credit Facility.
57
In total, we had approximately $4.8 billion in principal outstanding under various debt
agreements at December 31, 2005.
As a result of our growth objectives, we expect to access debt and equity capital markets from
time-to-time and we believe that financing arrangements to support our growth activities can be
obtained on reasonable terms. Furthermore, we believe that maintenance of an investment grade
credit rating combined with continued ready access to debt and equity capital at reasonable rates
and sufficient trade credit to operate our businesses efficiently provide a solid foundation to meet our long and
short-term liquidity and capital resource requirements.
For additional information regarding our growth strategy, please read Capital Spending
included within this Item 7.
Credit Ratings
At February 15, 2006, the credit ratings of our Operating Partnerships debt securities were
Baa3 with a stable outlook as rated by Moodys Investor Services; BBB- with a stable outlook as
rated by Fitch Ratings; and BB+ with a stable outlook as rated by Standard and Poors.
In connection with the construction of our Pascagoula, Mississippi natural gas processing
plant, the Operating Partnership entered into a $54 million, ten-year, fixed-rate loan with the
Mississippi Business Finance Corporation (MBFC). The indenture agreement for this loan contains
an acceleration clause whereby if the Operating Partnerships credit rating by Moodys declines
below Baa3 in combination with our credit rating at Standard & Poors remaining at BB+ or lower,
the $54 million principal balance of this loan, together with all accrued and unpaid interest would
become immediately due and payable 120 days following such event. If such an event occurred, we
would have to either redeem the Pascagoula MBFC Loan or provide an alternative credit agreement to
support our obligation under this loan.
Registration Statements
From time-to-time, we issue equity or debt securities to assist us in meeting our liquidity
and capital spending requirements. In March 2005, we filed a universal shelf registration
statement with the SEC registering the issuance of $4 billion of equity and debt securities.
After taking into account our issuance of securities under this universal registration statement
during 2005, we can issue an additional $3.4 billion of securities under this registration
statement as of February 15, 2006.
During 2003, we instituted a distribution reinvestment plan (DRIP). The DRIP provides
unitholders of record and beneficial owners of our common units a voluntary means by which they can
increase the number of common units they own by reinvesting the quarterly cash distributions they
would otherwise receive into the purchase of additional common units. We have a registration
statement on file with the SEC covering the issuance of up to 15,000,000 common units in connection
with the DRIP. A total of 10,925,102 common units have been issued under this registration
statement through February 15, 2006.
We also have a registration statement on file related to our employee unit purchase plan,
under which we can issue up to 1,200,000 common units. Under this plan, employees of EPCO can
purchase our common units at a 10% discount through payroll deductions. A total of 260,222 common
units have been issued to employees under this plan through February 15, 2006.
For information regarding our public debt obligations or partnership equity, please read Note
14 and 15, respectively, of the Notes to Consolidated Financial Statements included under Item 8 of
this annual report.
58
Debt Obligations
For detailed information regarding our consolidated debt obligations and those of our
unconsolidated affiliates, please read Note 14 of the Notes to Consolidated Financial Statements
included under Item 8 of this annual report. The following table summarizes our consolidated debt
obligations at the dates indicated (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2005 |
|
2004 |
|
|
|
Operating Partnership debt obligations: |
|
|
|
|
|
|
|
|
364-Day Acquisition Credit Facility, variable rate, repaid in February 2005(1) |
|
|
|
|
|
$ |
242,229 |
|
Multi-Year Revolving Credit Facility, variable rate, due October 2010 |
|
$ |
490,000 |
|
|
|
321,000 |
|
Seminole Notes, 6.67% fixed-rate, repaid December 2005 |
|
|
|
|
|
|
15,000 |
|
Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010 |
|
|
54,000 |
|
|
|
54,000 |
|
Senior Notes A, 8.25% fixed-rate, repaid March 2005 |
|
|
|
|
|
|
350,000 |
|
Senior Notes B, 7.50% fixed-rate, due February 2011 |
|
|
450,000 |
|
|
|
450,000 |
|
Senior Notes C, 6.375% fixed-rate, due February 2013 |
|
|
350,000 |
|
|
|
350,000 |
|
Senior Notes D, 6.875% fixed-rate, due March 2033 |
|
|
500,000 |
|
|
|
500,000 |
|
Senior Notes E, 4.00% fixed-rate, due October 2007 |
|
|
500,000 |
|
|
|
500,000 |
|
Senior Notes F, 4.625% fixed-rate, due October 2009 |
|
|
500,000 |
|
|
|
500,000 |
|
Senior Notes G, 5.60% fixed-rate, due October 2014 |
|
|
650,000 |
|
|
|
650,000 |
|
Senior Notes H, 6.65% fixed-rate, due October 2034 |
|
|
350,000 |
|
|
|
350,000 |
|
Senior Notes I, 5.00% fixed-rate, due March 2015(2) |
|
|
250,000 |
|
|
|
|
|
Senior Notes J, 5.75% fixed-rate, due March 2035(3) |
|
|
250,000 |
|
|
|
|
|
Senior Notes K, 4.950% fixed-rate, due June 2010(4) |
|
|
500,000 |
|
|
|
|
|
Dixie Revolving Credit Facility, variable rate, due June 2007 |
|
|
17,000 |
|
|
|
|
|
Debt obligations assumed from GulfTerra |
|
|
5,068 |
|
|
|
6,469 |
|
|
|
|
Total principal amount |
|
|
4,866,068 |
|
|
|
4,288,698 |
|
Other, including unamortized discounts and premiums and changes in fair value(5) |
|
|
(32,287 |
) |
|
|
(7,462 |
) |
|
|
|
Subtotal long-term debt |
|
|
4,833,781 |
|
|
|
4,281,236 |
|
Less current maturities of debt(6) |
|
|
|
|
|
|
(15,000 |
) |
|
|
|
Long-term debt |
|
$ |
4,833,781 |
|
|
$ |
4,266,236 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Standby letters of credit outstanding |
|
$ |
33,129 |
|
|
$ |
139,052 |
|
|
|
|
|
|
|
(1) |
|
We used the proceeds from our February 2005 common unit offering to fully repay and terminate the 364-Day Acquisition Credit Facility. For additional information regarding this equity offering,
see Note 15 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
|
|
(2) |
|
Senior Notes I were issued at 99.379% of their face amount in February 2005.
|
|
(3) |
|
Senior Notes J were issued at 98.691% of their face amount in February 2005.
|
|
(4) |
|
Senior Notes K were issued at 99.834% of their face amount in June 2005.
|
|
(5) |
|
The December 31, 2005 amount includes $18.2 million related to fair value hedges and $14.1 million in net unamortized discounts. The December 31, 2004 amount includes $1.8 million related to
fair value hedges and $9.2 million in net unamortized discounts.
|
|
(6) |
|
In accordance with Statement of Financial Accounting Standards (SFAS) No. 6, Classification of Short-Term Obligations Expected to Be Refinanced, long-term and current maturities of debt at
December 31, 2004, reflected (i) our refinancing of Senior Notes A with proceeds from our Senior Notes I and J in March 2005 and (ii) the repayment of our 364-Day Acquisition Facility using proceeds
from an equity offering completed in February 2005. |
59
Our significant debt-related transactions during 2005 were as follows:
|
§ |
|
In February 2005, we completed repayment of the 364-Day Acquisition Credit Facility
using proceeds from our February 2005 equity offering. |
|
|
§ |
|
Also in February 2005, we issued $500 million in aggregate principal amount of Senior
Notes I and J. A portion of the proceeds from these Senior Notes were used to repay
Senior Notes A, which matured in March 2005. |
|
|
§ |
|
In June 2005, we issued $500 million in aggregate principal amount of Senior Notes K. |
|
|
§ |
|
In October 2005, the borrowing capacity under the Operating Partnerships Multi-Year
Revolving Credit Facility was increased from $750 million to $1.25 billion, with the
possibility that the borrowing capacity could be increased further to $1.4 billion
(subject to certain conditions). In addition, the maturity date for debt outstanding
under this facility was extended from September 2009 to October 2010. |
|
|
§ |
|
In December 2005, Seminole Pipeline Company, a majority-owned subsidiary, made the
final payment on its indebtedness. |
We have three unconsolidated affiliates with long-term debt obligations. The following table
summarizes the debt obligations of these unconsolidated affiliates (on a 100% basis to the joint
venture) at December 31, 2005 and our ownership interest in each entity on that date (dollars in
thousands):
|
|
|
|
|
|
|
|
|
|
|
Our |
|
|
|
|
|
|
Ownership |
|
|
|
|
|
|
Interest |
|
|
Total |
|
|
|
|
Cameron Highway |
|
50.0 |
% |
|
|
$ |
415,000 |
|
Poseidon |
|
36.0 |
% |
|
|
|
95,000 |
|
Evangeline |
|
49.5 |
% |
|
|
|
30,650 |
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
$ |
540,650 |
|
|
|
|
|
|
|
|
|
For information regarding the scheduled maturities of our consolidated debt obligations
and estimated cash payments for interest, please read Contractual Obligations within this Item 7.
Cash Flows from Operating, Investing and Financing Activities
The following table summarizes our cash flows from operating, investing and financing
activities for the periods indicated (dollars in thousands). For information regarding the
individual components of our cash flow amounts, please see the Statements of Consolidated Cash
Flows included under Item 8 of this annual report.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For Year Ended December 31, |
|
|
|
|
|
2005 |
|
2004 |
|
2003 |
|
|
|
Net cash provided from operating activities |
|
$ |
631,708 |
|
|
$ |
391,541 |
|
|
$ |
424,705 |
|
Net cash used in investing activities |
|
|
1,130,395 |
|
|
|
941,424 |
|
|
|
662,076 |
|
Net cash provided by financing activities |
|
|
516,229 |
|
|
|
543,973 |
|
|
|
254,020 |
|
We prepare our Statements of Consolidated Cash Flows using the indirect method. The
indirect method derives net cash flows from operating activities by adjusting net income to remove
(i) the effects of all deferrals of past operating cash receipts and payments, such as changes
during the period in inventory, deferred income and the like, (ii) the effects of all accruals of
expected future operating cash receipts and cash payments, such as changes during the period in
receivables and payables, and (iii) the effects of all items classified as investing or financing
cash flows, such as gains or losses on sale of assets or gains or losses from the extinguishment of
debt. In general, the net effect of changes in operating accounts results from the timing of cash
receipts from sales and cash payments for purchases and other expenses during
60
each period.
Increases or decreases in inventory balances are influenced by changes in commodity prices and the
quantity of products held in connection with our marketing activities.
In addition, noncash items that were subtracted in determining income must be added back in
determining net cash flows from operating activities. Each of these noncash items is a charge
against income but does not decrease cash. Items to be added back include depreciation,
amortization of intangibles, amortization in interest expense, operating lease expense paid by
EPCO, provisions for impairments of long-lived assets and increases in deferred tax liabilities.
Conversely, noncash items that were added in determining income (such as amortization of bond
premiums or decreases in deferred tax liabilities) must be subtracted in determining net cash flows
from operating activities.
Equity in income or loss from unconsolidated affiliates is also a non-cash item that must
be removed in determining net cash flows from operating activities. Our cash flows from operating
activities reflect the actual cash distributions we receive from such investees.
Net cash provided from operating activities is largely dependent on earnings from our business
activities. As a result, these cash flows are exposed to certain risks. We operate predominantly
in the midstream energy industry. We provide services for producers and consumers of natural gas,
NGLs and crude oil. 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. Reduced demand for our services or products by industrial
customers, whether because of general economic conditions, reduced demand for the end products made
with our products or increased competition from other service providers or producers due to pricing
differences or other reasons could have a negative impact on our earnings and thus the availability
of cash from operating activities. For a more complete discussion of these and other risk factors
pertinent to our business, please read Item 1A of this annual report.
Cash used in investing activities primarily represents expenditures for capital projects,
business combinations, asset purchases and investments in unconsolidated affiliates. Cash provided
by (or used in) financing activities generally consists of borrowings and repayments of debt,
distributions to partners and proceeds from the issuance of equity securities. Amounts presented
in our Statements of Consolidated Cash Flows for borrowings and repayments under debt agreements
are influenced by the magnitude of cash receipts and payments under our revolving credit
facilities.
The following information highlights the significant year-to-year variances in our cash flow
amounts:
Comparison of Year Ended December 31, 2005 with Year Ended December 31, 2004
Operating activities. Net cash provided from operating activities was $631.7 million
in 2005 compared to $391.5 million in 2004. The $240.2 million, or 61%, year-to-year increase in
net cash provided from operating activities is primarily due to:
|
§ |
|
Net income adjusted for all non-cash items and the net effects of changes in operating
accounts increased $252.1 million year-to-year primarily due to the addition of earnings
from assets acquired in connection with the GulfTerra Merger in September 2004. |
|
|
§ |
|
Distributions received from unconsolidated affiliates decreased by $12 million
year-to-year primarily due to the consolidation of GulfTerra GP in September 2004
partially offset by increased cash distributions from offshore Gulf of Mexico investments.
GulfTerra GP accounted for $32.3 million in cash distributions from unconsolidated
affiliates during 2004. |
The carrying value of our inventories increased from $189 million at December 31, 2004 to
$339.6 million at December 31, 2005. The $150.6 million increase is primarily due to higher
commodity prices during 2005 when compared to 2004 and an increase in volumes purchased and held in
inventory in connection with our marketing activities at December 31, 2005 versus December 31,
2004.
61
Investing activities. Cash used in investing activities was $1.1 billion in 2005
compared to $941.4 million in 2004. Expenditures for growth and sustaining capital projects (net
of contributions in aid of construction costs) increased $670.5 million year-to-year primarily due
to cash payments associated with our offshore Gulf of Mexico projects. Our cash outlays for asset
purchases and business combinations were $326.6 million in 2005 versus $724.7 million in 2004.
The 2004 period includes $638.8 million paid to El Paso in connection with the GulfTerra Merger.
Our investments in unconsolidated affiliates increased to $87.3 million in 2005 from $57.9
million in 2004. In 2005, we contributed $72 million to Deepwater Gateway, L.L.C. to fund our
share of the
repayment of its term loan. During 2004, we used $27.5 million to acquire additional
ownership interests in Promix, which owns the Promix NGL fractionator, and contributed $24 million
to Cameron Highway for the construction of its crude oil pipeline.
Cash flows related to investing activities for 2005 also include (i) a $47.5 million cash
receipt related to the partial return of our investment in Cameron Highway and (ii) a $42.1 million
cash receipt from the sale of our investment in Starfish Pipeline Company, LLC (Starfish). The
sale of our Starfish investment was required by the FTC in order to gain its approval for the
GulfTerra Merger.
For additional information related to our capital spending program, please read Capital
Spending included within this Item 7.
Financing activities. Cash provided by financing activities was $516.2 million in
2005 compared to $544 million in 2004. We had net borrowings under our debt agreements of $561.7
million during 2005 versus $125.6 million during 2004. During 2005, we issued an aggregate $1
billion in senior notes, the proceeds of which were used to temporarily reduce debt outstanding
under our bank credit facilities, repay Senior Notes A and for general partnership purposes,
including capital expenditures, asset purchases and business combinations. In addition, we repaid
the remaining $242.2 million that was outstanding at the end of 2004 under our 364-Day Acquisition
Credit Facility using proceeds from our February 2005 equity offering. We used the net proceeds
from our November 2005 equity offering to temporarily reduce amounts outstanding under our
Multi-Year Revolving Credit Facility.
In September 2004, we borrowed $2.8 billion under our bank credit facilities (principally the
364-Day Acquisition Credit Facility) to fund $655.3 million in cash payment obligations to El Paso
in connection with the GulfTerra Merger; purchase $1.1 billion of GulfTerras senior and senior
subordinated notes in connection with our tender offers; and repay $962 million outstanding under
GulfTerras revolving credit facility and secured term loans. In October 2004, we issued an
aggregate $2 billion in senior notes, the proceeds of which were used to reduce indebtedness
outstanding under our bank credit facilities. Our repayments of debt during 2004 also reflect the
use of $563.1 million of net proceeds from our May 2004 and August 2004 equity offerings to reduce
indebtedness under bank credit facilities.
Net proceeds from the issuance of limited partner interests were $646.9 million in 2005
compared to $846.1 million in 2004. We issued 23,979,740 common units in 2005 and 39,683,591
common units in 2004. Net proceeds from underwritten equity offerings were $555.5 million during
2005 reflecting the sale of 21,250,000 units and $694.3 million during 2004 reflecting the sale of
34,500,000 units. We used net proceeds from these underwritten offerings to reduce debt, including
the temporary repayment of indebtedness under bank credit facilities. Our distribution reinvestment
program and related plan generated net proceeds of $69.7 million in 2005 and $111.6 million in
2004. We used net proceeds from these offerings for general partnership purposes. For additional
information regarding our equity issuances, please read Note 15 of the Notes to Consolidated
Financial Statements included under Item 8 of this annual report.
Cash distributions to partners increased from $438.8 million in 2004 to $716.7 million in 2005
primarily due to an increase in common units outstanding and our quarterly cash distribution rates.
We expect that future cash distributions to partners will increase as a result of our periodic
issuance of common units. Cash contributions from minority interests were $39.1 million in 2005
compared to $9.6 million in
62
2004. These amounts relate to contributions from our joint venture
partner in the Independence Hub project.
Our financing activities for 2004 include a net cash receipt of $19.4 million resulting from
the settlement of forward starting interest rate swaps.
Comparison of Year Ended December 31, 2004 with Year Ended December 31, 2003
Operating activities. Net cash provided from operating activities was $391.5 million
in 2004 compared to $424.7 million in 2003. The $33.2 million decrease in net cash provided from
operating
activities is primarily due to (i) net income adjusted for all non-cash items and the net effects
of changes in operating accounts decreased $69.3 million year-to-year primarily due to timing of
cash receipts from sales and cash payments for purchases and other expenses between periods and
(ii) distributions received from unconsolidated affiliates increased $36.1 million year-to-year
primarily due to distributions from GulfTerra GP, which we acquired in December 2003.
Investing activities. Cash used in investing activities was $941.4 million in 2004
compared to $662.1 million in 2003. We used $638.8 million in 2004 to complete the GulfTerra
Merger, including our purchase of the South Texas midstream assets. Our expenditures for other
asset purchases and business combinations were $724.7 million in 2004 versus $37.3 million in 2003.
Investments in unconsolidated affiliates were $57.9 million in 2004 compared to $463.9 million in
2003, which includes our $425 million cash payment to El Paso to acquire GulfTerra GP in December
2003. Expenditures for growth and sustaining capital projects (net of contributions in aid of
construction costs) were essentially flat year-to-year at approximately $146 million for each
period.
Financing activities. Cash provided by financing activities was $544 million in 2004
compared to $254 million in 2003. We had net borrowings of $125.6 million during 2004 compared to
net repayments of $106.8 million during 2003. As discussed under Financing activities on page
62, net borrowings during 2004 primarily reflect debt transactions associated with the GulfTerra
Merger. Our borrowing transactions during 2003 include the issuance of an aggregate $850 million
in senior notes and the borrowing of $425 million under a bank credit facility to purchase
GulfTerra GP. Repayments of debt during 2003 reflect the use of net proceeds from debt and equity
offerings completed in 2003 to reduce indebtedness under bank credit facilities, including the
repayment of $1 billion outstanding under a term loan we used to acquire ownership interests in the
Mid-America Pipeline System and Seminole Pipeline.
Net proceeds from the issuance of limited partner interests were $846.1 million in 2004
compared to $675.7 million in 2003. We issued 39,683,591 common units in 2004 and 29,506,303
common units in 2003. Net proceeds from underwritten equity offerings were $694.3 million during
2004 reflecting the sale of 34,500,000 units and $519.2 million during 2003 reflecting the sale of
26,622,500 units. We used net proceeds from these underwritten offerings primarily to reduce debt,
including the temporary repayment of indebtedness under bank credit facilities. In addition, we
received $100 million from the sale of 4,413,549 Class B special units to an affiliate of EPCO in
2003. The Class B special units converted to common units in July 2004.
Our distribution reinvestment program and related plan generated net proceeds of $111.6
million in 2004 and $60.3 million in 2003. We used net proceeds from these offerings for general
partnership purposes. The year-to-year increase in net proceeds from our distribution reinvestment
program is attributable to EPCO, which publicly announced in 2003 that it would reinvest
approximately $140 million of its cash distributions in support of our growth objectives. This
commitment extended from the distribution paid in February 2004 to the distribution paid in
February 2005.
Cash distributions to partners increased from $309.9 million in 2003 to $438.8 million in 2004
primarily due to an increase in distribution-bearing units outstanding and higher cash distribution
rates.
Financing activities include net cash receipts of $19.4 million in 2004 and $5.4 million in
2003 resulting from the settlement of interest rate hedging financial instruments.
63
CONTRACTUAL OBLIGATIONS
The following table summarizes our significant contractual obligations at December 31, 2005.
A description of each type of contractual obligation follows (dollars in thousands).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payment or Settlement due by Period |
|
|
|
|
|
|
Less than |
|
1-3 |
|
3-5 |
|
More than |
Contractual Obligations |
|
Total |
|
1 year |
|
years |
|
years |
|
5 years |
|
|
|
|
|
|
(2006) |
|
(2007 2008) |
|
(2009 2010) |
|
Beyond 2010 |
Scheduled Maturities of Long-Term Debt |
|
$ |
4,866,068 |
|
|
|
|
|
|
$ |
517,000 |
|
|
$ |
1,549,068 |
|
|
$ |
2,800,000 |
|
Estimated Cash Payments for Interest |
|
$ |
3,160,380 |
|
|
$ |
271,597 |
|
|
$ |
518,809 |
|
|
$ |
455,189 |
|
|
$ |
1,914,785 |
|
Operating Lease Obligations |
|
$ |
179,623 |
|
|
$ |
19,099 |
|
|
$ |
33,848 |
|
|
$ |
20,089 |
|
|
$ |
106,587 |
|
Purchase Obligations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product purchase commitments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated payment obligations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
|
$ |
1,518,016 |
|
|
$ |
216,690 |
|
|
$ |
433,973 |
|
|
$ |
433,380 |
|
|
$ |
433,973 |
|
NGLs |
|
$ |
6,095,907 |
|
|
$ |
684,250 |
|
|
$ |
1,118,948 |
|
|
$ |
999,800 |
|
|
$ |
3,292,909 |
|
Petrochemicals |
|
$ |
1,290,952 |
|
|
$ |
1,079,110 |
|
|
$ |
211,842 |
|
|
|
|
|
|
|
|
|
Other |
|
$ |
87,162 |
|
|
$ |
31,578 |
|
|
$ |
44,724 |
|
|
$ |
10,860 |
|
|
|
|
|
Underlying major volume commitments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (in BBtus) |
|
|
127,850 |
|
|
|
18,250 |
|
|
|
36,550 |
|
|
|
36,500 |
|
|
|
36,550 |
|
NGLs (in MBbls) |
|
|
63,130 |
|
|
|
9,251 |
|
|
|
12,827 |
|
|
|
10,172 |
|
|
|
30,880 |
|
Petrochemicals (in MBbls) |
|
|
19,717 |
|
|
|
16,525 |
|
|
|
3,192 |
|
|
|
|
|
|
|
|
|
Service payment commitments |
|
$ |
5,765 |
|
|
$ |
5,037 |
|
|
$ |
728 |
|
|
|
|
|
|
|
|
|
Capital expenditure commitments |
|
$ |
208,575 |
|
|
$ |
208,575 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Long-Term Liabilities, as reflected on our
Consolidated Balance Sheet |
|
$ |
84,486 |
|
|
|
|
|
|
$ |
24,828 |
|
|
$ |
9,897 |
|
|
$ |
49,761 |
|
|
|
|
Total |
|
$ |
17,496,934 |
|
|
$ |
2,515,936 |
|
|
$ |
2,904,700 |
|
|
$ |
3,478,283 |
|
|
$ |
8,598,015 |
|
|
|
|
Scheduled Maturities of Long-Term Debt
We have long and short-term payment obligations under debt agreements such as the indentures
governing our Operating Partnerships senior notes and the credit agreement governing our Operating
Partnerships Multi-Year Revolving Credit Facility. Amounts shown in the table represent our
scheduled future maturities of long-term debt principal for the periods indicated. For additional
information regarding our debt obligations, please read Note 14 of the Notes to Consolidated
Financial Statements included under Item 8 of this annual report.
Estimated Cash Payments for Interest
We are obligated to make interest payments on our debt principal amounts outstanding. The
amounts shown in the preceding table for estimated cash interest payments represent our forecast of
variable and fixed interest payments to be made in connection with debt principal amounts
outstanding at December 31, 2005. Our estimates of future cash interest payments include the
following amounts to be paid in connection with variable interest rates: $146.6 million in total,
$31.5 million for 2006, $31.2 million for 2007, $30.8 million for each of 2008 and 2009, and $22.3
million for 2010. We estimated our variable interest rate cash payments by multiplying the
weighted-average variable interest rate paid during 2005 (under each of our variable rate debt
obligations that were outstanding at December 31, 2005) by the debt principal amount outstanding at
that date and assumed that the balance outstanding would not change until maturity.
Our estimates of cash interest payments to be paid under fixed interest rate obligations were
determined by multiplying the fixed interest rate associated with each fixed-rate obligation for
each period that the principal would be outstanding until maturity. To the extent that we have
exchanged a fixed interest rate for a variable interest rate, we have included the impact of such
interest rate swap agreements in our calculations. Our internal estimates of long-term interest
rates indicate that variable interest rates may exceed the fixed interest rates of the debt
obligations underlying our interest rate swap agreements. If
this occurs, we are responsible for payment of the excess of the current variable interest
rate over the fixed
64
interest rate of the underlying debt obligation. For conservatism, the amounts
shown in the table above do not reflect any cash receipts from interest rate swap agreements (i.e.
net reductions in cash outlays for interest) when the variable interest rate is less than the fixed
interest rate of the underlying debt obligations.
For information regarding our interest rate swap agreements, please read Item 7A of this
annual report.
Operating Lease Obligations
We lease certain property, plant and equipment under noncancelable and cancelable operating
leases. Amounts shown in the preceding table represent minimum cash lease payment obligations
under our third-party operating leases with terms in excess of one year for the periods indicated.
For additional information regarding our operating lease commitments, please read Note 21 of the
Notes to Consolidated Financial Statements included under Item 8 of this annual report.
Purchase Obligations
We define a purchase obligation as an agreement to purchase goods or services that is
enforceable and legally binding (unconditional) on us that specifies all significant terms,
including: fixed or minimum quantities to be purchased; fixed, minimum or variable price
provisions; and the approximate timing of the transactions. We have classified our unconditional
purchase obligations into the following categories:
Product purchase commitments. We have long and short-term product purchase
obligations for NGLs, petrochemicals and natural gas with third-party suppliers. The prices that
we are obligated to pay under these contracts approximate market prices at the time we take
delivery of the volumes. The preceding table shows our volume commitments and estimated payment
obligations under these contracts for the periods indicated. Our estimated future payment
obligations are based on the contractual price under each contract for purchases made at December
31, 2005 applied to all future volume commitments. Actual future payment obligations may vary
depending on market prices at the time of delivery.
Service contract commitments. We have long and short-term commitments to pay
third-party providers for services such as maintenance agreements. Our contractual payment
obligations vary by contract. The preceding table shows our future payment obligations under these
service contracts.
Capital expenditure commitments. We have short-term payment obligations relating to
capital projects we have initiated and are also responsible for our share of such obligations
associated with the capital projects of our unconsolidated affiliates. These commitments represent
unconditional payment obligations that we or our unconsolidated affiliates have agreed to pay
vendors for services rendered or products purchased. The preceding table shows these combined
amounts for the periods indicated.
Other Long-Term Liabilities
We have recorded long-term liabilities on our balance sheet reflecting amounts we expect to
pay in future periods beyond one year. These liabilities primarily relate to reserves for asset
retirement obligations, environmental liabilities and other amounts. Amounts shown in the
preceding table represent our best estimate as to the timing of payments based on available
information.
65
OFF-BALANCE SHEET ARRANGEMENTS
Cameron Highway issued senior secured notes in December 2005. We secure a portion of these
notes by (i) a pledge by us of our 50% partnership interest in Cameron Highway, (ii) mortgages on
and pledges of certain assets related to certain rights of way and pipeline assets of an indirect
wholly-owned subsidiary of ours that serves as the operator of the Cameron Highway Oil Pipeline,
and (iii) letters of credit in an initial amount of $18.4 million issued by the Operating
Partnership on behalf of Cameron Highway. For more information regarding Cameron Highways senior
secured notes, please read Note 14 of the Notes to Consolidated Financial Statements included under
Item 8 of this annual report. In addition, we have furnished $1.2 million in letters of credit on
behalf of Evangeline at December 31, 2005. We currently expect
that Cameron Highway will seek to amend its senior secured notes
during 2006 to address delayed increases in volumes due to
disruptions of production caused by Hurricanes Katrina and Rita, but
we believe that such amendments will be obtained without any material
adverse effect on us.
Except for the foregoing, we have no off-balance sheet arrangements, as described in Item
303(a)(4)(ii) of Regulation S-K, that have or are reasonably expected to have a material current or
future effect on our financial condition, revenues, expenses, results of operations, liquidity,
capital expenditures or capital resources.
RECENT ACCOUNTING DEVELOPMENTS
The following information summarizes recently issued accounting guidance that will (or may)
affect our financial statements in the future:
|
§ |
|
SFAS 123(R), Share-Based Payment, eliminates the ability to account for share-based
compensation transactions using Accounting Principles Board (APB) 25 and generally
requires that such transactions be accounted for using a fair value method.
Historically, we have accounted for our share-based transactions using APB 25. We adopted
SFAS 123(R) on January 1, 2006, which resulted in our recording a cumulative effect of a
change in accounting principle of $0.3 million. During 2006, we expect to record
compensation expense of $7 million associated with the fair value method of accounting for
unit options, profits interests and nonvested (or restricted) units using SFAS 123(R)
based on awards outstanding at January 1, 2006. |
|
|
§ |
|
SFAS 154, Accounting Changes and Error Corrections, provides guidance on the
accounting for and reporting of accounting changes and error corrections. We adopted SFAS
154 on January 1, 2006. |
|
|
§ |
|
Emerging Issues Task Force (EITF) 04-13, Accounting for Purchases and Sale of
Inventory With the Same Counterparty, requires that two or more inventory transactions
with the same counterparty be viewed as a single nonmonetary transaction, if the
transactions were entered into in contemplation of one another. Exchanges of inventory
between entities in the same line of business should be accounted for at fair value or
recorded at carrying amounts, depending on the classification of such inventory. We are
still evaluating this recent guidance, which is effective April 1, 2006 for our
partnership, but we do not believe that our revenues or costs and expenses will be
materially affected. |
66
CRITICAL ACCOUNTING POLICIES
In our financial reporting process, we employ methods, estimates and assumptions that affect
the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities
as of the date of our financial statements. These methods, estimates and assumptions also affect
the reported amounts of revenues and expenses during the reporting period. Investors should be
aware that actual results could differ from these estimates if the underlying assumptions prove to
be incorrect. The following describes the estimation risk underlying our most significant
financial statement items:
Depreciation methods and estimated useful lives of property, plant and equipment
In general, depreciation is the systematic and rational allocation of an assets cost, less
its residual value (if any), to the periods it benefits. The majority of our property, plant and
equipment is depreciated using the straight-line method, which results in depreciation expense
being incurred evenly over the life of the assets. Our estimate of depreciation incorporates
assumptions regarding the useful economic lives and residual values of our assets. At the time we
place our assets in service, we believe such assumptions are reasonable; however, circumstances may
develop that would cause us to change these assumptions, which would change our depreciation
amounts on a going forward basis. Some of these circumstances include changes in laws and
regulations relating to restoration and abandonment requirements; changes in expected costs for
dismantlement, restoration and abandonment as a result of changes, or expected changes, in labor,
materials and other related costs associated with these activities; changes in the useful life of
an asset based on the actual known life of similar assets, changes in technology, or other factors;
and changes in expected salvage proceeds as a result of a change, or expected change in the salvage
market.
At December 31, 2005 and 2004, the net book value of our property, plant and equipment was
$8.7 billion and $7.8 billion, respectively. We recorded $328.7 million, $161 million and $101
million in depreciation expense during 2005, 2004 and 2003, respectively. A significant portion of
the year-to-year increase in depreciation expense between 2005 and 2004 is attributable to the
property, plant and equipment assets we acquired in the GulfTerra Merger in September 2004. For
additional information regarding our property, plant and equipment, please read Notes 2 and 10 of
the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
Measuring recoverability of long-lived assets and equity method investments
In general, long-lived assets (including intangible assets with finite useful lives and
property, plant and equipment) are reviewed for impairment whenever events or changes in
circumstances indicate that their carrying amount may not be recoverable. Examples of such events
or changes might be production declines that are not replaced by new discoveries or long-term
decreases in the demand or price of natural gas, oil or NGLs. Long-lived assets with recorded
values that are not expected to be recovered through future expected cash flows are written-down to
their estimated fair values. The carrying value of a long-lived asset is not recoverable if it
exceeds the sum of undiscounted estimated cash flows expected to result from the use and eventual
disposition of the existing asset. Our estimates of such undiscounted cash flows are based on a
number of assumptions including anticipated operating margins and volumes; estimated useful life of
the asset or asset group; and estimated salvage values. An impairment charge would be recorded for
the excess of a long-lived assets carrying value over its estimated fair value, which is based on
a series of assumptions similar to those used to derive undiscounted cash flows. Those assumptions
also include usage of probabilities for a range of possible outcomes, market values and replacement
cost estimates. We recorded $1.2 million and $4.1 million for asset impairment charges in 2003
and 2004, respectively, related to NGL fractionation and storage facilities located in Mississippi.
Equity method investments are evaluated for impairment whenever events or changes in
circumstances indicate that there is a possible loss in value for the investment other than a
temporary decline. Examples of such events include sustained operating losses of the investee or
long-term negative changes in the investees industry. The carrying value of an equity method
investment is not recoverable if it exceeds the sum of discounted estimated cash flows expected to
be derived from the investment. This
estimate of discounted cash flows is based on a number of assumptions including discount
rates;
67
probabilities assigned to different cash flow scenarios; anticipated margins and volumes and
estimated useful life of the investment. A significant change in these underlying assumptions
could result in our recording an impairment charge.
Due to a deteriorating business environment, BEF evaluated the carrying value of its
long-lived assets for impairment during the third quarter of 2003. This review indicated that the
carrying value of its long-lived assets exceeded their collective fair value, which resulted in a
non-cash impairment charge of $67.5 million. Since BEF was one of our equity investments at that
time, our share of this loss was $22.5 million and was recorded as a component of equity earnings
from unconsolidated affiliates during 2003.
For additional information regarding our asset impairment charges, please read Notes 2 and 11
of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
Amortization methods and estimated useful lives of qualifying intangible assets
The specific, identifiable intangible assets of a business enterprise depend largely upon the
nature of its operations. Potential intangible assets include intellectual property, such as
technology, patents, trademarks and trade names, customer contracts and relationships, and
non-compete agreements, as well as other intangible assets. The method used to value each
intangible asset will vary depending upon the nature of the asset, the business in which it is
utilized, and the economic returns it is generating or is expected to generate.
Our customer relationship intangible assets primarily represent the customer base we acquired
in connection with the GulfTerra Merger and related transactions. The value we assigned to these
customer relationships is being amortized to earnings using methods that closely resemble the
pattern in which the economic benefits of the underlying oil and natural gas resource bases from
which the customers produce are estimated to be consumed or otherwise used. Our estimate of the
useful life of each resource base is based on a number of factors, including third-party reserve
estimates, the economic viability of production and exploration activities and other industry
factors.
Our contract-based intangible assets represent the rights we own arising from discrete
contractual agreements, such as the long-term rights we possess under the Shell natural gas
processing agreement. A contract-based intangible asset with a finite life is amortized over its
estimated useful life (or term), which is the period over which the asset is expected to contribute
directly or indirectly to the cash flows of an entity. Our estimates of useful life are based on
a number of factors, including (i) the expected useful life of the related tangible assets (e.g.,
fractionation facility, pipeline, etc.), (ii) any legal or regulatory developments that would
impact such contractual rights, and (iii) any contractual provisions that enable us to renew or
extend such agreements.
If our underlying assumptions regarding the estimated useful life of an intangible asset
change, then the amortization period for such asset would be adjusted accordingly. Additionally,
if we determine that an intangible assets unamortized cost may not be recoverable due to
impairment; we may be required to reduce the carrying value and the subsequent useful life of the
asset. Any such write-down of the value and unfavorable change in the useful life of an intangible
asset would increase operating costs and expenses at that time.
At December 31, 2005 and 2004, the carrying value of our intangible asset portfolio was $913.6
million and $980.6 million, respectively. We recorded $88.9 million, $33.8 million and $14.8
million in amortization expense associated with our intangible assets during 2005, 2004 and 2003,
respectively. A significant portion of the year-to-year increase in amortization expense between
2005 and 2004 is attributable to the intangible assets we acquired in the GulfTerra Merger.
For additional information regarding our intangible assets, please read Notes 2 and 13 of the
Notes to Consolidated Financial Statements included under Item 8 of this annual report.
68
Methods we employ to measure the fair value of goodwill
Goodwill represents the excess of the purchase prices we paid for certain businesses over their respective fair values and is primarily comprised of $387.1 million
associated with the GulfTerra Merger. We do not amortize goodwill; however, we test our goodwill
(at the reporting unit level) for impairment during the second quarter of each fiscal year, and
more frequently, if circumstances indicate it is more likely than not that the fair value of
goodwill is below its carrying amount. Our goodwill testing involves the determination of a
reporting units fair value, which is predicated on our assumptions regarding the future economic
prospects of the reporting unit. Such assumptions include (i) discrete financial forecasts for
the assets contained within the reporting unit, which rely on managements estimates of operating
margins and transportation volumes, (ii) long-term growth rates for cash flows beyond the discrete
forecast period, and (iii) appropriate discount rates. If the fair value of the reporting unit
(including its inherent goodwill) is less than its carrying value, a charge to earnings is required
to reduce the carrying value of goodwill to its implied fair value. At December 31, 2005 and
2004, the carrying value of our goodwill was $494 million and $459.2 million, respectively.
For additional information regarding our goodwill, please read Notes 2 and 13 of the Notes to
Consolidated Financial Statements included under Item 8 of this annual report.
Our revenue recognition policies and use of estimates for revenues and expenses
In general, we recognize revenue from our customers when all of the following criteria are
met: (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or
services have been rendered, (iii) the buyers price is fixed or determinable and (iv)
collectibility is reasonably assured. When sales contracts are settled (i.e., either physical
delivery of product has taken place or the services designated in the contract have been
performed), we record any necessary allowance for doubtful accounts.
Our use of certain estimates for revenues and operating costs and other expenses has increased
as a result of SEC regulations that require us to submit financial information on accelerated time
frames. Such estimates are necessary due to the timing of compiling actual billing information and
receiving third-party data needed to record transactions for financial reporting purposes. One
example of such use of estimates is the accrual of an estimate of processing plant revenue and the
cost of natural gas for a given month (prior to receiving actual customer and vendor-related plant
operating information for the subject period). These estimates reverse in the following month and
are offset by the corresponding actual customer billing and vendor-invoiced amounts. Accordingly,
we include one month of certain estimated data in our results of operations. Such estimates are
generally based on actual volume and price data through the first part of the month and estimated
for the remainder of the month, adjusted accordingly for any known or expected changes in volumes
or rates through the end of the month. If the basis of our estimates proves to be substantially
incorrect, it could result in material adjustments in results of operations between periods.
Reserves for environmental matters
Each of our business segments is subject to federal, state and local laws and regulations
governing environmental quality and pollution control. Such laws and regulations may, in certain
instances, require us to remediate current or former operating sites where specified substances
have been released or disposed of. We accrue reserves for environmental matters when our
assessments indicate that it is probable that a liability has been incurred and an amount can be
reasonably estimated. Our assessments are based on studies, as well as site surveys, to determine
the extent of any environmental damage and the necessary requirements to remediate this damage.
Future environmental developments, such as increasingly strict environmental laws and additional
claims for damages to property, employees and other persons resulting from current or past
operations, could result in substantial additional costs beyond our current reserves.
At December 31, 2005 and 2004, we had a liability for environmental remediation of $21
million, which was derived from a range of reasonable estimates based upon studies and site
surveys. In accordance with SFAS 5 Accounting for Contingencies and Financial Accounting
Standards Board
69
Interpretation (FIN) 14, Reasonable Estimation of the Amount of a Loss, we recorded our
best estimate of these remediation activities.
Natural gas imbalances
Natural gas imbalances result when customers physically deliver a larger or smaller quantity
of natural gas into our pipelines than they take out. In general, we value such imbalances using a
twelve-month moving average of natural gas prices, which we believe is reasonable given that the
actual settlement dates for such imbalances are generally not known. As a result, significant
changes in natural gas prices between reporting periods may impact our estimates.
At December 31, 2005 and 2004, our imbalance receivables were $89.4 million and $56.7 million,
respectively, and are reflected as a component of accounts receivable. At December 31, 2005 and
2004, our imbalance payables were $80.5 million and $59 million, respectively, and are reflected as
a component of accrued gas payables.
SUMMARY OF RELATED PARTY TRANSACTIONS
In accordance with SFAS 57, Related Party Disclosures, we have identified our material
related party revenues and costs and expenses. The following table summarizes our related party
transactions for the periods indicated (dollars in thousands).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For Year Ended December 31, |
|
|
2005 |
|
2004 |
|
2003 |
|
|
|
Revenues from consolidated operations |
|
|
|
|
|
|
|
|
|
|
|
|
EPCO and affiliates |
|
$ |
311 |
|
|
$ |
2,697 |
|
|
$ |
4,241 |
|
Shell |
|
|
|
|
|
|
542,912 |
|
|
|
293,109 |
|
Unconsolidated affiliates |
|
|
354,461 |
|
|
|
258,541 |
|
|
|
266,894 |
|
|
|
|
Total |
|
$ |
354,772 |
|
|
$ |
804,150 |
|
|
$ |
564,244 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses |
|
|
|
|
|
|
|
|
|
|
|
|
EPCO and affiliates |
|
$ |
293,134 |
|
|
$ |
203,100 |
|
|
$ |
149,915 |
|
Shell |
|
|
|
|
|
|
725,420 |
|
|
|
607,277 |
|
Unconsolidated affiliates |
|
|
23,563 |
|
|
|
37,587 |
|
|
|
43,752 |
|
|
|
|
Total |
|
$ |
316,697 |
|
|
$ |
966,107 |
|
|
$ |
800,944 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses |
|
|
|
|
|
|
|
|
|
|
|
|
EPCO and affiliates |
|
$ |
40,954 |
|
|
$ |
29,307 |
|
|
$ |
28,716 |
|
|
|
|
For additional information regarding our related party transactions identified in
accordance with GAAP, please read Note 18 of the Notes to Consolidated Financial Statements
included under Item 8 of this annual report. For information regarding certain business
relationships and related transactions, please read Item 13 of this annual report.
We have an extensive and ongoing relationship with EPCO and its affiliates, including TEPPCO.
Our revenues from EPCO and affiliates are primarily associated with sales of NGL products. Our
expenses with EPCO are primarily due to (i) reimbursements we pay EPCO in connection with an
administrative services agreement and (ii) purchases of NGL products. TEPPCO is an affiliate of
ours due to the common control relationship of both entities.
Historically, Shell was considered a related party under GAAP because it owned more than 10%
of our limited partner interests and, prior to 2003, held a 30% membership interest in Enterprise
Products GP. As a result of Shell selling a portion of its limited partner interests in us to
third parties and our issuance of additional common units, Shell owned less than 10% of our common
units at the beginning of 2005. Shell sold its 30% interest in Enterprise Products GP to an
affiliate of EPCO in September 2003. As a result of Shells reduced equity interest in us and its
lack of control of Enterprise Products GP, Shell ceased to be considered a related party under GAAP
in January 2005.
70
Many of our unconsolidated affiliates perform supporting or complementary roles to our
consolidated business operations. The majority of our revenues from unconsolidated affiliates
relate to natural gas sales to a Louisiana affiliate. The majority of our expenses with
unconsolidated affiliates pertain to payments to Promix for NGL transportation, storage and
fractionation services.
OTHER ITEMS
Non-GAAP reconciliation
A reconciliation of our measurement of total non-GAAP gross operating margin to GAAP operating
income and income before provision for income taxes, minority interest and the cumulative effect of
changes in accounting principles follows (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2005 |
|
2004 |
|
2003 |
|
|
|
Total non-GAAP gross operating margin |
|
$ |
1,136,347 |
|
|
$ |
655,191 |
|
|
$ |
410,415 |
|
Adjustments to reconcile total non-GAAP gross operating margin
to GAAP operating income: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization in operating costs and expenses |
|
|
(413,441 |
) |
|
|
(193,734 |
) |
|
|
(115,643 |
) |
Retained lease expense, net in operating costs and expenses |
|
|
(2,112 |
) |
|
|
(7,705 |
) |
|
|
(9,094 |
) |
Gain on sale of assets in operating costs and expenses |
|
|
4,488 |
|
|
|
15,901 |
|
|
|
16 |
|
General and administrative costs |
|
|
(62,266 |
) |
|
|
(46,659 |
) |
|
|
(37,590 |
) |
|
|
|
GAAP consolidated operating income |
|
|
663,016 |
|
|
|
422,994 |
|
|
|
248,104 |
|
Other net expense, primarily interest expense |
|
|
(225,178 |
) |
|
|
(153,625 |
) |
|
|
(134,406 |
) |
|
|
|
GAAP income before provision for income taxes, minority interest
and cumulative effect of changes in accounting principles |
|
$ |
437,838 |
|
|
$ |
269,369 |
|
|
$ |
113,698 |
|
|
|
|
EPCO subleases to us certain equipment located at our Mont Belvieu facility and 100
railcars for $1 per year (the retained leases). These subleases are part of the administrative
services agreement that we executed with EPCO in connection with our formation in 1998. EPCO holds
this equipment pursuant to operating leases for which it has retained the corresponding cash lease
payment obligation. We record the full value of such lease payments made by EPCO as a non-cash
related party operating expense, with the offset to partners equity recorded as a general
contribution to our partnership. Apart from the partnership interests we granted to EPCO at our
formation, EPCO does not receive any additional ownership rights as a result of its contribution to
us of the retained leases. For additional information regarding the administrative services
agreement and the retained leases, please read Item 13 of this annual report.
Cumulative effect of changes in accounting principles
Our Consolidated Statements of Operations and Comprehensive Income reflect the following
cumulative effects of changes in accounting principles:
|
§ |
|
We recorded a $4.2 million non-cash expense related to certain asset retirement
obligations in 2005 due to our implementation of FIN 47 as of December 31, 2005. |
|
|
§ |
|
We recorded a combined $10.8 million non-cash gain in 2004 related to the impact of (i)
changing the method our BEF subsidiary uses to account for its planned major maintenance
activities from the accrue-in-advance method to the expense-as-incurred method and (ii)
changing the method in which we account for our investment in VESCO from the cost method
to the equity method. |
For additional information regarding these changes in accounting principles, including a
presentation of the pro forma effects these changes would have had on our historical earnings,
please read Note 8 of the Notes to Consolidated Financial Statements included under Item 8 of this
annual report.
71
Financial statement reclassifications
Certain reclassifications have been made to the prior years financial statements to conform
to the current year presentation. During 2005, we changed the classification of changes in
restricted cash in our Statements of Consolidated Cash Flows to present such changes as an
investing activity. We previously presented such changes as an operating activity. In the
accompanying Statements of Consolidated Cash Flows for the years ended December 31, 2004 and 2003,
we reclassified the change in restricted cash to be consistent with our 2005 presentation. This
reclassification resulted in a $12.3 million and $5.1 million increase to cash flows used in
investing activities and a corresponding increase to cash provided by operating activities from the
amounts previously presented for the years ended December 31, 2004 and 2003, respectively.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
We are exposed to financial market risks, including changes in commodity prices and interest
rates. We may use financial instruments (i.e., futures, forwards, swaps, options and other
financial instruments with similar characteristics) to mitigate the risks of certain identifiable
and anticipated transactions. In general, the type of risks we attempt to hedge are those related
to the variability of future earnings, fair values of certain debt instruments and cash flows
resulting from changes in applicable interest rates or commodity prices. As a matter of policy, we
do not use financial instruments for speculative (or trading) purposes.
We recognize financial instruments as assets and liabilities on our Consolidated Balance
Sheets based on fair value. Fair value is generally defined as the amount at which a financial
instrument could be exchanged in a current transaction between willing parties, not in a forced or
liquidation sale. The estimated fair values of our financial instruments have been determined
using available market information and appropriate valuation techniques. We must use considerable
judgment, however, in interpreting market data and developing these estimates. Accordingly, our
fair value estimates are not necessarily indicative of the amounts that we could realize upon
disposition of these instruments. The use of different market assumptions and/or estimation
techniques could have a material effect on our estimates of fair value.
Changes in the fair value of financial instrument contracts are recognized currently in
earnings unless specific hedge accounting criteria are met. If the financial instruments meet
those criteria, the instruments gains and losses offset the related results of the hedged item in
earnings for a fair value hedge and are deferred in other comprehensive income for a cash flow
hedge. Gains and losses related to a cash flow hedge are reclassified into earnings when the
forecasted transaction affects earnings. For additional information regarding our accounting for
financial instruments, please read Note 7 of the Notes to Consolidated Financial Statements
included under Item 8 of this annual report.
To qualify as a hedge, the item to be hedged must be exposed to commodity or interest rate
risk and the hedging instrument must reduce the exposure and meet the hedging requirements of SFAS
133, Accounting for Derivative Instruments and Hedging Activities (as amended and interpreted).
We must formally designate the financial instrument as a hedge and document and assess the
effectiveness of the hedge at inception and on a quarterly basis. Any ineffectiveness of the hedge
is recorded in current earnings.
We routinely review our outstanding financial instruments in light of current market
conditions. If market conditions warrant, some financial instruments may be closed out in advance
of their contractual settlement dates thus realizing income or loss depending on the specific
exposure. When this occurs, we may enter into a new financial instrument to reestablish the
economic hedge to which the closed instrument relates.
Interest Rate Risk Hedging Program
Our interest rate exposure results from variable and fixed rate borrowings under debt
agreements. We assess cash flow risk related to interest rates by identifying and measuring
changes in our interest rate
72
exposures that may impact future cash flows and evaluating hedging opportunities to manage these
risks. We use analytical techniques to measure our exposure to fluctuations in interest rates,
including cash flow sensitivity analysis models to forecast the expected impact of changes in
interest rates on our future cash flows. Enterprise Products GP oversees the strategies associated
with these financial risks and approves instruments that are appropriate for our requirements.
We manage a portion of our interest rate exposures by utilizing interest rate swaps and
similar arrangements, which allow us to convert a portion of fixed rate debt into variable rate
debt or a portion of variable rate debt into fixed rate debt. We believe that it is prudent to
maintain an appropriate balance of variable rate and fixed rate debt in the current business
environment.
As summarized in the following table, we had eleven interest rate swap agreements outstanding
at December 31, 2005 that were accounted for as fair value hedges.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number |
|
Period Covered |
|
Termination |
|
Fixed to |
|
Notional |
Hedged Fixed Rate Debt |
|
Of Swaps |
|
by Swap |
|
Date of Swap |
|
Variable Rate (1) |
|
Amount |
|
Senior Notes B, 7.50% fixed rate, due Feb. 2011
|
|
|
1 |
|
|
Jan. 2004 to Feb. 2011
|
|
Feb. 2011
|
|
7.50% to 7.26%
|
|
$50 million |
Senior Notes C, 6.375% fixed rate, due Feb.
2013
|
|
|
2 |
|
|
Jan. 2004 to Feb. 2013
|
|
Feb. 2013
|
|
6.375% to 5.8%
|
|
$200 million |
Senior Notes G, 5.6% fixed rate, due Oct. 2014
|
|
|
6 |
|
|
4th Qtr. 2004 to Oct. 2014
|
|
Oct. 2014
|
|
5.6% to 5.24%
|
|
$600 million |
Senior Notes K, 4.95% fixed rate, due June 2010
|
|
|
2 |
|
|
Aug. 2005 to June 2010
|
|
June 2010
|
|
4.95% to 4.99%
|
|
$200 million |
(1) |
|
The variable rate indicated is the all-in variable rate for the current settlement period. |
We have designated these interest rate swaps as fair value hedges under SFAS 133 since
they mitigate changes in the fair value of the underlying fixed rate debt. As effective fair value
hedges, an increase in the fair value of these interest rate swaps is equally offset by an increase
in the fair value of the underlying hedged debt. The offsetting changes in fair value have no effect
on current period interest expense.
These eleven agreements have a combined notional amount of $1.1 billion and match the maturity
dates of the underlying debt being hedged. Under each swap agreement, we pay the counterparty a
variable interest rate based on six-month London interbank offered rate (LIBOR) (plus an
applicable margin as defined in each swap agreement), and receive back from the counterparty a
fixed interest rate payment based on the stated interest rate of the debt being hedged, with both
payments calculated using the notional amounts stated in each swap agreement. We settle amounts
receivable from or payable to the counterparties every six months (the settlement period). The
settlement amount is amortized ratably to earnings as either an increase or a decrease in interest
expense over the settlement period.
The total fair value of these eleven interest rate swaps at December 31, 2005, was a liability
of $19.2 million, with an offsetting decrease in the fair value of the underlying debt. Interest
expense for the years ended December 31, 2005 and 2004 reflects a $10.8 million and $9.1 million
benefit from these swap agreements, respectively.
The following tables show the effect of hypothetical price movements on the estimated fair
value of our interest rate swap portfolio and the related change in fair value of the underlying
debt at the dates indicated (dollars in thousands). Income is not affected by changes in the fair
value of these swaps; however, these swaps effectively convert the hedged portion of fixed-rate
debt to variable-rate debt. As a result, interest expense (and related cash outlays for debt
service) will increase or decrease with the change in the periodic reset rate associated with the
respective swap. Typically, the reset rate is an agreed upon index rate published for the first
day of the six-month interest calculation period.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Resulting |
|
Swap Fair Value at |
Scenario |
|
Classification |
|
December 31, 2004 |
|
December 31, 2005 |
|
February 1, 2006 |
|
FV assuming no change in underlying interest rates
|
|
Asset (Liability)
|
|
$ |
505 |
|
|
$ |
(19,179 |
) |
|
$ |
(28,621 |
) |
FV assuming 10% increase in underlying interest rates
|
|
Asset (Liability)
|
|
|
(31,586 |
) |
|
|
(50,308 |
) |
|
|
(59,744 |
) |
FV assuming 10% decrease in underlying interest rates
|
|
Asset (Liability)
|
|
|
32,596 |
|
|
|
11,950 |
|
|
|
2,503 |
|
73
The fair value of the interest rate swaps excludes the benefit we have already recorded
in earnings. The change in fair value between December 31, 2005 and February 1, 2006 is primarily
due to an increase in market interest rates relative to the forward interest rate curve used to
determine the fair value of our financial instruments. The underlying floating LIBOR forward
interest rate curve used to determine the February 1, 2006 fair values ranged from approximately
4.3% to 5.2% using 6-month reset periods ranging from October 2005 to October 2014.
Commodity Risk Hedging Program
The prices of natural gas, NGLs and petrochemical products are subject to fluctuations in
response to changes in supply, market uncertainty and a variety of additional factors that are
beyond our control. In order to manage the risks associated with natural gas and NGLs, we may
enter into commodity financial instruments.
The primary purpose of our commodity risk management activities is to hedge our exposure to
price risks associated with (i) natural gas purchases, (ii) NGL production and inventories, (iii)
related firm commitments, (iv) fluctuations in transportation revenues where the underlying fees
are based on natural gas index prices and (v) certain anticipated transactions involving either
natural gas or NGLs. The commodity financial instruments we utilize may be settled in cash or with
another financial instrument. Historically, we have not hedged our exposure to risks associated
with petrochemical products.
We have adopted a policy to govern our use of commodity financial instruments to manage the
risks of our natural gas and NGL businesses. The objective of this policy is to assist us in
achieving our profitability goals while maintaining a portfolio with an acceptable level of risk,
defined as remaining within the position limits established by Enterprise Products GP. We may
enter into risk management transactions to manage price risk, basis risk, physical risk or other
risks related to our commodity positions on both a short-term (less than 30 days) and long-term
basis, not to exceed 24 months. Enterprise Products GP oversees the strategies associated with
physical and financial risks (such as those mentioned previously), approves specific activities
subject to the policy (including authorized products, instruments and markets) and establishes
specific guidelines and procedures for implementing and ensuring compliance with the policy.
At December 31, 2005, we had a limited number of commodity financial instruments in our
portfolio, which primarily consisted of economic hedges. The fair value of our commodity financial
instrument portfolio at December 31, 2005 was a liability of $0.1 million. We recorded nominal
amounts of earnings from our commodity financial instruments during 2005, 2004 and 2003.
Product Purchase Commitments
We have long and short-term purchase commitments for NGLs, petrochemicals and natural gas with
several suppliers. The purchase prices that we are obligated to pay under these contracts are
based on market prices at the time we take delivery of the volumes. For additional information
regarding these commitments, please read Contractual Obligations included under Item 7 of this
annual report.
74
Item 8. Financial Statements and Supplementary Data.
ENTERPRISE PRODUCTS PARTNERS L.P.
INDEX TO FINANCIAL STATEMENTS
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Page No. |
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148 |
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149 |
|
75
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Enterprise Products GP, LLC and
Unitholders of Enterprise Products Partners L.P.
Houston, Texas
We have audited the accompanying consolidated balance sheets of Enterprise Products Partners
L.P. and subsidiaries (the Company) as of December 31, 2005 and 2004, and the related
consolidated statements of consolidated operations and comprehensive income, consolidated cash
flows and consolidated partners equity for each of the three years in the period ended December
31, 2005. Our audits also included the financial statement schedule in Item
15. These financial statements and financial statement schedule are the responsibility of the
Companys management. Our responsibility is to express an opinion on the financial statements and
financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, such consolidated financial statements present fairly, in all material
respects, the financial position of Enterprise Products Partners L.P. and subsidiaries at December
31, 2005 and 2004, and the results of their operations and their cash flows for each of the three
years in the period ended December 31, 2005, in conformity with accounting principles generally
accepted in the United States of America. Also, in our opinion, such financial statement schedule,
when considered in relation to the basic consolidated financial statements taken as a whole,
presents fairly, in all material respects, the information set forth therein.
We have also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the effectiveness of the Companys internal control over financial
reporting as of December 31, 2005, based on the criteria established in Internal ControlIntegrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our
report dated February 27, 2006 expressed an unqualified opinion on managements assessment of the
effectiveness of the Companys internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 27, 2006
76
ENTERPRISE PRODUCTS PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2005 |
|
2004 |
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
42,098 |
|
|
$ |
24,556 |
|
Restricted cash |
|
|
14,952 |
|
|
|
26,157 |
|
Accounts and notes receivable trade, net of allowance for doubtful accounts
of $25,849 at December 31, 2005 and $24,310 at December 31, 2004 |
|
|
1,448,026 |
|
|
|
1,058,375 |
|
Accounts receivable related parties |
|
|
6,557 |
|
|
|
25,161 |
|
Inventories |
|
|
339,606 |
|
|
|
189,019 |
|
Prepaid and other current assets |
|
|
120,208 |
|
|
|
80,893 |
|
Assets held for sale |
|
|
|
|
|
|
36,562 |
|
|
|
|
Total current assets |
|
|
1,971,447 |
|
|
|
1,440,723 |
|
Property, plant and equipment, net |
|
|
8,689,024 |
|
|
|
7,831,467 |
|
Investments in and advances to unconsolidated affiliates |
|
|
471,921 |
|
|
|
519,164 |
|
Intangible assets, net of accumulated amortization of $163,121 at
December 31, 2005 and $74,183 at December 31, 2004 |
|
|
913,626 |
|
|
|
980,601 |
|
Goodwill |
|
|
494,033 |
|
|
|
459,198 |
|
Deferred tax asset |
|
|
3,606 |
|
|
|
6,467 |
|
Other assets |
|
|
47,359 |
|
|
|
77,841 |
|
|
|
|
Total assets |
|
$ |
12,591,016 |
|
|
$ |
11,315,461 |
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
|
|
|
|
|
|
|
Current maturities of debt |
|
|
|
|
|
$ |
15,000 |
|
Accounts payable trade |
|
$ |
265,699 |
|
|
|
203,142 |
|
Accounts payable related parties |
|
|
23,367 |
|
|
|
41,293 |
|
Accrued gas payables |
|
|
1,372,837 |
|
|
|
1,021,294 |
|
Accrued expenses |
|
|
30,294 |
|
|
|
130,051 |
|
Accrued interest |
|
|
71,193 |
|
|
|
70,335 |
|
Other current liabilities |
|
|
126,881 |
|
|
|
104,764 |
|
|
|
|
Total current liabilities |
|
|
1,890,271 |
|
|
|
1,585,879 |
|
Long-term debt |
|
|
4,833,781 |
|
|
|
4,266,236 |
|
Other long-term liabilities |
|
|
84,486 |
|
|
|
63,521 |
|
Minority interest |
|
|
103,169 |
|
|
|
71,040 |
|
Commitments and contingencies |
|
|
|
|
|
|
|
|
Partners equity |
|
|
|
|
|
|
|
|
Limited Partners |
|
|
|
|
|
|
|
|
Common units (389,109,564 units outstanding at December 31, 2005
and 364,297,340 units outstanding at December 31, 2004 ) |
|
|
5,542,700 |
|
|
|
5,204,940 |
|
Restricted common units (751,604 units outstanding at December 31, 2005
and 488,525 units outstanding at December 31, 2004) |
|
|
18,638 |
|
|
|
12,327 |
|
Treasury units, at cost (427,200 units outstanding at December 31, 2004) |
|
|
|
|
|
|
(8,660 |
) |
General partner |
|
|
113,496 |
|
|
|
106,475 |
|
Accumulated other comprehensive income |
|
|
19,072 |
|
|
|
24,554 |
|
Deferred compensation |
|
|
(14,597 |
) |
|
|
(10,851 |
) |
|
|
|
Total partners equity |
|
|
5,679,309 |
|
|
|
5,328,785 |
|
|
|
|
Total liabilities and partners equity |
|
$ |
12,591,016 |
|
|
$ |
11,315,461 |
|
|
|
|
See Notes to Consolidated Financial Statements
77
ENTERPRISE PRODUCTS PARTNERS L.P.
STATEMENTS OF CONSOLIDATED OPERATIONS
AND COMPREHENSIVE INCOME
(Dollars in thousands, except per unit amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For Year Ended December 31, |
|
|
2005 |
|
2004 |
|
2003 |
|
|
|
REVENUES |
|
|
|
|
|
|
|
|
|
|
|
|
Third parties |
|
$ |
11,902,187 |
|
|
$ |
7,517,052 |
|
|
$ |
4,782,187 |
|
Related parties |
|
|
354,772 |
|
|
|
804,150 |
|
|
|
564,244 |
|
|
|
|
Total |
|
|
12,256,959 |
|
|
|
8,321,202 |
|
|
|
5,346,431 |
|
|
|
|
COST AND EXPENSES |
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Third parties |
|
|
11,229,528 |
|
|
|
6,938,229 |
|
|
|
4,245,833 |
|
Related parties |
|
|
316,697 |
|
|
|
966,107 |
|
|
|
800,944 |
|
|
|
|
Total operating costs and expenses |
|
|
11,546,225 |
|
|
|
7,904,336 |
|
|
|
5,046,777 |
|
|
|
|
General and administrative costs |
|
|
|
|
|
|
|
|
|
|
|
|
Third parties |
|
|
21,312 |
|
|
|
17,352 |
|
|
|
8,874 |
|
Related parties |
|
|
40,954 |
|
|
|
29,307 |
|
|
|
28,716 |
|
|
|
|
Total general and administrative costs |
|
|
62,266 |
|
|
|
46,659 |
|
|
|
37,590 |
|
|
|
|
Total costs and expenses |
|
|
11,608,491 |
|
|
|
7,950,995 |
|
|
|
5,084,367 |
|
|
|
|
EQUITY IN INCOME (LOSS) OF UNCONSOLIDATED AFFILIATES |
|
|
14,548 |
|
|
|
52,787 |
|
|
|
(13,960 |
) |
|
|
|
OPERATING INCOME |
|
|
663,016 |
|
|
|
422,994 |
|
|
|
248,104 |
|
|
|
|
OTHER INCOME (EXPENSE) |
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
(230,549 |
) |
|
|
(155,740 |
) |
|
|
(140,806 |
) |
Dividend income from unconsolidated affiliates |
|
|
|
|
|
|
|
|
|
|
5,595 |
|
Other, net |
|
|
5,371 |
|
|
|
2,115 |
|
|
|
805 |
|
|
|
|
Other expense |
|
|
(225,178 |
) |
|
|
(153,625 |
) |
|
|
(134,406 |
) |
|
|
|
INCOME BEFORE PROVISION FOR INCOME TAXES, MINORITY
INTEREST AND CHANGES IN ACCOUNTING PRINCIPLES |
|
|
437,838 |
|
|
|
269,369 |
|
|
|
113,698 |
|
Provision for income taxes |
|
|
(8,362 |
) |
|
|
(3,761 |
) |
|
|
(5,293 |
) |
|
|
|
INCOME BEFORE MINORITY INTEREST AND
CHANGES IN ACCOUNTING PRINCIPLES |
|
|
429,476 |
|
|
|
265,608 |
|
|
|
108,405 |
|
Minority interest |
|
|
(5,760 |
) |
|
|
(8,128 |
) |
|
|
(3,859 |
) |
|
|
|
INCOME BEFORE CHANGES IN ACCOUNTING PRINCIPLES |
|
|
423,716 |
|
|
|
257,480 |
|
|
|
104,546 |
|
Cumulative effect of changes in accounting principles (see Note 8) |
|
|
(4,208 |
) |
|
|
10,781 |
|
|
|
|
|
|
|
|
NET INCOME |
|
$ |
419,508 |
|
|
$ |
268,261 |
|
|
$ |
104,546 |
|
Cash flow financing hedges |
|
|
|
|
|
|
19,405 |
|
|
|
5,354 |
|
Amortization of cash flow financing hedges |
|
|
(4,048 |
) |
|
|
(1,275 |
) |
|
|
3,196 |
|
Change in fair value of commodity hedges |
|
|
(1,434 |
) |
|
|
1,434 |
|
|
|
|
|
|
|
|
COMPREHENSIVE INCOME |
|
$ |
414,026 |
|
|
$ |
287,825 |
|
|
$ |
113,096 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ALLOCATION OF NET INCOME TO: (see Note 16) |
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income |
|
$ |
348,512 |
|
|
$ |
231,153 |
|
|
$ |
83,817 |
|
|
|
|
General partner interest in net income |
|
$ |
70,996 |
|
|
$ |
37,108 |
|
|
$ |
20,729 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNING PER UNIT: (see Note 20) |
|
|
|
|
|
|
|
|
|
|
|
|
Basic income per unit before changes in accounting principles |
|
$ |
0.92 |
|
|
$ |
0.83 |
|
|
$ |
0.42 |
|
|
|
|
Basic income per unit |
|
$ |
0.91 |
|
|
$ |
0.87 |
|
|
$ |
0.42 |
|
|
|
|
Diluted income per unit before changes in accounting principles |
|
$ |
0.92 |
|
|
$ |
0.83 |
|
|
$ |
0.41 |
|
|
|
|
Diluted income per unit |
|
$ |
0.91 |
|
|
$ |
0.87 |
|
|
$ |
0.41 |
|
|
|
|
See Notes to Consolidated Financial Statements
78
ENTERPRISE PRODUCTS PARTNERS L.P.
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For Year Ended December 31, |
|
|
2005 |
|
2004 |
|
2003 |
|
|
|
OPERATING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
419,508 |
|
|
$ |
268,261 |
|
|
$ |
104,546 |
|
Adjustments to reconcile net income to cash flows provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization in operating costs and expenses |
|
|
413,441 |
|
|
|
193,734 |
|
|
|
115,642 |
|
Depreciation and amortization in general and administrative costs |
|
|
7,184 |
|
|
|
1,650 |
|
|
|
159 |
|
Amortization in interest expense |
|
|
152 |
|
|
|
3,503 |
|
|
|
12,634 |
|
Equity in (income) loss of unconsolidated affiliates |
|
|
(14,548 |
) |
|
|
(52,787 |
) |
|
|
13,960 |
|
Distributions received from unconsolidated affiliates |
|
|
56,058 |
|
|
|
68,027 |
|
|
|
31,882 |
|
Provision for impairment of long-lived asset |
|
|
|
|
|
|
4,114 |
|
|
|
1,200 |
|
Cumulative effect of changes in accounting principles |
|
|
4,208 |
|
|
|
(10,781 |
) |
|
|
|
|
Operating lease expense paid by EPCO, Inc. |
|
|
2,112 |
|
|
|
7,705 |
|
|
|
9,010 |
|
Other expenses paid by EPCO, Inc. |
|
|
|
|
|
|
|
|
|
|
436 |
|
Minority interest |
|
|
5,760 |
|
|
|
8,128 |
|
|
|
3,859 |
|
Gain on sale of assets |
|
|
(4,488 |
) |
|
|
(15,901 |
) |
|
|
(16 |
) |
Deferred income tax expense |
|
|
8,594 |
|
|
|
9,608 |
|
|
|
10,534 |
|
Changes in fair market value of financial instruments |
|
|
122 |
|
|
|
5 |
|
|
|
(29 |
) |
Net effect of changes in operating accounts (see Note 23) |
|
|
(266,395 |
) |
|
|
(93,725 |
) |
|
|
120,888 |
|
|
|
|
Net cash provided from operating activities |
|
|
631,708 |
|
|
|
391,541 |
|
|
|
424,705 |
|
|
|
|
INVESTING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(864,453 |
) |
|
|
(155,793 |
) |
|
|
(146,790 |
) |
Contributions in aid of construction costs |
|
|
47,004 |
|
|
|
8,865 |
|
|
|
877 |
|
Proceeds from sale of assets |
|
|
44,746 |
|
|
|
6,882 |
|
|
|
212 |
|
Decrease (increase) in restricted cash |
|
|
11,204 |
|
|
|
(12,305 |
) |
|
|
(5,100 |
) |
Cash used for business combinations and asset purchases (see Note 12) |
|
|
(326,602 |
) |
|
|
(724,661 |
) |
|
|
(37,348 |
) |
Acquisition of intangible asset |
|
|
(1,750 |
) |
|
|
|
|
|
|
(2,000 |
) |
Investments in unconsolidated affiliates |
|
|
(87,342 |
) |
|
|
(57,948 |
) |
|
|
(463,876 |
) |
Advances to unconsolidated affiliates |
|
|
(702 |
) |
|
|
(6,464 |
) |
|
|
(8,051 |
) |
Return of investment from unconsolidated affiliate |
|
|
47,500 |
|
|
|
|
|
|
|
|
|
|
|
|
Cash used in investing activities |
|
|
(1,130,395 |
) |
|
|
(941,424 |
) |
|
|
(662,076 |
) |
|
|
|
FINANCING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings under debt agreements |
|
|
4,192,345 |
|
|
|
5,934,505 |
|
|
|
1,926,210 |
|
Repayments of debt |
|
|
(3,630,611 |
) |
|
|
(5,808,877 |
) |
|
|
(2,033,000 |
) |
Debt issuance costs |
|
|
(9,297 |
) |
|
|
(19,911 |
) |
|
|
(8,833 |
) |
Distributions paid to partners |
|
|
(716,699 |
) |
|
|
(438,765 |
) |
|
|
(309,918 |
) |
Distributions paid to minority interests |
|
|
(5,724 |
) |
|
|
(6,440 |
) |
|
|
(8,113 |
) |
Contributions from minority interests |
|
|
39,110 |
|
|
|
9,585 |
|
|
|
5,949 |
|
Contributions from general partner related to issuance of restricted units |
|
|
177 |
|
|
|
|
|
|
|
|
|
Net proceeds from issuance of common units |
|
|
646,928 |
|
|
|
846,077 |
|
|
|
573,684 |
|
Net proceeds from issuance of Class B special units |
|
|
|
|
|
|
|
|
|
|
102,041 |
|
Treasury units reissued |
|
|
|
|
|
|
8,394 |
|
|
|
646 |
|
Settlement of cash flow financing hedges |
|
|
|
|
|
|
19,405 |
|
|
|
5,354 |
|
|
|
|
Cash provided by financing activities |
|
|
516,229 |
|
|
|
543,973 |
|
|
|
254,020 |
|
|
|
|
NET CHANGE IN CASH AND CASH EQUIVALENTS |
|
|
17,542 |
|
|
|
(5,910 |
) |
|
|
16,649 |
|
CASH AND CASH EQUIVALENTS, JANUARY 1 |
|
|
24,556 |
|
|
|
30,466 |
|
|
|
13,817 |
|
|
|
|
CASH AND CASH EQUIVALENTS, DECEMBER 31 |
|
$ |
42,098 |
|
|
$ |
24,556 |
|
|
$ |
30,466 |
|
|
|
|
See Notes to Consolidated Financial Statements
79
ENTERPRISE PRODUCTS PARTNERS L.P.
STATEMENTS OF CONSOLIDATED PARTNERS EQUITY
(See Note 15 for Unit History and Detail of Changes in Limited Partners Equity)
(Dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
Limited |
|
General |
|
Treasury |
|
Deferred |
|
Comprehensive |
|
|
|
|
Partners |
|
Partner |
|
units |
|
Compensation |
|
Income |
|
Total |
|
|
|
Balance, December 31, 2002 |
|
$ |
1,210,049 |
|
|
$ |
12,223 |
|
|
$ |
(17,808 |
) |
|
|
|
|
|
$ |
(3,560 |
) |
|
$ |
1,200,904 |
|
Net income |
|
|
83,817 |
|
|
|
20,729 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
104,546 |
|
Operating leases paid by EPCO, Inc. |
|
|
8,913 |
|
|
|
97 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,010 |
|
Other expenses paid by EPCO, Inc. |
|
|
433 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
436 |
|
Cash distributions to partners |
|
|
(284,593 |
) |
|
|
(22,574 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(307,167 |
) |
Unit option reimbursements to EPCO, Inc. |
|
|
(2,721 |
) |
|
|
(30 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,751 |
) |
Net proceeds from sales of common units |
|
|
567,945 |
|
|
|
5,739 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
573,684 |
|
Proceeds from issuance of Class B special units |
|
|
100,000 |
|
|
|
2,041 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
102,041 |
|
Restructuring of Enterprise Products GP
ownership in our Operating Partnership |
|
|
(73 |
) |
|
|
16,127 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,054 |
|
Treasury unit transactions: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- Reissued to satisfy unit options |
|
|
6 |
|
|
|
|
|
|
|
640 |
|
|
|
|
|
|
|
|
|
|
|
646 |
|
- Retired |
|
|
(643 |
) |
|
|
(6 |
) |
|
|
649 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury lock financial instruments recorded as
cash flow hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- Reclassification of change in fair value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,560 |
|
|
|
3,560 |
|
- Cash gains on settlement |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,354 |
|
|
|
5,354 |
|
- Amortization of gain as component of interest
expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(364 |
) |
|
|
(364 |
) |
|
|
|
Balance, December 31, 2003 |
|
|
1,683,133 |
|
|
|
34,349 |
|
|
|
(16,519 |
) |
|
|
|
|
|
|
4,990 |
|
|
|
1,705,953 |
|
Net income |
|
|
231,153 |
|
|
|
37,108 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
268,261 |
|
Operating leases paid by EPCO, Inc. |
|
|
7,551 |
|
|
|
154 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,705 |
|
Cash distributions to partners |
|
|
(394,434 |
) |
|
|
(40,440 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(434,874 |
) |
Unit option reimbursements to EPCO, Inc. |
|
|
(3,813 |
) |
|
|
(78 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,891 |
) |
Net proceeds from sales of common units |
|
|
789,758 |
|
|
|
16,117 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
805,875 |
|
Proceeds from conversion of Series F2
convertible units to common units |
|
|
38,800 |
|
|
|
792 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
39,592 |
|
Proceeds from exercise of unit options |
|
|
398 |
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
406 |
|
Value of equity interests granted
to complete GulfTerra Merger |
|
|
2,854,275 |
|
|
|
58,252 |
|
|
|
|
|
|
$ |
(1,755 |
) |
|
|
|
|
|
|
2,910,772 |
|
Other issuance of restricted units |
|
|
9,922 |
|
|
|
202 |
|
|
|
|
|
|
|
(9,922 |
) |
|
|
|
|
|
|
202 |
|
Amortization of deferred compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
826 |
|
|
|
|
|
|
|
826 |
|
Treasury units issued to satisfy unit options |
|
|
524 |
|
|
|
11 |
|
|
|
7,859 |
|
|
|
|
|
|
|
|
|
|
|
8,394 |
|
Change in fair value of commodity hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,434 |
|
|
|
1,434 |
|
Interest rate hedging financial instruments recorded
as cash flow hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- Cash gains on settlement |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,405 |
|
|
|
19,405 |
|
- Amortization of gain as component of interest
expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,275 |
) |
|
|
(1,275 |
) |
|
|
|
Balance, December 31, 2004 |
|
|
5,217,267 |
|
|
|
106,475 |
|
|
|
(8,660 |
) |
|
|
(10,851 |
) |
|
|
24,554 |
|
|
|
5,328,785 |
|
Net income |
|
|
348,512 |
|
|
|
70,996 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
419,508 |
|
Operating leases paid by EPCO, Inc. |
|
|
2,070 |
|
|
|
42 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,112 |
|
Cash distributions to partners |
|
|
(630,560 |
) |
|
|
(76,752 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(707,312 |
) |
Unit option reimbursements to EPCO, Inc. |
|
|
(9,199 |
) |
|
|
(188 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9,387 |
) |
Net proceeds from sales of common units |
|
|
612,616 |
|
|
|
12,502 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
625,118 |
|
Proceeds from exercise of unit options |
|
|
21,374 |
|
|
|
436 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21,810 |
|
Issuance of restricted units |
|
|
9,478 |
|
|
|
177 |
|
|
|
|
|
|
|
(9,480 |
) |
|
|
|
|
|
|
175 |
|
Forfeiture of restricted units |
|
|
(2,663 |
) |
|
|
(38 |
) |
|
|
|
|
|
|
2,361 |
|
|
|
|
|
|
|
(340 |
) |
Amortization of Employee Partnership awards |
|
|
1,358 |
|
|
|
28 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,386 |
|
Amortization of deferred compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,373 |
|
|
|
|
|
|
|
3,373 |
|
Cancellation of treasury units |
|
|
(8,915 |
) |
|
|
(182 |
) |
|
|
8,660 |
|
|
|
|
|
|
|
|
|
|
|
(437 |
) |
Change in fair value of commodity hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,434 |
) |
|
|
(1,434 |
) |
Interest rate hedging financial instruments recorded
as cash flow hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- Amortization of gain as component of interest
expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,048 |
) |
|
|
(4,048 |
) |
|
|
|
Balance, December 31, 2005 |
|
$ |
5,561,338 |
|
|
$ |
113,496 |
|
|
$ |
|
|
|
$ |
(14,597 |
) |
|
$ |
19,072 |
|
|
$ |
5,679,309 |
|
|
|
|
See Notes to Consolidated Financial Statements
80
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Partnership Organization
Enterprise Products Partners L.P. 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 EPD.
Unless the context requires otherwise, references to we, us, our, or Enterprise Products
Partners are intended to mean the consolidated business and operations of Enterprise Products
Partners L.P. and its subsidiaries.
We were formed in April 1998 to own and operate certain natural gas liquids (NGLs) related
businesses of EPCO, Inc. ( EPCO). We conduct substantially all of our business through our
wholly owned subsidiary, Enterprise Products Operating L.P. (our Operating Partnership). We are
owned 98% by our limited partners and 2% by Enterprise Products GP, LLC (our general partner,
referred to as Enterprise Products GP). Enterprise Products GP is owned 100% by Enterprise GP
Holdings L.P. (Enterprise GP Holdings), a publicly traded affiliate, the common units of which
are listed on the NYSE under the ticker symbol EPE. The general partner of Enterprise GP
Holdings is EPE Holdings, LLC (EPE Holdings), a wholly owned subsidiary of EPCO. We, Enterprise
Products GP, Enterprise GP Holdings and EPE Holdings are affiliates and under common control of Dan
L. Duncan, the Chairman and controlling shareholder of EPCO.
In September 2004, we completed the GulfTerra Merger transactions, whereby, among other
transactions, GulfTerra Energy Partners L.P. (GulfTerra) merged with one of our wholly owned
subsidiaries. As a result of the GulfTerra Merger, GulfTerra and its subsidiaries and GulfTerras
general partner (GulfTerra GP) became our wholly owned subsidiaries. The GulfTerra Merger
greatly expanded our asset base to include numerous natural gas and crude oil pipelines, offshore
platforms and other midstream energy assets. Additionally, the GulfTerra Merger included the
purchase of various midstream assets from El Paso Corporation
(El Paso) that are located in
South Texas (the STMA acquisition).
2. Summary of Significant Accounting Policies
Allowance for Doubtful Accounts
Our allowance for doubtful accounts amount is generally determined based on specific
identification and estimates of future uncollectible accounts. Our procedure for recording an
allowance for doubtful accounts is based on (i) our historical experience, (ii) the financial
stability of our customers and (iii) the levels of credit granted to customers. In addition, we
may also increase the allowance account in response to the specific identification of customers
involved in bankruptcy proceedings and those experiencing other financial difficulties. We
routinely review our estimates in this area to ascertain that we have recorded sufficient reserves
to cover potential losses. Our allowance for doubtful accounts was $25.8 million and $24.3 million
at December 31, 2005 and 2004, respectively.
Cash and Cash Equivalents
Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments
with original maturities of less than three months from the date of purchase. Our Statements of
Consolidated Cash Flows are prepared using the indirect method.
Consolidation Policy
Our consolidated financial statements include our accounts and those of our majority-owned
subsidiaries in which we have a controlling interest, after the elimination of all material
intercompany accounts and transactions. We consolidate majority-owned subsidiaries in which we
possess a controlling financial interest through a direct or indirect ownership of a majority
voting interest in the subsidiary.
81
Investments in which we own 3% to 50% and exercise significant influence over operating and
financial policies are accounted for using the equity method. If the investee is organized as a
limited liability company and maintains separate ownership accounts for its members, we account for
our investment using the equity method if our ownership interest is between 3% and 50%. For all
other types of investees, we apply the equity method of accounting if our ownership interest is
between 20% and 50%. Our proportionate share of profits and losses from transactions with equity
method unconsolidated affiliates are eliminated in consolidation to the extent such amounts are
material and remain on our or our equity method investees balance sheet in inventory or similar
accounts.
If our ownership interest in an investee does not provide us with either control or
significant influence over the investee, we account for the investment using the cost method.
Contingencies
Certain conditions may exist as of the date our financial statements are issued, which may
result in a loss to Enterprise Products Partners but which will only be resolved when one or more
future events occur or fail to occur. Our management and its legal counsel assess such contingent
liabilities, and such assessment inherently involves an exercise in judgment. In assessing loss
contingencies related to legal proceedings that are pending against us or unasserted claims that
may result in proceedings, our legal counsel evaluates the perceived merits of any legal
proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or
expected to be sought therein.
If the assessment of a contingency indicates that it is probable that a material loss has been
incurred and the amount of liability can be estimated, then the estimated liability would be
accrued in our financial statements. If the assessment indicates that a potentially material loss
contingency is not probable but is reasonably possible, or is probable but cannot be estimated,
then the nature of the contingent liability, together with an estimate of the range of possible
loss if determinable and material, is disclosed.
Loss contingencies considered remote are generally not disclosed unless they involve
guarantees, in which case the guarantees would be disclosed.
Deferred Revenues
We recognize revenues when earned. Amounts billed in advance of the period in which the
service is rendered or product delivered are recorded as deferred revenue. Please see Note 4 for
additional discussion of revenues.
Dollar Amounts
Except per unit amounts, or as noted within the context of each footnote disclosure, the
dollar amounts presented in the tabular data within these footnote disclosures are stated in
thousands of dollars.
Earnings Per Unit
Earnings per unit is based on the amount of income allocated to limited partners and the
weighted-average number of units outstanding during the period. See Note 20 for our computation of
earnings per unit for 2005, 2004 and 2003.
Environmental Costs
Environmental costs for remediation are accrued based on estimates of known remediation
requirements. Such accruals are based on managements estimate of the ultimate cost to remediate
the site. Ongoing environmental compliance costs are charged to expense as incurred. Expenditures
to mitigate or prevent future environmental contamination are capitalized.
82
Environmental costs and related accruals were not significant prior to the GulfTerra Merger.
As a result of the merger, we assumed an environmental liability estimated at $21 million for
remediation costs associated with mercury gas meters. This estimate is included in other long-term
liabilities on our Consolidated Balance Sheets at December 31, 2005 and 2004.
Costs of environmental compliance and monitoring aggregated $3.3 million, $1.9 million and
$1.6 million during 2005, 2004 and 2003, respectively.
Equity Awards
Beginning January 1, 2006, we will account for our equity awards using the provisions of
Statement of Financial Standards (SFAS) 123(R),Share-Based Payment. Historically, our equity
awards were accounted for using the intrinsic value method described in Accounting Principles Board
Opinion (APB) 25, Accounting for Stock Issued to Employees. SFAS 123(R) requires us to
recognize compensation expense related to our equity awards based on the fair value of the award at
the grant date. The fair value of an equity award will be determined using option pricing models
(Black-Scholes or Binomial models). Under SFAS 123(R), the fair value of an award will be
amortized to earnings on a straight-line basis over the requisite service or vesting period.
Previously recognized deferred compensation related to nonvested units will be reversed on January
1, 2006. See Note 5 for additional information regarding our equity awards.
Unit options. Under APB 25, we did not recognize any compensation expense related to
unit options when the exercise price was equal to or greater than the market price of the
underlying equity on the date of grant. Based on information currently available, we estimate that
our compensation expense related to unit options will be $0.6 million in 2006 using the provisions
of SFAS 123(R).
Profits Interests. In connection with the initial public offering of Enterprise GP
Holdings in August 2005, EPE Unit L.P. (the Employee Partnership) was formed to allow certain
employees of EPCO to increase their ownership in Enterprise GP Holdings and to serve as an
incentive arrangement for such employees through a profits interest in the Employee Partnership.
During 2005, the value of the profits interests was accounted for similar to a stock appreciation
right. Based on information currently available, we estimate that our share of compensation
expense related to the profits interests will be $2.2 million in 2006 using the provisions of SFAS
123(R). Using a Black-Scholes model, EPCO estimated the grant date fair value of the Class B
partnership interests to be $12.5 million. For additional information regarding the Employee
Partnership, see Relationship with EPCO and affiliates under Note 18.
Nonvested Units. We issued nonvested (or restricted) units to key employees of EPCO
during 2005 and 2004. In general, our nonvested common units are classified as either time-vested
or performance-based. Historically, unearned compensation, representing the fair market value of
such nonvested units at the date of issuance, was charged to earnings as compensation expense on a
straight-line basis over the vesting period. Prior to 2006, we recognized forfeitures of nonvested
units as they occurred. As a result of SFAS 123(R), we will estimate such forfeitures at grant
date. Based on information currently available, we estimate that our compensation expense related
to nonvested units will be $4.2 million in 2006 using the provisions of SFAS 123(R).
Pro forma disclosures under SFAS 123. In accordance with SFAS 148, Accounting for
Stock-Based Compensation Transition and Disclosure, we disclose the pro forma effect on our
earnings as if the fair value method of SFAS 123, Accounting for Stock-Based Compensation had
been used instead of the intrinsic-value method of APB 25 to account for our equity awards. The
effects of applying SFAS 123 in the following pro forma disclosure may not be indicative of future
amounts as additional awards in future years are anticipated. No pro forma adjustment is required
for our nonvested units since compensation expense was recognized in 2005 and 2004 based on
estimated fair values of the awards.
The fair value of each unit option is estimated on the date of grant using the Black-Scholes
option pricing model and various assumptions. For those unit options granted during 2005, we used
the
83
following assumptions: (i) expected life of options of seven years; (ii) risk-free interest
rate of 4.2%, (iii) expected dividend yield on our units of 9.2% and (iv) expected unit price
volatility of 20%.
The fair value of the Class B partnership equity awards was also estimated on the date of
grant using the Black-Scholes option pricing model and various assumptions. We used the following
assumptions to estimate the fair value of these equity awards: (i) expected life of award of five
years; (ii) risk-free interest rate of 4.1%; (iii) expected dividend yield on units of Enterprise
GP Holdings of 3% and (iv) expected Enterprise GP Holdings unit price volatility of 30%.
The following table shows the pro forma effects for the periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For Year Ended December 31, |
|
|
2005 |
|
2004 |
|
2003 |
|
|
|
Reported net income |
|
$ |
419,508 |
|
|
$ |
268,261 |
|
|
$ |
104,546 |
|
Additional unit option-based compensation
expense estimated using fair value-based method |
|
|
(708 |
) |
|
|
(932 |
) |
|
|
(1,107 |
) |
Reduction in compensation expense related to
Employee Partnership equity awards |
|
|
1,271 |
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma net income |
|
$ |
420,071 |
|
|
$ |
267,329 |
|
|
$ |
103,439 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per unit: |
|
|
|
|
|
|
|
|
|
|
|
|
As reported |
|
$ |
0.91 |
|
|
$ |
0.87 |
|
|
$ |
0.42 |
|
|
|
|
Pro forma |
|
$ |
0.91 |
|
|
$ |
0.87 |
|
|
$ |
0.41 |
|
|
|
|
Diluted earnings per unit: |
|
|
|
|
|
|
|
|
|
|
|
|
As reported |
|
$ |
0.91 |
|
|
$ |
0.87 |
|
|
$ |
0.41 |
|
|
|
|
Pro forma |
|
$ |
0.91 |
|
|
$ |
0.87 |
|
|
$ |
0.40 |
|
|
|
|
Estimates
Preparing Enterprise Products Partners financial statements in conformity with accounting
principles generally accepted in the United States of America (GAAP) requires management to make
estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and the reported amounts
of revenues and expenses during the reporting period. Our actual results could differ from these
estimates.
Exchange Contracts
Exchanges are contractual agreements for the movements of NGL and petrochemical products
between parties to satisfy timing and logistical needs of the parties. Net exchange volumes
borrowed from us under such agreements are valued and included in accounts receivable, and net
exchange volumes loaned to us under such agreements are valued and accrued as a liability in
accrued gas payables.
Receivables and payables arising from exchange transactions are satisfied with products rather
than cash. When monetary consideration is required for product differentials and service costs
such items are recognized on a net basis.
Exit and Disposal Costs
Exit
and disposal costs are charges associated with an exit activity not associated with
business combination or with a disposal activity covered by SFAS 144, Accounting for the
Impairment or Disposal of Long-Lived Assets. Examples of these costs include (i) termination
benefits provided to current employees that are involuntarily terminated under the terms of a
benefit arrangement that, in substance, is not an ongoing benefit arrangement or an individual
deferred compensation contract, (ii) costs to terminate a contract that is not a capital lease,
and (iii) costs to consolidate facilities or relocate employees. In accordance with SFAS 146,
Accounting for Costs Associated with Exit and Disposal Activities, we recognize such costs when
they are incurred rather than at the date of our commitment to an exit or disposal plan.
84
Financial Instruments
We use financial instruments such as swaps, forward and other contracts to manage price risks
associated with inventories, firm commitments, interest rates and certain anticipated transactions.
We recognize our transactions on the balance sheet as assets and liabilities based on the
instruments fair value. Fair value is generally defined as the amount at which the financial
instrument could be exchanged in a current transaction between willing parties, not in a forced or
liquidation sale. Changes in fair value of financial instrument contracts are recognized currently
in earnings unless specific hedge accounting criteria are met. If the financial instrument meets
the criteria of a fair value hedge, gains and losses from the instrument will be recorded on the
income statement to offset corresponding losses and gains of the hedged item. If the financial
instrument meets the criteria of a cash flow hedge, gains and losses from the instrument are
recorded in other comprehensive income. Gains and losses on cash flow hedges are reclassified from
other comprehensive income to earnings when the forecasted transaction occurs or, as appropriate,
over the economic life of the underlying asset. A contract designated as a hedge of an anticipated
transaction that is no longer likely to occur is immediately recognized in earnings.
To qualify as a hedge, the item to be hedged must expose us to commodity or interest rate risk
and the hedging instrument must reduce the exposure and meet the hedging requirements of SFAS 133,
Accounting for Derivative Instruments and Hedging Activities (as amended and interpreted). We
formally designate the financial instrument as a hedge and document and assess the effectiveness of
the hedge at inception and on a quarterly basis. Any ineffectiveness is immediately recognized in
earnings. See Note 7 for a further discussion of our financial instruments.
Impairment Testing for Goodwill
Our goodwill amounts are assessed for recoverability (i) on an annual basis during the second
quarter of each year or (ii) on an interim basis when impairment indicators are present. If such
indicators are present (e.g., loss of a significant customer, economic obsolescence of plant
assets, etc.), the fair value of the reporting unit to which the goodwill is assigned will be
calculated and compared to its book value.
If the fair value of the reporting unit exceeds its book value, the goodwill amount is not
considered to be impaired and no impairment charge is required. If the fair value of the reporting
unit is less than its book value, a charge to earnings is recorded to adjust the carrying value of
the goodwill to its implied fair value. We have not recognized any impairment losses related to
our goodwill for any of the periods presented. See Note 13 for a further discussion of our
goodwill.
Impairment Testing for Long-Lived Assets
Long-lived assets (including intangible assets with finite useful lives and property, plant
and equipment) are reviewed for impairment whenever events or changes in circumstances indicate
that the carrying amount of such assets may not be recoverable.
Long-lived assets with carrying values that are not expected to be recovered through future
cash flows are written-down to their estimated fair values in accordance with SFAS 144. The
carrying value of a long-lived asset is deemed not recoverable if it exceeds the sum of
undiscounted cash flows expected to result from the use and eventual disposition of the asset. If
the carrying value exceeds the sum of the undiscounted cash flows, a non-cash asset impairment
charge is recognized equal to the excess of the assets carrying value over its fair value. Fair value
is defined as the amount at which an asset or liability could be bought or settled in an
arms-length transaction. We measure fair value using market prices or, in the absence of such
data, appropriate valuation techniques.
We recognized non-cash asset impairment charges of $4.1 million and $1.2 million in 2004 and
2003, respectively, which are reflected as components of operating costs and expenses. No asset
impairment charges were recorded in 2005.
85
Impairment Testing for Unconsolidated Affiliates
We evaluate equity method investments (which include excess cost amounts attributable to
tangible or intangible assets) for impairment whenever events or changes in circumstances indicate
that there is a loss in value of the investment which is an other than temporary decline. Examples
of such events or changes in circumstances include continuing operating losses of the investee or
long-term negative changes in the investees industry. In the event that we determine that the
loss in value of an investment is other than a temporary decline, we would record a charge to
earnings to adjust the carrying value to fair value.
We had no such impairment charges during 2005 or 2004; however, a former unconsolidated
affiliate recorded a $67.5 million asset impairment charge during 2003. Our share of this charge
was $22.5 million, which was recorded as a reduction in equity earnings from this investee during
2003. See Note 11 for additional information regarding this non-cash charge.
Income taxes
Our limited partnership structure is not subject to federal income taxes. As a result, our
earnings or losses for federal income tax purposes are included in the tax returns of our
individual partners. We are organized as a pass-through entity for federal income tax purposes.
As a result, our partners are individually responsible for the federal income tax on their
allocable share of our taxable income. The aggregate difference in the basis of our net assets for
financial and tax reporting purposes cannot be readily determined as we do not have access to
information about each unitholders tax attributes in us.
Provision for income taxes is primarily applicable to certain federal and state tax
obligations related to our Seminole Pipeline and Dixie Pipeline. Deferred income tax assets and
liabilities are recognized for temporary differences between the assets and liabilities for
financial reporting and tax purposes. See Note 19 for additional information regarding our
provision of income taxes.
Inventories
Our inventories primarily consist of NGL, petrochemical and natural gas volumes and are valued
at the lower of average cost or market. We capitalize as a cost of inventory shipping and handling
charges directly related to volumes we (i) purchase from third parties or (ii) take title to in
connection with processing or other agreements. As these volumes are sold and delivered out of
inventory, the average cost of these products (which includes freight-in charges which have been
capitalized) are charged to operating costs and expenses. Shipping and handling fees associated
with products we sell and deliver to customers are charged to operating costs and expenses as
incurred. See Note 9 for a further discussion of our inventories.
Costs and expenses, as shown on our Statements of Consolidated Operations and Comprehensive
Income, include cost of sales related to inventories. Our consolidated cost of sales amounts were
$10.3 billion, $7.2 billion and $4.5 billion during 2005, 2004 and 2003, respectively.
Minority Interest
Minority interest represents third-party ownership interests in the net assets of our
subsidiaries that are joint ventures. For financial reporting purposes, the assets and liabilities
of our majority owned subsidiaries are consolidated with those of our own, with any third party
investors interest in our consolidated balance amounts shown as minority interest. Minority
interest expense reflects the allocation of joint venture earnings to third party investors.
Distributions to and contributions from minority interests represent cash payments and cash
contributions, respectively, from such third-party investors.
At December 31, 2005, our joint venture subsidiaries were Seminole Pipeline Company
(Seminole), Tri-States Pipeline LLC (Tri-States), Independence Hub, LLC (Independence Hub),
Dixie Pipeline Company (Dixie) and Belle Rose NGL Pipeline LLC (Belle Rose). At December 31,
86
2004, our joint venture subsidiaries included those listed for 2005 and Mapletree, LLC and
E-Oaktree, LLC. We purchased the remaining 2% membership interests in Mapletree, LLC and
E-Oaktree, LLC in June 2005 for $25 million. This acquisition increased our indirect ownership
interests in the Mid-America Pipeline System to 100% and the Seminole Pipeline to 90%.
Natural Gas Imbalances
Natural gas imbalances result when a customer injects more or less gas into a pipeline than
they withdraw. In general, we value our imbalance receivables and payables using a twelve-month
moving average of natural gas prices. We believe this valuation method is appropriate given that
actual settlement dates may vary by customer. Changes in natural gas prices may impact our
estimates. Prior to the GulfTerra Merger, natural gas imbalances were not significant.
At December 31, 2005 and 2004, our imbalance receivables were $89.4 million and $56.7 million,
respectively, and are reflected as a component of Accounts receivable trade on our Consolidated
Balance Sheets. At December 31, 2005 and 2004, our imbalance payables were $80.5 million and $59
million, respectively, and are reflected as a component of Accrued gas payables on our
Consolidated Balance Sheets.
Property, Plant and Equipment
Property, plant and equipment is recorded at cost. Expenditures for major additions and
improvements are capitalized and minor replacements, maintenance, and repairs are charged to
expense as incurred. When property and equipment are retired or otherwise disposed of, the cost
and accumulated depreciation are removed from the accounts and any resulting gain or loss is
included in the results of operations from the respective period. Depreciation is recorded over
the estimated useful lives of the related assets primarily using the straight-line method for
financial statement purposes. We use other depreciation methods (generally accelerated) for tax
purposes where appropriate. See Note 10 for additional information regarding our property, plant
and equipment.
Certain of our plant operations entail periodic planned outages for major maintenance
activities. These planned shutdowns typically result in significant expenditures, which are
principally comprised of amounts paid to third parties for materials, contract services and related
items. We use the expense-as-incurred method for our planned major maintenance activities.
Asset retirement obligations (AROs) are legal obligations associated with the retirement of
tangible long-lived assets that result from its acquisition, construction, development and/or
normal operation. We record a liability for AROs when incurred and capitalize an increase in the
carrying value of the related long-lived asset. Over time, the liability is accreted to its
present value each period, and the capitalized cost is depreciated over its useful life. We will
either settle our ARO obligations at the recorded amount or incur a gain or loss upon settlement.
Reclassifications
Certain reclassifications have been made to the financial statements of prior years to conform
to the current year presentation. These reclassifications had no effect on reported results of
operations or financial position for 2004 and 2003.
In 2005, we reclassified changes in restricted cash balances (as shown on our Statements of
Cash Flows) from operating activities to investing activities in response to best accounting
practices. In order to conform the Statements of Cash Flows for 2004 and 2003 to the current
period presentation, we reclassified the $12.3 million and $5.1 million increases in restricted
cash balances during 2004 and 2003, respectively, from operating activities to investing
activities.
87
Restricted Cash
Restricted cash represents amounts held by a brokerage firm in connection with (i) our
commodity financial instruments portfolio and (ii) physical natural gas purchases made on the NYMEX
exchange.
Revenue Recognition
See Note 4 for information regarding our revenue recognition policies.
Start-Up and Organization Costs
Start-up costs and organization costs are expensed as incurred. Start-up costs are defined as
one-time activities related to opening a new facility, introducing a new product or service,
conducting activities in a new territory, pursuing a new class of customer, initiating a new
process in an existing facility, or some new operation. Routine ongoing efforts to improve
existing facilities, products or services are not start-up costs. Organization costs include legal
fees, promotional costs and similar charges incurred in connection with the formation of a
business.
3. Recent Accounting Developments
The following information summarizes recently issued accounting guidance that will (or may)
affect our financial statements in the future:
|
§ |
|
SFAS 123(R), Share-Based Payment, eliminates the ability to account for share-based
compensation transactions using APB 25 and generally requires instead that such
transactions be accounted for using a fair value method. Historically, we have accounted
for our share-based transactions using APB 25. We adopted SFAS 123(R) on January 1, 2006,
which resulted in our recording a cumulative effect of a change in accounting principle of
$0.3 million. During 2006, we expect to record compensation expense of $7 million
associated with the fair value method of accounting for unit options, profits interests
and nonvested (or restricted) units using SFAS 123(R) based on awards outstanding at
January 1, 2006. |
|
|
§ |
|
SFAS 154, Accounting Changes and Error Corrections, provides guidance on the
accounting for and reporting of accounting changes and error corrections. We adopted SFAS
154 on January 1, 2006. |
|
|
§ |
|
Emerging Issues Task Force (EITF) 04-13, Accounting for Purchases and Sale of
Inventory With the Same Counterparty, requires that two or more inventory transactions
with the same counterparty should be viewed as a single nonmonetary transaction, if the
transactions were entered into in contemplation of one another. Exchanges of inventory
between entities in the same line of business should be accounted for at fair value or
recorded at carrying amounts, depending on the classification of such inventory. We are
still evaluating this recent guidance, which is effective April 1, 2006 for our
partnership, but we do not believe that our revenues or costs and expenses will be
materially affected. |
88
4. Revenue Recognition
We recognize revenue using the following criteria: (i) persuasive evidence of an exchange
arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the buyers
price is fixed or determinable and (iv) collectibility is reasonably assured. We generally do not
take title to products gathered, transported or processed unless noted below. The following
information summarizes our revenue recognition policies by business segment:
NGL Pipelines & Services
In our natural gas processing activities, we enter into margin-band contracts,
percent-of-liquids contracts, percent-of-proceeds, fee-based contracts, hybrid contracts (mixed
percent-of-liquids and fee-based) and keepwhole contracts. Under margin-band and keepwhole
contracts, we take ownership of mixed NGLs extracted from the producers natural gas stream and
recognize revenue when the extracted NGLs are delivered and sold to customers. In the same way,
revenue is recognized under our percent-of-liquids contracts except that the volume of NGLs we
extract 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. Under a percent-of-proceeds contract, we share in the proceeds generated
from the producers sale of the mixed NGLs we extract on their behalf. Revenue is recognized under
percent-of-proceeds arrangements when the extracted NGLs are delivered and sold to customers. If a
cash fee for natural gas processing services is stipulated by the contract, we record revenue in
the period the services are provided.
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. Revenues from these sales contracts
are recognized when the NGLs are delivered to customers. In general, the sales prices referenced
in these contracts are market-related and can include pricing differentials for such factors as
delivery location.
Under our NGL pipeline transportation contracts, revenue is recognized when volumes have been
delivered to customers. Revenue from these contracts is generally based upon a fixed fee per
gallon of liquids transported multiplied by the volume delivered. The transportation fees charged
under these arrangements are either contractual or regulated by governmental agencies, including
the FERC.
Under our NGL and related product storage contracts, we collect a fee based on the number of
days a customer has volumes in storage multiplied by a storage rate for each product. Under these
contracts, revenue is recognized ratably over the length of the storage period based on the storage
fees specified in each contract.
Revenues from product terminalling contracts (applicable to our import and export operations)
are recorded in the period services are provided. Customers are typically billed a fee per unit of
volume loaded or unloaded. In our export operations, we may also record revenues related to demand
fees we charge customers who reserve to use our export facilities and later fail to do so. We
recognize such demand fee revenue when the customer fails to utilize our facilities as required by
contract.
In our NGL fractionation business, we enter into fee-based arrangements and percent-of-liquids
contracts. Under our fee-based arrangements, we recognize revenue in the period the services are
provided. These fee-based arrangements typically include a base-processing fee (typically in cents
per gallon) that is subject to adjustment for changes in certain fractionation expenses, including
natural gas fuel costs. At certain of our NGL fractionation facilities, we generate revenues using
percent-of-liquids contracts. Such contracts allow us to retain a contractually determined
percentage of the NGLs fractionated for customers as payment for our services. We recognize
revenue from such arrangements when the NGLs we retain are sold and delivered to customers.
89
Onshore Natural Gas Pipelines & Services
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 Federal Energy Regulatory
Commission (FERC). Revenues associated with these fee-based contracts are recognized when
volumes have been physically delivered to our customer through the pipeline.
In addition, we have natural gas sales contracts associated with some of our onshore natural
gas pipelines whereby revenue is recognized when we sell and deliver a volume of natural gas to a
customer. Revenues from these sales contracts are based upon market-related prices as determined
by the individual agreements.
Under our natural gas storage contracts, there are typically two components of revenues: (i)
fixed monthly demand payments, which are associated with storage capacity reservation and paid
regardless of the customers usage of the storage facilities, and (ii) storage fees per unit of
volume stored at the facilities. Revenues from demand payments are recognized throughout the
period the customer reserves capacity. Revenues from storage fees are recognized in the period the
services are provided.
Offshore Pipelines & Services
Our revenues from offshore natural gas pipelines are derived from fee-based contracts and are
typically based on transportation fees per unit of volume transported (typically in MMBtus)
multiplied by the volume delivered. We recognize revenue when volumes have been physically
delivered for the customer through the pipeline.
The majority of our revenues from offshore crude oil pipelines are derived from purchase and
sale arrangements whereby we purchase oil from shippers at various receipt points along our crude
oil pipelines for an index-based price (less a price differential) and sell the oil back to the
shippers at various redelivery points at the same index-based price. Net revenue recognized from
such arrangements is based on the price differential per unit of volume (typically in barrels)
multiplied by the volume delivered. We recognize revenues from such arrangements when we complete
the delivery of crude oil to the purchaser.
In addition, certain of our offshore crude oil pipelines generate revenues based upon a
gathering fee per unit of volume (typically in barrels) multiplied by the volume delivered to the
customer. We recognize revenues from these gathering contracts when we complete delivery of the
crude oil for the producer.
Revenues from offshore platform services generally consist of demand fees and commodity
charges. Demand fees represent fixed-fees charged to customers who use 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 fees and commodity charges, but demand
fees generally expire after a contractual fixed period of time. Revenues for platform services,
including both demand fees and commodity charges, are recognized in the period the services are
provided.
Petrochemical Services
We enter into isomerization and propylene fractionation fee-based processing arrangements and
petrochemical product sales contracts. Under our processing arrangements, we recognize revenue in
the period the services are provided. 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.
90
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. Revenues from these sales contracts are recognized when the products are delivered to
customers. In general, the sales prices referenced in these contracts are market-related and can
include pricing differentials for such factors as delivery location.
5. Accounting for Equity Awards
As discussed in Note 2, we will account for our equity awards using the provisions of SFAS
123(R) beginning January 1, 2006. See Notes 2 and 3 for information regarding our adoption of this
new accounting guidance. The following discussion pertains to our historical practice of
accounting for equity awards using the intrinsic value method described in APB 25.
Unit Options
During 1998, EPCO adopted its 1998 Long-Term Incentive Plan (the 1998 Plan). Under this
program, non-qualified incentive options to purchase a fixed number of our common units may be
granted to EPCOs key employees who perform management, administrative or operational functions for
us. The exercise price per unit, vesting and expiration terms, and rights to receive distributions
on units granted are determined by EPCO for each grant agreement. EPCO has not granted the right
to receive distributions on unvested unit options. EPCO purchases common units to fund its
obligations under the 1998 Plan at fair value either in the open market or from us.
Historically, we accounted for unit options using the intrinsic value method described in APB
25. The exercise price of each option granted was equivalent to or greater than the market price
of the underlying equity at the date of grant. Accordingly, no compensation expense related to
unit options has been recognized in our Statements of Consolidated Operations and Comprehensive
Income for the periods presented.
When employees exercise unit options, we reimburse EPCO for the cash difference between the
strike price paid by the employee and the actual purchase price paid by EPCO for the units issued
to the employee. Our option-related reimbursements were $9.2 million, $3.8 million and $2.7
million in 2005, 2004 and 2003, respectively.
91
Summary of 1998 Plan activity
The information in the following table shows unit option activity for EPCO personnel who work
on our behalf.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted- |
|
|
|
Number of |
|
|
average strike |
|
|
|
Units |
|
|
price |
|
Outstanding at December 31, 2002 |
|
|
2,310,078 |
|
|
$ |
14.57 |
|
Granted |
|
|
35,000 |
|
|
|
22.26 |
|
Exercised |
|
|
(372,078 |
) |
|
|
7.10 |
|
Forfeited |
|
|
(35,000 |
) |
|
|
18.86 |
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2003 |
|
|
1,938,000 |
|
|
|
16.07 |
|
Granted |
|
|
910,000 |
|
|
|
22.17 |
|
Exercised |
|
|
(385,000 |
) |
|
|
12.79 |
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2004 |
|
|
2,463,000 |
|
|
|
18.84 |
|
Granted |
|
|
530,000 |
|
|
|
26.49 |
|
Exercised |
|
|
(826,000 |
) |
|
|
14.77 |
|
Forfeited |
|
|
(85,000 |
) |
|
|
24.73 |
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2005 |
|
|
2,082,000 |
|
|
|
22.16 |
|
|
|
|
|
|
|
|
|
Options exercisable at: |
|
|
|
|
|
|
|
|
December 31, 2003 |
|
|
509,000 |
|
|
$ |
9.68 |
|
|
|
|
December 31, 2004 |
|
|
1,154,000 |
|
|
$ |
14.65 |
|
|
|
|
December 31, 2005 |
|
|
727,000 |
|
|
$ |
19.19 |
|
|
|
|
The following table provides additional information regarding our unit options
outstanding at December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Exercisable at |
|
|
|
|
|
|
Weighted |
|
|
|
|
|
December 31, 2005 |
|
|
Options |
|
Average |
|
Weighted |
|
Number |
|
Weighted |
Range |
|
outstanding at |
|
Remaining |
|
Average |
|
Exercisable at |
|
Average |
of Strike |
|
December 31, |
|
Contractual |
|
Strike |
|
December 31, |
|
Strike |
Prices |
|
2005 |
|
Life (in Years) |
|
Price |
|
2005 |
|
Price |
$9.00-$12.56
|
|
|
118,000 |
|
|
|
4.41 |
|
|
$ |
10.68 |
|
|
|
118,000 |
|
|
$ |
10.68 |
|
$15.93-$17.63
|
|
|
225,000 |
|
|
|
5.14 |
|
|
|
16.47 |
|
|
|
225,000 |
|
|
|
16.47 |
|
$20.00-$24.73
|
|
|
1,249,000 |
|
|
|
7.84 |
|
|
|
22.57 |
|
|
|
384,000 |
|
|
|
23.40 |
|
$26.47-$26.95
|
|
|
490,000 |
|
|
|
9.57 |
|
|
|
26.49 |
|
|
|
|
|
|
|
n/a |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,082,000 |
|
|
|
|
|
|
|
|
|
|
|
727,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The weighted-average fair value of options granted during 2005, 2004 and 2003 was $1.35,
$2.26 and $2.17 per option, respectively.
Employee Partnership
In connection with the initial public offering of Enterprise GP Holdings in August 2005, the
Employee Partnership was formed to serve as an incentive arrangement for certain employees of EPCO
through a profits interest in the Employee Partnership. During 2005, the value of the profits
interests was accounted for similar to a stock appreciation right. For additional information
regarding the Employee Partnership, see Relationship with EPCO and affiliates under Note 18.
EPCO accounted for this share-based compensation arrangement under APB 25 until it adopted
SFAS 123(R) on January 1, 2006. Under APB 25, the intrinsic value of the Class B limited
partnership interest was accounted for similar to a stock appreciation right. EPCOs compensation
expense related to this share-based compensation arrangement is allocated to us and other
affiliates of EPCO pursuant to an administrative services agreement. For the year ended December
31, 2005, we were allocated $2 million of non-cash compensation expense associated with this
share-based compensation arrangement.
92
Nonvested Units
We began issuing nonvested (or restricted) common units to key employees of EPCO and directors
of our general partner in 2004. In general, our restricted common units are classified as either
time-vested or performance-based. Time-vested restricted unit awards entitle recipients to
acquire the underlying common units (at no cost to them) once the defined vesting period expires,
subject to certain forfeiture provisions. The restrictions on time-vested restricted common units
lapse four years from the date of grant.
Unearned compensation, representing the fair market value of such restricted units at the date
of issuance, was charged to earnings as compensation expense on a straight-line basis over the
vesting period. During the vesting period, each holder of time-vested restricted units is entitled
to receive cash distributions per unit in an amount equal to those received by our common
unitholders. For basic and diluted earnings per unit purposes, time-vested restricted common units
are treated as outstanding units.
In general, performance-based restricted unit awards entitle recipients to acquire the
underlying common units (at no cost to them) if we achieve a specified level of financial
performance for certain capital projects during 2007. If we do not reach the specified financial
targets by the dates identified within each agreement, these units will be forfeited. However, at
December 31, 2005, we believe it is probable that financial performance will be met. Unearned
compensation, representing the fair market value of these units at the date of issuance, was
charged to earnings as compensation expense on a straight-line basis over the performance period.
The performance-based restricted units are not entitled to vote or to receive distributions, until
after (and if) we achieve the specified level of target performance. Performance-based restricted
units are counted as outstanding units for dilutive earnings per unit purposes only.
At December 31, 2005, we had 751,604 restricted common units outstanding, which includes
724,454 time-vested restricted units and 27,150 performance-based restricted units. Unearned
compensation attributable to restricted units was $14.6 million and $10.9 million at December 31,
2005 and 2004, respectively. We amortized $3.4 million and $0.8 million of such compensation
expense to earnings in 2005 and 2004, respectively.
6. Employee Benefit Plans
During the first quarter of 2005, we acquired a controlling ownership interest in Dixie
Pipeline Company (Dixie), which resulted in Dixie becoming a consolidated subsidiary of ours.
Dixie employs the personnel that operate its pipeline system and certain of these employees are
eligible to participate in a defined contribution plan and pension and postretirement benefit
plans. Due to the immaterial nature of Dixies employee benefit plans to our consolidated
financial position, results of operations and cash flows, our discussion is limited to the
following:
Defined contribution plan. Dixie contributed $0.3 million to its company-sponsored
defined contribution plan during 2005.
Pension and postretirement benefit plans. Dixies pension plan is a noncontributory
defined benefit plan that provides for the payment of benefits to retirees based on their age at
retirement, years of service and average compensation. Dixies postretirement benefit plan also
provides medical and life insurance to retired employees. The medical plan is contributory and the
life insurance plan is noncontributory. Dixie employees hired after July 1, 2004 are not eligible
for pension and other benefit plans after retirement.
93
The following table shows Dixies benefit obligations, fair value of plan assets, unfunded
liabilities and accrued benefit liabilities at December 31, 2005.
|
|
|
|
|
|
|
|
|
|
|
Pension |
|
|
Postretirement |
|
|
|
Plan |
|
|
Plan |
|
|
|
|
Projected benefit obligation |
|
$ |
9,434 |
|
|
$ |
4,505 |
|
Accumulated benefit obligation |
|
|
7,023 |
|
|
|
4,505 |
|
Fair value of plan assets |
|
|
4,954 |
|
|
|
|
|
Unfunded liability |
|
|
4,480 |
|
|
|
4,505 |
|
Accrued benefit liability |
|
|
4,348 |
|
|
|
4,747 |
|
Dixies net pension and postretirement benefit costs for 2005 were $0.6 million and $0.2
million, respectively. Projected benefit obligations and net periodic benefit costs are based on
actuarial estimates and assumptions. The weighted-average actuarial assumptions used in determining
net periodic benefit costs for 2005 were as follows: discount rate of 5.75%; expected long-term
return on plan assets of 7%; rate of compensation increase of 4%; and a medical trend rate of 7% in
2005 grading to an ultimate trend of rate of 5% in 2007 and later years. The weighted-average
actuarial assumptions used in determining the projected benefit obligation at December 31, 2005
were as follows: discount rate of 5.5%, expected long-term rate of return on assets of 7%; rate of
compensation increase of 4%; and a medical trend rate of 6% for 2006 grading to an ultimate trend
of 5% for 2007 and later years.
Future benefits expected to be paid from Dixies pension and postretirement plans are as
follows for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
Pension |
|
|
Postretirement |
|
|
|
Plan |
|
|
Plan |
|
|
|
|
2006 |
|
$ |
448 |
|
|
$ |
272 |
|
2007 |
|
|
682 |
|
|
|
289 |
|
2008 |
|
|
558 |
|
|
|
283 |
|
2009 |
|
|
800 |
|
|
|
302 |
|
2010 |
|
|
832 |
|
|
|
330 |
|
2011 through 2015 |
|
|
4,804 |
|
|
|
1,883 |
|
|
|
|
Total |
|
$ |
8,124 |
|
|
$ |
3,359 |
|
|
|
|
7. Financial Instruments
We are exposed to financial market risks, including changes in commodity prices and interest
rates. We may use financial instruments (i.e., futures, forwards, swaps, options and other
financial instruments with similar characteristics) to mitigate the risks of certain identifiable
and anticipated transactions. In general, the type of risks we attempt to hedge are those related
to the variability of future earnings, fair values of certain debt instruments and cash flows
resulting from changes in applicable interest rates or commodity prices. As a matter of policy, we
do not use financial instruments for speculative (or trading) purposes.
We recognize financial instruments as assets and liabilities on our Consolidated Balance
Sheets based on fair value. Fair value is generally defined as the amount at which a financial
instrument could be exchanged in a current transaction between willing parties, not in a forced or
liquidation sale. The estimated fair values of our financial instruments have been determined
using available market information and appropriate valuation techniques. We must use considerable
judgment, however, in interpreting market data and developing these estimates. Accordingly, our
fair value estimates are not necessarily indicative of the amounts that we could realize upon
disposition of these instruments. The use of different market assumptions and/or estimation
techniques could have a material effect on our estimates of fair value.
Changes in the fair value of financial instrument contracts are recognized currently in
earnings unless specific hedge accounting criteria are met. If the financial instruments meet
those criteria, the instruments gains and losses offset the related results of the hedged item in
earnings for a fair value hedge
94
and are deferred in other comprehensive income for a cash flow hedge. Gains and losses related to
a cash flow hedge are reclassified into earnings when the forecasted transaction affects earnings.
To qualify as a hedge, the item to be hedged must be exposed to commodity or interest rate
risk and the hedging instrument must reduce the exposure and meet the hedging requirements of SFAS
133, (as amended and interpreted). We must formally designate the financial instrument as a hedge
and document and assess the effectiveness of the hedge at inception and on a quarterly basis. Any
ineffectiveness of the hedge is recorded in current earnings.
We routinely review our outstanding financial instruments in light of current market
conditions. If market conditions warrant, some financial instruments may be closed out in advance
of their contractual settlement dates thus realizing income or loss depending on the specific
exposure. When this occurs, we may enter into a new financial instrument to reestablish the
economic hedge to which the closed instrument relates.
Interest Rate Risk Hedging Program
Our interest rate exposure results from variable and fixed rate borrowings under debt
agreements. We assess cash flow risk related to interest rates by identifying and measuring
changes in our interest rate exposures that may impact future cash flows and evaluating hedging
opportunities to manage these risks. We use analytical techniques to measure our exposure to
fluctuations in interest rates, including cash flow sensitivity analysis models to forecast the
expected impact of changes in interest rates on our future cash flows. Enterprise Products GP
oversees the strategies associated with these financial risks and approves instruments that are
appropriate for our requirements.
We manage a portion of our interest rate exposures by utilizing interest rate swaps and
similar arrangements, which allow us to convert a portion of fixed rate debt into variable rate
debt or a portion of variable rate debt into fixed rate debt. We believe that it is prudent to
maintain an appropriate balance of variable rate and fixed rate debt in the current business
environment.
As summarized in the following table, we had eleven interest rate swap agreements outstanding
at December 31, 2005 that were accounted for as fair value hedges.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number |
|
Period Covered |
|
Termination |
|
Fixed to |
|
Notional |
Hedged Fixed Rate Debt |
|
Of Swaps |
|
by Swap |
|
Date of Swap |
|
Variable Rate (1) |
|
Amount |
|
Senior Notes B, 7.50% fixed rate, due Feb. 2011
|
|
|
1 |
|
|
Jan. 2004 to Feb. 2011
|
|
Feb. 2011
|
|
7.50% to 7.26%
|
|
$50 million |
Senior Notes C, 6.375% fixed rate, due Feb.
2013
|
|
|
2 |
|
|
Jan. 2004 to Feb. 2013
|
|
Feb. 2013
|
|
6.375% to 5.8%
|
|
$200 million |
Senior Notes G, 5.6% fixed rate, due Oct. 2014
|
|
|
6 |
|
|
4th Qtr. 2004 to Oct. 2014
|
|
Oct. 2014
|
|
5.6% to 5.24%
|
|
$600 million |
Senior Notes K, 4.95% fixed rate, due June 2010
|
|
|
2 |
|
|
Aug. 2005 to June 2010
|
|
June 2010
|
|
4.95% to 4.99%
|
|
$200 million |
|
|
|
|
(1) |
|
The variable rate indicated is the all-in variable rate for the current settlement period. |
We have designated these interest rate swaps as fair value hedges under SFAS 133 since
they mitigate changes in the fair value of the underlying fixed rate debt. As effective fair value
hedges, an increase in the fair value of these interest rate swaps is equally offset by an increase
in the fair value of the underlying hedged debt. The offsetting changes in fair value have no effect
on current period interest expense.
These eleven agreements have a combined notional amount of $1.1 billion and match the maturity
dates of the underlying debt being hedged. Under each swap agreement, we pay the counterparty a
variable interest rate based on six-month London interbank offered rate (LIBOR) (plus an
applicable margin as defined in each swap agreement), and receive back from the counterparty a
fixed interest rate payment based on the stated interest rate of the debt being hedged, with both
payments calculated using the notional amounts stated in each swap agreement. We settle amounts
receivable from or payable to the counterparties every six months (the settlement period). The
settlement amount is amortized ratably to earnings as either an increase or a decrease in interest
expense over the settlement period.
95
The total fair value of these eleven interest rate swaps at December 31, 2005, was a
liability of $19.2 million, with an offsetting decrease in the fair value of the underlying debt.
Interest expense for the years ended December 31, 2005 and 2004
reflects a $10.8 million and $9.1
million benefit from these swap agreements, respectively.
During the first nine months of 2004, we entered into eight forward starting interest rate
swaps having an aggregate notional value of $2 billion in anticipation of our financing activities
associated with closing the GulfTerra Merger. Our purpose in entering into these financial
instruments was to effectively hedge the underlying U.S. treasury rate related to our issuance of
$2 billion in principal amount of fixed-rate debt. In October 2004, the Operating Partnership
issued $2 billion of private placement debt under Senior Notes E through H. Each of the forward
starting swaps was designated as a cash flow hedge under SFAS 133.
In April 2004, we elected to terminate the initial four forward starting swaps in order to
manage and maximize the value of the swaps and to reduce future debt service costs. As a result,
we received $104.5 million in cash from the counterparties. In September 2004, we settled the
remaining four swaps resulting in an $85.1 million payment to the counterparties.
The following table shows the notional amount covered by each forward starting swap and the
cash gain (loss) associated with each swap upon settlement:
|
|
|
|
|
|
|
|
|
|
|
Notional |
|
Net Cash |
|
|
Amount of |
|
Received upon |
|
|
Debt covered by |
|
Settlement of |
Term of Anticipated Debt Offering |
|
Forward |
|
Forward |
(or Forecasted Transaction) |
|
Starting Swaps |
|
Starting Swaps |
|
3-year, fixed rate debt instrument |
|
$ |
500,000 |
|
|
$ |
4,613 |
|
5-year, fixed rate debt instrument |
|
|
500,000 |
|
|
|
7,213 |
|
10-year, fixed rate debt instrument |
|
|
650,000 |
|
|
|
10,677 |
|
30-year, fixed rate debt instrument |
|
|
350,000 |
|
|
|
(3,098 |
) |
|
|
|
Total |
|
$ |
2,000,000 |
|
|
$ |
19,405 |
|
|
|
|
The net gain of $19.4 million from these settlements will be reclassified from
Accumulated Other Comprehensive Income (AOCI) to reduce interest expense over the life of the
associated debt. We reclassified $4 million and $1.3 million from AOCI during 2005 and 2004,
respectively, which reduced the amount of interest expense we recognized.
Commodity Risk Hedging Program
The prices of natural gas, NGLs and petrochemical products are subject to fluctuations in
response to changes in supply, market uncertainty and a variety of additional factors that are
beyond our control. In order to manage the risks associated with natural gas and NGLs, we may
enter into commodity financial instruments.
The primary purpose of our commodity risk management activities is to hedge our exposure to
price risks associated with (i) natural gas purchases, (ii) NGL production and inventories, (iii)
related firm commitments, (iv) fluctuations in transportation revenues where the underlying fees
are based on natural gas index prices and (v) certain anticipated transactions involving either
natural gas or NGLs. The commodity financial instruments we utilize may be settled in cash or with
another financial instrument. Historically, we have not hedged our exposure to risks associated
with petrochemical products, including MTBE.
We have adopted a policy to govern our use of commodity financial instruments to manage the
risks of our natural gas and NGL businesses. The objective of this policy is to assist us in
achieving our profitability goals while maintaining a portfolio with an acceptable level of risk,
defined as remaining within the position limits established by Enterprise Products GP. We may
enter into risk management
transactions to manage price risk, basis risk, physical risk or other risks related to our
commodity positions
96
on both a short-term (less than 30 days) and long-term basis, not to exceed 24
months. Enterprise Products GP oversees the strategies associated with physical and financial
risks (such as those mentioned previously), approves specific activities subject to the policy
(including authorized products, instruments and markets) and establishes specific guidelines and
procedures for implementing and ensuring compliance with the policy.
At December 31, 2005, we had a limited number of commodity financial instruments in our
portfolio, which primarily consisted of economic hedges. The fair value of our commodity financial
instrument portfolio at December 31, 2005 was a liability of $0.1 million. We recorded nominal
amounts of earnings from our commodity financial instruments during 2005, 2004 and 2003.
Fair value information
Cash and cash equivalents, accounts receivable, accounts payable and accrued expenses are
carried at amounts which reasonably approximate their fair values due to their short-term nature.
The estimated fair values of our fixed rate debt are based on quoted market prices for such debt or
debt of similar terms and maturities. The carrying amounts of our variable rate debt obligations
reasonably approximate their fair values due to their variable interest rates. The fair values
associated with our interest rate and commodity hedging portfolios were developed using available
market information and appropriate valuation techniques.
The following table presents the estimated fair values of our financial instruments at the
dates indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2005 |
|
December 31, 2004 |
|
|
Carrying |
|
Fair |
|
Carrying |
|
Fair |
Financial Instruments |
|
Value |
|
Value |
|
Value |
|
Value |
|
Financial assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
57,050 |
|
|
$ |
57,050 |
|
|
$ |
50,713 |
|
|
$ |
50,713 |
|
Accounts receivable |
|
|
1,454,583 |
|
|
|
1,454,583 |
|
|
|
1,083,536 |
|
|
|
1,083,536 |
|
Commodity financial instruments (1) |
|
|
1,114 |
|
|
|
1,114 |
|
|
|
3,904 |
|
|
|
3,904 |
|
Interest rate hedging financial instruments (2) |
|
|
|
|
|
|
|
|
|
|
505 |
|
|
|
505 |
|
Financial liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued expenses |
|
|
1,763,390 |
|
|
|
1,763,390 |
|
|
|
1,466,115 |
|
|
|
1,466,115 |
|
Fixed-rate debt (principal amount) |
|
|
4,359,068 |
|
|
|
4,395,110 |
|
|
|
3,725,469 |
|
|
|
3,922,459 |
|
Variable-rate debt |
|
|
507,000 |
|
|
|
507,000 |
|
|
|
563,229 |
|
|
|
563,229 |
|
Commodity financial instruments (1) |
|
|
1,167 |
|
|
|
1,167 |
|
|
|
3,685 |
|
|
|
3,685 |
|
Interest rate hedging financial instruments (2) |
|
|
19,179 |
|
|
|
19,179 |
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represent commodity financial instrument transactions that either have not settled or have settled and not been invoiced. Settled and invoiced transactions are
reflected in either accounts receivable or accounts payable depending on the outcome of the transaction. |
|
(2) |
|
Represent interest rate hedging financial instrument
transactions that have not settled. Settled transactions are reflected in
either accounts receivable or accounts payable depending on the outcome
of the transaction. |
8. Cumulative Effect of Changes in Accounting Principles
In 2005 and 2004, we recorded various amounts related to the cumulative effect of changes in
accounting principles, including (i) $4.2 million in December 2005 related to our implementation of
FIN 47 and (ii) a combined $10.8 million during 2004 related to changing a subsidiarys accounting
method for planned major maintenance activities and the method we use to account for our investment
in Venice Energy Services Company, LLC (VESCO).
Implementation of FIN 47. In December 2005, we adopted Financial Accounting Standards
Board (FIN) 47, which required us to record a liability for asset retirement obligations (AROs)
in which the timing and/or amount of settlement of the obligation are uncertain. These conditional
asset retirement
obligations were not addressed in SFAS 143, which we adopted on January 1, 2003. We recorded
a
97
cumulative effect of change in accounting principle of $4.2 million in connection with our
implementation of FIN 47, which represents the depreciation and accretion expense we would have
recognized had we recorded these conditional asset retirement obligations when incurred. For
additional information regarding our asset retirement obligations, see Note 10.
BEF major maintenance costs. In January 2004, our Belvieu Environmental Fuels (BEF)
subsidiary changed its accounting method for planned major maintenance activities from the
accrue-in-advance method to the expense-as-incurred approach. BEF owns an octane additive
production facility that undergoes periodic planned outages of 30 to 45 days for major maintenance
work. These planned shutdowns typically result in significant expenditures, which are principally
comprised of amounts paid to third parties for materials, contract services, and other related
items. This change conformed BEFs accounting policy for such costs to that followed by our other
operations, which use the expense-as-incurred approach. As such, we believe the change is to a
method that is preferable under the circumstances. The cumulative effect of this accounting change
for years prior to 2004 resulted in a benefit of $7 million.
Investment in VESCO. In July 2004, we changed the method we use to account for our
investment in VESCO from the cost method to the equity method in accordance with EITF 03-16,
Accounting for Investments in Limited Liability Companies. EITF 03-16 requires partnership-type
accounting for investments in limited liability companies that have separate ownership accounts for
each investor. As a result of EITF 03-16, investors are required to apply the equity method of
accounting to their investments at a much lower ownership threshold (typically any ownership
interest greater than 3% to 5%) than the traditional 20% threshold applied under APB 18, The
Equity Method of Accounting for Investments in Common Stock.
Prior to adopting EITF 03-16, we accounted for our 13.1% investment in VESCO using the cost
method. As a result, we recognized dividend income from VESCO to the extent we received cash
distributions from them. Our cumulative effect adjustment for EITF 03-16 represents (i) equity
earnings from VESCO that would have been recorded had we used the equity method of accounting prior
to 2004 less (ii) the dividend income we recorded from VESCO prior to 2004 using the cost method.
The cumulative effect of this accounting change resulted in a benefit of $3.8 million.
98
For the periods indicated, the following table shows unaudited pro forma net income for the
years ended December 31, 2005, 2004 and 2003, assuming the three accounting changes noted above
were applied retroactively to January 1, 2003.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, |
|
|
2005 |
|
2004 |
|
2003 |
|
|
|
Pro Forma income statement amounts: |
|
|
|
|
|
|
|
|
|
|
|
|
Historical net income |
|
$ |
419,508 |
|
|
$ |
268,261 |
|
|
$ |
104,546 |
|
Adjustments to derive pro forma net income: |
|
|
|
|
|
|
|
|
|
|
|
|
Effect of implementation of FIN 47
|
|
|
|
|
|
|
|
|
|
|
|
|
Remove cumulative effect of change in accounting
principle recorded in December 2005 |
|
|
4,208 |
|
|
|
|
|
|
|
|
|
Record depreciation and accretion expense associated with
conditional asset retirement obligations |
|
|
(735 |
) |
|
|
(373 |
) |
|
|
(246 |
) |
Effect of change from the accrue-in-advance method to
the expense-as-incurred method for BEF major
maintenance costs: |
|
|
|
|
|
|
|
|
|
|
|
|
Remove historical equity in income (losses) recorded for BEF |
|
|
|
|
|
|
|
|
|
|
31,508 |
|
Record equity in (income) losses from BEF calculated using
new method of accounting for major maintenance costs |
|
|
|
|
|
|
|
|
|
|
(31,800 |
) |
Remove cumulative effect of change in accounting
principle recorded in January 2004 |
|
|
|
|
|
|
(7,013 |
) |
|
|
|
|
Remove minority interest expense associated with
change in accounting principle Sun 33.33% portion |
|
|
|
|
|
|
2,338 |
|
|
|
|
|
Effect of changing from the cost method to the equity method
with respect to our investment in VESCO: |
|
|
|
|
|
|
|
|
|
|
|
|
Remove cumulative effect of change in accounting
principle recorded in July 2004 |
|
|
|
|
|
|
(3,768 |
) |
|
|
|
|
Remove historical dividend income recorded from VESCO |
|
|
|
|
|
|
(2,136 |
) |
|
|
(5,595 |
) |
Record equity earnings from VESCO |
|
|
|
|
|
|
2,429 |
|
|
|
5,133 |
|
|
|
|
Pro forma net income |
|
|
422,981 |
|
|
|
259,738 |
|
|
|
103,546 |
|
Enterprise Products GP interest |
|
|
(71,066 |
) |
|
|
(36,938 |
) |
|
|
(20,705 |
) |
|
|
|
Pro forma net income available to limited partners |
|
$ |
351,915 |
|
|
$ |
222,800 |
|
|
$ |
82,841 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma per unit data (basic): |
|
|
|
|
|
|
|
|
|
|
|
|
Historical units outstanding |
|
|
381,857 |
|
|
|
265,370 |
|
|
|
199,915 |
|
Per unit data: |
|
|
|
|
|
|
|
|
|
|
|
|
As reported |
|
$ |
0.91 |
|
|
$ |
0.87 |
|
|
$ |
0.42 |
|
|
|
|
Pro forma |
|
$ |
0.92 |
|
|
$ |
0.84 |
|
|
$ |
0.41 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma per unit data (diluted): |
|
|
|
|
|
|
|
|
|
|
|
|
Historical units outstanding |
|
|
382,963 |
|
|
|
266,045 |
|
|
|
206,367 |
|
Per unit data: |
|
|
|
|
|
|
|
|
|
|
|
|
As reported |
|
$ |
0.91 |
|
|
$ |
0.87 |
|
|
$ |
0.41 |
|
|
|
|
Pro forma |
|
$ |
0.92 |
|
|
$ |
0.84 |
|
|
$ |
0.40 |
|
|
|
|
99
9. Inventories
Our inventory amounts were as follows at the dates indicated:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2005 |
|
2004 |
|
|
|
Working inventory |
|
$ |
279,237 |
|
|
$ |
171,485 |
|
Forward-sales inventory |
|
|
60,369 |
|
|
|
17,534 |
|
|
|
|
Inventory |
|
$ |
339,606 |
|
|
$ |
189,019 |
|
|
|
|
A general description of our inventories is as follows:
|
§ |
|
Our regular trade (or working) inventory is primarily comprised of inventories of
natural gas, NGLs and petrochemical products that are available for sale or used in the
provision of services. This inventory is valued at the lower of average cost or market,
with market being determined by industry-related posted prices such as those published
by Oil Price Information Service (OPIS) and Chemical Market Associates, Inc. (CMAI). |
|
|
§ |
|
The forward-sales inventory is comprised of segregated NGL volumes dedicated to the
fulfillment of forward sales contracts and is valued at the lower of average cost or
market, with market being defined as the weighted-average sales price for NGL volumes to
be delivered in future months on the forward sales contracts. |
Our inventory values reflect payments for product purchases, freight charges associated with
such purchase volumes and other related costs including terminal and storage fees, vessel
inspection and demurrage charges and processing costs.
In those instances where we take ownership of inventory volumes through percent-of-liquids
contracts and similar arrangements (as opposed to actually purchasing volumes for cash from third
parties, see Note 4), these volumes are valued at market-related prices during the month in which
they are acquired. As with inventory volumes we purchase for cash, we capitalize as a component of
inventory those ancillary costs (e.g. freight-in and other handling and processing charges)
incurred in connection with volumes obtained through such contracts.
Due to fluctuating market conditions in the NGL, natural gas and petrochemical industry, we
occasionally recognize lower of average cost or market (LCM) adjustments when the cost of our
inventories exceed their net realizable value. These non-cash adjustments are charged to operating
costs and expenses and generally affect our segment operating results in the following manner:
|
§ |
|
NGL inventory write-downs are recorded as a cost of our NGL marketing activities within
our NGL Pipelines & Services business segment; |
|
|
§ |
|
Natural gas inventory write downs are recorded as a cost of our natural gas pipeline
operations within our Onshore Natural Gas Pipelines & Services business segment; and |
|
|
§ |
|
Petrochemical inventory write downs are recorded as a cost of our petrochemical
marketing activities or octane additive production business within our Petrochemical
Services business segment, as applicable. |
For the years ended December 31, 2005, 2004 and 2003, we recognized LCM adjustments of
approximately $21.9 million, $9.4 million and $16.9 million, respectively. The majority of these
write-downs were taken against NGL inventories. To the extent our commodity hedging strategies
address inventory-related risks and are successful, these inventory valuation adjustments are
mitigated or offset. See Note 7 for a description of our commodity hedging activities.
100
10. Property, Plant and Equipment
Our property, plant and equipment values and accumulated depreciation balances were as follows
at the dates indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
|
Useful Life |
|
At December 31, |
|
|
in Years |
|
2005 |
|
2004 |
|
|
|
Plants and pipelines (1) |
|
|
5-35 |
(5) |
|
$ |
8,209,580 |
|
|
$ |
7,691,197 |
|
Underground and other storage facilities (2) |
|
|
5-35 |
(6) |
|
|
549,923 |
|
|
|
531,394 |
|
Platforms and facilities (3) |
|
|
23-31 |
|
|
|
161,807 |
|
|
|
162,645 |
|
Transportation equipment (4) |
|
|
3-10 |
|
|
|
24,939 |
|
|
|
7,240 |
|
Land |
|
|
|
|
|
|
38,757 |
|
|
|
29,142 |
|
Construction in progress |
|
|
|
|
|
|
854,595 |
|
|
|
230,375 |
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
|
9,839,601 |
|
|
|
8,651,993 |
|
Less accumulated depreciation |
|
|
|
|
|
|
1,150,577 |
|
|
|
820,526 |
|
|
|
|
|
|
|
|
Property, plant and equipment, net |
|
|
|
|
|
$ |
8,689,024 |
|
|
$ |
7,831,467 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Plants and pipelines includes processing plants; NGL, petrochemical, oil and natural gas pipelines; terminal loading and unloading facilities; office furniture
and equipment; buildings; laboratory and shop equipment; and related assets.
|
|
(2) |
|
Underground and other storage facilities includes underground product storage caverns; storage tanks; water wells; and related assets. |
|
(3) |
|
Platforms and facilities includes offshore platforms and related facilities and other associated assets. |
|
(4) |
|
Transportation equipment includes vehicles and similar assets used in our operations. |
|
(5) |
|
In general, the estimated useful lives of major components of this category are: processing plants, 20-35 years; pipelines, 18-35 years (with some equipment at
5 years); terminal facilities, 10-35 years; office furniture and equipment, 3-20 years; buildings 20-35 years; and laboratory and shop equipment, 5-35 years. |
|
(6) |
|
In general, the estimated useful lives of major components of this category are: underground storage facilities, 20-35 years (with some components at 5 years);
storage tanks, 10-35 years; and water wells, 25-35 years (with some components at 5 years). |
Depreciation expense for the years ended December 31, 2005, 2004 and 2003 was $328.7
million, $161 million and $101 million, respectively. A significant portion of the year-to-year
increase in depreciation expense between 2005 and 2004 is attributable to assets we acquired in
connection with the GulfTerra Merger, which was completed on September 30, 2004.
We capitalized $22 million, $2.8 million and $1.6 million of interest associated with
construction projects during 2005, 2004 and 2003, respectively.
101
Asset retirement obligations. We have recorded asset retirement obligations related
to legal requirements to perform retirement activities as specified in contractual arrangements
and/or governmental regulations. In general, our asset retirement obligations primarily result
from (i) right-of-way agreements associated with our pipeline operations, (ii) leases of plant
sites and (iii) regulatory requirements triggered by the abandonment or retirement of certain
underground storage assets and offshore facilities. In addition, our asset retirement obligations
may result from the renovation or demolition of certain assets containing hazardous substances such
as asbestos.
Previously, we recorded asset retirement obligations associated with the future retirement and
removal activities of certain offshore assets located in the Gulf of Mexico. In December 2005, we
adopted FIN 47 and recorded an additional $10.1 million in connection with conditional asset
retirement obligations. The cumulative effect of this change in accounting principle for years
prior to 2005 was a non-cash charge of $4.2 million. None of our assets are legally restricted for
purposes of settling asset retirement obligations.
The following table presents information regarding our asset retirement obligations since
December 31, 2004.
|
|
|
|
|
Asset retirement obligation liability balance, December 31, 2004 |
|
$ |
6,236 |
|
Adoption of FIN 47 for conditional obligations |
|
|
10,076 |
|
Accretion expense |
|
|
483 |
|
|
|
|
|
Asset retirement obligation liability balance, December 31, 2005 |
|
$ |
16,795 |
|
|
|
|
|
Property, plant and equipment at December 31, 2005 and 2004 includes $0.9 million and
$0.2 million, respectively, of asset retirement costs capitalized as an increase in the associated
long-lived asset. Also, based on information currently available, we estimate that accretion
expense will approximate $1.4 million for 2006, $1.1 million for 2007, $1.2 million for 2008, $1.3
million for 2009 and $1.4 million for 2010.
Certain of our unconsolidated affiliates have AROs recorded at December 31, 2005 and 2004
relating to contractual agreements and regulatory requirements. These amounts are immaterial to
our financial statements.
102
11. Investments in and Advances to Unconsolidated Affiliates
Our investments in and advances to our unconsolidated affiliates are grouped according to the
business segment to which they relate. For a general discussion of our business segments, see Note
17. The following table shows our investments in and advances to unconsolidated affiliates at the
dates indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ownership |
|
Investments in and advances to |
|
|
Percentage at |
|
Unconsolidated Affiliates at |
|
|
December 31, |
|
December 31, |
|
December 31, |
|
|
2005 |
|
2005 |
|
2004 |
|
|
|
NGL Pipelines & Services: |
|
|
|
|
|
|
|
|
|
|
|
|
Dixie Pipeline Company (Dixie) (1) |
|
|
|
|
|
|
|
|
|
$ |
32,514 |
|
Venice Energy Services Company, LLC (VESCO) |
|
|
13.1 |
% |
|
$ |
39,689 |
|
|
|
38,437 |
|
Belle Rose NGL Pipeline LLC (Belle Rose) (2) |
|
|
|
|
|
|
|
|
|
|
10,172 |
|
K/D/S Promix LLC (Promix) |
|
|
50 |
% |
|
|
65,103 |
|
|
|
65,748 |
|
Baton Rouge Fractionators LLC (BRF) |
|
|
32.3 |
% |
|
|
25,584 |
|
|
|
27,012 |
|
Onshore Natural Gas Pipelines & Services: |
|
|
|
|
|
|
|
|
|
|
|
|
Evangeline (3) |
|
|
49.5 |
% |
|
|
3,151 |
|
|
|
2,810 |
|
Coyote Gas Treating, LLC (Coyote) |
|
|
50 |
% |
|
|
1,493 |
|
|
|
2,441 |
|
Offshore Pipelines & Services: |
|
|
|
|
|
|
|
|
|
|
|
|
Poseidon Oil Pipeline, L.L.C. (Poseidon) |
|
|
36 |
% |
|
|
62,918 |
|
|
|
63,944 |
|
Cameron Highway Oil Pipeline Company (Cameron Highway) (4) |
|
|
50 |
% |
|
|
58,207 |
|
|
|
114,354 |
|
Deepwater Gateway, L.L.C. (Deepwater Gateway) (5) |
|
|
50 |
% |
|
|
115,477 |
|
|
|
56,527 |
|
Neptune Pipeline Company, L.L.C. (Neptune) |
|
|
25.67 |
% |
|
|
68,085 |
|
|
|
72,052 |
|
Nemo Gathering Company, LLC (Nemo) |
|
|
33.92 |
% |
|
|
12,157 |
|
|
|
12,586 |
|
Petrochemical Services: |
|
|
|
|
|
|
|
|
|
|
|
|
Baton Rouge Propylene Concentrator, LLC (BRPC) |
|
|
30 |
% |
|
|
15,212 |
|
|
|
15,617 |
|
La Porte (6) |
|
|
50 |
% |
|
|
4,845 |
|
|
|
4,950 |
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
$ |
471,921 |
|
|
$ |
519,164 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
We acquired an additional 20% ownership interest in Dixie in January 2005 and an additional 26.1% ownership interest in February 2005. As a result of these acquisitions, Dixie became a
consolidated subsidiary. |
|
(2) |
|
We acquired an additional 41.7% ownership interest in Belle Rose in June 2005. As a result of this acquisition, Belle Rose became a consolidated subsidiary. |
|
(3) |
|
Refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively. |
|
(4) |
|
Cameron Highway began deliveries of Gulf of Mexico crude oil production to major refining markets along the Texas Gulf Coast during the first quarter of 2005. In June 2005, we received a $47.5
million return of our investment in Cameron Highway due to the refinancing of Cameron Highways project debt. For additional information regarding the refinancing of Cameron Highways debt, please
read Note 14. |
|
(5) |
|
In March 2005, we contributed $72 million to Deepwater Gateway to fund our share of the repayment of its $144 million term loan. For additional information regarding Deepwater Gateways
repayment of its term loan, please read Note 14. |
|
(6) |
|
Refers to our ownership interests in La Porte Pipeline Company, L.P. and La Porte GP, LLC, collectively. |
On occasion, the price we pay to acquire an ownership interest in an investee exceeds the
carrying value of the historical net assets of the investee we are purchasing. Such excess amounts
(or excess costs) are a component of our investments in and advances to unconsolidated
affiliates.
At December 31, 2005, our investments in Promix, La Porte, Neptune, Poseidon, Cameron Highway
and Nemo included excess cost amounts. At the time of purchase, an analysis of each of these
investments indicated that such excess cost amounts were attributable to either (i) an increase in
the fair value of tangible or qualifying intangible assets owned by each entity over its historical
carrying values for such assets or (ii) it was unattributable and deemed to be goodwill.
To the extent that we attribute all or a portion of an excess cost amount to an increase in
the fair value of assets, we amortize such excess cost as a reduction in equity earnings in a
manner similar to depreciation. To the extent we attribute an excess cost amount to goodwill, we
do not amortize this amount but it is subject to evaluation for impairment.
103
At December 31, 2005, our investments in and advances to unconsolidated affiliates included
$48.1 million of excess cost amounts, all of which were attributed to increases in fair value of
the underlying assets of the investees. At December 31, 2004, our excess cost amounts totaled
$83.6 million, of which $74.3 million was attributed to increases in fair value of the underlying
assets and the remainder to goodwill. The decrease in total excess cost during 2005 is due to the
consolidation of Dixie and amortization of excess cost amounts attributable to the fair value of
underlying assets. Equity earnings from unconsolidated affiliates were reduced by $2.3 million,
$1.9 million and $1.6 million during 2005, 2004 and 2003, respectively, due to the amortization of
excess cost amounts.
The following table shows our equity in income (loss) of unconsolidated affiliates for the
periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, |
|
|
2005 |
|
2004 |
|
2003 |
|
|
|
NGL Pipelines & Services: |
|
|
|
|
|
|
|
|
|
|
|
|
Dixie (1) |
|
$ |
1,103 |
|
|
$ |
1,273 |
|
|
$ |
1,323 |
|
VESCO (2) |
|
|
1,412 |
|
|
|
6,132 |
|
|
|
|
|
Belle Rose (1) |
|
|
(151 |
) |
|
|
(402 |
) |
|
|
(55 |
) |
Promix |
|
|
1,876 |
|
|
|
859 |
|
|
|
2,106 |
|
BRF |
|
|
1,313 |
|
|
|
2,190 |
|
|
|
832 |
|
Tri-States NGL Pipeline LLC (Tri-States) (1) |
|
|
|
|
|
|
(154 |
) |
|
|
1,542 |
|
Wilprise Pipeline Company, LLC (Wilprise) (1) |
|
|
|
|
|
|
|
|
|
|
276 |
|
EPIK
(1, 3) |
|
|
|
|
|
|
|
|
|
|
1,818 |
|
Onshore Natural Gas Pipelines & Services: |
|
|
|
|
|
|
|
|
|
|
|
|
Evangeline |
|
|
331 |
|
|
|
231 |
|
|
|
131 |
|
Coyote |
|
|
2,053 |
|
|
|
541 |
|
|
|
|
|
Offshore Pipelines & Services: |
|
|
|
|
|
|
|
|
|
|
|
|
Poseidon |
|
|
7,279 |
|
|
|
2,509 |
|
|
|
|
|
Cameron Highway (4) |
|
|
(15,872 |
) |
|
|
(461 |
) |
|
|
|
|
Deepwater Gateway |
|
|
10,612 |
|
|
|
3,562 |
|
|
|
|
|
Neptune |
|
|
2,019 |
|
|
|
(1,852 |
) |
|
|
1,014 |
|
Nemo |
|
|
1,774 |
|
|
|
1,628 |
|
|
|
1,268 |
|
Starfish Pipeline Company, LLC (Starfish) (5) |
|
|
313 |
|
|
|
3,473 |
|
|
|
3,279 |
|
Petrochemical Services: |
|
|
|
|
|
|
|
|
|
|
|
|
BRPC |
|
|
1,224 |
|
|
|
1,943 |
|
|
|
1,198 |
|
La Porte |
|
|
(738 |
) |
|
|
(710 |
) |
|
|
(698 |
) |
Belvieu Environmental Fuels, L.P. (BEF) (1) |
|
|
|
|
|
|
|
|
|
|
(27,864 |
) |
Olefins Terminal Corporation (OTC) (1) |
|
|
|
|
|
|
|
|
|
|
(77 |
) |
Other: |
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Terra GP (6) |
|
|
|
|
|
|
32,025 |
|
|
|
(53 |
) |
|
|
|
Total |
|
$ |
14,548 |
|
|
$ |
52,787 |
|
|
$ |
(13,960 |
) |
|
|
|
|
|
|
(1) |
|
We acquired additional ownership interests in or control over these entities since January 1, 2003 resulting in our consolidation of each companys
post-acquisition financial results with those of our own. Our
consolidation of each companys post-acquisition financial results began in the following periods: EPIK, March 2003; Wilprise, October 2003; OTC, August 2003; BEF, September 2003; Tri-States, April 2004; Dixie, February 2005; and Belle Rose, June 2005. |
|
(2) |
|
As a result of adopting EITF 03-16 during 2004, we changed from the cost method to the equity method of accounting with respect to our investment in VESCO. See
Note 8 for information regarding this accounting change. |
|
(3) |
|
EPIK refers to EPIK Terminalling L.P. and EPIK Gas Liquids, LLC, collectively. |
|
(4) |
|
Equity earnings from Cameron Highway for the year ended December 31, 2005 were reduced by a charge of $11.5 million for costs associated with the refinancing of
Cameron Highways project debt (see Note 14). |
|
(5) |
|
We were required under a consent decree published for comment by the FTC on September 30, 2004 to sell our 50% interest in Starfish. On March 31, 2005, we sold
this asset to a third-party. |
|
(6) |
|
In connection with the GulfTerra Merger (see Note 12), GulfTerra GP became a wholly owned consolidated subsidiary of ours on September 30, 2004. We had previously
accounted for our 50% ownership interest in GulfTerra GP as an equity method investment from December 15, 2003 through September 29, 2004. |
104
NGL Pipelines & Services
At December 31, 2005, our NGL Pipelines & Services segment included the following
unconsolidated affiliates accounted for using the equity method:
VESCO. We own a 13.1% interest in VESCO, which owns a natural gas processing and NGL
fractionation facility and related storage and pipeline assets located in south Louisiana. On July
1, 2004, we changed our method of accounting for VESCO from the cost method to the equity method in
accordance with EITF 03-16 (see Note 8).
Promix. We own a 50% interest in Promix, which owns an NGL fractionation facility and
related storage and pipeline assets located in south Louisiana.
BRF. We own an approximate 32.3% interest in BRF, which owns an NGL fractionation
facility located in south Louisiana.
The combined balance sheet information for the last two years and results of operations data
for the last three years of this segments current unconsolidated affiliates are summarized below.
|
|
|
|
|
|
|
|
|
|
|
At December 31, |
|
|
2005 |
|
2004 |
|
|
|
BALANCE SHEET DATA: |
|
|
|
|
|
|
|
|
Current assets |
|
$ |
72,784 |
|
|
$ |
93,017 |
|
Property, plant and equipment, net |
|
|
328,270 |
|
|
|
348,168 |
|
Other assets |
|
|
12,471 |
|
|
|
13,017 |
|
|
|
|
Total assets |
|
$ |
413,525 |
|
|
$ |
454,202 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
32,886 |
|
|
$ |
72,427 |
|
Other liabilities |
|
|
7,343 |
|
|
|
6,882 |
|
Combined equity |
|
|
373,296 |
|
|
|
374,893 |
|
|
|
|
Total liabilities and combined equity |
|
$ |
413,525 |
|
|
$ |
454,202 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For Year Ended December 31, |
|
|
2005 |
|
2004 |
|
2003 |
|
|
|
INCOME STATEMENT DATA: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
207,775 |
|
|
$ |
244,521 |
|
|
$ |
258,939 |
|
Operating income |
|
|
6,696 |
|
|
|
40,259 |
|
|
|
34,630 |
|
Net income |
|
|
6,509 |
|
|
|
40,355 |
|
|
|
34,500 |
|
Onshore Natural Gas Pipelines & Services
At December 31, 2005, our Onshore Natural Gas Pipelines & Services segment included the
following unconsolidated affiliates accounted for using the equity method:
Evangeline. We own an approximate 49.5% aggregate interest in Evangeline, which owns
a natural gas pipeline system located in south Louisiana.
Coyote. We own a 50% interest in Coyote, which owns a natural gas treating facility
located in the San Juan Basin of southwestern Colorado.
105
The combined balance sheet information for the last two years and results of operations data
for the last three years of this segments current unconsolidated affiliates are summarized below.
|
|
|
|
|
|
|
|
|
|
|
At December 31, |
|
|
2005 |
|
2004 |
|
|
|
BALANCE SHEET DATA: |
|
|
|
|
|
|
|
|
Current assets |
|
$ |
41,674 |
|
|
$ |
21,652 |
|
Property, plant and equipment, net |
|
|
36,380 |
|
|
|
38,821 |
|
Other assets |
|
|
28,732 |
|
|
|
35,149 |
|
|
|
|
Total assets |
|
$ |
106,786 |
|
|
$ |
95,622 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
72,441 |
|
|
$ |
24,365 |
|
Other liabilities |
|
|
32,737 |
|
|
|
37,210 |
|
Combined equity |
|
|
1,608 |
|
|
|
34,047 |
|
|
|
|
Total liabilities and combined equity |
|
$ |
106,786 |
|
|
$ |
95,622 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For Year Ended December 31, |
|
|
2005 |
|
2004 |
|
2003 |
|
|
|
INCOME STATEMENT DATA: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
347,561 |
|
|
$ |
257,539 |
|
|
$ |
230,429 |
|
Operating income |
|
|
12,908 |
|
|
|
8,552 |
|
|
|
9,275 |
|
Net income |
|
|
4,721 |
|
|
|
4,657 |
|
|
|
5,037 |
|
Offshore Pipelines & Services
At December 31, 2005, our Offshore Pipelines & Services segment included the following
unconsolidated affiliates accounted for using the equity method:
Poseidon. We own a 36% interest in Poseidon, which owns a crude oil pipeline that
gathers production from the outer continental shelf and deepwater areas of the Gulf of Mexico for
delivery to onshore locations in south Louisiana.
Cameron Highway. We own a 50% interest in Cameron Highway, which owns a crude oil
pipeline that gathers production from deepwater areas of the Gulf of Mexico, primarily the South
Green Canyon area, for delivery to refineries and terminals in southeast Texas. The Cameron
Highway Oil Pipeline commenced operations during the first quarter of 2005.
Deepwater Gateway. We own a 50% interest in Deepwater Gateway, which owns the Marco
Polo platform located in Green Canyon Block 608 of the Gulf of Mexico. The Marco Polo platform
processes crude oil and natural gas production from the Marco Polo, K2, K2 North and Genghis Khan
fields located in the South Green Canyon area of the Gulf of Mexico.
Neptune. We own a 25.7% interest in Neptune, which owns the Manta Ray Offshore
Gathering System and Nautilus System, which are natural gas pipelines located in the Gulf of
Mexico.
Nemo. We own a 33.9% interest in Nemo, which owns the Nemo Gathering System, which is
a natural gas pipeline located in the Gulf of Mexico.
In connection with obtaining regulatory approval for the GulfTerra Merger, we were required by
the U.S. Federal Trade Commission (FTC) to sell our ownership interest in Starfish by March 31,
2005. We classified the $36.6 million carrying value of this investment under Assets held for
sale on our consolidated balance sheet at December 31, 2004. In March 2005, we sold this asset to
a third-party for $42.1 million in cash and realized a gain on the sale of $5.5 million.
106
The combined balance sheet information for the last two years and results of operations
data for the last three years of this segments current unconsolidated affiliates are summarized
below.
|
|
|
|
|
|
|
|
|
|
|
At December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
|
|
BALANCE SHEET DATA: |
|
|
|
|
|
|
|
|
Current assets |
|
$ |
141,756 |
|
|
$ |
79,196 |
|
Property, plant and equipment, net |
|
|
1,201,926 |
|
|
|
712,182 |
|
Other assets |
|
|
7,961 |
|
|
|
528,443 |
|
|
|
|
Total assets |
|
$ |
1,351,643 |
|
|
$ |
1,319,821 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
120,611 |
|
|
$ |
71,758 |
|
Other liabilities |
|
|
511,633 |
|
|
|
526,990 |
|
Combined equity |
|
|
719,399 |
|
|
|
721,073 |
|
|
|
|
Total liabilities and combined equity |
|
$ |
1,351,643 |
|
|
$ |
1,319,821 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For Year Ended December 31, |
|
|
2005 |
|
2004 |
|
2003 |
|
|
|
INCOME STATEMENT DATA: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
1,309,836 |
|
|
$ |
88,603 |
|
|
$ |
76,168 |
|
Operating income |
|
|
78,027 |
|
|
|
46,938 |
|
|
|
39,658 |
|
Net income |
|
|
29,161 |
|
|
|
38,473 |
|
|
|
33,700 |
|
Petrochemical Services
At December 31, 2005, our Petrochemical Services segment included the following unconsolidated
affiliates accounted for using the equity method:
BRPC. We own a 30% interest in BRPC, which owns a propylene fractionation facility
located in south Louisiana.
La Porte. We own an aggregate 50% interest in La Porte, which owns a propylene
pipeline extending from Mont Belvieu, Texas to La Porte, Texas.
The combined balance sheet information for the last two years and results of operations data
for the last three years of this segments current unconsolidated affiliates are summarized below.
|
|
|
|
|
|
|
|
|
|
|
At December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
|
|
BALANCE SHEET DATA: |
|
|
|
|
|
|
|
|
Current assets |
|
$ |
5,508 |
|
|
$ |
3,266 |
|
Property, plant and equipment, net |
|
|
54,751 |
|
|
|
57,516 |
|
|
|
|
Total assets |
|
$ |
60,259 |
|
|
$ |
60,782 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
1,178 |
|
|
$ |
438 |
|
Other liabilities |
|
|
1 |
|
|
|
|
|
Combined equity |
|
|
59,080 |
|
|
|
60,344 |
|
|
|
|
Total liabilities and combined equity |
|
$ |
60,259 |
|
|
$ |
60,782 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For Year Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
|
|
INCOME STATEMENT DATA: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
16,849 |
|
|
$ |
18,378 |
|
|
$ |
14,512 |
|
Operating income |
|
|
2,606 |
|
|
|
5,131 |
|
|
|
2,726 |
|
Net income |
|
|
2,650 |
|
|
|
5,151 |
|
|
|
2,685 |
|
107
Equity earnings from unconsolidated affiliates for 2003 includes a $22.5 million loss
related to non-cash impairment charges recorded by BEF, a former unconsolidated affiliate that we
now wholly own and consolidate. As a result of declining domestic demand and a prolonged period of
weak MTBE production economics, several of BEFs competitors announced their withdrawal from the
marketplace during 2003. Due to the deteriorating business environment and outlook for domestic
MTBE sales and the completion of its preliminary engineering studies regarding conversion
alternatives, BEF evaluated the carrying value of its long-lived assets for impairment during the
third quarter of 2003. This review indicated that the carrying value of its long-lived assets
exceeded
their collective fair value, which resulted in BEF recognizing a non-cash asset impairment
charge of $67.5 million. Based on our ownership interest at the time, we recorded our 33.3% share
of this loss ($22.5 million) in equity earnings from BEF.
Other, non-segment
The Other, non-segment category is presented for financial reporting purposes only to reflect
the historical equity earnings we received from GulfTerra GP. We acquired a 50% membership
interest in GulfTerra GP on December 15, 2003, in connection with the GulfTerra Merger. Our $425
million investment in GulfTerra GP was accounted for using the equity method until the GulfTerra
Merger was completed on September 30, 2004. On that date, GulfTerra GP became a wholly owned
consolidated subsidiary of ours. Since the historical equity earnings of GulfTerra GP were based
on net income amounts allocated to it by GulfTerra, it is impractical for us to allocate the equity
income we received during the periods presented to each of our new business segments. Therefore,
we have segregated equity earnings from GulfTerra GP from our other segment results to aid in
comparability between the periods presented.
12. Business Combinations and Other Acquisitions
2003 Transactions
Our expenditures for business combinations and acquisitions during 2003 were $37.3 million,
which included $4.9 million of purchase price adjustments relating to transactions that occurred
prior to 2003.
In March 2003, we purchased an additional 50% ownership interest in EPIK, which owns our NGL
export terminal located on the Houston Ship Channel. Also in March 2003, we acquired entities that
own the Port Neches petrochemical pipeline. In September 2003, we acquired an additional ownership
interest in BEF, which owns our octane additive production facility. In October 2003, we purchased
an additional 37.4% ownership interest in Wilprise, which owns an NGL pipeline in Louisiana. In
November 2003, we purchased an additional 50% ownership interest in OTC. As a result of these
transactions, all of these entities became consolidated subsidiaries of ours.
Our purchase of a 50% equity interest in GulfTerra GP in December 2003 from El Paso was
accounted for as an investment in an unconsolidated affiliate (see Note 11). Upon completion of
the GulfTerra Merger, GulfTerra GP became a consolidated subsidiary of ours.
2004 Transactions
Our expenditures for business combinations and acquisitions during 2004 were $4.1 billion,
which includes consideration paid or granted to complete the GulfTerra Merger in September 2004.
GulfTerra Merger. In September 2004, we completed the merger of GulfTerra with a
wholly owned subsidiary of ours. In addition, we completed certain other transactions related to
the merger, including (i) the receipt of Enterprise Products GPs contribution of a 50% membership
interest in GulfTerra GP, which was acquired by Enterprise Products GP from El Paso, and (ii) the
purchase of certain midstream energy assets located in South Texas from El Paso. As a result of
the merger transactions, GulfTerra and GulfTerra GP became wholly owned subsidiaries of ours.
108
The aggregate value of the total consideration we paid or issued to complete the GulfTerra
Merger was approximately $4 billion. The merger occurred in several interrelated transactions as
described below.
|
§ |
|
Step One. In December 2003, we purchased a 50% membership interest in
GulfTerra GP from El Paso for $425 million in cash. GulfTerra GP owned a 1%
general partner interest in GulfTerra. Prior to completion of the GulfTerra
Merger, we accounted for our investment in GulfTerra GP using the equity
method of accounting. The $425 million in funds required to complete Step One
was borrowed under an interim term loan and our pre-merger revolving credit
facilities. This borrowing was fully repaid using net proceeds from equity
offerings completed during 2004. |
|
|
§ |
|
Step Two. On September 30, 2004, the GulfTerra Merger was completed and
GulfTerra and GulfTerra GP became wholly-owned subsidiaries of ours. The
GulfTerra Merger was accounted for using purchase accounting. Step Two of the
GulfTerra Merger included the following transactions: |
|
§ |
|
Immediately prior to closing the GulfTerra Merger, Enterprise Products GP acquired
from El Paso the remaining 50% membership interest in GulfTerra GP for $370 million in
cash and the issuance of a 9.9% membership interest in Enterprise Products GP to El
Paso. Subsequently, Enterprise Products GP contributed this 50% membership interest in
GulfTerra GP to us without the receipt of additional general partner interest, common
units or other
consideration. Enterprise Products GP borrowed the $370 million from an affiliate of
EPCO, which obtained the required funds through a loan from EPCO (which at the time
indirectly owned the remaining membership interests in Enterprise Products GP). |
|
|
§ |
|
Immediately prior to closing the GulfTerra Merger, we paid $500 million in cash to El
Paso for 10,937,500 Series C units of GulfTerra and 2,876,620 common units of GulfTerra.
The remaining 57,762,369 GulfTerra common units were converted into 104,549,823 of our
common units, of which 13,454,498 were issued to El Paso. |
|
§ |
|
Step Three. Immediately after Step Two was completed, we acquired certain
midstream assets located in South Texas from El Paso for $155.3 million in
cash. |
In connection with closing the merger transactions, our Operating Partnership borrowed an
aggregate $2.8 billion under its credit facilities to fund our cash payment obligations under Steps
Two and Three of the GulfTerra Merger and to finance tender offers for GulfTerras outstanding
senior and senior subordinated notes.
109
The total consideration paid or granted for the GulfTerra Merger (including $7 million of
purchase price adjustments paid during 2005) is summarized below:
|
|
|
|
|
Step One transaction: |
|
|
|
|
Cash payment by us to El Paso for initial 50% membership interest
in GulfTerra GP (a non-voting interest) made in December 2003 |
|
$ |
425,000 |
|
|
|
|
|
Total Step One consideration |
|
|
425,000 |
|
|
|
|
|
Step Two transactions: |
|
|
|
|
Cash payment by us to El Paso for 10,937,500 GulfTerra Series C units
and 2,876,620 GulfTerra common units |
|
|
500,000 |
|
Fair value of equity interests granted to acquire remaining 50% membership interest in
GulfTerra GP (voting interest) (1) |
|
|
461,347 |
|
Fair value of our common units issued in exchange for remaining
GulfTerra common units (see Note 15) |
|
|
2,445,420 |
|