epdform10k_123108.htm
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
þ ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE
SECURITIES EXCHANGE ACT OF 1934
For the
fiscal year ended December 31, 2008
OR
o TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE
SECURITIES EXCHANGE ACT OF 1934
For the
transition period from ___ to ___.
Commission
file number: 1-14323
ENTERPRISE
PRODUCTS PARTNERS L.P.
(Exact name of Registrant as
Specified in Its Charter)
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Delaware
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76-0568219
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(State
or Other Jurisdiction of
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(I.R.S.
Employer Identification No.)
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Incorporation
or Organization)
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1100
Louisiana, 10th Floor, Houston,
Texas 77002
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(Address
of Principal Executive
Offices) (Zip
Code)
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(713)
381-6500
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(Registrant's
Telephone Number, Including Area Code)
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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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Securities to be registered pursuant
to Section 12(g) of the Act: None.
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act.
Yes þ No
o
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act.
Yes o No
þ
Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days.
Yes þ
No o
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not
be contained, to the best of registrant’s knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. o
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting
company. See definitions of “large accelerated filer,” “accelerated
filer” and “smaller reporting company” in Rule 12b-2 of the Exchange
Act.
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Large
accelerated filer þ
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Accelerated
filer o
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Non-accelerated
filer o
(Do not check if a smaller reporting company)
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Smaller
reporting company o
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Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes o No
þ
The
aggregate market value of Enterprise Products Partners L.P.’s (or “EPD’s”)
common units held by non-affiliates at June 30, 2008 was approximately $8.44
billion based on the closing price of such equity securities in the daily
composite list for transactions on the New York Stock Exchange on June 30,
2008. This figure excludes common units beneficially owned by certain
affiliates, including Dan L. Duncan. There were 449,944,731
common units of EPD outstanding at March 2, 2009.
TABLE
OF CONTENTS
SIGNIFICANT
RELATIONSHIPS REFERENCED IN THIS
ANNUAL
REPORT
Unless the context requires otherwise,
references to “we,” “us,” “our,” or “Enterprise Products Partners” are intended
to mean the business and operations of Enterprise Products Partners L.P. and its
consolidated subsidiaries.
References to “EPO” mean Enterprise
Products Operating LLC as successor in interest by merger to Enterprise Products
Operating L.P., which is a wholly owned subsidiary of Enterprise Products
Partners through which Enterprise Products Partners conducts substantially all
of its business.
References
to “Duncan Energy Partners” mean Duncan Energy Partners L.P., which is a
consolidated subsidiary of EPO. Duncan Energy Partners is a publicly
traded Delaware limited partnership, the common units of which are listed on the
New York Stock Exchange (“NYSE”) under the ticker symbol “DEP.” References
to “DEP GP” mean DEP Holdings, LLC, which is the general partner of Duncan
Energy Partners and is wholly owned by EPO.
References
to “EPGP” mean Enterprise Products GP, LLC, which is our general
partner.
References to “Enterprise GP Holdings”
mean Enterprise GP Holdings L.P., a publicly traded affiliate, the units of
which are listed on the NYSE under the ticker symbol
“EPE.” Enterprise GP Holdings owns EPGP. References to
“EPE Holdings” mean EPE Holdings, LLC, which is the general partner of
Enterprise GP Holdings.
References
to “TEPPCO” mean TEPPCO Partners, L.P., a publicly traded affiliate, the common
units of which are listed on the NYSE under the ticker symbol
“TPP.” References to “TEPPCO GP” refer to Texas Eastern Products
Pipeline Company, LLC, which is the general partner of TEPPCO and is wholly
owned by Enterprise GP Holdings.
References
to “Energy Transfer Equity” mean the business and operations of Energy Transfer
Equity, L.P. and its consolidated subsidiaries, which include Energy Transfer
Partners, L.P. (“ETP”). Energy Transfer Equity is a publicly traded
Delaware limited partnership, the common units of which are listed on the NYSE
under the ticker symbol “ETE.” The general partner of Energy Transfer Equity is
LE GP, LLC (“LE GP”). On May 7, 2007, Enterprise GP Holdings
acquired non-controlling interests in both LE GP and Energy Transfer
Equity. Enterprise GP Holdings accounts for its investments in LE GP
and Energy Transfer Equity using the equity method of accounting.
References
to “Employee Partnerships” mean EPE Unit L.P. (“EPE Unit I”), EPE Unit II, L.P.
(“EPE Unit II”), EPE Unit III, L.P. (“EPE Unit III”), Enterprise Unit L.P.
(“Enterprise Unit”) and EPCO Unit L.P. (“EPCO Unit”), collectively, all of which
are private company affiliates of EPCO, Inc.
References
to “EPCO” mean EPCO, Inc. and its wholly owned private company affiliates, which
are related parties to all of the foregoing named entities.
We, EPO,
Duncan Energy Partners, DEP GP, EPGP, Enterprise GP Holdings, EPE Holdings,
TEPPCO and TEPPCO GP are affiliates under the common control of Dan L. Duncan,
the Group Co-Chairman and controlling shareholder of EPCO.
CAUTIONARY
STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This
annual report contains various forward-looking statements and information that
are based on our beliefs and those of our general partner, as well as
assumptions made by us and information currently available to
us. When used in this document, words such as “anticipate,”
“project,” “expect,” “plan,” “seek,” “goal,” “estimate,” “forecast,”
“intend,” “could,” “should,” “will,” “believe,” “may,” “potential” and similar
expressions and statements regarding our plans and objectives for future
operations, are intended to identify forward-looking
statements. Although we and our general partner believe that such
expectations reflected in such forward-looking statements are reasonable,
neither we nor our general partner can give any assurances that such
expectations will prove to be correct. Such statements are subject to
a variety of risks, uncertainties and assumptions as described in more detail in
Item 1A of this annual report. If one or more of these risks or
uncertainties materialize, or if underlying assumptions prove incorrect, our
actual results may vary materially from those anticipated, estimated, projected
or expected. You should not put undue reliance on any forward-looking
statements.
General
We are a
North American midstream energy company providing a wide range of services to
producers and consumers of natural gas, natural gas liquids (“NGLs”), crude oil
and certain petrochemicals. In addition, we are an industry leader in
the development of pipeline and other midstream energy infrastructure in the
continental United States and Gulf of Mexico. We conduct
substantially all of our business through EPO. Our principal
executive offices are located at 1100 Louisiana, 10th Floor,
Houston, Texas 77002, our telephone number is (713) 381-6500 and our
website is www.epplp.com.
We are a
publicly traded Delaware limited partnership formed in 1998, the common units of
which are listed on the NYSE under the ticker symbol “EPD.” We are
owned 98.0% by our limited partners and 2.0% by our general partner,
EPGP. Our general partner is owned by a publicly traded affiliate,
Enterprise GP Holdings, the common units of which are listed on the NYSE under
the ticker symbol “EPE.”
Business
Strategy
We operate an integrated network of
midstream energy assets that includes: natural gas gathering, treating,
processing, transportation and storage; NGL fractionation (or separation),
transportation, storage and import and export terminalling; crude oil
transportation; offshore production platform services; and petrochemical
transportation and services. Our business strategies are
to:
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§
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capitalize
on expected increases in natural gas, NGL and crude oil production
resulting from development activities in the Rocky Mountains, Midcontinent
and U.S. Gulf Coast regions, including the Gulf of Mexico and Barnett
Shale producing regions;
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§
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capitalize
on expected demand growth for natural gas, NGLs, crude oil and refined
products;
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§
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maintain
a diversified portfolio of midstream energy assets and expand this asset
base through growth capital projects and accretive acquisitions of
complementary midstream energy
assets;
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§
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share
capital costs and risks through joint ventures or alliances with strategic
partners, including those that will provide the raw materials for these
growth projects or purchase the project’s end products;
and
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§
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increase
fee-based cash flows by investing in pipelines and other fee-based
businesses.
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As noted above, part of our business
strategy involves expansion through growth capital projects. We
expect that these projects will enhance our existing asset base and provide us
with additional growth opportunities in the future. For information
regarding our growth capital projects, see “Liquidity and Capital Resources -
Capital Spending” included under Item 7 of this annual report.
Financial
Information by Business Segment
For
information regarding our business segments, see Note 16 of the Notes to
Consolidated Financial Statements included under Item 8 of this annual
report. Such financial information is incorporated by reference into
this Item 1 and 2 discussion.
Recent
Developments
For
information regarding our recent developments, see “Recent Developments”
included under Item 7 of this annual report, which is incorporated by reference
into this Item 1 and 2 discussion.
Segment
Discussion
Our
midstream energy asset network links producers of natural gas, NGLs and crude
oil from some of the largest supply basins in the United States, Canada and the
Gulf of Mexico with domestic consumers and international markets. We
have four reportable business segments:
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NGL
Pipelines & Services;
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§
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Onshore
Natural Gas Pipelines &
Services;
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Offshore
Pipelines & Services; and
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§
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Petrochemical
Services.
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Our business segments are generally
organized and managed according to the type of services rendered (or
technologies employed) and products produced and/or sold.
The
following sections present an overview of our business segments, including
information regarding the principal products produced, services rendered,
seasonality, competition and regulation. Our results of operations
and financial condition are subject to a variety of risks. For
information regarding our key risk factors, see Item 1A of this annual
report.
Our business activities are subject to
various federal, state and local laws and regulations governing a wide variety
of topics, including commercial, operational, environmental, safety and other
matters. For a discussion of the principal effects such laws and
regulations have on our business, see “Regulation” and “Environmental and Safety
Matters” included within this Item 1 and 2.
Our revenues are derived from a wide
customer base. During 2008 our largest customer was LyondellBasell
Industries (“LBI”) and its affiliates, which accounted for 9.6% of our
consolidated revenues. In 2007 and 2006, our largest customer was The
Dow Chemical Company and its affiliates, which accounted for 6.9% and 6.1%,
respectively, of our consolidated revenues.
On January 6, 2009, LBI announced that
its U.S. operations had voluntarily filed to reorganize under Chapter 11 of the
U.S. Bankruptcy Code. At the time of the bankruptcy filing, we had
approximately $17.3 million of credit exposure to LBI, which was reduced to
approximately $10.0 million through remedies provided under certain pipeline
tariffs. In addition, we are seeking to have LBI accept certain
contracts and have filed claims pursuant to current Bankruptcy Court Orders that
we expect will allow us to recover the majority of the remaining credit
exposure.
For 2008,
LBI accounted for 10.2%, or $1.6 billion, of revenues attributable to our NGL
Pipelines & Services business segment and 19.2%, or $516.2 million, of
revenues attributable to our Petrochemical Services business
segment.
As
generally used in the energy industry and in this document, the identified terms
have the following meanings:
|
/d
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=
per day
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BBtus
|
=
billion British thermal units
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Bcf
|
=
billion cubic feet
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MBPD
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=
thousand barrels per day
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MMBbls
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=
million barrels
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MMBtus
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=
million British thermal units
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MMcf
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=
million cubic feet
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The following discussion of our
business segments provides information regarding our principal plants, pipelines
and other assets. For information regarding our results of
operations, including significant measures of historical throughput, production
and processing rates, see Item 7 of this annual report.
NGL
Pipelines & Services
Our NGL
Pipelines & Services business segment includes our (i) natural gas
processing business and related NGL marketing activities, (ii) NGL pipelines
aggregating approximately 14,322 miles including our 7,808-mile Mid-America
Pipeline System, (iii) NGL and related product storage facilities and (iv) NGL
fractionation facilities located in Texas and Louisiana. This segment
also includes our import and export terminal operations.
NGL
products (ethane, propane, normal butane, isobutane and natural gasoline) are
used as raw materials by the petrochemical industry, as feedstocks by refiners
in the production of motor gasoline and by industrial and residential users as
fuel. Ethane is primarily used in the petrochemical industry as a
feedstock for ethylene production, one of the basic building blocks for a wide
range of plastics and other chemical products. Propane is used both as a
petrochemical feedstock in the production of ethylene and propylene and as a
heating, engine and industrial fuel. Normal butane is used as a
petrochemical feedstock in the production of ethylene and butadiene (a key
ingredient of synthetic rubber), as a blendstock for motor gasoline and to
derive isobutane through isomerization. Isobutane is fractionated
from mixed butane (a mixed stream of normal butane and isobutane) or produced
from normal butane through the process of isomerization, principally for use in
refinery alkylation to enhance the octane content of motor gasoline, in the
production of isooctane and other octane additives and in the production of
propylene oxide. Natural gasoline, a mixture of pentanes and heavier
hydrocarbons, is primarily used as a blendstock for motor gasoline or as a
petrochemical feedstock.
Natural
gas processing and related NGL marketing activities. At the core of
our natural gas processing business are 24 processing plants located in
Colorado, Louisiana, Mississippi, New Mexico, Texas
and Wyoming. Natural gas produced at the wellhead especially in
association with crude oil contains varying amounts of NGLs. This
“rich” natural gas in its raw form is usually not acceptable for transportation
in the nation’s major natural gas pipeline systems or for commercial use as a
fuel. Natural gas processing plants remove the NGLs from the natural
gas stream, enabling the natural gas to meet pipeline and commercial quality
specifications. In addition, on an energy equivalent basis, NGLs
generally have a greater economic value as a raw material for petrochemical and
motor gasoline production than their value as components of the natural gas
stream. After extraction, we typically transport the mixed NGLs to a
centralized facility for fractionation (or separation) into purity NGL products
such as ethane, propane, normal butane, isobutane and natural
gasoline. The purity NGL products can then be used in our NGL
marketing activities to meet contractual requirements or sold on spot and
forward markets.
When
operating and extraction costs of natural gas processing plants are higher than
the incremental value of the NGL products that would be extracted, the recovery
levels of certain NGL
products,
principally ethane, may be reduced or eliminated. This leads to a
reduction in NGL volumes available for transportation and
fractionation.
In our natural gas processing
activities, we enter into margin-band contracts, percent-of-liquids contracts,
percent-of-proceeds contracts, fee-based contracts, hybrid contracts (a
combination of percent-of-liquids and fee-based contract terms) and keepwhole
contracts. Under margin-band and keepwhole contracts, we take
ownership of mixed NGLs extracted from the producer’s natural gas stream and
recognize revenue when the extracted NGLs are delivered and sold to customers on
NGL marketing sales contracts. In the same way, revenue is recognized
under our percent-of-liquids contracts except that the volume of NGLs we earn
and sell is less than the total amount of NGLs extracted from the producers’
natural gas. Under a percent-of-liquids contract, the producer
retains title to the remaining percentage of mixed NGLs we extract and generally
bears the natural gas cost for shrinkage and plant fuel. Under a
percent-of-proceeds contract, we share in the proceeds generated from the sale
of the mixed NGLs we extract on the producer’s behalf. If a cash fee
for natural gas processing services is stipulated by the contract, we record
revenue when the natural gas has been processed and delivered to the
producer. The NGL volumes we earn and take title to in connection
with our processing activities are referred to as our equity NGL
production.
In
general, our percent-of-liquids, hybrid and keepwhole contracts give us the
right (but not the obligation) to process natural gas for a producer; thus, we
are protected from processing at an economic loss during times when the sum of
our costs exceeds the value of the mixed NGLs of which we would take
ownership. Generally, our natural gas processing agreements have
terms ranging from month-to-month to life of the producing
lease. Intermediate terms of one to ten years are also
common.
To the
extent that we are obligated under our margin-band and keepwhole gas processing
contracts to compensate the producer for the natural gas equivalent energy value
of mixed NGLs we extract from the natural gas stream, we are exposed to various
risks, primarily commodity price fluctuations. However, our margin band
contracts contain terms which limit our exposure to such risks. The
prices of natural gas and NGLs are subject to fluctuations in response to
changes in supply, market uncertainty and a variety of additional factors that
are beyond our control. Periodically, we attempt to mitigate these
risks through the use of commodity financial instruments. For
information regarding our use of commodity financial instruments, see “Commodity
Risk Hedging Program” included under Item 7A of this annual report.
Our NGL marketing activities generate
revenues from the sale and delivery of NGLs obtained through our processing
activities and purchases from third parties on the open market. These
sales contracts may also include forward product sales contracts. In
general, the sales prices referenced in these contracts are market-related and
can include pricing differentials for such factors as delivery
location.
NGL
pipelines, storage facilities and import/export terminals. Our NGL pipeline,
storage and terminalling operations include approximately 14,322 miles of NGL
pipelines, 157.2 MMBbls of working capacity of NGL and related product storage
and two import/export facilities.
Our NGL
pipelines transport mixed NGLs and other hydrocarbons from natural gas
processing facilities, refineries and import terminals to fractionation plants
and storage facilities; distribute and collect NGL products to and from
fractionation plants, petrochemical plants and refineries; and deliver propane
to customers along the Dixie Pipeline and certain sections of the Mid-America
Pipeline System. Revenue from our NGL pipeline transportation
agreements is generally based upon a fixed fee per gallon of liquids transported
multiplied by the volume delivered. Accordingly, the results of
operations for this business are generally dependent upon the volume of product
transported and the level of fees charged to customers (including those charged
to our NGL and petrochemical marketing activities, which are eliminated in
consolidation). The transportation fees charged under these
arrangements are either contractual or regulated by governmental agencies,
including the Federal Energy Regulatory Commission
(“FERC”). Typically, we do not take title to the products transported
by our NGL pipelines; rather, the shipper retains title and the associated
commodity price risk.
Our NGL and related product storage
facilities are integral parts of our operations. In general, our
underground storage wells are used to store our and our customers’ mixed NGLs,
NGL products and petrochemical products. Under our NGL and related
product storage agreements, we charge customers monthly storage reservation fees
to reserve storage capacity in our underground caverns. The customers
pay reservation fees based on the quantity of capacity reserved rather than the
actual quantity utilized. When a customer exceeds its reserved
capacity, we charge those customers an excess storage fee. In
addition, we charge our customers throughput fees based on volumes injected and
withdrawn from the storage facility. Accordingly, the profitability
of our storage operations is dependent upon the level of capacity reserved by
our customers, the volume of product injected and withdrawn from our underground
caverns and the level of fees charged.
We
operate NGL import and export facilities located on the Houston Ship Channel in
southeast Texas. Our import facility is primarily used to offload
volumes for delivery to our NGL storage and fractionation facilities near Mont
Belvieu, Texas. Our export facility includes an NGL products chiller and
related equipment used for loading refrigerated marine tankers for third-party
export customers. Revenues from our import and export services are
primarily based on fees per unit of volume loaded or unloaded and may also
include demand payments. Accordingly, the profitability of our import
and export activities primarily depends on the available quantities of NGLs to
be loaded and offloaded and the fees we charge for these services.
NGL
fractionation.
We own or have interests in eight NGL fractionation facilities located in
Texas and Louisiana. NGL fractionation facilities separate mixed NGL
streams into purity NGL products. The three primary sources of mixed NGLs
fractionated in the United States are (i) domestic natural gas processing
plants, (ii) domestic crude oil refineries and (iii) imports of butane and
propane mixtures. The mixed NGLs delivered from domestic natural gas
processing plants and crude oil refineries to our NGL fractionation facilities
are typically transported by NGL pipelines and, to a lesser extent, by railcar
and truck.
Mixed
NGLs extracted by domestic natural gas processing plants represent the largest
source of volumes processed by our NGL fractionators. Based upon industry
data, we believe that sufficient volumes of mixed NGLs, especially those
originating from Gulf Coast, Rocky Mountain and Midcontinent natural gas
processing plants, will be available for fractionation in commercially viable
quantities for the foreseeable future. Significant volumes of mixed NGLs are
contractually committed to our NGL fractionation facilities by joint owners and
third-party customers.
The majority of our NGL fractionation
facilities process mixed NGL streams for third-party customers and support our
NGL marketing activities under fee-based arrangements. These fees
(typically in cents per gallon) are subject to adjustment for changes in certain
fractionation expenses, including natural gas fuel costs. At our
Norco facility, we perform fractionation services for certain customers under
percent-of-liquids contracts. The results of operations of our NGL
fractionation business are dependent upon the volume of mixed NGLs fractionated
and either the level of fractionation fees charged (under fee-based contracts)
or the value of NGLs received (under percent-of-liquids arrangements). Our
fee-based customers generally retain title to the NGLs that we process for them;
however, we are exposed to fluctuations in NGL prices (i.e., commodity price
risk) to the extent we fractionate volumes for customers under
percent-of-liquids arrangements. Periodically, we attempt to mitigate these
risks through the use of commodity financial instruments. For
information regarding our use of commodity financial instruments, see “Commodity
Risk Hedging Program” included under Item 7A of this annual report.
Seasonality. Our natural gas processing
and NGL fractionation operations exhibit little to no seasonal
variation. Likewise, our NGL pipeline operations have not exhibited a
significant degree of seasonality overall. However, propane transportation
volumes are generally higher in the October through March timeframe in
connection with increased use of propane for heating in the upper Midwest and
southeastern United States. Our facilities located in the southern
United States may be affected by weather events such as hurricanes and tropical
storms originating in the Gulf of Mexico.
We
operate our NGL and related product storage facilities based on the needs and
requirements of our customers in the NGL, petrochemical, heating and other
related industries. We usually experience an increase in the demand
for storage services during the spring and summer months due to increased
feedstock storage requirements for motor gasoline production and a decrease
during the fall and winter months when propane inventories are being drawn for
heating needs. In general, our import volumes peak during the spring and
summer months and our export volumes are at their highest levels during the
winter months.
In
support of our commercial goals, our NGL marketing activities rely on
inventories of mixed NGLs and purity NGL products. These inventories
are the result of accumulated equity NGL production volumes, imports and other
spot and contract purchases. Our inventories of ethane, propane and
normal butane are typically higher on a seasonal basis from March through
November as each are normally in higher demand and at higher price levels during
winter months. Isobutane and natural gasoline inventories are
generally stable throughout the year. Generally, our inventory cycle
begins in late-February to mid-March (the seasonal low point), builds through
September, and remains level until early December before being drawn
through winter until the seasonal low is reached again.
Competition. Our
natural gas processing business and NGL marketing activities encounter
competition from fully integrated oil companies, intrastate pipeline companies,
major interstate pipeline companies and their non-regulated affiliates, and
independent processors. Each of our competitors has varying levels of
financial and personnel resources, and competition generally revolves around
price, service and location.
In the
markets served by our NGL pipelines, we compete with a number of intrastate and
interstate liquids pipelines companies (including those affiliated with major
oil, petrochemical and gas companies) and barge, rail and truck fleet
operations. In general, our NGL pipelines compete with these entities
in terms of transportation fees and service.
Our
competitors in the NGL and related product storage businesses are integrated
major oil companies, chemical companies and other storage and pipeline
companies. We compete with other storage service providers primarily in
terms of the fees charged, number of pipeline connections and operational
dependability. Our import and export operations also compete with those
operated by major oil and chemical companies primarily in terms of loading and
offloading volumes per hour.
We
compete with a number of NGL fractionators in Texas, Louisiana and
Kansas. Although competition for NGL fractionation services is
primarily based on the fractionation fee charged, the ability of an NGL
fractionator to receive mixed NGLs, store and distribute NGL products is also an
important competitive factor and is a function of the existence of the necessary
pipeline and storage infrastructure.
Properties. The following table
summarizes the significant natural gas processing assets of our NGL Pipelines
& Services business segment at February 2, 2009.
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|
|
Net
Gas
|
|
Total
Gas
|
|
|
|
|
|
Our
|
|
Processing
|
|
Processing
|
|
|
|
|
|
Ownership
|
|
Capacity
|
|
Capacity
|
|
|
Description
of Asset
|
Location(s)
|
|
Interest
|
|
(Bcf/d)
(1)
|
|
(Bcf/d)
|
|
|
Natural
gas processing facilities:
|
|
|
|
|
|
|
|
|
|
Meeker
(2)
|
Colorado
|
|
100.0%
|
|
|
1.40 |
|
|
1.40 |
|
|
Pioneer
(3)
|
Wyoming
|
|
100.0%
|
|
|
1.30 |
|
|
1.30 |
|
|
Toca
|
Louisiana
|
|
67.4%
|
|
|
0.70 |
|
|
1.10 |
|
|
Chaco
|
New
Mexico
|
|
100.0%
|
|
|
0.65 |
|
|
0.65 |
|
|
North
Terrebonne
|
Louisiana
|
|
52.5%
|
|
|
0.63 |
|
|
1.30 |
|
|
Calumet
|
Louisiana
|
|
32.7%
|
|
|
0.51 |
|
|
1.60 |
|
|
Neptune
|
Louisiana
|
|
66.0%
|
|
|
0.43 |
|
|
0.65 |
|
|
Pascagoula
|
Mississippi
|
|
40.0%
|
|
|
0.40 |
|
|
1.50 |
|
|
Yscloskey
|
Louisiana
|
|
14.6%
|
|
|
0.34 |
|
|
1.85 |
|
|
Thompsonville
|
Texas
|
|
100.0%
|
|
|
0.30 |
|
|
0.30 |
|
|
Shoup
|
Texas
|
|
100.0%
|
|
|
0.29 |
|
|
0.29 |
|
|
Gilmore
|
Texas
|
|
100.0%
|
|
|
0.26 |
|
|
0.26 |
|
|
Armstrong
|
Texas
|
|
100.0%
|
|
|
0.25 |
|
|
0.25 |
|
|
Others
(10 facilities) (4)
|
Texas,
New Mexico, Louisiana
|
|
Various
(5)
|
|
|
1.19 |
|
|
2.85 |
|
|
Total
processing capacities
|
|
|
|
|
|
|
8.65 |
|
|
15.30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
The
approximate net natural gas processing capacity does not necessarily
correspond to our ownership interest in each facility. It is based on
a variety of factors such as volumes processed at the facility and
ownership interest in the facility.
(2)
We
commenced natural gas processing operations at our Meeker facility in
October 2007 and subsequently began the Meeker Phase II expansion project
to double the natural gas processing capacity to 1.4 Bcf/d at this
facility. The Meeker Phase II expansion is expected to be operational
during the first quarter of 2009.
(3)
We
acquired a silica gel natural gas processing facility from TEPPCO in March
2006 and subsequently increased the processing capacity from 0.3 Bcf/d to
0.6 Bcf/d. In addition, we constructed a new cryogenic processing
facility having 0.7 Bcf/d of processing capacity, which became operational
in February 2008.
(4)
Includes
our Venice, Sea Robin and Burns Point facilities located in Louisiana;
Indian Basin and Carlsbad facilities located in New Mexico; and San
Martin, Delmita, Sonora, Shilling and Indian Springs facilities located in
Texas. Our ownership in the Venice plant is through our 13.1% equity
method investment in Venice Energy Services Company, L.L.C.
(“VESCO”).
(5)
Our
ownership in these facilities ranges from 13.1% to
100.0%.
|
|
At the core of our natural gas
processing business are 24 processing plants located in Colorado, Louisiana,
Mississippi, New Mexico, Texas and Wyoming. Our natural gas
processing facilities can be characterized as two distinct types: (i) straddle
plants situated on mainline natural gas pipelines owned either by us or by third
parties or (ii) field plants that process natural gas from gathering
pipelines. We operate the Meeker, Pioneer, Toca, Chaco, North
Terrebonne, Calumet, Neptune, Burns Point and Carlsbad plants and all of the
Texas facilities. On a weighted-average basis, utilization rates
for these assets were 66.4%, 66.4%, and 56.0% during the years ended December
31, 2008, 2007 and 2006, respectively. These rates reflect the
periods in which we owned an interest in such facilities.
Our NGL marketing activities utilize a
fleet of approximately 730 railcars, the majority of which are
leased. These railcars are used to deliver feedstocks to our
facilities and to distribute NGLs throughout the United States and parts of
Canada. We have rail loading and unloading facilities in Alabama,
Arizona, California, Kansas, Louisiana, Minnesota, Mississippi, Nevada, North
Carolina and Texas. These facilities service both our rail shipments
and those of our customers.
The
following table summarizes the significant NGL pipelines and related storage
assets of our NGL Pipelines & Services business segment at February 2,
2009.
|
|
|
|
|
|
Useable
|
|
|
|
|
Our
|
|
Storage
|
|
|
|
|
Ownership
|
Length
|
Capacity
|
|
Description
of Asset
|
Location(s)
|
Interest
|
(Miles)
|
(MMBbls)
|
|
NGL
pipelines:
|
|
|
|
|
|
|
Mid-America
Pipeline System
|
Midwest
and Western U.S.
|
100.0%
|
7,808
|
|
|
|
Dixie
Pipeline
|
South
and Southeastern U.S.
|
100.0%
(1)
|
1,371
|
|
|
|
Seminole
Pipeline
|
Texas
|
90.0%
(2)
|
1,342
|
|
|
|
EPD
South Texas NGL System
|
Texas
|
100.0%
(3)
|
1,020
|
|
|
|
Louisiana
Pipeline System
|
Louisiana
|
Various
(4)
|
612
|
|
|
|
Skelly-Belvieu
Pipeline
|
Texas
|
49.0%
(5)
|
570
|
|
|
|
Promix
NGL Gathering System
|
Louisiana
|
50.0%
|
364
|
|
|
|
DEP
South Texas NGL Pipeline System
|
Texas
|
100.0%
(3)
|
297
|
|
|
|
Houston
Ship Channel
|
Texas
|
100.0%
|
252
|
|
|
|
Lou-Tex
NGL
|
Texas,
Louisiana
|
100.0%
|
205
|
|
|
|
Others
(6 systems) (6)
|
Various
|
Various
|
481
|
|
|
|
Total
miles
|
|
|
14,322
|
|
|
NGL
and related product storage facilities by state:
|
|
|
|
|
|
Texas
(7)
|
124.7
|
|
|
Louisiana
|
|
|
|
15.3
|
|
|
Kansas
|
|
|
|
7.5
|
|
|
Mississippi
|
|
|
|
5.7
|
|
|
Others
(Arizona, Georgia, Iowa, Kansas, Nebraska, North Carolina,
Oklahoma)
|
|
|
4.0
|
|
|
Total
capacity (8)
|
|
|
|
157.2
|
|
|
|
|
|
|
|
|
(1)
We
acquired the remaining 25.8% ownership interest in this system during
August 2008 and now own 100.0% of the Dixie Pipeline through our
subsidiary, Dixie Pipeline Company (“Dixie”).
(2)
We
hold a 90.0% interest in this system through a majority owned subsidiary,
Seminole Pipeline Company (“Seminole”).
(3)
Reflects
consolidated ownership of these systems by EPO (34.0%) and Duncan Energy
Partners (66.0%).
(4)
Of
the 612 total miles for this system, we own 100.0% of 559 miles and 52.5%
of the remaining 53 miles.
(5)
Our
ownership interest in this pipeline is held indirectly through our equity
method investment in Skelly-Belvieu Pipeline Company, L.L.C.
(“Skelly-Belvieu”), which we acquired in December
2008.
(6)
Includes
our Tri-States, Belle Rose, Wilprise, Chunchula and Bay Area pipelines
located in the coastal regions of Alabama, Louisiana, Mississippi and
Texas and our Meeker pipeline in Colorado. We acquired the
remaining 16.7% ownership interest in Belle Rose NGL Pipeline, L.L.C. and
an additional 16.7% interest in Tri-States NGL Pipeline, L.L.C. in October
2008.
(7)
The
amount shown for Texas includes 33 underground NGL and petrochemical
storage caverns with an aggregate useable storage capacity of
approximately 100 MMBbls that we own jointly with Duncan Energy
Partners. These caverns are located in Mont Belvieu,
Texas.
(8)
The
157.2 MMBbls of total useable storage capacity includes 22.4 MMBbls held
under long-term operating leases. The leased facilities are
located in Texas, Louisiana and
Kansas.
|
The maximum number of barrels that our
NGL pipelines can transport per day depends upon the operating balance achieved
at a given point in time between various segments of the
systems. Since the operating balance is dependent upon the mix of
products to be shipped and demand levels at various delivery points, the exact
capacities of our NGL pipelines cannot be determined. We measure the
utilization rates of such pipelines in terms of net throughput (i.e., on a net
basis in accordance with our consolidated ownership interest). Total
net throughput volumes for these pipelines were 1,747 MBPD, 1,583 MBPD and 1,450
MBPD during the years ended December 31, 2008, 2007 and 2006,
respectively.
The
following information highlights the general use of each of our principal NGL
pipelines. We operate our NGL pipelines with the exception of
Skelly-Belvieu Pipeline, Tri-States and a small portion of the Louisiana
Pipeline System.
|
§
|
The
Mid-America Pipeline System is a
regulated NGL pipeline system consisting of three primary segments: the
2,785-mile Rocky Mountain pipeline, the 2,771-mile Conway North
pipeline and the 2,252-mile Conway South pipeline. This system
covers thirteen states: Wyoming, Utah, Colorado, New Mexico, Texas,
Oklahoma, Kansas, Missouri, Nebraska, Iowa, Illinois, Minnesota and
Wisconsin. The Rocky Mountain pipeline transports mixed NGLs from the
Rocky Mountain
|
Overthrust
and San Juan Basin areas to the Hobbs hub located on the Texas-New Mexico
border. During 2007, the Rocky Mountain pipeline’s capacity was
increased by 50 MBPD. The Conway North segment links the NGL hub at
Conway, Kansas to refineries, petrochemical plants and propane markets in the
upper Midwest. In addition, the Conway North segment has access to
NGL supplies from Canada’s Western Sedimentary Basin through
third-party connections. The Conway South pipeline, which completed
an expansion in 2007, connects the Conway hub with Kansas refineries and
transports NGLs to and from Conway, Kansas to the Hobbs hub. The
Mid-America Pipeline System interconnects with our Seminole Pipeline and Hobbs
NGL fractionator and storage facility at the Hobbs hub. We also own
fifteen unregulated propane terminals that are an integral part of the
Mid-America Pipeline System.
During
2008, approximately 52.0% of the volumes transported on the Mid-America Pipeline
System were mixed NGLs originating from natural gas processing plants located in
the Permian Basin in west Texas, the Hugoton Basin of southwestern Kansas, the
San Juan Basin of northwest New Mexico, the Piceance Basin of Colorado, the
Uintah Basin of Colorado and Utah and the Greater Green River Basin of
southwestern Wyoming. The remaining volumes are generally purity NGL
products originating from NGL fractionators in the mid-continent areas of
Kansas, Oklahoma, and Texas, as well as deliveries from Canada.
|
§
|
The
Dixie Pipeline is a regulated
pipeline that extends from southeast Texas and Louisiana to markets in the
southeastern United States and transports propane and other
NGLs. Propane supplies transported on this system primarily
originate from southeast Texas, southern Louisiana and
Mississippi. This system operates in seven
states: Texas, Louisiana, Mississippi, Alabama, Georgia, South
Carolina and North Carolina.
|
|
§
|
The
Seminole Pipeline
is a regulated pipeline that transports NGLs from the Hobbs hub and the
Permian Basin area of west Texas to markets in southeastern
Texas. NGLs originating on the Mid-America Pipeline System are
the primary source of throughput for the Seminole
Pipeline.
|
|
§
|
The
EPD South Texas NGL System is a
network of NGL gathering and transportation pipelines located in south
Texas. The system includes approximately 380 miles of pipeline
used to gather and transport mixed NGLs from our south Texas natural gas
processing facilities to our south Texas NGL fractionation
facilities. The pipeline system also includes approximately 640
miles of pipelines that deliver NGLs from our south Texas fractionation
facilities to refineries and petrochemical plants located
between Corpus Christi and Houston, Texas and within the
Texas City-Houston area, as well as to common carrier NGL
pipelines.
|
We
contributed a 66.0% equity interest in Enterprise GC, LP (“Enterprise GC”), our
subsidiary that owns the EPD South Texas NGL Pipeline, to Duncan Energy Partners
effective December 8, 2008. We own, through our other subsidiaries,
the remaining 34.0% equity interest in Enterprise GC. For additional
information regarding this transaction, see “Other Items – Duncan Energy
Partners Transactions” included under Item 7 of this annual report.
|
§
|
The
Louisiana Pipeline
System is a network of NGL pipelines located in
Louisiana. This system transports NGLs originating in southern
Louisiana and in Texas to refineries and petrochemical companies
along the Mississippi River corridor in southern Louisiana. This
system also provides transportation services for our natural gas
processing plants, NGL fractionators and other facilities located in
Louisiana.
|
|
§
|
The
Skelly-Belvieu
Pipeline is a regulated pipeline that transports mixed NGLs from
Skellytown, Texas to markets in southeast Texas. Volumes
originating on the Mid-America Pipeline System and NGLs produced at local
refineries are the primary source of throughput for the Skelly-Belvieu
Pipeline.
|
|
§
|
The
Promix NGL Gathering
System is a NGL pipeline system that gathers mixed NGLs from
natural gas processing plants in Louisiana for delivery to an NGL
fractionator owned by K/D/S
|
Promix, L.L.C. (“Promix”). This gathering system is an
integral part of the Promix NGL fractionation facility. Our ownership
interest in this pipeline is held indirectly through our equity method
investment in Promix.
|
§
|
The
DEP South Texas NGL
Pipeline
System transports NGLs from our Shoup and Armstrong fractionation
facilities in south Texas to Mont Belvieu,
Texas.
|
|
§
|
The
Houston Ship
Channel pipeline system is a collection of pipelines
interconnecting our Mont Belvieu facilities with our Houston Ship Channel
import/export terminals and various third party petrochemical plants,
refineries and other pipelines located along the Houston Ship
Channel. This system is used to deliver NGL products to
third-party petrochemical plants and refineries as well as to deliver
feedstocks to our Mont Belvieu
facilities.
|
|
§
|
The
Lou-Tex NGL
pipeline system is used to provide transportation services for NGLs and
refinery grade propylene between the Louisiana and Texas markets. We also
use this pipeline to transport mixed NGLs from Mont Belvieu to our
Louisiana Pipeline System.
|
Our NGL and related product storage
facilities are integral parts of our pipeline and other
operations. In general, these underground storage facilities are used
to store NGLs and petrochemical products for us and our customers. We
operate these facilities, with the exception of certain Louisiana storage
locations operated for us by a third party.
Duncan Energy Partners, one of our
consolidated subsidiaries, owns a 66.0% equity interest in our subsidiary, Mont
Belvieu Caverns, LLC (“Mont Belvieu Caverns”). We own, through
our other subsidiaries, the remaining 34.0% equity interest in Mont Belvieu
Caverns. Mont Belvieu Caverns owns 33 underground NGL and
petrochemical storage caverns with an aggregate storage capacity of
approximately 100 MMBbls, a brine system with approximately 20 MMBbls of
above-ground brine storage pit capacity and two brine production
wells. These assets store and deliver NGLs (such as ethane and
propane) and certain refined and petrochemical products for industrial customers
located along the upper Texas Gulf Coast.
The following table summarizes the
significant NGL fractionation assets of our NGL Pipelines & Services
business segment at February 2, 2009.
|
|
|
|
|
Net
|
Total
|
|
|
|
|
Our
|
Plant
|
Plant
|
|
|
|
|
Ownership
|
Capacity
|
Capacity
|
|
Description
of Asset
|
Location(s)
|
Interest
|
(MBPD)
(1)
|
(MBPD)
|
|
NGL
fractionation facilities:
|
|
|
|
|
|
|
Mont
Belvieu
|
Texas
|
75.0%
|
178
|
230
|
|
|
Shoup
and Armstrong
|
Texas
|
100.0%
(2)
|
87
|
87
|
|
|
Hobbs
|
Texas
|
100.0%
|
75
|
75
|
|
|
Norco
|
Louisiana
|
100.0%
|
75
|
75
|
|
|
Promix
|
Louisiana
|
50.0%
|
73
|
145
|
|
|
BRF
|
Louisiana
|
32.2%
|
19
|
60
|
|
|
Tebone
|
Louisiana
|
52.5%
|
12
|
30
|
|
|
Total
plant capacities
|
|
|
519
|
702
|
|
|
|
|
|
|
|
|
(1)
The
approximate net NGL fractionation capacity does not necessarily correspond
to our ownership interest in each facility. It is based on a
variety of factors such as volumes processed at the facility and ownership
interest in the facility.
(2)
Reflects
consolidated ownership of these fractionators by EPO (34.0%) and Duncan
Energy Partners (66.0%).
|
The
following information highlights the general use of each of our principal NGL
fractionation facilities. We operate all of our NGL fractionation
facilities.
|
§
|
Our
Mont Belvieu NGL
fractionation facility is located at Mont Belvieu, Texas, which is a
key hub of the domestic and international NGL industry. This
facility fractionates mixed NGLs from several major NGL supply basins in
North America including the Mid-Continent, Permian Basin, San
Juan Basin, Rocky Mountains, East Texas and the
Gulf Coast.
|
|
§
|
Our
Shoup and Armstrong NGL
fractionation facilities fractionate mixed NGLs supplied by our south
Texas natural gas processing plants. In turn, the Shoup and
Armstrong facilities supply NGLs transported by the DEP South Texas NGL
Pipeline System.
|
We
contributed a 66.0% equity interest in Enterprise GC, our subsidiary that owns
the Shoup and Armstrong NGL fractionators, to Duncan Energy Partners effective
December 8, 2008. We own through our other subsidiaries the remaining
34.0% equity interest in Enterprise GC. For additional information
regarding this transaction, see “Other Items – Duncan Energy Partners
Transactions” included under Item 7 of this annual report.
|
§
|
Our
Hobbs NGL
fractionation facility is located in Gaines County, Texas, where it serves
petrochemical end users and refineries in West Texas, New Mexico and
California. In addition, the Hobbs facility can supply exports
to northern Mexico through existing third-party pipeline
infrastructure. The Hobbs facility receives mixed NGLs from
several major supply basins including Mid-Continent, Permian Basin,
San Juan Basin and the Rocky Mountains. The facility is strategically
located at the interconnect of our Mid-America Pipeline System and
Seminole Pipeline, providing us flexibility to supply the nation’s largest
NGL hub at Mont Belvieu, Texas as well as access to the second-largest NGL
hub at Conway, Kansas.
|
|
§
|
Our
Norco NGL
fractionation facility receives mixed NGLs via pipeline from refineries
and natural gas processing plants located in southern Louisiana and along
the Mississippi and Alabama Gulf Coast, including our Yscloskey,
Pascagoula, Venice and Toca
facilities.
|
|
§
|
The
Promix NGL
fractionation facility receives mixed NGLs via pipeline from natural gas
processing plants located in southern Louisiana and along the Mississippi
Gulf Coast, including our Calumet, Neptune, Burns Point and Pascagoula
facilities. In addition to the 364-mile Promix NGL Gathering
System, Promix owns five NGL storage caverns and a barge loading facility
that are integral to its
operations.
|
|
§
|
The
BRF facility
fractionates mixed NGLs from natural gas processing plants located in
Alabama, Mississippi and southern
Louisiana.
|
On a weighted-average basis,
utilization rates for our NGL fractionators were 83.3%, 77.7% and 72.2% during
the years ended December 31, 2008, 2007 and 2006, respectively. These
rates reflect the periods in which we owned an interest in such
facilities. We own direct consolidated interests in all of our NGL
fractionation facilities with the exception of a 50.0% interest in the facility
owned by Promix and a 32.2% interest in the facility owned by Baton Rouge
Fractionators LLC (“BRF”).
Our NGL operations include import and
export facilities located on the Houston Ship Channel in southeast
Texas. We own an import and export facility located on land we lease
from Oiltanking Houston LP (“OTTI”). Our OTTI import facility can
offload NGLs from tanker vessels at rates up to 20,000 barrels per hour
depending on the product. Our OTTI export facility can load cargoes
of refrigerated propane and butane onto tanker vessels at rates up to 6,700
barrels per hour. In addition to our OTTI facilities, we own a barge
dock that can load or offload two barges of NGLs or refinery-grade propylene
simultaneously at rates up to 5,000 barrels per hour. Our average
combined NGL import and export volumes were 74 MBPD, 84 MBPD and 127 MBPD for
the years ended December 31, 2008, 2007 and 2006, respectively.
Onshore
Natural Gas Pipelines & Services
Our
Onshore Natural Gas Pipelines & Services business segment includes
approximately 18,346 miles of onshore natural gas pipeline systems that provide
for the gathering and transmission of natural gas in Alabama, Colorado,
Louisiana, Mississippi, New Mexico, Texas and Wyoming. We
own two salt dome natural gas storage facilities located in Mississippi and
lease natural gas storage facilities located in Texas and
Louisiana. This segment also includes our natural gas marketing
activities.
Onshore
natural gas pipelines and
related natural gas marketing. Our onshore natural gas
pipeline systems provide for the gathering and transmission of natural gas from
onshore developments, such as the San Juan, Barnett Shale, Permian, Piceance and
Greater Green River supply basins in the Western U.S., and from offshore
developments in the Gulf of Mexico through connections with offshore
pipelines. Typically, these systems receive natural gas from
producers, other pipelines or shippers through system interconnects and
redeliver the natural gas to processing facilities, local gas distribution
companies, industrial or municipal customers or to other onshore
pipelines.
Certain of our onshore natural gas
pipelines generate revenues from transportation agreements where shippers are
billed a fee per unit of volume transported (typically in MMBtus) multiplied by
the volume delivered. The transportation fees charged under these
arrangements are either contractual or regulated by governmental agencies,
including the FERC. Certain of our onshore natural gas pipelines may also
offer firm capacity reservation services whereby the shipper pays a
contractually stated fee based on the level of capacity reserved in our
pipelines whether or not the shipper actually ships the reserved quantity of
natural gas. Intrastate natural gas pipelines (such as our Acadian Gas and
Alabama Intrastate systems) may also purchase natural gas from producers and
suppliers and resell such natural gas to customers such as electric utility
companies, local natural gas distribution companies and industrial
customers.
We
entered the natural gas marketing business in 2001 when we acquired the Acadian
Gas System. In 2007, we initiated an expansion of this marketing
business to maximize the utilization of our portfolio of natural gas pipeline
and storage assets. Our natural gas marketing activities generate
revenues from the sale and delivery of natural gas obtained from (i) third party
well-head purchases, (ii) our natural gas processing plants and (iii) the open
market. In general, our natural gas sales contracts utilize
market-based pricing and can incorporate pricing differentials for factors such
as delivery location. We expect our natural gas marketing business to
continue to expand in the future. Our consolidated revenues from this
business were $3.10 billion, $1.48 billion and $1.10 billion for the years ended
December 31, 2008, 2007 and 2006, respectively.
We are
exposed to commodity price risk to the extent that we take title to natural gas
volumes through our natural gas marketing activities or through certain
contracts on our intrastate natural gas pipelines. In addition, our
San Juan, Carlsbad and Jonah Gathering Systems and certain segments of our
Texas Intrastate System provide aggregating and bundling services, in which we
purchase and resell natural gas for certain small producers. Also,
several of our gathering systems, while not providing marketing services, have
some exposure to risks related to commodity prices through transportation
arrangements with shippers. For example, revenues generated by
approximately 94.0% of the natural gas volumes gathered on our San Juan
Gathering System are calculated using a percentage of a regional price index for
natural gas. We use commodity financial instruments from time to time
to mitigate our exposure to risks related to commodity prices. For
information regarding our use of commodity financial instruments, see “Commodity
Risk Hedging Program” included under Item 7A of this annual report.
Underground
natural gas storage. We own two underground salt dome natural gas
storage facilities located near Hattiesburg, Mississippi that are ideally
situated to serve the domestic Northeast, Mid-Atlantic and Southeast natural gas
markets. On a combined basis, these facilities (our Petal Gas Storage
(“Petal”) and Hattiesburg Gas Storage (“Hattiesburg”) locations) are capable of
delivering in excess of 1.4 Bcf/d of natural gas into five interstate pipeline
systems. We also lease underground salt dome natural gas storage caverns
that serve markets in Texas and Louisiana.
The ability of salt dome storage
caverns to handle high levels of injections and withdrawals of natural gas
benefits customers who desire the ability to meet load swings and to cover major
supply interruption events, such as hurricanes and temporary losses of
production. High injection and withdrawal rates also allow
customers to take advantage of periods of volatile natural gas prices and
respond in situations where they have natural gas imbalance issues on pipelines
connected to the storage facilities. Our salt dome storage facilities
permit sustained periods of high natural gas deliveries, including the ability
to quickly switch from full injection to full withdrawal.
Under our natural gas storage
contracts, there are typically two components of revenues: (i) monthly
demand payments, which are associated with storage capacity reservation and paid
regardless of the customer’s usage, and (ii) storage fees per unit of volume
stored at our facilities.
Seasonality. Typically, our onshore
natural gas pipelines experience higher throughput rates during the summer
months as natural gas-fired power generation facilities increase output to meet
residential and commercial demand for electricity for air
conditioning. Higher throughput rates are also experienced in the
winter months as natural gas is needed to fuel residential and commercial
heating. Likewise, this seasonality also impacts the timing of
injections and withdrawals at our natural gas storage facilities.
Competition. Within their market areas,
our onshore natural gas pipelines compete with other onshore natural gas
pipelines on the basis of price (in terms of transportation fees and/or natural
gas selling prices), service and flexibility. Our competitive
position within the onshore market is enhanced by our longstanding relationships
with customers and the limited number of delivery pipelines connected (or
capable of being economically connected) to the customers we serve.
Competition
for natural gas storage is primarily based on location and the ability to
deliver natural gas in a timely and reliable manner. Our natural gas
storage facilities compete with other providers of natural gas storage,
including other salt dome storage facilities and depleted reservoir
facilities. We believe that the locations of our natural gas storage
facilities allow us to compete effectively with other companies who provide
natural gas storage services.
Properties. The
following table summarizes the significant assets of our Onshore Natural Gas
Pipelines & Services business segment at February 2, 2009.
|
|
|
|
|
|
Approx.
Net
|
|
|
|
|
|
Our
|
|
Capacity,
|
Gross
|
|
|
|
|
Ownership
|
Length
|
Natural
Gas
|
Capacity
|
|
Description
of Asset
|
Location(s)
|
Interest
|
(Miles)
|
(MMcf/d)
|
(Bcf)
|
|
Onshore
natural gas pipelines:
|
|
|
|
|
|
|
|
Texas
Intrastate System
|
Texas
|
100.0% (1)
|
7,860
|
5,535
|
|
|
|
Piceance
Basin Gathering System
|
Colorado
|
100.0%
|
79
|
1,600
|
|
|
|
White
River Hub
|
Colorado
|
50.0%
|
10
|
1,500
|
|
|
|
San
Juan Gathering System
|
New
Mexico, Colorado
|
100.0%
|
6,065
|
1,200
|
|
|
|
Acadian
Gas System
|
Louisiana
|
Various
(2)
|
1,042
|
1,149
|
|
|
|
Jonah
Gathering System
|
Wyoming
|
19.4%
|
714
|
455
|
|
|
|
Carlsbad
Gathering System
|
Texas,
New Mexico
|
100.0%
|
919
|
220
|
|
|
|
Alabama
Intrastate System
|
Alabama
|
100.0%
|
408
|
200
|
|
|
|
Encinal
Gathering System
|
Texas
|
100.0%
|
449
|
143
|
|
|
|
Other
(6 systems) (3)
|
Texas,
Mississippi
|
Various
(4)
|
800
|
460
|
|
| |
Total
miles |
|
|
18,346
|
|
|
|
Natural
gas storage facilities:
|
|
|
|
|
|
|
|
Petal
|
Mississippi
|
100.0%
|
|
|
16.6
|
|
|
Hattiesburg
|
Mississippi
|
100.0%
|
|
|
2.1
|
|
|
Wilson
|
Texas
|
Leased
(5)
|
|
|
6.8
|
|
|
Acadian
|
Louisiana
|
Leased
(6)
|
|
|
1.7
|
|
|
Total
gross capacity
|
|
|
|
|
27.2
|
|
|
|
|
|
|
|
|
|
(1)
In
general, our consolidated ownership of this system is 100.0% through
interests held by EPO and Duncan Energy Partners. However, we
own and operate a consolidated 50.0% undivided interest in the 641-mile
Channel pipeline system, which is a component of the Texas Intrastate
System. The remaining 50.0% is owned by affiliates of Energy
Transfer Equity. In addition, we own less than a 100.0%
undivided interest in certain segments of the Enterprise Texas pipeline
system.
(2)
Reflects
consolidated ownership of Acadian Gas by EPO (34.0%) and Duncan Energy
Partners (66.0%). Also includes the 49.5% equity investment
that Acadian Gas has in the Evangeline pipeline.
(3)
Includes
the Delmita, Big Thicket, Indian Springs and Canales gathering systems
located in Texas and the Petal and Hattiesburg pipelines located in
Mississippi. The Delmita and Big Thicket gathering systems are
integral parts of our natural gas processing operations, the results of
operations and assets of which are accounted for under our NGL Pipelines
& Services business segment. We acquired the Canales
gathering system in connection with the Encinal acquisition in July
2006. The Petal and Hattiesburg pipelines are integral
components of our natural gas storage operations.
(4)
We
own 100.0% of these assets with the exception of the Indian Springs
system, in which we own an 80.0% undivided interest through a consolidated
subsidiary. Our 100.0% interest in Big Thicket reflects
consolidated ownership by EPO (34.0%) and Duncan Energy Partners
(66.0%).
(5)
We
hold this facility under an operating lease that expires in January
2028.
(6)
We
hold this facility under an operating lease that expires in December
2012.
|
On a weighted-average basis, aggregate
utilization rates for our onshore natural gas pipelines were approximately
65.5%, 63.5% and 70.9% during the years ended December 31, 2008, 2007 and 2006,
respectively. The utilization rate for 2008 excludes the White River Hub,
which commenced operations during December 2008 and continues to experience a
ramp-up in volumes. The utilization rate for 2007 excludes our
Piceance Creek Gathering System, which operated at an average utilization rate
of 24.3% during 2007 as volumes ramped-up on this system. Generally, our
utilization rates reflect the periods in which we owned an interest in such
assets, or, for recently constructed assets, since the dates such assets were
placed into service.
The following information highlights
the general use of each of our principal onshore natural gas pipelines and
storage facilities. We operate our onshore natural gas pipelines and
storage facilities with the exception of the White River Hub and small segments
of the Texas Intrastate System.
|
§
|
The
Texas Intrastate
System gathers and transports natural gas from supply basins in
Texas (from both onshore and offshore sources) to local gas distribution
companies and electric generation and industrial and municipal consumers
as well as to connections with intrastate and interstate
pipelines. The Texas Intrastate System is comprised of the
6,547-mile Enterprise Texas pipeline system, the 641-mile
Channel pipeline system, the 465-mile Waha gathering system and the
207-
|
mile TPC
Offshore gathering system. The leased Wilson natural gas storage
facility is an integral part of the Texas Intrastate System. The
Enterprise Texas pipeline system includes a 263-mile pipeline we lease from
an affiliate of ETP. Collectively, the Texas Intrastate System serves
important natural gas producing regions and commercial markets in Texas,
including Corpus Christi, the San Antonio/Austin area, the Beaumont/Orange area
and the Houston area, including the Houston Ship Channel industrial
market.
The
178-mile Sherman Extension of our Texas Intrastate System is scheduled for final
completion in March 2009. The Sherman Extension is capable of
transporting up to 1.1 Bcf/d of natural gas from the prolific Barnett Shale
production basin in North Texas and provides producers with interconnects with
third party interstate pipelines having access to markets outside of
Texas. Customers, including EPO, have contracted for an aggregate 1.0
Bcf/d of the capacity of the Sherman Extension.
In late
2008, we began design of the 40-mile Trinity River Basin Extension, which is
expected to be completed in the fourth quarter of 2009. The Trinity
River Basin Extension will be capable of transporting up to 1.0 Bcf/d of natural
gas and will provide producers in the Barnett Shale production basin with
additional takeaway capacity. We are also constructing a new storage
cavern adjacent to the leased Wilson natural gas storage facility that is
expected to be completed in 2010. When completed, this new cavern is
expected to provide us with an additional 5.0 Bcf of useable natural gas storage
capacity.
We
contributed equity interests in our subsidiaries that own the Texas Intrastate
System to Duncan Energy Partners effective December 8, 2008. As a
result, Duncan Energy Partners owns a 51.0% voting equity interest in the entity
that owns the Enterprise Texas pipeline system, the Channel pipeline system
and the Wilson storage facility. Also, Duncan Energy Partners owns a
66.0% voting equity interest in the entity that owns the Waha gathering system
and the TPC Offshore gathering system. We own, through our other
subsidiaries, the remaining equity interests in these entities. For
additional information regarding this transaction, see “Other Items – Duncan
Energy Partners Transactions” included under Item 7 of this annual
report.
|
§
|
The
Piceance Basin
Gathering
System consists of the 48-mile Piceance Creek and the 31-mile
Great Divide gathering systems located in the Piceance Basin of
northwestern Colorado. We acquired the Piceance Creek gathering
system from EnCana Oil & Gas USA (“EnCana”) in December 2006 and
subsequently placed this asset in-service during January 2007. We
acquired the Great Divide gathering system from EnCana in December 2008.
The Great Divide gathering system gathers natural gas from the
southern portion of the Piceance basin, including EnCana’s Mamm Creek
field, to our Piceance Creek gathering system. The Piceance
Creek gathering system extends from a connection with the Great Divide
gathering system to the Meeker facility. For additional
information regarding our acquisition of the Great Divide system, see Note
12 of the Notes to Consolidated Financial Statements included under Item 8
of this annual report.
|
|
§
|
The
White River Hub
is a FERC-regulated interstate natural gas transmission system designed to
provide natural gas transportation and hub services. The White
River Hub connects to six interstate natural gas pipelines in northwest
Colorado and has a gross capacity of 3.0 Bcf/d of natural gas (1.5 Bcf/d
net to our interest). White River Hub began service in December
2008.
|
|
§
|
The
San Juan Gathering
System serves natural gas producers in the San Juan Basin of New
Mexico and Colorado. This system gathers natural gas from
approximately 10,813 producing wells in the San Juan Basin and
delivers the natural gas to natural gas processing facilities, including
our Chaco facility.
|
|
§
|
The
Acadian Gas
System purchases, transports, stores and sells natural gas in
Louisiana. The Acadian Gas System is comprised of the 577-mile
Cypress pipeline, the 438-mile Acadian pipeline and the 27-mile Evangeline
pipeline. The leased Acadian natural gas storage facility is an
integral part of the Acadian Gas
System.
|
|
§
|
The
Jonah Gathering
System is located in the Greater Green River Basin of southwestern
Wyoming. This system gathers natural gas from the Jonah and
Pinedale fields for delivery to regional natural gas processing plants,
including our Pioneer facility, and major interstate
pipelines. Our ownership in this gathering system is through
our 19.4% equity method investment in Jonah Gas Gathering Company, which
we acquired from TEPPCO in August 2006. We completed the Phase
V expansion of the Jonah Gathering System in June
2008.
|
|
§
|
The
Carlsbad Gathering System
gathers natural gas from wells in the Permian Basin region of Texas
and New Mexico and delivers natural gas into the El Paso Natural Gas,
Transwestern and Oasis pipelines.
|
|
§
|
The
Alabama Intrastate
System mainly gathers coal bed methane from wells in the
Black Warrior Basin in Alabama. This system is also
involved in the purchase, transportation and sale of natural
gas.
|
|
§
|
The
Encinal Gathering
System gathers natural gas from the Olmos and Wilcox formations in
south Texas and delivers into our Texas Intrastate System, which delivers
the natural gas to our south Texas facilities for
processing. We acquired this gathering system in connection
with the Encinal acquisition in July
2006.
|
|
§
|
The
Petal and Hattiesburg underground
storage facilities are strategically situated to serve the domestic
Northeast, Mid-Atlantic and Southeast natural gas markets and are capable
of delivering in excess of 1.4 Bcf/d of natural gas into five interstate
pipeline systems. We placed a new natural gas storage cavern at our
Petal facility into service during the third quarter of
2008. The new cavern has a total of 9.1 Bcf of storage capacity
which represents 5.9 Bcf of FERC certificated working gas capacity
and approximately 3.2 Bcf of base gas requirements needed to support
minimum pressures.
|
Offshore
Pipelines & Services
Our
Offshore Pipelines & Services business segment includes (i) approximately
1,544 miles of offshore natural gas pipelines strategically located to serve
production areas including some of the most active drilling and development
regions in the Gulf of Mexico, (ii) approximately 909 miles of offshore Gulf of
Mexico crude oil pipeline systems and (iii) six multi-purpose offshore hub
platforms located in the Gulf of Mexico with crude oil or natural gas processing
capabilities.
Offshore
natural gas pipelines. Our offshore
natural gas pipeline systems provide for the gathering and transmission of
natural gas from production developments located in the Gulf of Mexico,
primarily offshore Louisiana and Texas. Typically, these systems receive
natural gas from producers, other pipelines and shippers through system
interconnects and transport the natural gas to various downstream pipelines,
including major interstate transmission pipelines that access multiple markets
in the eastern half of the United States.
Our revenues from offshore natural gas
pipelines are derived from fee-based agreements and are typically based on
transportation fees per unit of volume transported (generally in MMBtus)
multiplied by the volume delivered. These transportation
agreements tend to be long-term in nature, often involving life-of-reserve
commitments with firm and interruptible components. We do not take
title to the natural gas volumes that are transported on our natural gas
pipeline systems; rather, the shipper retains title and the associated commodity
price risk.
Offshore
oil pipelines. We own interests in several offshore oil pipeline
systems, which are located in the vicinity of oil-producing areas in the Gulf of
Mexico. Typically, these systems receive crude oil from offshore
production developments, other pipelines or shippers through system
interconnects and deliver the crude oil to either onshore locations or to other
offshore interconnecting pipelines.
The majority of revenues from our
offshore crude oil pipelines are generated based upon a transportation fee per
unit of volume (typically in barrels) multiplied by the volume delivered to the
customer. A substantial portion of the revenues generated by our
offshore crude oil pipeline systems are attributable to long-term transportation
agreements with producers. The revenues we earn for our services are
dependent on the volume of crude oil to be delivered and the level of fees
charged to customers.
Offshore
platforms. We have ownership
interests in six multi-purpose offshore hub platforms located in the Gulf of
Mexico with crude oil and/or natural gas processing
capabilities. Offshore platforms are critical components of the
energy-related infrastructure in the Gulf of Mexico, supporting drilling and
producing operations, and therefore play a key role in the overall development
of offshore oil and natural gas reserves. Platforms are used to: (i)
interconnect with the offshore pipeline grid; (ii) provide an efficient means to
perform pipeline maintenance; (iii) locate compression, separation and
production handling and other facilities; (iv) conduct drilling operations
during the initial development phase of an oil and natural gas property; and (v)
process off-lease production.
Revenues
from offshore platform services generally consist of demand payments and
commodity charges. Demand fees represent charges to customers served
by our offshore platforms regardless of the volume the customer delivers to the
platform. Revenues from commodity charges are based on a fixed-fee
per unit of volume delivered to the platform (typically per MMcf of natural gas
or per barrel of crude oil) multiplied by the total volume of each product
delivered. Contracts for platform services often include both demand
payments and commodity charges, but demand payments generally expire after a
contractually fixed period of time and in some instances may be subject to
cancellation by customers. Our Independence Hub and Marco Polo
offshore platforms earn a significant amount of demand revenues. The
Independence Hub platform will earn $54.6 million of demand revenues annually
through March 2012. The Marco Polo platform will earn $2.1 million of
demand revenues monthly through March 2009.
Seasonality.
Our offshore operations exhibit little to no effects of seasonality; however,
they may be affected by weather events such as hurricanes and tropical storms in
the Gulf of Mexico.
Competition.
Within their market areas, our offshore natural gas and oil pipelines compete
with other pipelines (both regulated and unregulated systems) primarily on the
basis of price (in terms of transportation fees), available capacity and
connections to downstream markets. To a limited extent, our
competition includes other offshore pipeline systems, built, owned and operated
by producers to handle their own production and, as capacity is available,
production for others. We compete with other platform service
providers on the basis of proximity and access to existing reserves and pipeline
systems, as well as costs and rates. Furthermore, our competitors may
possess greater capital resources than we have available, which could enable
them to address business opportunities more quickly than us.
Properties. The
following table summarizes the significant assets of our Offshore Pipelines
& Services business segment at February 2, 2009, all of which are located in
the Gulf of Mexico primarily offshore Louisiana and Texas.
|
|
|
Our
|
|
Water
|
Approximate
Net Capacity
|
|
|
|
Ownership
|
Length
|
Depth
|
Natural
Gas
|
Crude
Oil
|
|
Description
of Asset
|
Interest
|
(Miles)
|
(Feet)
|
(MMcf/d)
|
(MPBD)
|
|
Offshore
natural gas pipelines:
|
|
|
|
|
|
|
|
High
Island Offshore System
|
100.0%
|
291
|
|
1,800
|
|
|
|
Viosca
Knoll Gathering System
|
100.0%
|
162
|
|
1,000
|
|
|
|
Independence
Trail
|
100.0%
|
134
|
|
1,000
|
|
|
|
Green
Canyon Laterals
|
Various
(1)
|
94
|
|
605
|
|
|
|
Phoenix
Gathering System
|
100.0%
|
77
|
|
450
|
|
|
|
Falcon
Natural Gas Pipeline
|
100.0%
|
14
|
|
400
|
|
|
|
Anaconda
Gathering System
|
100.0%
|
137
|
|
300
|
|
|
|
Manta
Ray Offshore Gathering System (2)
|
25.7%
|
250
|
|
206
|
|
|
|
Nautilus
System (2)
|
25.7%
|
101
|
|
154
|
|
|
|
VESCO
Gathering System (3)
|
13.1%
|
260
|
|
105
|
|
|
|
Nemo
Gathering System (4)
|
33.9%
|
24
|
|
102
|
|
| |
Total
miles |
|
1,544
|
|
|
|
|
Offshore
crude oil pipelines:
|
|
|
|
|
|
|
|
Cameron
Highway Oil Pipeline (5)
|
50.0%
|
374
|
|
|
250
|
|
|
Poseidon
Oil Pipeline System (6)
|
36.0%
|
367
|
|
|
144
|
|
|
Allegheny
Oil Pipeline
|
100.0%
|
43
|
|
|
140
|
|
|
Marco
Polo Oil Pipeline
|
100.0%
|
37
|
|
|
120
|
|
|
Constitution
Oil Pipeline
|
100.0%
|
67
|
|
|
80
|
|
|
Typhoon
Oil Pipeline
|
100.0%
|
17
|
|
|
80
|
|
|
Tarantula
Oil Pipeline
|
100.0%
|
4
|
|
|
30
|
| |
Total
miles |
|
909 |
|
|
|
|
Offshore
platforms:
|
|
|
|
|
|
|
|
Independence
Hub
|
80.0%
|
|
8,000
|
800
|
NA
|
|
|
Marco
Polo (7)
|
50.0%
|
|
4,300
|
150
|
60
|
|
|
Viosca
Knoll 817
|
100.0%
|
|
671
|
145
|
5
|
|
|
Garden
Banks 72
|
50.0%
|
|
518
|
38
|
18
|
|
|
East
Cameron 373
|
100.0%
|
|
441
|
195
|
3
|
|
|
Falcon
Nest
|
100.0%
|
|
389
|
400
|
3
|
|
|
|
|
|
|
|
|
|
(1)
Our
ownership interests in the Green Canyon Laterals ranges from 2.7% to
100.0%.
(2)
Our
ownership interest in these pipelines is held indirectly through our
equity method investment in Neptune Pipeline Company, L.L.C.
(“Neptune”).
(3)
Our
ownership interest in this system is held indirectly through our equity
method investment in VESCO.
(4)
Our
ownership interest in this pipeline is held indirectly through our equity
method investment in Nemo Gathering Company, LLC
(“Nemo”).
(5)
Our
50.0% joint control ownership interest in this pipeline is held indirectly
through our equity method investment in Cameron Highway Oil Pipeline
Company (“Cameron Highway”).
(6)
Our
ownership interest in this pipeline is held indirectly through our equity
method investment in Poseidon Oil Pipeline Company, LLC.
(“Poseidon”).
(7)
Our
50.0% joint control ownership interest in this platform is held indirectly
through our equity method investment in Deepwater Gateway, L.L.C.
(“Deepwater Gateway”).
|
We operate our offshore natural gas
pipelines, with the exception of the VESCO Gathering System, Manta Ray Offshore
Gathering System, Nautilus System, Nemo Gathering System and certain components
of the Green Canyon Laterals. On a weighted-average basis, aggregate
utilization rates for our offshore natural gas pipelines were approximately
22.0%, 24.1% and 25.9% during the years ended December 31, 2008, 2007 and 2006,
respectively. For recently constructed assets (e.g., Independence
Trail), utilization rates reflect the periods since the dates such assets were
placed into service.
The following information highlights
the general use of each of our principal Gulf of Mexico offshore natural gas
pipelines.
|
§
|
The
High Island Offshore
System (“HIOS”)
transports natural gas from producing fields located in the Galveston,
Garden Banks, West Cameron, High Island and East Breaks areas of the
Gulf of
|
Mexico to the
ANR pipeline system, Tennessee Gas Pipeline and the U-T Offshore
System. The HIOS pipeline system includes eight pipeline junction and
service platforms. This system also includes the 86-mile East Breaks
System that connects HIOS to the Hoover-Diana deepwater platform located in
Alaminos Canyon Block 25.
|
§
|
The
Viosca Knoll Gathering
System transports natural gas from producing fields located in the
Main Pass, Mississippi Canyon and Viosca Knoll areas of the Gulf of Mexico
to several major interstate pipelines, including the Tennessee Gas,
Columbia Gulf, Southern Natural, Transco, Dauphin Island Gathering System
and Destin Pipelines.
|
|
§
|
The
Independence
Trail natural gas pipeline transports natural gas from our
Independence Hub platform to the Tennessee Gas
Pipeline. Natural gas transported on the Independence Trail
pipeline originates from production fields in the Atwater Valley,
DeSoto Canyon, Lloyd Ridge and Mississippi Canyon areas of
the Gulf of Mexico. This pipeline includes one pipeline
junction platform at West Delta 68. We completed construction
of the Independence Trail natural gas pipeline in 2006 and, in July 2007,
the pipeline received its first production from deepwater wells connected
to the Independence Hub platform.
|
|
§
|
The
Green Canyon
Laterals consist of 15 pipeline laterals (which are extensions
of natural gas pipelines) that transport natural gas to downstream
pipelines, including HIOS.
|
|
§
|
The
Phoenix Gathering
System connects the Red Hawk platform located in the Garden Banks
area of the Gulf of Mexico to the ANR pipeline
system.
|
|
§
|
The
Falcon Natural Gas Pipeline delivers
natural gas processed at our Falcon Nest platform to a connection with the
Central Texas Gathering System located on the Brazos Addition Block 133
platform.
|
|
§
|
The
Anaconda Gathering
System connects our Marco Polo platform and the third-party owned
Constitution platform to the ANR pipeline system. The Anaconda
Gathering System includes our wholly owned Typhoon, Marco Polo and
Constitution natural gas pipelines. The Constitution
natural gas pipeline serves the Constitution and Ticonderoga fields
located in the central Gulf of
Mexico.
|
|
§
|
The
Manta Ray Offshore Gathering System
transports natural gas from producing fields located in the Green Canyon,
Southern Green Canyon, Ship Shoal, South Timbalier and Ewing Bank areas of
the Gulf of Mexico to numerous downstream pipelines, including our
Nautilus System.
|
|
§
|
The
Nautilus System
connects our Manta Ray Offshore Gathering System to our Neptune natural
gas processing plant on the Louisiana gulf
coast.
|
|
§
|
The
VESCO Gathering
System is a regulated natural gas pipeline system associated with
the Venice natural gas processing plant in Louisiana. This
pipeline is an integral part of the natural gas processing operations of
VESCO.
|
|
§
|
The
Nemo Gathering
System transports natural gas from Green Canyon developments
to an interconnect with our Manta Ray Offshore Gathering
System.
|
The following information highlights
the general use of each of our principal Gulf of Mexico offshore crude oil
pipelines, all of which we operate. On a weighted-average basis,
aggregate utilization rates for our offshore crude oil pipelines were
approximately 20.1%, 19.3% and 18.1% during the years ended December 31, 2008,
2007 and 2006, respectively.
|
§
|
The
Cameron Highway Oil
Pipeline gathers crude oil production from deepwater areas of the
Gulf of Mexico, primarily the South Green Canyon area, for
delivery to refineries and terminals in southeast Texas. This
pipeline includes one pipeline junction
platform.
|
|
§
|
The
Poseidon Oil Pipeline System gathers
production from the outer continental shelf and deepwater areas of the
Gulf of Mexico for delivery to onshore locations in south
Louisiana. This system includes one pipeline junction
platform.
|
|
§
|
The
Allegheny Oil
Pipeline connects the Allegheny and South Timbalier 316 platforms
in the Green Canyon area of the Gulf of Mexico with our Cameron
Highway Oil Pipeline and Poseidon Oil Pipeline
System.
|
|
§
|
The
Marco Polo Oil
Pipeline transports crude oil from our Marco Polo platform to an
interconnect with our Allegheny Oil Pipeline in Green Canyon Block
164.
|
|
§
|
The
Constitution Oil
Pipeline serves the Constitution and Ticonderoga fields located in
the central Gulf of Mexico. The Constitution Oil Pipeline
connects with our Cameron Highway Oil Pipeline and Poseidon Oil Pipeline
System at a pipeline junction
platform.
|
In October 2006, we announced the
execution of definitive agreements with producers to construct, own and operate
an oil export pipeline (the “Shenzi Oil Pipeline”) that will provide firm
gathering services from the BHP Billiton Plc-operated Shenzi production field
located in the South Green Canyon area of the central Gulf of
Mexico. The Shenzi Oil Pipeline is expected to commence operations
during the second quarter of 2009. In August 2008, we, together
with TEPPCO and Oiltanking Holding Americas, Inc., announced the formation of
the Texas Offshore Port System, a joint venture to design, construct, operate
and own a Texas offshore crude oil port and related pipeline and storage system
that would facilitate delivery of waterborne crude oil cargoes to refining
centers located along the upper Texas Gulf Coast. For information
regarding these projects, see “Liquidity and Capital Resources – Significant
Ongoing Growth Capital Projects” included under Item 7 of this annual
report.
The following information highlights
the general use of each of our principal Gulf of Mexico offshore
platforms. We operate these offshore platforms with the exception of
the Independence Hub, Marco Polo and East Cameron 373 platforms.
On a weighted-average basis,
utilization rates with respect to natural gas processing capacity of our
offshore platforms were approximately 36.5%, 28.6% and 17.2% during the years
ended December 31, 2008, 2007 and 2006, respectively. Likewise, utilization
rates for our offshore platforms were approximately 16.9%, 26.1% and 19.2%,
respectively, in connection with platform crude oil processing
capacity. For recently constructed assets (e.g., Independence Hub),
these rates reflect the periods since the dates such assets were placed into
service. In addition to the offshore platforms we identified in the
preceding table, we own or have an ownership interest in fourteen pipeline
junction and service platforms. Our pipeline junction and service
platforms do not have processing capacity.
|
§
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The
Independence Hub
platform is located in Mississippi Canyon Block 920. This platform
processes natural gas gathered from deepwater production fields in the
Atwater Valley, DeSoto Canyon, Lloyd Ridge and
Mississippi Canyon areas of the Gulf of Mexico. We
successfully installed the Independence Hub platform and began earning
demand revenues in March 2007. In July 2007, the Independence
Hub platform received first production from deepwater wells connected to
the platform.
|
|
§
|
The
Marco Polo platform, which
is located in Green Canyon Block 608, processes crude oil and natural gas
from the Marco Polo, K2, K2 North and Genghis Khan
fields. These fields are located in the
South Green Canyon area of the Gulf of
Mexico.
|
|
§
|
The
Viosca Knoll 817
platform is centrally located on our Viosca Knoll Gathering
System. This platform primarily serves as a base for gathering
deepwater production in the area, including the Ram Powell
development.
|
|
§
|
The
Garden Banks 72
platform serves as a base for gathering deepwater production from the
Garden Banks Block 161 development and the Garden Banks Block 378 and 158
leases. This
|
platform also
serves as a junction platform for our Cameron Highway Oil Pipeline and Poseidon
Oil Pipeline System.
|
§
|
The
East Cameron 373
platform serves as the host for East Cameron Block 373 production and also
processes production from Garden Banks Blocks 108, 152, 197, 200 and
201.
|
|
§
|
The
Falcon Nest
platform, which is located in the Mustang Island Block 103 area of the
Gulf of Mexico, currently processes natural gas from the Falcon
field.
|
Petrochemical
Services
Our
Petrochemical Services business segment primarily includes two propylene
fractionation facilities, an isomerization complex, and an octane additive
production facility. This segment also includes approximately 649
miles of petrochemical pipeline systems.
Propylene
fractionation.
Our propylene fractionation business consists primarily of two propylene
fractionation facilities located in Texas and Louisiana and propylene
pipeline systems aggregating approximately 579 miles. These
operations also include an export facility located on the Houston Ship Channel
and our petrochemical marketing activities.
In general, propylene fractionation
plants separate refinery grade propylene (a mixture of propane and propylene)
into either polymer grade propylene or chemical grade propylene along with
by-products of propane and mixed butane. Polymer grade and chemical grade
propylene can also be produced as a by-product of olefin (ethylene)
production. The demand for polymer grade propylene primarily relates
to the manufacture of polypropylene, which has a variety of end uses,
including packaging film, fiber for carpets and upholstery and molded plastic
parts for appliance, automotive, houseware and medical products. Chemical
grade propylene is a basic petrochemical used in the manufacturing of plastics,
synthetic fibers and foams.
Results
of operations for our polymer grade propylene plants are generally dependent
upon toll processing arrangements and petrochemical marketing
activities. These processing arrangements typically include a
base-processing fee per gallon (or other unit of measurement) subject to
adjustment for changes in natural gas, electricity and labor costs, which are
the primary costs of propylene fractionation and isomerization
operations. Our petrochemical marketing activities generate
revenues from the sale and delivery of products obtained through our processing
activities and purchases from third parties on the open market. In
general, we sell our petrochemical products at market-related prices, which may
include pricing differentials for such factors as delivery
location.
As part
of our petrochemical marketing activities, we have several long-term polymer
grade propylene sales agreements. To meet our petrochemical marketing
obligations, we have entered into several agreements to purchase refinery grade
propylene. To limit the exposure of our petrochemical marketing activities to
price risk, we attempt to match the timing and price of our feedstock purchases
with those of the sales of end products.
Isomerization. Our isomerization business
includes three butamer reactor units and eight associated deisobutanizer units
located in Mont Belvieu, Texas, which comprise the largest commercial
isomerization complex in the United States. In addition, this
business includes a 70-mile pipeline system used to transport high-purity
isobutane from Mont Belvieu, Texas to Port Neches, Texas.
Our commercial isomerization units
convert normal butane into mixed butane, which is subsequently fractionated into
isobutane, high purity isobutane and residual normal butane. The
primary uses of isobutane are currently for the production of propylene oxide,
isooctane and alkylate for motor gasoline. The demand for commercial
isomerization services depends upon the industry’s requirements for high purity
isobutane and isobutane in excess of naturally occurring isobutane produced from
NGL fractionation and refinery operations.
The results of operation of this
business are generally dependent upon the volume of normal and mixed butanes
processed and the level of toll processing fees charged to customers. Our
isomerization facility provides processing services to meet the needs of
third-party customers and our other businesses, including our NGL marketing
activities and octane additive production facility.
Octane
enhancement. We own and operate an octane additive production
facility located in Mont Belvieu, Texas designed to produce isooctane, which is
an additive used in reformulated motor gasoline blends to increase octane, and
isobutylene. The facility produces isooctane and isobutylene using
feedstock of high-purity isobutane, which is supplied by our isomerization
units. Prior to mid-2005, the facility produced methyl tertiary butyl
ether (“MTBE”). We modified the facility to produce isooctane and
isobutylene. Depending on the outcome of various factors, the
facility may be further modified in the future to produce alkylate, another
motor gasoline additive.
Seasonality. Overall, the propylene
fractionation business exhibits little seasonality. Our isomerization
operations experience slightly higher demand in the spring and summer months due
to the demand for isobutane-based fuel additives used in the production of motor
gasoline. Likewise, isooctane prices have been stronger during the
April to September period of each year, which corresponds with the summer
driving season.
Competition. We compete with numerous
producers of polymer grade propylene, which include many of the major refiners
and petrochemical companies located along the
Gulf Coast. Generally, the propylene fractionation business
competes in terms of the level of toll processing fees charged and access to
pipeline and storage infrastructure. Our petrochemical marketing
activities encounter competition from fully integrated oil companies and various
petrochemical companies. Our petrochemical marketing competitors have
varying levels of financial and personnel resources and competition generally
revolves around price, service, logistics and location.
With
respect to our isomerization operations, we compete primarily with facilities
located in Kansas, Louisiana and New Mexico. Competitive factors affecting
this business include the level of toll processing fees charged, the quality of
isobutane that can be produced and access to pipeline and storage
infrastructure. We compete with other octane additive manufacturing
companies primarily on the basis of price.
Properties. The following table
summarizes the significant assets of our Petrochemical Services segment at
February 2, 2009, all of which we operate.
|
|
|
|
|
Net
|
Total
|
|
|
|
|
|
Our
|
Plant
|
Plant
|
|
|
|
|
|
Ownership
|
Capacity
|
Capacity
|
Length
|
|
Description
of Asset
|
Location(s)
|
Interest
|
(MBPD)
|
(MBPD)
|
(Miles)
|
|
Propylene
fractionation facilities:
|
|
|
|
|
|
|
Mont
Belvieu (six units)
|
Texas
|
Various
(1)
|
73
|
87
|
|
|
|
BRPC
|
Louisiana
|
30.0%
(2)
|
7
|
23
|
|
|
|
Total
capacity
|
|
|
80
|
110
|
|
|
Isomerization
facility:
|
|
|
|
|
|
|
|
Mont
Belvieu (3)
|
Texas
|
100.0%
|
116
|
116
|
|
|
Petrochemical
pipelines:
|
|
|
|
|
|
|
|
Lou-Tex
and Sabine Propylene
|
Texas,
Louisiana
|
100.0%
(4)
|
|
|
284
|
|
|
Texas
City RGP Gathering System
|
Texas
|
100.0%
|
|
|
86
|
|
|
Lake
Charles
|
Texas,
Louisiana
|
50.0%
|
|
|
81
|
|
|
Others
(5 systems) (5)
|
Texas
|
Various
(6)
|
|
|
198
|
|
|
Total
miles
|
|
|
|
|
649
|
|
Octane
additive production facilities:
|
|
|
|
|
|
|
Mont
Belvieu (7)
|
Texas
|
100.0%
|
12
|
12
|
|
|
|
|
|
|
|
|
|
|
(1)
We
own a 54.6% interest and lease the remaining 45.4% of a unit having 17
MBPD of plant capacity. We own a 66.7% interest in three
additional units having an aggregate 41 MBPD of total plant
capacity. We own 100.0% of the remaining two units, which have
14 MBPD and 15 MBPD of plant capacity, respectively.
(2)
Our
ownership interest in this facility is held indirectly through our equity
method investment in Baton Rouge Propylene Concentrator LLC
(“BRPC”).
(3)
On
a weighted-average basis, utilization rates for this facility were
approximately 74.1%, 77.6% and 69.8% during the years ended December 31,
2008, 2007 and 2006, respectively.
(4)
Reflects
consolidated ownership of these pipelines by EPO (34.0%) and Duncan Energy
Partners (66.0%).
(5)
Includes
our Texas City PGP Delivery System and Port Neches, La Porte, Port Arthur
and Bayport petrochemical pipelines.
(6)
We
own 100.0% of these pipelines with the exception of the 17-mile La Porte
pipeline, in which we hold an aggregate 50.0% indirect interest through
our equity method investments in La Porte Pipeline Company L.P. and La
Porte Pipeline GP, L.L.C.
(7)
On
a weighted-average basis, utilization rates for this facility were
approximately 58.3% during each of the years ended December 31, 2008, 2007
and 2006, respectively.
|
We produce polymer grade propylene at
our Mont Belvieu location and chemical grade propylene at our BRPC
facility. The primary purpose of the BRPC unit is to fractionate
refinery grade propylene produced by an affiliate of Exxon Mobil
Corporation into chemical grade propylene. The production of polymer
grade propylene from our Mont Belvieu facility is primarily used in our
petrochemical marketing activities. On a weighted-average basis,
aggregate utilization rates of our propylene fractionation facilities were
approximately 72.2%, 86.0% and 86.2% during the years ended December 31, 2008,
2007 and 2006, respectively. This business segment also includes an
above-ground polymer grade propylene storage and export facility located in
Seabrook, Texas. This facility can load vessels at rates up to 5,000
barrels per hour.
The
Lou-Tex Propylene pipeline is used to transport chemical grade propylene from
Sorrento, Louisiana to Mont Belvieu, Texas. The Sabine pipeline is
used to transport polymer grade propylene from Port Arthur, Texas to a pipeline
interconnect in Cameron Parish, Louisiana.
The
maximum number of barrels that our petrochemical pipelines can transport per day
depends upon the operating balance achieved at a given point in time between
various segments of the systems. Since the operating balance is
dependent upon the mix of products to be shipped and demand levels at various
delivery points, the exact capacities of our petrochemical pipelines cannot be
determined. We measure the utilization rates of such pipelines in
terms of net throughput (i.e., on a net basis in accordance with our ownership
interest). Total net throughput volumes for these pipelines were 108
MBPD, 105 MBPD and 97 MBPD during the years ended December 31, 2008, 2007 and
2006, respectively.
Title
to Properties
Our real property holdings fall into
two basic categories: (i) parcels that we and our unconsolidated affiliates own
in fee (e.g., we own the land upon which our Mont Belvieu NGL fractionator is
constructed) and (ii) parcels in which our interests and those of our
unconsolidated affiliates are derived from leases, easements, rights-of-way,
permits or licenses from landowners or governmental authorities permitting the
use of such land for our operations. The fee sites upon which our
significant facilities are located have been owned by us or our predecessors in
title for many years without any material challenge known to us relating to
title to the land upon which the assets are located, and we believe that we have
satisfactory title to such fee sites. We and our unconsolidated
affiliates have no knowledge of any challenge to the underlying fee title of any
material lease, easement, right-of-way, permit or license held by us or to our
rights pursuant to any material lease, easement, right-of-way, permit or
license, and we believe that we have satisfactory rights pursuant to all of our
material leases, easements, rights-of-way, permits and licenses.
Capital
Spending
We are committed to the long-term
growth and viability of Enterprise Products Partners. Part of our
business strategy involves expansion through business combinations, growth
capital projects and investments in joint ventures. We believe we are
positioned to continue to grow our system of assets through the construction of
new facilities and to capitalize on expected future production increases from
areas such as the Piceance Basin of western Colorado, the Greater Green River
Basin in Wyoming, the Barnett Shale in North Texas and the deepwater Gulf of
Mexico. For a discussion of our capital spending program, see
“Liquidity and Capital Resources - Capital Spending” included under Item 7 of
this annual report.
Weather-Related
Risks
In the
third quarter of 2008, our onshore and offshore facilities located along the
Gulf Coast of Texas and Louisiana were adversely impacted by Hurricanes Gustav
and Ike. The disruptions in natural gas, NGL and crude oil production
caused by these storms resulted in decreased volumes for some of our pipeline
systems, natural gas processing plants, NGL fractionators and offshore
platforms, which, in turn, caused a decrease in gross operating margin from
these operations. See Note 21 of the Notes to Consolidated Financial
Statements included under Item 8 of this annual report for more information
regarding significant risks and uncertainties.
Regulation
Interstate
Pipelines
Liquids
Pipelines. Certain of our crude oil and NGL pipeline systems
(collectively referred to as “liquids pipelines”) are interstate common carrier
pipelines subject to regulation by the FERC under the Interstate Commerce Act
(“ICA”) and the Energy Policy Act of 1992 (“Energy Policy Act”). The
ICA prescribes that interstate tariffs must be just and reasonable and must not
be unduly discriminatory or confer any undue preference upon any shipper. FERC
regulations require that interstate oil pipeline transportation rates and terms
of service be filed with the FERC and posted publicly.
The ICA
permits interested persons to challenge proposed new or changed rates or rules
and authorizes the FERC to investigate such changes and to suspend their
effectiveness for a period of up to seven months. If, upon completion
of an investigation, the FERC finds that the new or changed rate is unlawful, it
may require the carrier to refund the revenues in excess of the prior tariff
during the term of the investigation. The FERC may also investigate,
upon complaint or on its own motion, rates and related rules that are already in
effect and may order a carrier to change them prospectively. Upon an
appropriate showing, a shipper may obtain reparations for damages sustained for
a period of up to two years prior to the filing of its complaint.
The
Energy Policy Act deems just and reasonable (i.e., deems “grandfathered”)
liquids pipeline rates that (i) were in effect for the twelve months preceding
enactment and (ii) that had not been subject to complaint, protest or
investigation. Some, but not all, of our interstate liquids pipeline
rates are considered grandfathered under the Energy Policy
Act. Certain other rates for our interstate liquids pipeline services
are charged pursuant to a FERC-approved indexing methodology, which allows a
pipeline to charge rates up to a prescribed ceiling that changes annually based
on the change from year-to-year in the Producer Price Index for finished goods
(“PPI”). A rate increase within the indexed rate ceiling is presumed
to be just and reasonable unless a protesting party can demonstrate that the
rate increase is substantially in excess of the pipeline’s
costs. Effective March 21, 2006, the FERC concluded that for the
five-year period commencing July 1, 2006, liquids pipelines charging indexed
rates may adjust their indexed ceilings annually by the PPI plus
1.3%.
As an
alternative to using the indexing methodology, interstate liquids pipelines may
elect to support rate filings by using a cost-of-service methodology,
competitive market showings (“Market-Based Rates”) or agreements with all of the
pipeline’s shippers that the rate is acceptable.
Because
of the complexity of ratemaking, the lawfulness of any rate is never
assured. Prescribed rate methodologies for approving regulated tariff
rates may limit our ability to set rates based on our actual costs or may delay
the use of rates reflecting higher costs. Changes in the FERC’s
methodology for approving rates could adversely affect us. In
addition, challenges to our tariff rates could be filed with the FERC and
decisions by the FERC in approving our regulated rates could adversely affect
our cash flow. We believe the transportation rates currently charged
by our interstate common carrier liquids pipelines are in accordance with the
ICA. However, we cannot predict the rates we will be allowed to
charge in the future for transportation services by such pipelines.
The
Lou-Tex Propylene and Sabine Propylene pipelines are interstate common carrier
pipelines regulated under the ICA by the Surface Transportation Board
(“STB”). If the STB finds that a carrier’s rates are not just and
reasonable or are unduly discriminatory or preferential, it may prescribe a
reasonable rate. In determining a reasonable rate, the STB will
consider, among other factors, the effect of the rate on the volumes transported
by that carrier, the carrier’s revenue needs and the availability of other
economic transportation alternatives.
The STB
does not need to provide rate relief unless shippers lack effective competitive
alternatives. If the STB determines that effective competitive
alternatives are not available and a pipeline holds market power, then we may be
required to show that our rates are reasonable.
Mid-America
Pipeline Company, LLC (“Mid-America”) is currently involved in a rate case
before the FERC. The case primarily involves shipper protests of rate
increases on Mid-America's Conway North pipeline filed on March 31, 2005 and
March 31, 2006. A hearing before an Administrative Law Judge began on
October 2, 2007 and culminated with an initial decision on September 3,
2008. Briefs on Exceptions were filed October 31, 2008, with Briefs
Opposing Exceptions filed on January 8, 2009. The matter is presently
pending before the FERC, with a decision expected to be issued in the second
half of 2009. We are unable to predict the outcome of this
litigation.
Natural
Gas Pipelines. Our interstate natural gas pipelines and storage
facilities that provide services in interstate commerce are regulated by the
FERC under the Natural Gas Act of 1938 (“NGA”). Under the NGA, the
rates for service on these interstate facilities must be just and reasonable and
not unduly discriminatory. We operate these interstate facilities
pursuant to tariffs which set forth rates and terms and conditions of
service. These tariffs must be filed with and approved by the FERC
pursuant to its regulations and orders. Our tariff rates may be
lowered on a prospective basis only by the FERC if it finds, on its own
initiative or as a result of challenges to the rates by third parties, that they
are unjust, unreasonable or otherwise unlawful. Unless the FERC
grants specific authority to charge market-based rates, our rates are derived
and charged based on a cost-of-service methodology.
The
FERC’s authority over companies that provide natural gas pipeline transportation
or storage services in interstate commerce also includes: (i)
certification, construction, and operation of certain new
facilities;
(ii) the acquisition, extension, disposition or abandonment of such facilities;
(iii) the maintenance of accounts and records; (iv) the initiation, extension
and termination of regulated services; and (v) various other
matters. The FERC’s rules require interstate pipelines and their
affiliates to adhere to Standards of Conduct that, among other things, require
that transmission employees function independently of marketing
employees. The Energy Policy Act of 2005 amended the NGA to add an
anti-manipulation provision. Pursuant to that act, the FERC
established rules prohibiting energy market manipulation. A violation
of these rules may subject us to civil penalties, disgorgement of unjust
profits, or appropriate non-monetary remedies imposed by the FERC. In
addition, the Energy Policy Act of 2005 amended the NGA and the Natural Gas
Policy Act of 1978 (“NGPA”) to increase civil and criminal penalties for any
violation of the NGA, NGPA and any rules, regulations or orders of the FERC up
to $1.0 million per day per violation.
Offshore
Pipelines. Our offshore natural gas gathering pipelines and
crude oil pipeline systems are subject to federal regulation under the Outer
Continental Shelf Lands Act, which requires that all pipelines operating on or
across the outer continental shelf provide nondiscriminatory transportation
service.
Intrastate
Pipelines
Liquids
Pipelines.
Certain of our pipeline systems operate within a single state and provide
intrastate pipeline transportation services. These pipeline systems
are subject to various regulations and statutes mandated by state regulatory
authorities. Although the applicable state statutes and regulations
vary, they generally require that intrastate pipelines publish tariffs setting
forth all rates, rules and regulations applying to intrastate service, and
generally require that pipeline rates and practices be reasonable and
nondiscriminatory. Shippers may also challenge our intrastate tariff
rates and practices on our pipelines. Our intrastate liquids
pipelines are subject to regulation in many states, including Alabama, Colorado,
Louisiana, Mississippi, New Mexico and Texas.
Natural
Gas Pipelines. Our intrastate natural gas pipelines are subject to
regulation in many states, including Alabama, Colorado, Louisiana, Mississippi,
New Mexico and Texas. Certain of our intrastate natural gas pipelines
are also subject to limited regulation by the FERC under the NGPA because they
provide transportation and storage service pursuant to Section 311 of the NGPA
and Part 284 of the FERC’s regulations. Under Section 311 of the
NGPA, an intrastate pipeline company may transport gas for an interstate
pipeline or any local distribution company served by an interstate pipeline
without becoming subject to the FERC’s jurisdiction under the
NGA. However, such a pipeline is required to provide these services
on an open and nondiscriminatory basis, and to make certain rate and other
filings and reports are in compliance with the FERC’s
regulations. The rates for 311 services may be established by the
FERC or the respective state agency, but such rates may not exceed a fair and
equitable rate.
In
September 2007, the FERC also approved an uncontested settlement establishing
our maximum firm and interruptible transportation rates for NGPA Section 311
service on the Enterprise Texas Pipeline. In September 2008, we
submitted to the FERC a new proposed Section 311 rate for service on our Sherman
Extension pipeline, which rate is presently under review by the
FERC. We are required to file another rate petition on or before
April 2009 to justify our current rates or establish new rates for NGPA Section
311 service. The Texas Railroad Commission has the authority to
regulate the rates and terms of service for our intrastate transportation
service in Texas.
In
September 2007, the FERC approved an uncontested settlement establishing our
maximum firm and interruptible transportation rates for NGPA Section 311 service
on the Enterprise Alabama Intrastate Pipeline. We are required to
file another rate petition on or before May 2010 to justify our current rates or
establish new rates for NGPA Section 311 service. The Alabama Public
Service Commission has the authority to regulate the rates and terms of service
for our intrastate transportation service in Alabama.
Sales
of Natural Gas
We are engaged in natural gas marketing
activities. The resale of natural gas in interstate commerce is
subject to FERC jurisdiction. However, under current federal rules the
price at which we sell
natural
gas currently is not regulated, insofar as the interstate market is concerned
and, for the most part, is not subject to state regulation. Our
affiliates that engage in natural gas marketing are considered marketing
affiliates of our interstate natural gas pipelines. The FERC’s rules
require interstate pipelines and their marketing affiliates who sell natural gas
in interstate commerce subject to the FERC’s jurisdiction to adhere to standards
of conduct that, among other things, require that their transmission and
marketing employees function independently of each other. Pursuant to
the Energy Policy Act of 2005, the FERC has established rules prohibiting energy
market manipulation. A violation of these rules may subject us to
civil penalties, disgorgement of unjust profits, suspension, loss of
authorization to perform such sales or other appropriate non-monetary remedies
imposed by the FERC.
The FERC
is continually proposing and implementing new rules and regulations affecting
segments of the natural gas industry. For example, the FERC recently
established rules requiring certain non-interstate pipelines to post daily
scheduled volume information and design capacity for certain points, and has
also required the annual reporting of gas sales information, in order to
increase transparency in natural gas markets. In November 2008, the
FERC commenced an inquiry into whether to expand the contract reporting
requirements of Section 311 service providers. We cannot predict the
ultimate impact of these regulatory changes on our natural gas marketing
activities; however, we believe that any new regulations will also be applied to
other natural gas marketers with whom we compete.
Environmental
and Safety Matters
General
Our
operations are subject to multiple environmental obligations and potential
liabilities under a variety of federal, state and local laws and regulations.
These include, without limitation: the Comprehensive Environmental
Response, Compensation, and Liability Act; the Resource Conservation and
Recovery Act; the Clean Air Act; the Federal Water Pollution Control Act or the
Clean Water Act; the Oil Pollution Act; and analogous state and local laws and
regulations. Such laws and regulations affect many aspects of our present
and future operations, and generally require us to obtain and comply with a wide
variety of environmental registrations, licenses, permits, inspections and other
approvals, with respect to air emissions, water quality, wastewater discharges
and solid and hazardous waste management. Failure to comply with these
requirements may expose us to fines, penalties and/or interruptions in our
operations that could influence our financial position, results of
operations and cash flows. If an accidental leak, spill or release of
hazardous substances occurs at a facility that we own, operate or otherwise use,
or where we send materials for treatment or disposal, we could be held jointly
and severally liable for all resulting liabilities, including investigation,
remedial and clean-up costs. Likewise, we could be required to remove or
remediate previously disposed wastes or property contamination, including
groundwater contamination. Any or all of this could materially affect our
financial position, results of operations and cash flows.
We
believe our operations are in material compliance with applicable environmental
and safety laws and regulations, other than certain matters discussed under Item
3 of this annual report, and that compliance with existing environmental and
safety laws and regulations are not expected to have a material adverse effect
on our financial position, results of operations and cash
flows. Environmental and safety laws and regulations are subject to
change. The clear trend in environmental regulation is to place more
restrictions and limitations on activities that may be perceived to affect the
environment, and thus there can be no assurance as to the amount or timing of
future expenditures for environmental regulation compliance or remediation, and
actual future expenditures may be different from the amounts we currently
anticipate. Revised or additional regulations that result in increased
compliance costs or additional operating restrictions, particularly if those
costs are not fully recoverable from our customers, could have a material
adverse effect on our business, financial position, results of operations and
cash flows.
Water
The Federal Water Pollution Control Act
of 1972, as renamed and amended as the Clean Water Act (“CWA”), and analogous
state laws impose restrictions and strict controls regarding the discharge of
pollutants into navigable waters of the United States, as well as state
waters. Permits must be obtained to
discharge
pollutants into these waters. The CWA imposes substantial civil and
criminal penalties for non-compliance. The Environmental Protection
Agency (“EPA”) has promulgated regulations that require us to have permits in
order to discharge storm water runoff. The EPA has entered into
agreements with states in which we operate whereby the permits are administered
by the respective states.
The
primary federal law for oil spill liability is the Oil Pollution Act of 1990
(“OPA”), which addresses three principal areas of oil pollution - prevention,
containment and cleanup, and liability. The OPA subjects owners of
certain facilities to strict, joint and potentially unlimited liability for
containment and removal costs, natural resource damages and certain other
consequences of an oil spill, where such spill affects navigable waters, along
shorelines or in the exclusive economic zone of the United
States. Any unpermitted release of petroleum or other pollutants from
our operations could also result in fines or penalties. The OPA
applies to vessels, offshore platforms and onshore facilities, including
terminals, pipelines and transfer facilities. In order to handle,
store or transport oil, shore facilities are required to file oil spill response
plans with the United States Coast Guard, the United States Department of
Transportation Office of Pipeline Safety (“OPS”) or the EPA, as
appropriate.
Some states maintain groundwater
protection programs that require permits for discharges or commercial operations
that may impact groundwater conditions. Groundwater contamination
resulting from spills or releases of petroleum products is an inherent risk
within the midstream energy industry. To the extent that groundwater
contamination requiring remediation exists along our pipeline systems as a
result of past operations, we believe any such contamination could be controlled
or remedied without having a material adverse effect on our financial position,
results of operations and cash flows, but such costs are site specific and we
cannot predict that the effect will not be material in the
aggregate.
Air
Emissions
Our operations are subject to the
Federal Clean Air Act (the “Clean Air Act”) and comparable state laws and
regulations. These laws and regulations regulate emissions of air
pollutants from various industrial sources, including our facilities, and also
impose various monitoring and reporting requirements. Such laws and regulations
may require that we obtain pre-approval for the construction or modification of
certain projects or facilities expected to produce air emissions or result in
the increase of existing air emissions, obtain and strictly comply with air
permits containing various emissions and operational limitations, or utilize
specific emission control technologies to limit emissions.
Our
permits and related compliance obligations under the Clean Air Act, as well as
recent or soon to be adopted changes to state implementation plans for
controlling air emissions in regional, non-attainment areas, may require our
operations to incur capital expenditures to add to or modify existing air
emission control equipment and strategies. In addition, some of our
facilities are included within the categories of hazardous air pollutant
sources, which are subject to increasing regulation under the Clean Air Act and
many state laws. Our failure to comply with these requirements could
subject us to monetary penalties, injunctions, conditions or restrictions on
operations and enforcement actions. We may be required to incur certain
capital expenditures in the future for air pollution control equipment in
connection with obtaining and maintaining operating permits and approvals for
air emissions. We believe, however, that such requirements will not have a
material adverse effect on our operations, and the requirements are not expected
to be any more burdensome to us than to any other similarly situated
companies.
Some
recent scientific studies have suggested that emissions of certain gases,
commonly referred to as “greenhouse gases” and including carbon dioxide and
methane, may be contributing to the warming of the Earth’s atmosphere. In
response to such studies, the U.S. Congress is considering legislation to reduce
emissions of greenhouse gases. In addition, at least 17 states have
declined to wait on Congress to develop and implement climate control
legislation and have already taken legal measures to reduce emissions of
greenhouse gases. Also, as a result of the U.S. Supreme Court’s decision
on April 2, 2007 in Massachusetts, et al. v. EPA,
the EPA must consider whether it is required to regulate greenhouse gas
emissions from mobile sources (e.g., cars and trucks) even if Congress does not
adopt new legislation specifically addressing emissions of greenhouse
gases. The Supreme Court’s position in the Massachusetts case that
greenhouse gases fall under the federal Clean Air Act’s definition of “air
pollutant” may also
result in
future regulation of greenhouse gas emissions from stationary sources under
various Clean Air Act programs, including those that may be used in our
operations. It is not possible at this time to predict how legislation
that may be enacted to address greenhouse gas emissions would impact our
business. However, future laws and regulations could result in increased
compliance costs or additional operating restrictions, and could have a material
adverse effect on our business, financial position, demand for our operations,
results of operations, and cash flows.
Solid
Waste
In our normal operations, we generate
hazardous and non-hazardous solid wastes, including hazardous substances, that
are subject to the requirements of the federal Resource Conservation and
Recovery Act (“RCRA”) and comparable state laws, which impose detailed
requirements for the handling, storage treatment and disposal of hazardous and
solid waste. We also utilize waste minimization and recycling processes to
reduce the volumes of our waste. Amendments to RCRA required the EPA
to promulgate regulations banning the land disposal of all hazardous wastes
unless the waste meets certain treatment standards or the land-disposal method
meets certain waste containment criteria. In the past, although we
utilized operating and disposal practices that were standard in the industry at
the time, hydrocarbons and other materials may have been disposed of or
released. In the future we may be required to remove or remediate
these materials.
Environmental
Remediation
The Comprehensive Environmental
Response, Compensation and Liability Act (“CERCLA”), also known as “Superfund,”
imposes liability, without regard to fault or the legality of the original act,
on certain classes of persons who contributed to the release of a “hazardous
substance” into the environment. These persons include the owner or operator of
a facility where a release occurred, transporters that select the site of
disposal of hazardous substances and companies that disposed of or arranged for
the disposal of any hazardous substances found at a facility. Under CERCLA,
these persons may be subject to joint and several liability for the costs of
cleaning up the hazardous substances that have been released into the
environment, for damages to natural resources and for the costs of certain
health studies. CERCLA also authorizes the EPA and, in some
instances, third parties to take actions in response to threats to the public
health or the environment and to seek to recover the costs they incur from the
responsible classes of persons. It is not uncommon for neighboring
landowners and other third parties to file claims for personal injury and
property damage allegedly caused by hazardous substances or other pollutants
released into the environment. Despite the “petroleum exclusion” of
CERCLA that currently encompasses natural gas, we may nonetheless handle
“hazardous substances” subject to CERCLA in the course of our operations and our
pipeline systems may generate wastes that fall within CERCLA’s definition of a
“hazardous substance.” In the event a disposal facility previously
used by us requires clean up in the future, we may be responsible under CERCLA
for all or part of the costs required to clean up sites at which such wastes
have been disposed.
Pipeline
Safety Matters
We are subject to regulation by the
United States Department of Transportation (“DOT”) under the Accountable
Pipeline and Safety Partnership Act of 1996, sometimes referred to as the
Hazardous Liquid Pipeline Safety Act (“HLPSA”), and comparable state statutes
relating to the design, installation, testing, construction, operation,
replacement and management of our pipeline facilities. The HLPSA covers
petroleum and petroleum products. The HLPSA requires any entity that
owns or operates pipeline facilities to (i) comply with such regulations, (ii)
permit access to and copying of records, (iii) file certain reports and (iv)
provide information as required by the Secretary of
Transportation. We believe that we are in material compliance with
these HLPSA regulations.
We are also subject to the DOT
regulation requiring qualification of pipeline personnel. The
regulation requires pipeline operators to develop and maintain a written
qualification program for individuals performing covered tasks on pipeline
facilities. The intent of this regulation is to ensure a qualified
work force and to reduce the probability and consequence of incidents caused by
human error.
The
regulation establishes qualification requirements for individuals performing
covered tasks. We believe that we are in material compliance with
these DOT regulations.
In addition, we are subject to the DOT
Integrity Management regulations, which specify how companies should assess,
evaluate, validate and maintain the integrity of pipeline segments that, in the
event of a release, could impact High Consequence Areas
(“HCAs”). HCAs are defined to include populated areas, unusually
sensitive environmental areas and commercially navigable
waterways. The regulation requires the development and implementation
of an Integrity Management Program that utilizes internal pipeline inspection,
pressure testing, or other equally effective means to assess the integrity of
HCA pipeline segments. The regulation also requires periodic review
of HCA pipeline segments to ensure that adequate preventative and mitigative
measures exist and that companies take prompt action to address integrity issues
raised by the assessment and analysis. We have identified our HCA
pipeline segments and developed an appropriate Integrity Management
Program.
Risk
Management Plans
We are
subject to the EPA’s Risk Management Plan regulations at certain
facilities. These regulations are intended to work with the
Occupational Safety and Health Act (“OSHA”) Process Safety Management
regulations (see “Safety Matters” below) to minimize the offsite consequences of
catastrophic releases. The regulations required us to develop and
implement a risk management program that includes a five-year accident history,
an offsite consequence analysis process, a prevention program and an emergency
response program. We believe we are operating in material compliance
with our risk management program.
Safety
Matters
Certain of our facilities are also
subject to the requirements of the federal OSHA and comparable state
statutes. We believe we are in material compliance with OSHA and
state requirements, including general industry standards, record keeping
requirements and monitoring of occupational exposures.
We are subject to OSHA Process Safety
Management (“PSM”) regulations, which are designed to prevent or minimize the
consequences of catastrophic releases of toxic, reactive, flammable or explosive
chemicals. These regulations apply to any process which involves a
chemical at or above the specified thresholds or any process which involves
certain flammable liquid or gas. We believe we are in material
compliance with the OSHA PSM regulations.
The OSHA hazard communication standard,
the EPA community right-to-know regulations under Title III of the federal
Superfund Amendment and Reauthorization Act and comparable state statutes
require us to organize and disclose information about the hazardous materials
used in our operations. Certain parts of this information must be
reported to employees, state and local governmental authorities and local
citizens upon request.
Employees
Like many publicly traded partnerships,
we have no employees. All of our management, administrative and
operating functions are performed by employees of EPCO pursuant to an
administrative services agreement (the “ASA”). For additional
information regarding the ASA, see “EPCO Administrative Services Agreement”
under Item 13 of this annual report. As of December 31, 2008, there
were approximately 3,500 EPCO personnel who spend all or a portion of their time
engaged in our business. Approximately 2,100 of these individuals
devote all of their time performing management and operating duties for
us. The remaining approximate 1,400 personnel are part of EPCO’s
shared service organization and spend a portion of their time engaged in our
business.
Available
Information
As a
large accelerated filer, we electronically file certain documents with the U.S.
Securities and Exchange Commission (“SEC”). We file annual reports on
Form 10-K; quarterly reports on Form 10-Q; and current reports on Form 8-K (as
appropriate); along with any related amendments and supplements
thereto. Occasionally, we may also file registration statements and
related documents in connection with equity or debt offerings. You
may read and copy any materials we file with the SEC at the SEC’s Public
Reference Room at 100 F Street, NE, Washington, DC 20549. You
may obtain information regarding the Public Reference Room by calling the SEC at
(800) SEC-0330. In addition, the SEC maintains an Internet website at
www.sec.gov
that contains reports and other information regarding registrants that file
electronically with the SEC, including us.
We provide electronic access to our
periodic and current reports on our Internet website, www.epplp.com. These
reports are available as soon as reasonably practicable after we electronically
file such materials with, or furnish such materials to, the SEC. You
may also contact our investor relations department at (866) 230-0745 for paper
copies of these reports free of charge.
An
investment in our common units involves certain risks. If any of
these risks were to occur, our business, financial position, results of
operations and cash flows could be materially adversely affected. In
that case, the trading price of our common units could decline and you could
lose part or all of your investment.
The
following section lists some, but not all, of the key risk factors that may have
a direct impact on our business, financial position, results of operations and
cash flows.
Risks
Relating to Our Business
Changes
in demand for and production of hydrocarbon products may materially adversely
affect our financial position, results of operations and cash
flows.
We operate predominantly in the
midstream energy sector which includes gathering, transporting, processing,
fractionating and storing natural gas, NGLs and crude oil. As such,
our financial position, results of operations and cash flows may be materially
adversely affected by changes in the prices of these hydrocarbon products and by
changes in the relative price levels among these hydrocarbon
products. Changes in prices and relative price levels may impact
demand for hydrocarbon products, which in turn may impact production, demand and
volumes of product for which we provide services. We may also incur credit and
price risk to the extent counterparties do not perform in connection with our
marketing of natural gas, NGLs and propylene.
In the
past, the price of natural gas has been extremely volatile, and we expect this
volatility to continue. The New York Mercantile Exchange daily
settlement price for natural gas for the prompt month contract in 2006 ranged
from a high of $10.63 per MMBtu to a low of $4.20 per
MMBtu. In 2007, the same index ranged from a high of $8.64 per MMBtu
to a low of $5.38 per MMBtu. In 2008, the same index ranged from a
high of $13.58 per MMBtu to a low of $5.29 per MMBtu.
Generally, the prices of natural gas,
NGLs, crude oil and other hydrocarbon products are subject to fluctuations in
response to changes in supply, demand, market uncertainty and a variety of
additional factors that are impossible to control. Some of these
factors include:
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the
level of domestic production and consumer product
demand;
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the
availability of imported oil and natural
gas;
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actions
taken by foreign oil and natural gas producing
nations;
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the
availability of transportation systems with adequate
capacity;
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the
availability of competitive fuels;
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fluctuating
and seasonal demand for oil, natural gas and
NGLs;
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the
impact of conservation efforts;
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the
extent of governmental regulation and taxation of production;
and
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the
overall economic environment.
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We are exposed to natural gas and NGL
commodity price risk under certain of our natural gas processing and gathering
and NGL fractionation contracts that provide for our fees to be calculated based
on a regional natural gas or NGL price index or to be paid in-kind by taking
title to natural gas or NGLs. A decrease in natural gas and NGL
prices can result in lower margins from these contracts, which may materially
adversely affect our financial position, results of operations and cash
flows.
Our
operating results in one or more geographic regions may also be affected by
uncertain or changing economic conditions within that region, such as the
challenges that are currently affecting economic conditions in the United
States. Volatility in commodity prices may also have an impact on
many of our customers, which in turn could have a negative impact on their
ability to meet their obligations to us.
A
decline in the volume of natural gas, NGLs and crude oil delivered to our
facilities could adversely affect our financial position, results of operations
and cash flows.
Our profitability could be materially
impacted by a decline in the volume of natural gas, NGLs and crude oil
transported, gathered or processed at our facilities. A material
decrease in natural gas or crude oil production or crude oil refining, as a
result of depressed commodity prices, a decrease in domestic and international
exploration and development activities or otherwise, could result in a decline
in the volume of natural gas, NGLs and crude oil handled by our
facilities.
The crude oil, natural gas and NGLs
currently transported, gathered or processed at our facilities originate from
existing domestic and international resource basins, which naturally deplete
over time. To offset this natural decline, our facilities will need
access to production from newly discovered properties that are either being
developed or expected to be developed. Exploration and development of new
oil and natural gas reserves is capital intensive, particularly offshore in the
Gulf of Mexico. Many economic and business factors are beyond our
control and can adversely affect the decision by producers to explore for and
develop new reserves. These factors could include relatively low oil
and natural gas prices, cost and availability of equipment and labor, regulatory
changes, capital budget limitations, the lack of available capital or the
probability of success in finding hydrocarbons. For example, a
sustained decline in the price of natural gas and crude oil could result in a
decrease in natural gas and crude oil exploration and development activities in
the regions where our facilities are located. This could result in a
decrease in volumes to our offshore platforms, natural gas processing plants,
natural gas, crude oil and NGL pipelines, and NGL fractionators, which would
have a material adverse affect on our financial position, results of operations
and cash flows. Additional reserves, if discovered, may not be
developed in the near future or at all.
In addition, imported liquefied natural
gas (“LNG”), is expected to be a significant component of future natural gas
supply to the United States. Much of this increase in LNG supplies is
expected to be imported through new LNG facilities to be developed over the next
decade. Twelve LNG projects have been approved by the FERC to be
constructed in the Gulf Coast region and an additional two LNG projects
have been proposed for the region. We cannot predict which, if any,
of these new projects will be
constructed. We
may not realize expected increases in future natural gas supply available to our
facilities and pipelines if (i) a significant number of these new projects fail
to be developed with their announced capacity, (ii) there are significant delays
in such development, (iii) they are built in locations where they are not
connected to our assets or (iv) they do not influence sources of supply on our
systems. If the expected increase in natural gas supply through
imported LNG is not realized, projected natural gas throughput on our pipelines
would decline, which could have a material adverse effect on our financial
position, results of operations and cash flows.
A
decrease in demand for NGL products by the petrochemical, refining or heating
industries could materially adversely affect our financial position,
results of operations and cash flows.
A decrease in demand for NGL products
by the petrochemical, refining or heating industries, whether because of general
economic conditions, reduced demand by consumers for the end products made with
NGL products, increased competition from petroleum-based products due to pricing
differences, adverse weather conditions, government regulations affecting prices
and production levels of natural gas or the content of motor gasoline or other
reasons, could materially adversely affect our financial position, results of
operations and cash flows. For example:
Ethane. Ethane is primarily
used in the petrochemical industry as feedstock for ethylene, one of the basic
building blocks for a wide range of plastics and other chemical
products. If natural gas prices increase significantly in relation to
NGL product prices or if the demand for ethylene falls (and, therefore, the
demand for ethane by NGL producers falls), it may be more profitable for natural
gas producers to leave the ethane in the natural gas stream to be burned as fuel
than to extract the ethane from the mixed NGL stream for sale as an ethylene
feedstock.
Propane. The demand for propane as a
heating fuel is significantly affected by weather
conditions. Unusually warm winters could cause the demand for propane
to decline significantly and could cause a significant decline in the volumes of
propane that we transport.
Isobutane. A reduction in demand for
motor gasoline additives may reduce demand for isobutane. During
periods in which the difference in market prices between isobutane and normal
butane is low or inventory values are high relative to current prices for normal
butane or isobutane, our operating margin from selling isobutane could be
reduced.
Propylene. Propylene is sold to
petrochemical companies for a variety of uses, principally for the production of
polypropylene. Propylene is subject to rapid and material price
fluctuations. Any downturn in the domestic or international economy
could cause reduced demand for, and an oversupply of propylene, which could
cause a reduction in the volumes of propylene that we transport.
We
face competition from third parties in our midstream businesses
Even if
crude oil and natural gas reserves exist in the areas accessed by our
facilities and are ultimately produced, we may not be chosen by the producers in
these areas to gather, transport, process, fractionate, store or otherwise
handle the hydrocarbons that are produced. We compete with others,
including producers of oil and natural gas, for any such production on the basis
of many factors, including but not limited to:
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geographic
proximity to the production;
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Our
future debt level may limit our flexibility to obtain additional financing and
pursue other business opportunities.
As of
December 31, 2008, we had approximately $9.05 billion of consolidated debt
outstanding including Duncan Energy Partners, which had approximately
$484.3 million of consolidated debt outstanding. The amount of our
future debt could have significant effects on our operations, including, among
other things:
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a
substantial portion of our cash flow, including that of Duncan Energy
Partners, could be dedicated to the payment of principal and interest on
our future debt and may not be available for other purposes, including the
payment of distributions on our common units and capital
expenditures;
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credit
rating agencies may view our debt level
negatively;
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covenants
contained in our existing and future credit and debt arrangements will
require us to continue to meet financial tests that may adversely affect
our flexibility in planning for and reacting to changes in our business,
including possible acquisition
opportunities;
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our
ability to obtain additional financing, if necessary, for working capital,
capital expenditures, acquisitions or other purposes may be impaired or
such financing may not be available on favorable
terms;
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we
may be at a competitive disadvantage relative to similar companies that
have less debt; and
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we
may be more vulnerable to adverse economic and industry conditions as a
result of our significant debt
level.
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Our public debt indentures currently do
not limit the amount of future indebtedness that we can create, incur, assume or
guarantee. Although EPO’s Multi-Year Revolving Credit Facility
restricts our ability to incur additional debt above certain levels, any debt we
may incur in compliance with these restrictions may still be
substantial. For information regarding EPO’s Multi-Year Revolving
Credit Facility, see Note 14 of the Notes to Consolidated Financial
Statements included under Item 8 of this annual report.
EPO’s Multi-Year Revolving Credit
Facility, its Japanese Yen Term Loan and each of its indentures for public debt
contain conventional financial covenants and other restrictions. For
example, we are prohibited from making distributions to our partners if such
distributions would cause an event of default or otherwise violate a covenant
under EPO’s Multi-Year Revolving Credit Facility. In addition, under
the terms of our junior subordinated notes, generally, if we elect to defer
interest payments thereon, we are restricted from making distributions with
respect to our equity securities. A breach of any of these
restrictions by us could permit our lenders or noteholders, as applicable, to
declare all amounts outstanding under these debt agreements to be immediately
due and payable and, in the case of EPO’s Multi-Year Revolving Credit Facility,
to terminate all commitments to extend further credit.
Our
ability to access capital markets to raise capital on favorable terms could be
affected by our debt level, the amount of our debt maturing in the next several
years and current maturities, and by prevailing market
conditions. Moreover, if the rating agencies were to downgrade our
credit ratings, then we could experience an increase in our borrowing costs,
difficulty assessing capital markets or a reduction in the market price of our
common units. Such a development could adversely affect our ability
to obtain financing for working capital, capital expenditures or acquisitions or
to refinance existing indebtedness. If we are unable to access the
capital markets on favorable terms in the future, we might be forced to seek
extensions for some of our short-term securities or to refinance some of our
debt obligations through bank credit, as opposed to long-term public debt
securities or equity securities. The price and terms upon which we
might receive such extensions or additional bank credit, if at all, could be
more onerous than those contained in existing debt agreements. Any
such arrangements could, in turn, increase the risk that our
leverage
may adversely affect our future financial and operating flexibility and thereby
impact our ability to pay cash distributions at expected levels.
We
may not be able to fully execute our growth strategy if we encounter illiquid
capital markets or increased competition for investment
opportunities.
Our strategy contemplates growth
through the development and acquisition of a wide range of midstream and other
energy infrastructure assets while maintaining a strong balance
sheet. This strategy includes constructing and acquiring additional
assets and businesses to enhance our ability to compete effectively and
diversifying our asset portfolio, thereby providing more stable cash
flow. We regularly consider and enter into discussions regarding, and
are currently contemplating and/or pursuing, potential joint ventures, stand
alone projects or other transactions that we believe will present opportunities
to realize synergies, expand our role in the energy infrastructure business and
increase our market position.
We will require substantial new capital
to finance the future development and acquisition of assets and
businesses. Any limitations on our access to capital will impair our
ability to execute this strategy. If the cost of such capital becomes
too expensive, our ability to develop or acquire accretive assets will be
limited. We may not be able to raise the necessary funds on
satisfactory terms, if at all. The primary factors that influence our
initial cost of equity include market conditions, fees we pay to underwriters
and other offering costs, which include amounts we pay for legal and accounting
services. The primary factors influencing our cost of borrowing
include interest rates, credit spreads, covenants, underwriting or loan
origination fees and similar charges we pay to lenders.
Recent
conditions in the financial markets have limited our ability to access equity
and credit markets. Generally, credit has become more expensive and
difficult to obtain, and the cost of equity capital has also become more
expensive. Some lenders are imposing more stringent credit terms and
there may be a general reduction in the amount of credit available in the
markets in which we conduct business. Tightening of the credit
markets may have a material adverse effect on us by, among other things,
decreasing our ability to finance expansion projects or business acquisitions on
favorable terms and by the imposition of increasingly restrictive borrowing
covenants. In addition, the distribution yields of new equity issued
may be at a higher yield than our historical levels, making additional equity
issuances more expensive.
We also
compete for the types of assets and businesses we have historically purchased or
acquired. Increased competition for a limited pool of assets could
result in our losing to other bidders more often or acquiring assets at less
attractive prices. Either occurrence would limit our ability to fully
execute our growth strategy. Our inability to execute our growth
strategy may materially adversely affect our ability to maintain or pay higher
distributions in the future.
Our
variable rate debt and future maturities of fixed-rate, long-term debt make us
vulnerable to increases in interest rates. Increases in interest
rates could materially adversely affect our business, financial position,
results of operation and cash flows.
As of December 31, 2008, we had
outstanding $9.05 billion of consolidated debt (excluding the value of interest
rate swaps and currency swaps). Of this amount, approximately $1.57
billion, or 17.3%, was subject to variable interest rates, either as short-term
or long-term variable rate debt obligations or as long-term fixed-rate debt
converted to variable rates through the use of interest rate
swaps. We have approximately $217.6 million in 4.93% fixed-rate debt
maturing in March 2009. We also have an additional $500.0 million of
4.625% fixed-rate Senior Notes maturing in October 2009, $54.0 million of 8.70%
fixed-rate debt maturing in March 2010, and $500.0 million of 4.95% fixed-rate
Senior Notes maturing in June 2010. The rate on our December 2008
issuance of $500.0 million of Senior Notes due January 2014 was
9.75%. Should interest rates continue at current levels or increase
significantly, the amount of cash required to service our debt would
increase. As a result, our financial position, results of operations
and cash flows, could be materially adversely affected.
An increase in interest rates may also
cause a corresponding decline in demand for equity investments, in general, and
in particular, for yield-based equity investments such as our common
units. Any such reduction in demand for our common units resulting
from other more attractive investment opportunities may cause the trading price
of our common units to decline.
Operating
cash flows from our capital projects may not be immediate.
We have announced and are engaged in
several construction projects involving existing and new facilities for which we
have expended or will expend significant capital, and our operating cash flow
from a particular project may not increase until a period of time after its
completion. For instance, if we build a new pipeline or platform or
expand an existing facility, the design, construction, development and
installation may occur over an extended period of time, and we may not receive
any material increase in operating cash flow from that project until a period of
time after it is placed in-service. If we experience any
unanticipated or extended delays in generating operating cash flow from these
projects, we may be required to reduce or reprioritize our capital budget, sell
non-core assets, access the capital markets or decrease or limit distributions
to unitholders in order to meet our capital requirements.
Our
growth strategy may adversely affect our results of operations if we do not
successfully integrate the businesses that we acquire or if we substantially
increase our indebtedness and contingent liabilities to make
acquisitions.
Our growth strategy includes making
accretive acquisitions. As a result, from time to time, we will evaluate
and acquire assets and businesses (either ourselves or Duncan Energy Partners
may do so) that we believe complement our existing operations. We may be
unable to integrate successfully businesses we acquire in the future. We
may incur substantial expenses or encounter delays or other problems in
connection with our growth strategy that could negatively impact our financial
position, results of operations and cash flows.
Moreover, acquisitions and business
expansions involve numerous risks, including but not limited to:
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difficulties
in the assimilation of the operations, technologies, services and products
of the acquired companies or business
segments;
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establishing
the internal controls and procedures that we are required to maintain
under the Sarbanes-Oxley Act of
2002;
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managing
relationships with new joint venture partners with whom we have not
previously partnered;
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inefficiencies
and complexities that can arise because of unfamiliarity with new assets
and the businesses associated with them, including with their
markets; and
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diversion
of the attention of management and other personnel from day-to-day
business to the development or acquisition of new businesses and other
business opportunities.
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If consummated, any acquisition or
investment would also likely result in the incurrence of indebtedness and
contingent liabilities and an increase in interest expense and depreciation,
accretion and amortization expenses. As a result, our capitalization and
results of operations may change significantly following an acquisition. A
substantial increase in our indebtedness and contingent liabilities could have a
material adverse effect on our financial position, results of operations and
cash flows. In addition, any anticipated benefits of a material
acquisition, such as expected cost savings, may not be fully realized, if at
all.
Acquisitions that
appear to be accretive may nevertheless reduce our cash from operations on a per
unit basis.
Even if
we make acquisitions that we believe will be accretive, these acquisitions may
nevertheless reduce our cash from operations on a per unit basis. Any
acquisition involves potential risks, including, among other
things:
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mistaken
assumptions about volumes, revenues and costs, including
synergies;
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an
inability to integrate successfully the businesses we
acquire;
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decrease
in our liquidity as a result of our using a significant portion of our
available cash or borrowing capacity to finance the
acquisition;
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a
significant increase in our interest expense or financial leverage if we
incur additional debt to finance the
acquisition;
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the
assumption of unknown liabilities for which we are not indemnified or for
which our indemnity is inadequate;
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an
inability to hire, train or retain qualified personnel to manage and
operate our growing business and
assets;
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limitations
on rights to indemnity from the
seller;
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mistaken
assumptions about the overall costs of equity or
debt;
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the
diversion of management’s and employees’ attention from other business
concerns;
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unforeseen
difficulties operating in new product areas or new geographic
areas; and
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customer
or key employee losses at the acquired
businesses.
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If we consummate any future
acquisitions, our capitalization and results of operations may change
significantly, and you will not have the opportunity to evaluate the economic,
financial and other relevant information that we will consider in determining
the application of these funds and other resources.
Our
actual construction, development and acquisition costs could exceed forecasted
amounts.
We have significant expenditures for
the development and construction of midstream energy infrastructure assets,
including construction and development projects with significant logistical,
technological and staffing challenges. We may not be able to complete our
projects at the costs we estimated at the time of each project’s initiation or
that we currently estimate. For example, material and labor costs
associated with our projects in the Rocky Mountains region increased over time
due to factors such as higher transportation costs and the availability of
construction personnel. Similarly, force majeure events such as hurricanes
along the Gulf Coast may cause delays, shortages of skilled labor and
additional expenses for these construction and development projects, as were
experienced with Hurricanes Gustav and Ike in 2008.
Our construction
of new assets is subject to regulatory, environmental, political, legal and
economic risks, which may result in delays, increased costs or decreased cash
flows.
One of the ways we intend to grow our
business is through the construction of new midstream energy
assets. The construction of new assets involves numerous operational,
regulatory, environmental, political and legal risks beyond our control and may
require the expenditure of significant amounts of capital. These
potential risks include, among other things, the following:
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we
may be unable to complete construction projects on schedule or at the
budgeted cost due to the unavailability of required construction personnel
or materials, accidents, weather conditions or an inability to obtain
necessary permits;
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we
will not receive any material increases in revenues until the project is
completed, even though we may have expended considerable funds during the
construction phase, which may be
prolonged;
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we
may construct facilities to capture anticipated future growth in
production in a region in which such growth does not
materialize;
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since
we are not engaged in the exploration for and development of natural gas
reserves, we may not have access to third-party estimates of reserves in
an area prior to our constructing facilities in the area. As a result, we
may construct facilities in an area where the reserves are materially
lower than we anticipate;
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where
we do rely on third-party estimates of reserves in making a decision to
construct facilities, these estimates may prove to be inaccurate because
there are numerous uncertainties inherent in estimating
reserves; and
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we
may be unable to obtain rights-of-way to construct additional pipelines or
the cost to do so may be
uneconomical.
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A
materialization of any of these risks could adversely affect our ability to
achieve growth in the level of our cash flows or realize benefits from expansion
opportunities or construction projects.
Substantially
all of the common units in us that are owned by EPCO and its affiliates are
pledged as security under EPCO's credit facility. Additionally, all
of the member interests in our general partner and all of the common units in us
that are owned by Enterprise GP Holdings are pledged under its credit
facility. Upon an event of default under either of these credit
facilities, a change in ownership or control of us could ultimately
result.
An affiliate of EPCO has pledged
substantially all of its common units in us as security under its credit
facility. EPCO’s credit facility contains customary and other events
of default relating to defaults of EPCO and certain of its subsidiaries,
including certain defaults by us and other affiliates of EPCO. An
event of default, followed by a foreclosure on EPCO’s pledged collateral, could
ultimately result in a change in ownership of us. In addition, the
100.0% membership interest in our general partner and the 13,670,925 of our
common units that are owned by Enterprise GP Holdings are pledged under
Enterprise GP Holdings’ credit facility. Enterprise GP Holdings’
credit facility contains customary and other events of default. Upon
an event of default, the lenders under Enterprise GP Holdings’ credit facility
could foreclose on Enterprise GP Holdings’ assets, which could ultimately result
in a change in control of our general partner and a change in the ownership of
our units held by Enterprise GP Holdings.
The
credit and risk profile of our general partner and its owners could adversely
affect our credit ratings and profile.
The credit and business risk profiles
of the general partner or owners of a general partner may be factors in credit
evaluations of a master limited partnership. This is because the
general partner can exercise significant influence over the business activities
of the partnership, including its cash distribution and acquisition strategy and
business risk profile. Another factor that may be considered is the
financial condition of the general partner and its owners, including the degree
of their financial leverage and their dependence on cash flow from the
partnership to service their indebtedness.
Entities controlling the owner of our
general partner have significant indebtedness outstanding and are dependent
principally on the cash distributions from their limited partner equity
interests in us,
Enterprise
GP Holdings and TEPPCO to service such indebtedness. Any
distributions by us, Enterprise GP Holdings and TEPPCO to such entities will be
made only after satisfying our then current obligations to
creditors. Although we have taken certain steps in our organizational
structure, financial reporting and contractual relationships to reflect the
separateness of us and our general partner from the entities that control our
general partner, our credit ratings and business risk profile could be adversely
affected if the ratings and risk profiles of EPCO or the entities that control
our general partner were viewed as substantially lower or more risky than
ours.
The
interruption of distributions to us from our subsidiaries and joint ventures may
affect our ability to satisfy our obligations and to make distributions to
our partners.
We are a holding company with no
business operations and our operating subsidiaries conduct all of our operations
and own all of our operating assets. Our only significant assets are
the ownership interests we own in our subsidiaries and joint
ventures. As a result, we depend upon the earnings and cash flow of
our subsidiaries and joint ventures and the distribution of that cash to us in
order to meet our obligations and to allow us to make distributions to our
partners. The ability of our subsidiaries and joint ventures to make
distributions to us may be restricted by, among other things, the provisions of
existing and future indebtedness, applicable state partnership and limited
liability company laws and other laws and regulations, including FERC policies.
For example, all cash flows from Evangeline are currently used to service its
debt.
As of December 31, 2008, we also owned
5,393,100 common units and 37,333,887 Class B units of Duncan Energy Partners
(these Class B units automatically converted to common units of Duncan Energy
Partners on February 1, 2009), representing approximately 74.1% of its
outstanding limited partner units, and owned minority equity interests in
subsidiaries of Duncan Energy Partners that held total assets of approximately
$4.6 billion as of December 31, 2008. With respect to three
subsidiaries of Duncan Energy Partners acquired from us on December 8, 2008 that
held approximately $3.5 billion of total assets as of December 31, 2008,
Duncan Energy Partners has effective priority rights to specified quarterly
distribution amounts ahead of distributions on our retained equity interests in
these subsidiaries.
In
addition, the charter documents governing our joint ventures typically allow
their respective joint venture management committees sole discretion regarding
the occurrence and amount of distributions. Some of the joint
ventures in which we participate have separate credit agreements that contain
various restrictive covenants. Among other things, those covenants
may limit or restrict the joint venture's ability to make distributions to us
under certain circumstances. Accordingly, our joint ventures may be
unable to make distributions to us at current levels if at all.
We
may be unable to cause our joint ventures to take or not to take certain actions
unless some or all of our joint venture participants agree.
We participate in several joint
ventures. Due to the nature of some of these arrangements, each
participant in these joint ventures has made substantial investments in the
joint venture and, accordingly, has required that the relevant charter documents
contain certain features designed to provide each participant with the
opportunity to participate in the management of the joint venture and to protect
its investment, as well as any other assets which may be substantially dependent
on or otherwise affected by the activities of that joint
venture. These participation and protective features customarily
include a corporate governance structure that requires at least a
majority-in-interest vote to authorize many basic activities and requires a
greater voting interest (sometimes up to 100.0%) to authorize more significant
activities. Examples of these more significant activities are large
expenditures or contractual commitments, the construction or acquisition of
assets, borrowing money or otherwise raising capital, transactions with
affiliates of a joint venture participant, litigation and transactions not in
the ordinary course of business, among others. Thus, without the
concurrence of joint venture participants with enough voting interests, we may
be unable to cause any of our joint ventures to take or not to take certain
actions, even though those actions may be in the best interest of us or the
particular joint venture.
Moreover, any joint venture owner may
sell, transfer or otherwise modify its ownership interest in a joint venture,
whether in a transaction involving third parties or the other joint venture
owners. Any such transaction could result in us being required to
partner with different or additional parties.
A
natural disaster, catastrophe or other event could result in severe personal
injury, property damage and environmental damage, which could curtail our
operations and otherwise materially adversely affect our cash flow and,
accordingly, affect the market price of our common units.
Some of our operations involve risks of
personal injury, property damage and environmental damage, which could curtail
our operations and otherwise materially adversely affect our cash
flow. For example, natural gas facilities operate at high pressures,
sometimes in excess of 1,100 pounds per square inch. We also operate
oil and natural gas facilities located underwater in the Gulf of Mexico, which
can involve complexities, such as extreme water pressure. Virtually
all of our operations are exposed to potential natural disasters, including
hurricanes, tornadoes, storms, floods and/or earthquakes. The
location of our assets and our customers’ assets in the U.S. Gulf Coast region
makes them particularly vulnerable to hurricane risk.
If one or more facilities that are
owned by us or that deliver oil, natural gas or other products to us are damaged
by severe weather or any other disaster, accident, catastrophe or event, our
operations could be significantly interrupted. Similar interruptions
could result from damage to production or other facilities that supply our
facilities or other stoppages arising from factors beyond our
control. These interruptions might involve significant damage to
people, property or the environment, and repairs might take from a week or less
for a minor incident to six months or more for a major
interruption. Additionally, some of the storage contracts that we are
a party to obligate us to indemnify our customers for any damage or injury
occurring during the period in which the customers’ natural gas is in our
possession. Any event that interrupts the revenues generated by our
operations, or which causes us to make significant expenditures not covered by
insurance, could reduce our cash available for paying distributions and,
accordingly, adversely affect the market price of our common units.
We believe that EPCO maintains adequate
insurance coverage on our behalf, although insurance will not cover many types
of interruptions that might occur and will not cover amounts up to applicable
deductibles. As a result of market conditions, premiums and
deductibles for certain insurance policies can increase substantially, and in
some instances, certain insurance may become unavailable or available only for
reduced amounts of coverage. For example, change in the insurance
markets subsequent to the hurricanes in 2005 and 2008 have made it more
difficult for us to obtain certain types of coverage. As a result,
EPCO may not be able to renew existing insurance policies on behalf of us or
procure other desirable insurance on commercially reasonable terms, if at
all. If we were to incur a significant liability for which we were
not fully insured, it could have a material adverse effect on our financial
position, results of operations and cash flows. In addition, the
proceeds of any such insurance may not be paid in a timely manner and may be
insufficient if such an event were to occur.
An
impairment of goodwill and intangible assets could reduce our
earnings.
At December 31, 2008, our balance sheet
reflected $706.9 million of goodwill and $855.4 million of intangible
assets. Goodwill is recorded when the purchase price of a business
exceeds the fair market value of the tangible and separately measurable
intangible net assets. Generally accepted accounting principles in
the United States (“GAAP”) require us to test goodwill for impairment on an
annual basis or when events or circumstances occur indicating that goodwill
might be impaired. Long-lived assets such as intangible assets with
finite useful lives are reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount may not be
recoverable. If we determine that any of our goodwill or intangible
assets were impaired, we would be required to take an immediate charge to
earnings with a correlative effect on partners’ equity and balance sheet
leverage as measured by debt to total capitalization.
The
use of derivative financial instruments could result in material financial
losses by us.
We historically have sought to limit a
portion of the adverse effects resulting from changes in energy commodity prices
and interest rates by using financial derivative instruments and other hedging
mechanisms from time to time. To the extent that we hedge our
commodity price and interest rate exposures, we will forego the benefits we
would otherwise experience if commodity prices or interest rates were to change
in our favor. In addition, even though monitored by management,
hedging activities can result in losses. Such losses could occur
under various circumstances, including if a counterparty does not perform its
obligations under the hedge arrangement, the hedge is imperfect, or hedging
policies and procedures are not followed.
Our
pipeline integrity program may impose significant costs and liabilities on
us.
The U.S. DOT issued final rules
(effective March 2001 with respect to hazardous liquid pipelines and
February 2004 with respect to natural gas pipelines) requiring pipeline
operators to develop integrity management programs to comprehensively evaluate
their pipelines, and take measures to protect pipeline segments located in what
the rules refer to as “high consequence areas.” The final rule
resulted from the enactment of the Pipeline Safety Improvement Act of
2002. At this time, we cannot predict the ultimate costs of
compliance with this rule because those costs will depend on the number and
extent of any repairs found to be necessary as a result of the pipeline
integrity testing that is required by the rule. We will continue our
pipeline integrity testing programs to assess and maintain the integrity of our
pipelines. The results of these tests could cause us to incur
significant and unanticipated capital and operating expenditures for repairs or
upgrades deemed necessary to ensure the continued safe and reliable operation of
our pipelines.
Environmental
costs and liabilities and changing environmental regulation, including climate
change regulation, could affect our results of operations, cash flows and
financial condition.
Our operations are subject to extensive
federal, state and local regulatory requirements relating to environmental
affairs, health and safety, waste management and chemical and petroleum
products. Further, we cannot ensure that existing environmental
regulations will not be revised or that new regulations, such as regulations
designed to reduce the emissions of greenhouse gases, will not be adopted or
become applicable to us. Governmental authorities have the power to
enforce compliance with applicable regulations and permits and to subject
violators to civil and criminal penalties, including substantial fines,
injunctions or both. Certain environmental laws, including CERCLA and
analogous state laws and regulations, impose strict, joint and several liability
for costs required to cleanup and restore sites where hazardous substances or
hydrocarbons have been disposed or otherwise released. Moreover,
third parties, including neighboring landowners, may also have the right to
pursue legal actions to enforce compliance or to recover for personal injury and
property damage allegedly caused by the release of hazardous substances,
hydrocarbons or other waste products into the environment.
We will make expenditures in connection
with environmental matters as part of normal capital expenditure programs.
However, future environmental law developments, such as stricter laws,
regulations, permits or enforcement policies, could significantly increase some
costs of our operations, including the handling, manufacture, use, emission or
disposal of substances and wastes.
Climate
change regulation is one area of potential future environmental law
development. Studies have suggested that emissions of certain gases,
commonly referred to as “greenhouse gases,” may be contributing to warming of
the Earth’s atmosphere. Methane, a primary component of natural gas,
and carbon dioxide, a byproduct of the burning of natural gas, are examples of
greenhouse gases. The U.S. Congress is considering legislation to
reduce emissions of greenhouse gases. In addition, at least nine
states in the Northeast and five states in the West have developed initiatives
to regulate emissions of greenhouse gases, primarily through the planned
development of greenhouse gas emission inventories and/or regional greenhouse
gas cap and trade programs. The EPA is separately considering whether
it will regulate greenhouse gases as “air pollutants” under the existing federal
Clean Air Act.
Passage
of climate control legislation or other regulatory initiatives by Congress or
various states of the U.S. or the adoption of regulations by the EPA or
analogous state agencies that regulate or restrict emissions of greenhouse
gases, including methane or carbon dioxide in areas in which we conduct
business, could result in changes to the consumption and demand for natural gas
and could have adverse effects on our business, financial position, results of
operations and prospects. These changes could increase the costs of
our operations, including costs to operate and maintain our facilities, install
new emission controls on our facilities, acquire allowances to authorize our
greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions
and administer and manage a greenhouse gas emissions program. While
we may be able to include some or all of such increased costs in the rates
charged by our pipelines or other facilities, such recovery of costs is
uncertain and may depend on events beyond our control, including the outcome of
future rate proceedings before the FERC and the provisions of any final
legislation.
Federal,
state or local regulatory measures could materially adversely affect our
business, results of operations, cash flows and financial
condition.
The FERC regulates our interstate
natural gas pipelines and natural gas storage facilities under the Natural Gas
Act, and interstate NGL and petrochemical pipelines under the
ICA. The STB regulates our interstate propylene
pipelines. State regulatory agencies regulate our intrastate natural
gas and NGL pipelines, intrastate storage facilities and gathering
lines.
Under the NGA, the FERC has authority
to regulate natural gas companies that provide natural gas pipeline
transportation services in interstate commerce. Its authority to
regulate those services is comprehensive and includes the rates charged for the
services, terms and condition of service and certification and construction of
new facilities. The FERC requires that our services are provided on a
non-discriminatory basis so that all shippers have open access to our pipelines
and storage. Pursuant to the FERC’s jurisdiction over interstate gas
pipeline rates, existing pipeline rates may be challenged by customer complaint
or by the FERC Staff and proposed rate increases may be challenged by
protest.
We have interests in natural gas
pipeline facilities offshore from Texas and Louisiana. These
facilities are subject to regulation by the FERC and other federal agencies,
including the Department of Interior, under the Outer Continental Shelf Lands
Act, and by the DOT’s OPS under the Natural Gas Pipeline Safety
Act.
Our intrastate NGL and natural gas
pipelines are subject to regulation in many states, including Alabama, Colorado,
Louisiana, Mississippi, New Mexico and Texas, and by the FERC pursuant to
Section 311 of the Natural Gas Policy Act. We also have natural gas
underground storage facilities in Louisiana, Mississippi and
Texas. Although state regulation is typically less onerous than at
the FERC, proposed and existing rates subject to state regulation and the
provision of services on a non-discriminatory basis are also subject to
challenge by protest and complaint, respectively.
For a general overview of federal,
state and local regulation applicable to our assets, see “Regulation”
included under Items 1 and 2 of this annual report. This regulatory
oversight can affect certain aspects of our business and the market for our
products and could materially adversely affect our cash flows.
We are subject to
strict regulations at many of our facilities regarding employee safety, and
failure to comply with these regulations could adversely affect our ability to
make distributions to unitholders.
The
workplaces associated with our facilities are subject to the requirements of the
federal Occupational Safety and Health Act, or OSHA, and comparable state
statutes that regulate the protection of the health and safety of workers. In
addition, the OSHA hazard communication standard requires that we maintain
information about hazardous materials used or produced in our operations and
that we provide this information to employees, state and local governmental
authorities and local residents. The failure to comply with OSHA requirements or
general industry standards, keep adequate records or monitor
occupational
exposure to regulated substances could have a material adverse effect on our
business, financial position, results of operations and ability to make
distributions to unitholders.
Terrorist
attacks aimed at our facilities could adversely affect our business, results of
operations, cash flows and financial condition.
Since the September 11, 2001 terrorist
attacks on the United States, the United States government has issued warnings
that energy assets, including our nation’s pipeline infrastructure, may be the
future target of terrorist organizations. Any terrorist attack on our
facilities or pipelines or those of our customers could have a material adverse
effect on our business.
We
depend on the leadership and involvement of Dan L. Duncan and other key
personnel for the success of our businesses.
We depend on the leadership,
involvement and services of Dan L. Duncan, the founder of EPCO and the chairman
of our general partner and other key personnel. Mr. Duncan has been
integral to our success and the success of EPCO due in part to his ability to
identify and develop business opportunities, make strategic decisions and
attract and retain key personnel. The loss of his leadership and
involvement or the services of certain key members of our senior management
team could have a material adverse effect on our business, financial position,
results of operations, cash flows and market price of our
securities.
EPCO’s
employees may be subjected to conflicts in managing our business and the
allocation of time and compensation costs between our business and the business
of EPCO and its other affiliates.
We have no officers or employees and
rely solely on officers of our general partner and employees of
EPCO. Certain of our officers are also officers of EPCO and other
affiliates of EPCO. These relationships may create conflicts of interest
regarding corporate opportunities and other matters, and the resolution of any
such conflicts may not always be in our or our unitholders’ best interests. In
addition, these overlapping officers allocate their time among us, EPCO and
other affiliates of EPCO. These officers face potential conflicts
regarding the allocation of their time, which may adversely affect our business,
results of operations and financial condition.
We have entered into an ASA that
governs business opportunities among entities controlled by EPCO, which includes
us and our general partner, Enterprise GP Holdings and its general partner,
Duncan Energy Partners and its general partner and TEPPCO and its general
partner. For information regarding how business opportunities are
handled within the EPCO group of companies, please read Item 13 of this annual
report.
We do not have an independent
compensation committee, and aspects of the compensation of our executive
officers and other key employees, including base salary, are not reviewed or
approved by our independent directors. The determination of executive officer
and key employee compensation could involve conflicts of interest resulting in
economically unfavorable arrangements for us.
The
global financial crisis may have impacts on our business and financial
condition that we currently cannot predict.
The
continued credit crisis and related turmoil in the global financial system has
had, and may continue to have, an impact on our business and financial
condition. We may face significant challenges if conditions in the
financial markets revert to those that existed in the fourth quarter of
2008. Our ability to access the capital markets may be severely
restricted at a time when we would like, or need, to do so, which could have an
adverse impact on our ability to meet capital commitments and achieve the
flexibility needed to react to changing economic and business
conditions. The credit crisis could have a negative impact on our
lenders or customers, causing them to fail to meet their obligations to
us. Additionally, demand for our services and products depends on
activity and expenditure levels in the energy industry, which are directly and
negatively impacted by depressed oil and gas prices. Also, a decrease
in demand for NGLs by the
petrochemical
and refining industries due to a decrease in demand for their products as a
result of general economic conditions would likely impact demand for our
services and products. Any of these factors could lead to reduced
usage of our pipelines and energy logistics services, which could have a
material negative impact on our revenues and prospects.
Risks
Relating to Our Partnership Structure
We
may issue additional securities without the approval of our common
unitholders.
At any time, we may issue an unlimited
number of limited partner interests of any type (to parties other than our
affiliates) without the approval of our unitholders. Our partnership
agreement does not give our common unitholders the right to approve the issuance
of equity securities including equity securities ranking senior to our common
units. The issuance of additional common units or other equity
securities of equal or senior rank will have the following effects:
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the
ownership interest of a unitholder immediately prior to the issuance will
decrease;
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the
amount of cash available for distributions on each common unit may
decrease;
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the
ratio of taxable income to distributions may
increase;
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the
relative voting strength of each previously outstanding common unit may be
diminished; and
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the
market price of our common units may
decline.
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We
may not have sufficient cash from operations to pay distributions at the current
level following establishment of cash reserves and payments of fees and
expenses, including payments to EPGP.
Because distributions on our common
units are dependent on the amount of cash we generate, distributions may
fluctuate based on our performance. We cannot guarantee that we will
continue to pay distributions at the current level each quarter. The
actual amount of cash that is available to be distributed each quarter will
depend upon numerous factors, some of which are beyond our control and the
control of EPGP. These factors include but are not limited to the
following:
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the
level of our operating costs;
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the
level of competition in our business
segments;
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prevailing
economic conditions;
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the
level of capital expenditures we
make;
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the
restrictions contained in our debt agreements and our debt service
requirements;
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fluctuations
in our working capital needs;
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the
cost of acquisitions, if any; and
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the
amount, if any, of cash reserves established by EPGP in its sole
discretion.
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In addition, you should be aware that
the amount of cash we have available for distribution depends primarily on our
cash flow, including cash flow from financial reserves and working capital
borrowings, not solely on profitability, which is affected by non-cash
items. As a result, we may make cash distributions during periods
when we record losses and we may not make distributions during periods when we
record net income.
We
do not have the same flexibility as other types of organizations to accumulate
cash and equity to protect against illiquidity in the future.
Unlike a corporation, our partnership
agreement requires us to make quarterly distributions to our unitholders of all
available cash reduced by any amounts of reserves for commitments and
contingencies, including capital and operating costs and debt service
requirements. The value of our units and other limited partner
interests may decrease in correlation with decreases in the amount we distribute
per unit. Accordingly, if we experience a liquidity problem in the
future, we may not be able to issue more equity to recapitalize.
Cost
reimbursements and fees due to EPCO and its affiliates, including our general
partner may be substantial and will reduce our cash available for distribution
to holders of our units.
Prior to making any distribution on our
units, we will reimburse EPCO and its affiliates, including officers and
directors of EPGP, for all expenses they incur on our behalf, including
allocated overhead. These amounts will include all costs incurred in
managing and operating us, including costs for rendering administrative staff
and support services to us, and overhead allocated to us by EPCO. The payment of
these amounts could adversely affect our ability to pay cash distributions to
holders of our units. EPCO has sole discretion to determine the
amount of these expenses. In addition, EPCO and its affiliates may
provide other services to us for which we will be charged fees as determined by
EPCO.
EPGP
and its affiliates have limited fiduciary responsibilities to, and conflicts of
interest with respect to, our partnership, which may permit it to favor its own
interests to your detriment.
The directors and officers of EPGP and
its affiliates have duties to manage EPGP in a manner that is beneficial to its
members. At the same time, EPGP has duties to manage our partnership
in a manner that is beneficial to us. Therefore, EPGP’s duties to us
may conflict with the duties of its officers and directors to its
members. Such conflicts may include, among others, the
following:
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neither
our partnership agreement nor any other agreement requires EPGP or EPCO to
pursue a business strategy that favors
us;
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decisions
of EPGP regarding the amount and timing of asset purchases and sales, cash
expenditures, borrowings, issuances of additional units and reserves in
any quarter may affect the level of cash available to pay quarterly
distributions to unitholders and
EPGP;
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under
our partnership agreement, EPGP determines which costs incurred by it and
its affiliates are reimbursable by
us;
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EPGP
is allowed to resolve any conflicts of interest involving us and EPGP and
its affiliates;
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EPGP
is allowed to take into account the interests of parties other than us,
such as EPCO, in resolving conflicts of interest, which has the effect of
limiting its fiduciary duty to
unitholders;
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any
resolution of a conflict of interest by EPGP not made in bad faith and
that is fair and reasonable to us shall be binding on the partners and
shall not be a breach of our partnership
agreement;
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affiliates
of EPGP, including TEPPCO, may compete with us in certain
circumstances;
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EPGP
has limited its liability and reduced its fiduciary duties and has also
restricted the remedies available to our unitholders for actions that
might, without the limitations, constitute breaches of fiduciary
duty. As a result of purchasing our units, you are deemed to
consent to some actions and conflicts of interest that might otherwise
constitute a breach of fiduciary or other duties under applicable
law;
|
|
§
|
we
do not have any employees and we rely solely on employees of EPCO and its
affiliates;
|
|
§
|
in
some instances, EPGP may cause us to borrow funds in order to permit the
payment of distributions, even if the purpose or effect of the borrowing
is to make incentive distributions;
|
|
§
|
our
partnership agreement does not restrict EPGP from causing us to pay it or
its affiliates for any services rendered to us or entering into additional
contractual arrangements with any of these entities on our
behalf;
|
|
§
|
EPGP
intends to limit its liability regarding our contractual and other
obligations and, in some circumstances, may be entitled to be indemnified
by us;
|
|
§
|
EPGP
controls the enforcement of obligations owed to us by our general partner
and its affiliates; and
|
|
§
|
EPGP
decides whether to retain separate counsel, accountants or others to
perform services for us.
|
We have
significant business relationships with entities controlled by Dan L. Duncan,
including EPCO and TEPPCO. For detailed information on these
relationships and related transactions with these entities, see Item 13 included
within this annual report.
Unitholders
have limited voting rights and are not entitled to elect our general partner or
its directors, which could lower the trading price of our common
units. In addition, even if unitholders are dissatisfied, they cannot
easily remove our general partner.
Unlike the holders of common stock in a
corporation, unitholders have only limited voting rights on matters affecting
our business and, therefore, limited ability to influence management’s decisions
regarding our business. Unitholders did not elect EPGP or its
directors and will have no right to elect our general partner or its directors
on an annual or other continuing basis. The Board of Directors of our
general partner, including the independent directors, is chosen by the owners of
the general partner and not by the unitholders.
Furthermore, if unitholders are
dissatisfied with the performance of our general partner, they currently have no
practical ability to remove EPGP or its officers or directors. EPGP
may not be removed except upon the vote of the holders of at least 60.0% of our
outstanding units voting together as a single class. Because
affiliates of EPGP currently own approximately 34.0% of our outstanding
common units, the removal of EPGP as our general partner is highly unlikely
without the consent of both EPGP and its affiliates. As a result of
this provision, the trading price of our common units may be lower than other
forms of equity ownership because of the absence or reduction of a takeover
premium in the trading price.
Our
partnership agreement restricts the voting rights of unitholders owning 20.0% or
more of our common units.
Unitholders’ voting rights are further
restricted by a provision in our partnership agreement stating that any units
held by a person that owns 20.0% or more of any class of our common units then
outstanding, other than our general partner and its affiliates, cannot be voted
on any matter. In addition, our partnership agreement contains
provisions limiting the ability of unitholders to call meetings or to acquire
information about our operations, as well as other provisions limiting our
unitholders’ ability to influence the manner or direction of our
management. As a result of this provision, the trading price of our common
units may be lower than other forms of equity ownership because of the absence
or reduction of a takeover premium in the trading price.
EPGP
has a limited call right that may require common unitholders to sell their units
at an undesirable time or price.
If at any time EPGP and its affiliates
own 85.0% or more of the common units then outstanding, EPGP will have the
right, but not the obligation, which it may assign to any of its affiliates or
to us, to acquire all, but not less than all, of the remaining common units held
by unaffiliated persons at a price not less than the then current market
price. As a result, common unitholders may be required to sell their
common units at an undesirable time or price and may therefore not receive any
return on their investment. They may also incur a tax liability upon
a sale of their units.
Our
common unitholders may not have limited liability if a court finds that limited
partner actions constitute control of our business.
Under Delaware law, common unitholders
could be held liable for our obligations to the same extent as a general partner
if a court determined that the right of limited partners to remove our general
partner or to take other action under our partnership agreement constituted
participation in the “control” of our business.
Under Delaware law, our general partner
generally has unlimited liability for our obligations, such as our debts and
environmental liabilities, except for those of our contractual obligations that
are expressly made without recourse to our general partner.
The
limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been
clearly established in some of the states in which we do business. You could
have unlimited liability for our obligations if a court or government agency
determined that:
|
§
|
we
were conducting business in a state, but had not complied with that
particular state’s partnership
statute; or
|
|
§
|
your
right to act with other unitholders to remove or replace our general
partner, to approve some amendments to our partnership agreement or to
take other actions under our partnership agreement constituted “control”
of our business.
|
Unitholders may
have liability to repay distributions.
Under
certain circumstances, our unitholders may have to repay amounts wrongfully
returned or distributed to them. Under Section 17-607 of the Delaware
Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make a
distribution to our unitholders if the distribution would cause our liabilities
to exceed the fair value of our assets. Liabilities to partners on
account of their partnership interests and liabilities that are non-recourse to
the partnership are not counted for purposes of determining whether a
distribution is permitted. Delaware law provides that for a period of
three years from the date of an impermissible distribution, limited partners who
received the distribution and who knew at the time of the distribution that it
violated Delaware law will be liable to the limited partnership for the
distribution amount. A purchaser of common units who becomes a
limited partner is liable for the obligations of the transferring limited
partner to make contributions to the partnership that are known to such
purchaser of common units at the time it became a limited partner and for
unknown obligations if the liabilities could be determined from our partnership
agreement.
Our
general partner’s interest in us and the control of our general partner may be
transferred to a third party without unitholder consent.
Our general partner, in accordance with
our partnership agreement, may transfer its general partner interest without the
consent of unitholders. In addition, our general partner may transfer
its general partner interest to a third party in a merger or consolidation or in
a sale of all or substantially all of its assets without the consent of our
unitholders. Furthermore, there is no restriction in our partnership agreement
on the ability of Enterprise GP Holdings or its affiliates to transfer their
equity interests in our general partner
to a
third party. The new equity owner of our general partner would then
be in a position to replace the board of directors and officers of our general
partner with their own choices and to influence the decisions taken by the board
of directors and officers of our general partner.
Tax
Risks to Common Unitholders
Our tax treatment
depends on our status as a partnership for federal income tax purposes, as well
as our not being subject to a material amount of entity-level taxation by
individual states. If the Internal Revenue Service were to treat us as a
corporation or if we were to become subject to a material amount of entity-level
taxation for state tax purposes, then our cash
available for distribution to our common unitholders would be substantially
reduced.
The anticipated after-tax economic
benefit of an investment in our common units depends largely on our being
treated as a partnership for federal income tax purposes. We have not
requested, and do not plan to request, a ruling from the Internal Revenue
Service (“IRS”) on this matter.
If we were treated as a corporation for
federal income tax purposes, we would pay federal income tax on our taxable
income at the corporate tax rate, which is currently a maximum of
35.0%. Distributions to our unitholders would generally be taxed
again as corporate distributions, and no income, gains, losses or deductions
would flow through to our unitholders. Because a tax would be imposed
upon us as a corporation, the cash available for distributions to our common
unitholders would be substantially reduced. Thus, treatment of us as
a corporation would result in a material reduction in the after-tax return to
our common unitholders, likely causing a substantial reduction in the value of
our common units.
Current law may change, causing us to
be treated as a corporation for federal income tax purposes or otherwise
subjecting us to a material amount of entity level taxation. In
addition, because of widespread state budget deficits and other reasons, several
states (including Texas) are evaluating ways to enhance state-tax collections.
For example, with respect to tax reports due on or after January 1, 2008, our
operating subsidiaries are subject to the Revised Texas Franchise Tax on that
portion of their revenue generated in Texas. Specifically, the
Revised Texas Franchise Tax is imposed at a maximum effective rate of 0.7% of
the operating subsidiaries’ gross revenue that is apportioned to
Texas. If any additional state were to impose an entity-level tax
upon us or our operating subsidiaries, the cash available for distribution to
our common unitholders would be reduced.
The
tax treatment of publicly traded partnerships or an investment in our common
units could be subject to potential legislative, judicial or administrative
changes and differing interpretations, possibly on a retroactive
basis.
The
present U.S. federal income tax treatment of publicly traded partnerships,
including us, or an investment in our common units may be modified by
administrative, legislative or judicial interpretation at any
time. Any modification to the U.S. federal income tax laws and
interpretations thereof could make it more difficult or impossible to meet the
exception for us to be treated as a partnership for U.S. federal income tax
purposes that is not taxable as a corporation, or Qualifying Income Exception,
affect or cause us to change our business activities, affect the tax
considerations of an investment in us, change the character or treatment of
portions of our income and adversely affect an investment in our common
units. For example, in response to certain recent developments,
members of Congress are considering substantive changes to the definition of
qualifying income under Section 7704(d) of the Internal Revenue
Code. It is possible that these legislative efforts could result in
changes to the existing U.S. tax laws that affect publicly traded partnerships,
including us. Modifications to the U.S. federal income tax laws and
interpretations thereof may or may not be applied retroactively. We
are unable to predict whether any changes will ultimately be
enacted. Any such changes could negatively impact the value of an
investment in our common units.
We
prorate our items of income, gain, loss and deduction between transferors and
transferees of our common units each month based upon the ownership of our
common units on the first day of each month, instead of on the basis of the date
a particular common unit is transferred.
We
prorate our items of income, gain, loss and deduction between transferors and
transferees of our common units each month based upon the ownership of our
common units on the first day of each month, instead of on the basis of the date
a particular unit is transferred. The use of this proration method
may not be permitted under existing Treasury regulations, and, accordingly, our
counsel is unable to opine as to the validity of this method. If the
IRS were to successfully challenge this method or new Treasury regulations were
issued, we may be required to change the allocation of items of income, gain,
loss and deduction among our unitholders.
A
successful IRS contest of the federal income tax positions we take may adversely
impact the market for our common units, and the costs of any contests will be
borne by our unitholders and our general partner.
The IRS may adopt positions that differ
from the positions we take, even positions taken with advice of
counsel. It may be necessary to resort to administrative or court
proceedings to sustain some or all of the positions we take. A court
may not agree with some or all of the positions we take. Any contest
with the IRS may materially and adversely impact the market for our common units
and the price at which our common units trade. In addition, the costs
of any contest with the IRS, principally legal, accounting and related fees,
will be borne indirectly by our unitholders and our general
partner.
Even
if our common unitholders do not receive any cash distributions from us, they
will be required to pay taxes on their share of our taxable income.
Common unitholders will be required to
pay federal income taxes and, in some cases, state and local income taxes on
their share of our taxable income whether or not they receive any cash
distributions from us. Our common unitholders may not receive cash
distributions from us equal to their share of our taxable income or even equal
to the actual tax liability which results from their share of our taxable
income.
Tax gain or loss on the disposition
of our common units could be different than expected.
If a common unitholder sells its common
units, the unitholder will recognize a gain or loss equal to the difference
between the amount realized and the unitholder’s tax basis in those common
units. Prior distributions to a unitholder in excess of the total net
taxable income a unitholder is allocated for a common unit, which decreased the
unitholder’s tax basis in that common unit, will, in effect, become taxable
income to the unitholder if the common unit is sold at a price greater than the
unitholder’s tax basis in that common unit, even if the price the unitholder
receives is less than the unitholder’s original cost. A substantial
portion of the amount realized, whether or not representing gain, may be
ordinary income to a unitholder.
Tax-exempt
entities and non-U.S. persons face unique tax issues from owning common
units that may result in adverse tax consequences to them.
Investments in common units by
tax-exempt entities, such as individual retirement accounts (known as
IRAs), other retirement plans and non-U.S. persons, raise issues unique to
them. For example, virtually all of our income allocated to
unitholders who are organizations exempt from federal income tax, including
individual retirement accounts and other retirement plans, will be unrelated
business taxable income and will be taxable to them. Distributions to
non-U.S. persons will be reduced by withholding taxes at the highest applicable
effective tax rate, and non-U.S. persons will be required to file United States
federal income tax returns and pay tax on their share of our taxable
income.
We
will treat each purchaser of our common units as having the same tax benefits
without regard to the units purchased. The IRS may challenge this
treatment, which could adversely affect the value of our common
units.
Because we cannot match transferors and
transferees of common units, we adopt depreciation and amortization positions
that may not conform with all aspects of applicable Treasury
regulations. A successful IRS challenge to those positions could
adversely affect the amount of tax benefits available to a common
unitholder. It also could affect the timing of these tax benefits or
the amount of gain from a sale of common units and could have a negative impact
on the value of our common units or result in audit adjustments to the common
unitholder’s tax returns.
Our
common unitholders will likely be subject to state and local taxes and return
filing requirements in states where they do not live as a result of an
investment in our common units.
In addition to federal income taxes,
our common unitholders will likely be subject to other taxes, including state
and local income taxes, unincorporated business taxes and estate, inheritance or
intangible taxes that are imposed by the various jurisdictions in which we do
business or own property. Our common unitholders will likely be
required to file state and local income tax returns and pay state and local
income taxes in some or all of these various jurisdictions. Further,
they may be subject to penalties for failure to comply with those
requirements. We may own property or conduct business in other states
or foreign countries in the future. It is the responsibility of the
common unitholder to file all federal, state and local tax returns.
The
sale or exchange of 50.0% or more of our capital and profits interests during
any twelve-month period will result in the termination of our partnership for
federal income tax purposes.
We will
be considered to have terminated for federal income tax purposes if there is a
sale or exchange of 50.0% or more of the total interests in our capital and
profits within a twelve-month period. Our termination would, among
other things, result in the closing of our taxable year for all unitholders and
could result in a deferral of depreciation deductions allowable in computing our
taxable income.
We
have adopted certain valuation methodologies that may result in a shift of
income, gain, loss and deduction between EPGP and our
unitholders. The IRS may challenge this treatment, which could
adversely affect the value of our common units.
When we issue additional common units
or engage in certain other transactions, we determine the fair market value of
our assets and allocate any unrealized gain or loss attributable to our assets
to the capital accounts of our unitholders and EPGP. Our methodology
may be viewed as understating the value of our assets. In that case,
there may be a shift of income, gain, loss and deduction between certain
unitholders and EPGP, which may be unfavorable to such
unitholders. Moreover, subsequent purchasers of common units may have
a greater portion of their Internal Revenue code Section 743(b) adjustment
allocated to our tangible assets and a lesser portion allocated to our
intangible assets. The IRS may challenge our methods, or our
allocation of the Section 743(b) adjustment attributable to our tangible and
intangible assets, and allocations of income, gain, loss and deduction between
EPGP and certain of our unitholders.
A successful IRS challenge to these
methods or allocations could adversely affect the amount of taxable income or
loss being allocated to our unitholders. It also could affect the
amount of gain from a unitholder’s sale of common units and could have a
negative impact on the value of the common units or result in audit adjustments
to the unitholder’s tax returns.
None.
On
occasion, we or our unconsolidated affiliates are named as defendants in
litigation relating to our normal business activities, including regulatory and
environmental matters. Although we are insured against various
business risks to the extent we believe it is prudent, there is no assurance
that the nature and amount of such insurance will be adequate, in every case, to
indemnify us against liabilities arising from future legal proceedings as a
result of our ordinary business activities. We are unaware of any
significant litigation, pending or threatened, that could have a significant
adverse effect on our financial position, results of operations or cash
flows. For detailed information regarding our legal proceedings, see
Note 20 of the Notes to Consolidated Financial Statements included under Item 8
of this annual report.
None.
and Issuer Purchases of Equity
Securities.
Market
Information and Cash Distributions
Our common units are listed on
the NYSE under the ticker symbol “EPD.” As of February 2, 2009, there
were approximately 988 unitholders of record of our common units. The
following table presents the high and low sales prices for our common units
during the periods indicated (as reported by the NYSE Composite Transaction
Tape) and the amount, record date and payment date of the quarterly cash
distributions we paid on each of our common units.
|
|
|
|
|
|
|
|
|
Cash
Distribution History
|
|
|
|
Price
Ranges
|
|
|
Per
|
|
Record
|
Payment
|
|
|
|
High
|
|
|
Low
|
|
|
Unit
|
|
Date
|
Date
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
1st
Quarter
|
|
$ |
32.750 |
|
|
$ |
28.060 |
|
|
$ |
0.4750 |
|
Apr.
30, 2007
|
May
10, 2007
|
|
2nd
Quarter
|
|
$ |
33.350 |
|
|
$ |
30.220 |
|
|
$ |
0.4825 |
|
Jul.
31, 2007
|
Aug.
9, 2007
|
|
3rd
Quarter
|
|
$ |
33.700 |
|
|
$ |
26.136 |
|
|
$ |
0.4900 |
|
Oct.
31, 2007
|
Nov.
8, 2007
|
|
4th
Quarter
|
|
$ |
32.450 |
|
|
$ |
29.920 |
|
|
$ |
0.5000 |
|
Jan.
31, 2008
|
Feb.
7, 2008
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1st
Quarter
|
|
$ |
32.630 |
|
|
$ |
26.750 |
|
|
$ |
0.5075 |
|
Apr.
30, 2008
|
May
7, 2008
|
|
2nd
Quarter
|
|
$ |
32.640 |
|
|
$ |
29.040 |
|
|
$ |
0.5150 |
|
Jul.
31, 2008
|
Aug.
7, 2008
|
|
3rd
Quarter
|
|
$ |
30.070 |
|
|
$ |
22.580 |
|
|
$ |
0.5225 |
|
Oct.
31, 2008
|
Nov.
12, 2008
|
|
4th
Quarter
|
|
$ |
26.300 |
|
|
$ |
16.000 |
|
|
$ |
0.5300 |
|
Jan.
30, 2009
|
Feb.
9, 2009
|
The quarterly cash distributions shown
in the table above correspond to cash flows for the quarters
indicated. The actual cash distributions (i.e., the payments made to
our partners) occur within 45 days after the end of such quarter. We
expect to fund our quarterly cash distributions to partners primarily with cash
provided by operating activities. For additional information
regarding our cash flows from operating activities, see “Liquidity and
Capital Resources” included under Item 7 of this annual report. Although
the payment of cash distributions is not guaranteed, we expect to continue
to pay comparable cash distributions in the future.
In
January 2009, we sold 10,590,000 common units (including an over-allotment of
990,000 common units) to the public at an offering price of $22.20 per
unit. We used the net offering proceeds of $225.6 million to
temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving
Credit Facility, which may be reborrowed to fund capital expenditures and other
growth projects, and for general partnership purposes.
Recent
Sales of Unregistered Securities
There
were no sales of unregistered equity securities during 2008.
Common
Units Authorized for Issuance Under Equity Compensation Plan
See “Securities Authorized for Issuance
Under Equity Compensation Plans” under Item 12 of this annual report, which is
incorporated by reference into this Item 5.
Issuer
Purchases of Equity Securities
We have
not repurchased any of our common units since 2002. In December 1998,
we announced a common unit repurchase program whereby we, together with certain
affiliates, intended to repurchase up to 2,000,000 of our common units for the
purpose of granting options to management and key employees (amount adjusted for
the 2-for-1 unit split in May 2002). As of February 2, 2009, we and
our affiliates could repurchase up to 618,400 additional common units under this
repurchase program.
The
following table summarizes our repurchase activity during 2008 in connection
with other arrangements:
|
|
|
|
|
Maximum
|
|
|
|
|
Total
Number of
|
Number
of Units
|
|
|
|
Average
|
of
Units Purchased
|
That
May Yet
|
|
|
Total
Number of
|
Price
Paid
|
as
Part of Publicly
|
Be
Purchased
|
|
Period
|
Units
Purchased
|
per
Unit
|
Announced
Plans
|
Under
the Plans
|
|
May
2008
|
21,413
(1)
|
$30.37
|
--
|
--
|
|
August
2008
|
4,940
(2)
|
$29.19
|
--
|
--
|
|
September
2008
|
4,565
(3)
|
$25.77
|
--
|
--
|
|
October
2008
|
54,328
(4)
|
$18.39
|
--
|
--
|
|
(1)
Of
the 67,500 restricted unit awards that vested in May 2008 and converted to
common units, 21,413 of these units were sold back to the partnership by
employees to cover related withholding tax
requirements.
(2)
Of
the 28,650 restricted unit awards that vested in August 2008 and converted
to common units, 4,940 of these units were sold back to the partnership by
employees to cover related withholding tax
requirements.
(3)
Of
the 16,500 restricted unit awards that vested in September 2008 and
converted to common units, 4,565 of these units were sold back to the
partnership by employees to cover related withholding tax
requirements.
(4)
Of
the 165,958 restricted unit awards that vested in October 2008 and
converted to common units, 54,328 of these units were sold back to the
partnership by employees to cover related withholding tax
requirements.
|
The
following table presents selected historical consolidated financial data of our
partnership. This information has been derived from and should be
read in conjunction with the audited financial statements. In
addition, information regarding our results of operations and liquidity and
capital resources can be found under Item 7 of this annual report. As
presented in the table, amounts are in thousands (except per unit
data).
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Operating results data:
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
21,905,656 |
|
|
$ |
16,950,125 |
|
|
$ |
13,990,969 |
|
|
$ |
12,256,959 |
|
|
$ |
8,321,202 |
|
|
Income
from continuing operations (2)
|
|
$ |
954,021 |
|
|
$ |
533,674 |
|
|
$ |
599,683 |
|
|
$ |
423,716 |
|
|
$ |
257,480 |
|
|
Income per
unit from continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
and Diluted
|
|
$ |
1.85 |
|
|
$ |
0.96 |
|
|
$ |
1.22 |
|
|
$ |
0.92 |
|
|
$ |
0.83 |
|
|
Other
financial data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions
per common unit (3)
|
|
$ |
2.0750 |
|
|
$ |
1.9475 |
|
|
$ |
1.825 |
|
|
$ |
1.698 |
|
|
$ |
1.540 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As
of December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Financial position data:
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
assets
|
|
$ |
17,957,535 |
|
|
$ |
16,608,007 |
|
|
$ |
13,989,718 |
|
|
$ |
12,591,016 |
|
|
$ |
11,315,461 |
|
|
Long-term
and current maturities of debt (4)
|
|
$ |
9,108,410 |
|
|
$ |
6,906,145 |
|
|
$ |
5,295,590 |
|
|
$ |
4,833,781 |
|
|
$ |
4,281,236 |
|
|
Partners'
equity (5)
|
|
$ |
6,084,988 |
|
|
$ |
6,131,649 |
|
|
$ |
6,480,233 |
|
|
$ |
5,679,309 |
|
|
$ |
5,328,785 |
|
|
Total
units outstanding (excluding treasury) (5)
|
|
|
441,435 |
|
|
|
435,297 |
|
|
|
432,408 |
|
|
|
389,861 |
|
|
|
364,786 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
In
general, our historical operating results and financial position have been
affected by numerous acquisitions since 2002. Our most significant
transaction to date was the GulfTerra Merger, which was completed on
September 30, 2004. The aggregate value of the total consideration we
paid or issued to complete the GulfTerra Merger was approximately $4
billion. We accounted for the GulfTerra Merger and our other
acquisitions using purchase accounting; therefore, the operating results
of these acquired entities are included in our financial results
prospectively from their respective acquisition dates.
(2)
Amounts
presented for the years ended December 31, 2006, 2005 and 2004 are before
the cumulative effect of accounting changes.
(3)
Distributions
per common unit represent declared cash distributions with respect to the
four fiscal quarters of each period presented.
(4)
In
general, the balances of our long-term and current maturities of debt have
increased over time as a result of financing all or a portion of
acquisitions and other capital spending.
(5)
We
regularly issue common units through underwritten public offerings and,
less frequently, in connection with acquisitions or other
transactions. The September 2004 issuance of 104.5 million common
units in connection with the GulfTerra Merger being our largest. For
additional information regarding our partners’ equity and unit history,
see Note 15 of the Notes to Consolidated Financial Statements included
under Item 8 of this annual report.
|
|
For
the years ended December 31, 2008, 2007 and 2006.
The following information should be
read in conjunction with our consolidated financial statements and our
accompanying notes. Our discussion and analysis includes the
following:
|
§
|
Cautionary
Note Regarding Forward-Looking
Statements.
|
|
§
|
Significant
Relationships Referenced in this Discussion and
Analysis.
|
|
§
|
General
Outlook for 2009.
|
|
§
|
Recent
Developments – Discusses significant developments during the year ended
December 31, 2008.
|
|
§
|
Results
of Operations – Discusses material year-to-year variances in our
Statements of Consolidated
Operations.
|
|
§
|
Liquidity
and Capital Resources – Addresses available sources of liquidity and
capital resources and includes a discussion of our capital spending
program.
|
|
§
|
Critical
Accounting Policies and Estimates.
|
|
§
|
Other
Items – Includes information related to contractual obligations,
off-balance sheet arrangements, related party transactions, recent
accounting pronouncements and other
matters.
|
As generally used in the energy
industry and in this discussion, the identified terms have the following
meanings:
|
/d
|
=
per day
|
|
BBtus
|
=
billion British thermal units
|
|
Bcf
|
=
billion cubic feet
|
|
MBPD
|
=
thousand barrels per day
|
|
MMBbls
|
=
million barrels
|
|
MMBtus
|
=
million British thermal units
|
|
MMcf
|
=
million cubic feet
|
Our
financial statements have been prepared in accordance with U.S. generally
accepted accounting principles (“GAAP”).
Cautionary
Note Regarding Forward-Looking Statements
This
discussion contains various forward-looking statements and information that are
based on our beliefs and those of our general partner, as well as assumptions
made by us and information currently available to us. When used in
this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,”
“goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “will,” “believe,”
“may,” “potential” and similar expressions and statements regarding our plans
and objectives for future operations, are intended to identify forward-looking
statements. Although we and our general partner believe that such
expectations reflected in such forward-looking statements are reasonable,
neither we nor our general partner can give any assurances that such
expectations will prove to be correct. Such statements are subject to
a variety of risks, uncertainties and assumptions as described in more detail in
Item 1A of this annual report. If one or more of these risks or
uncertainties materialize, or if underlying
assumptions
prove incorrect, our actual results may vary materially from those anticipated,
estimated, projected or expected. You should not put undue reliance
on any forward-looking statements.
Significant
Relationships Referenced in this Discussion and Analysis
Unless the context requires otherwise,
references to “we,” “us,” “our,” or “Enterprise Products Partners” are intended
to mean the business and operations of Enterprise Products Partners L.P. and its
consolidated subsidiaries.
References to “EPO” mean Enterprise
Products Operating LLC as successor in interest by merger to Enterprise Products
Operating L.P., which is a wholly owned subsidiary of Enterprise Products
Partners through which Enterprise Products Partners conducts substantially all
of its business.
References
to “Duncan Energy Partners” mean Duncan Energy Partners L.P., which is a
consolidated subsidiary of EPO. Duncan Energy Partners is a publicly
traded Delaware limited partnership, the common units of which are listed on the
New York Stock Exchange (“NYSE”) under the ticker symbol “DEP.” References
to “DEP GP” mean DEP Holdings, LLC, which is the general partner of Duncan
Energy Partners and is wholly owned by EPO.
References
to “EPGP” mean Enterprise Products GP, LLC, which is our general
partner.
References to “Enterprise GP Holdings”
mean Enterprise GP Holdings L.P., a publicly traded affiliate, the units of
which are listed on the NYSE under the ticker symbol
“EPE.” Enterprise GP Holdings owns EPGP. References to
“EPE Holdings” mean EPE Holdings, LLC, which is the general partner of
Enterprise GP Holdings.
References
to “TEPPCO” mean TEPPCO Partners, L.P., a publicly traded affiliate, the common
units of which are listed on the NYSE under the ticker symbol
“TPP.” References to “TEPPCO GP” refer to Texas Eastern Products
Pipeline Company, LLC, which is the general partner of TEPPCO and is wholly
owned by Enterprise GP Holdings.
References
to “Energy Transfer Equity” mean the business and operations of Energy Transfer
Equity, L.P. and its consolidated subsidiaries, which include Energy Transfer
Partners, L.P. (“ETP”). Energy Transfer Equity is a publicly traded
Delaware limited partnership, the common units of which are listed on the NYSE
under the ticker symbol “ETE.” The general partner of Energy Transfer
Equity is LE GP, LLC (“LE GP”). On May 7, 2007, Enterprise GP
Holdings acquired non-controlling interests in both LE GP and Energy Transfer
Equity. Enterprise GP Holdings accounts for its investments in LE GP
and Energy Transfer Equity using the equity method of accounting.
References
to “Employee Partnerships” mean EPE Unit L.P. (“EPE Unit I”), EPE Unit II, L.P.
(“EPE Unit II”), EPE Unit III, L.P. (“EPE Unit III”), Enterprise Unit L.P.
(“Enterprise Unit”) and EPCO Unit L.P. (“EPCO Unit”), collectively, all of which
are private company affiliates of EPCO, Inc.
References
to “EPCO” mean EPCO, Inc. and its wholly owned private company affiliates, which
are related parties to all of the foregoing named entities.
We, EPO,
Duncan Energy Partners, DEP GP, EPGP, Enterprise GP Holdings, EPE Holdings,
TEPPCO and TEPPCO GP are affiliates under the common control of Dan L. Duncan,
the Group Co-Chairman and controlling shareholder of EPCO.
Overview
of Business
We are a
North American midstream energy company providing a wide range of services to
producers and consumers of natural gas, natural gas liquids (“NGLs”), crude oil
and certain petrochemicals. In addition, we are an industry leader in
the development of pipeline and other midstream energy infrastructure in the
continental United States and Gulf of Mexico. We are a publicly
traded Delaware
limited
partnership formed in 1998, the common units of which are listed on the NYSE
under the ticker symbol “EPD.”
Our midstream energy asset network
links producers of natural gas, NGLs and crude oil from some of the largest
supply basins in the United States, Canada and the Gulf of Mexico with domestic
consumers and international markets. We have four reportable business
segments: NGL Pipelines & Services; Onshore Natural Gas Pipelines &
Services; Offshore Pipelines & Services; and Petrochemical
Services. Our business segments are generally organized and managed
according to the type of services rendered (or technologies employed) and
products produced and/or sold.
We
conduct substantially all of our business through EPO. We are owned
98.0% by our limited partners and 2.0% by our general partner,
EPGP. EPGP is owned 100.0% by Enterprise GP Holdings.
General
Outlook for 2009
The current global recession and
financial crisis have impacted energy companies generally. The
recession and related slowdown in economic activity has reduced demand for
energy and related products, which in turn has generally led to significant
decreases in the prices of crude oil, natural gas and NGLs. The
financial crisis has resulted in the effective insolvency, liquidation or
government intervention for a number of financial institutions, investment
companies, hedge funds and highly leveraged industrial
companies. This has had an adverse impact on the prices of debt and
equity securities that has generally increased the cost and limited the
availability of debt and equity capital.
Commercial
Outlook
In 2008,
there was significant volatility in the prices of refined products, crude oil,
natural gas and NGLs. For example, the price of West Texas
Intermediate crude oil ranged from a high near $147 per barrel in mid-2008 to
$35 per barrel in January 2009; while the price of natural gas at the Henry Hub
ranged from a high of over $13.00 per MMBtu in mid-2008 to $5.00 per MMBtu in
January 2009. On a composite basis, the average price of NGLs
declined from $1.68 per gallon for the third quarter of 2008 to $0.74 per gallon
for the fourth quarter of 2008. The decrease in energy commodity
prices combined with higher costs of capital have led many crude oil and natural
gas producers to reconsider their drilling budgets for 2009. As a
midstream energy company, we provide services for producers and consumers of
natural gas, NGLs, crude oil and certain petrochemicals. The products
that we process, sell or transport are principally used as fuel for residential,
agricultural and commercial heating; feedstocks in petrochemical manufacturing;
and in the production of motor gasoline.
The decrease
in energy commodity prices has caused many oil and natural gas producers, which
include many of our customers, to reduce their drilling budgets in
2009. This has resulted in a substantial reduction in the number of
drilling rigs operating in the United States as surveyed by Baker Hughes
Incorporated. The U.S. operating rig count decreased from a peak of
2,031 rigs in September 2008 to approximately 1,300 in February
2009. We expect oil and gas producers in our operating areas to
reduce their drilling activity to varying degrees, which may lead to lower crude
oil, natural gas and NGL production growth in the near term and, as a result,
lower transportation, processing and marketing volumes for us than would have
otherwise been the case.
In our
natural gas processing business, we hedged approximately 80% of our equity NGL
production margins for 2008 to mitigate the commodity price risk associated with
these volumes. We have hedged approximately 67% of our expected
equity NGL production margins for 2009. Since the hedges were
consummated at prices that are significantly higher than current levels, we are
expected to be partially insulated from lower natural gas processing margins in
2009.
The
recession has reduced demand for midstream energy services and products by
industrial customers. In the fourth quarter of 2008, the
petrochemical industry experienced a dramatic destocking of inventories, which
reduced demand for purity NGL products such as ethane, propane and normal
butane. We expect that petrochemical demand will strengthen in early
2009 and have starting seeing signs of such
demand
through February 2009 as petrochemical customers have begun to restock their
depleted inventories. This trend is also evidenced by slightly higher
operating rates of U.S. ethylene crackers, which averaged approximately 70% of
capacity in February 2009 as compared to 56% in December 2008. Four
additional ethylene crackers were expected to recommence operations in February
2009. The average utilization rate for ethylene crackers in 2008 was
approximately 80%. Based on currently available information, we
expect that the operating rates of U.S. ethylene crackers will approximate 80%
of capacity in 2009. We expect that crude oil prices will rebound
from recent lows in the second half of 2009. As a result, we believe the
petrochemical industry will continue to prefer NGL feedstocks over crude-based
alternatives such as naphtha. In general, when the price of crude oil
rises relative to that of natural gas, NGLs become more attractive as a source
of feedstocks for the petrochemical industry.
The reduction in near-term demand for
crude oil and NGLs has created a contango market (i.e., a market in which the
price of a commodity is higher in future months than the current spot price) for
these products, which, in turn, we are benefiting from through an increase in
revenues earned by our storage assets in Mont Belvieu, Texas.
Liquidity
Outlook
Debt and
equity capital markets have also experienced significant recent
volatility. The major U.S. and international equity market indices
experienced significant losses in 2008, including losses of approximately 38%
and 34% for the S&P 500 and Dow Jones Industrial Average,
respectively. Likewise, the Alerian MLP Index, which is a recognized
major index for publicly traded partnerships, lost approximately 42% of its
value. The contraction in credit available to and investor
redemptions of holdings in certain investment companies and hedge funds
exacerbated the selling pressure and volatility in both the debt and equity
capital markets. This has resulted in a higher cost of debt and
equity capital for the public and private sector. Near term demand
for equity securities through follow on offerings, including our common
units, may be reduced due to the recent problems encountered by investment
companies and hedge funds, both of which significantly participated in equity
offerings over the past few years.
While the
cost of capital has increased, we have demonstrated our ability to access the
debt and equity capital markets during this distressed period. In
December 2008, we issued $500.0 million of 9.75% senior notes. The
higher cost of capital is evident when you compare the interest rate of the
December 2008 senior notes offering to the $400.0 million of 5.65% senior notes
that we issued in March 2008. On a positive note, our indicative cost
of long-term borrowing has improved approximately 250 basis points in early 2009
in conjunction with the recent improvement in the debt capital markets. We
believe that we will be able to either access the capital markets or utilize
availability under our long-term multi-year revolving credit facility to
refinance our $717.6 million of debt obligations that mature in
2009. In January 2009, we issued approximately 10.6 million of our common
units at an effective annual distribution yield of 9.5%. Net offering
proceeds of $225.6 million were used to reduce borrowings and for general
partnership purposes.
The increase in the cost of capital has
caused us to prioritize our respective internal growth projects to select those
with higher rates of return. However, consistent with our business
strategies, we continuously evaluate possible acquisitions of assets that would
complement our current operations. Given the current state of the
credit markets, we believe competition for such assets has decreased, which may
result in opportunities for us to acquire assets at attractive prices that would
be accretive to our partners and expand our portfolio of midstream energy
assets.
Based on
information currently available, we estimate that our capital spending for
property, plant and equipment in 2009 will approximate $1.00 billion, which
includes $820.0 million for growth capital projects and $180.0 million
for sustaining capital expenditures. The 2009 forecast amounts for
growth capital projects include amounts that are expected to be spent on the
Texas Offshore Port System. See “Recent Developments – Texas Offshore
Port System” for additional information regarding this joint
venture.
We expect
four of our significant construction projects to be completed and the assets
placed into service during the first half of 2009. These projects
include (i) the expansion of the Meeker natural gas processing plant, which
began operations in February 2009, (ii) the Exxon Mobil central treating
facility, (iii) the Sherman Extension natural gas pipeline, and (iv) the Shenzi
Crude Oil Pipeline in the Gulf of Mexico. Substantially all of the
financing to fund these projects has been completed. In 2009, we
expect these projects to contribute significant new sources of revenue,
operating income and cash flow from operations.
Hurricanes
Gustav and Ike damaged a number of energy-related assets onshore and offshore
along the Texas and Louisiana Gulf Coast in the summer of 2008,
including certain of our offshore pipelines and platforms. Repairs
are being completed on our affected assets and they are expected to be
ready to return to service once third party production fields return to
operational status over the course of 2009.
A few of
our customers have experienced severe financial problems leading to a
significant impact on their creditworthiness. These financial
problems are rooted in various factors including the significant use of debt,
current financial crises, economic recession and changes in commodity
prices. We are working to implement, to the extent allowable under
applicable contracts, tariffs and regulations, prepayments and other security
requirements, such as letters of credit, to enhance our respective credit
position relating to amounts owed to us by certain customers. We
cannot provide assurance that one or more of our customers will not default on
their obligations to us or that such a default or defaults will not have a
material adverse effect on our consolidated financial position, results of
operations, or cash flows; however, we believe that we have provided adequate
allowances for such customers.
We expect
our proactive approach to funding capital spending and other partnership needs,
combined with sufficient trade credit to operate our businesses efficiently, and
available borrowing capacity under their credit facilities, to provide us with a
foundation to meet our anticipated liquidity and capital requirements in 2009.
We also believe that we will be able to access the capital markets in 2009
to maintain financial flexibility. Based on information currently
available to us, we believe that we will maintain our investment grade credit
ratings and meet our loan covenant obligations in 2009.
Recent
Developments
The
following information highlights our significant developments since January 1,
2008 through the date of this filing.
Enterprise
Products Partners Issues $225.6 million of Common Units
In
January 2009, Enterprise Products Partners sold 10,590,000 common units
representing limited partner interests (including an over-allotment of 990,000
common units) to the public at an offering price of $22.20 per
unit. Net offering proceeds of $225.6 million were used to reduce
borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility and for
general partnership purposes.
High Island
Offshore System Natural Gas Pipeline Resumes Operations
In
December 2008, repairs were completed on the High Island Offshore System
(“HIOS”) pipeline that was severed in September 2008 during Hurricane
Ike. Federal regulators, after approving our inspection and start-up
procedures, authorized the partnership to resume full service on
HIOS. The pipeline has the capacity to transport up to 1.8 Bcf/d of
natural gas.
Operations
Begin at White River Hub
In
December 2008, we and Questar Pipeline Company (“Questar”), a subsidiary of
Questar Corp., announced that service had begun on the White River Hub. Located
in Rio Blanco County, Colo., the White River Hub currently connects our
natural-gas processing plant at Meeker with four interstate natural gas
pipelines: Rockies Express Pipeline LLC; Questar; Northwest Pipeline GP
(including the Williams Willow Creek processing plant, which is currently under
construction); and TransColorado Gas
Transmission
Company. Two more interstate pipelines, the Wyoming Interstate
Company and Colorado Interstate Gas systems, are expected to be connected during
the first quarter of 2009.
Sale
of Interest in Companies to Duncan Energy Partners
In
December 2008, Duncan Energy Partners acquired controlling equity interests in
three midstream energy companies from affiliates of EPO in a transaction valued
at $730.0 million. Duncan Energy Partners acquired a 51.0% membership
interest in Enterprise Texas Pipeline LLC (“Enterprise Texas”); a 51.0%
general partnership interest in Enterprise Intrastate LP (“Enterprise
Intrastate”); and a 66.0% general partnership interest in Enterprise GC, LP
(“Enterprise GC”). In the aggregate, these companies own more than
8,000 miles of natural gas pipelines with 5.6 Bcf/d of capacity; a leased
natural gas storage facility with 6.8 Bcf of storage capacity; more than 1,000
miles of NGL pipelines; approximately 18 MMBbls of leased NGL storage capacity;
and two NGL fractionators with a combined fractionation capacity of 87
MBPD. All of these assets are located in Texas. As
consideration for this dropdown transaction, EPO received 37,333,887 Class B
units valued at $449.5 million and $280.5 million in cash from Duncan Energy
Partners. The Class B limited partner units automatically converted
to common units of Duncan Energy Partners on February 1, 2009. For
additional information regarding this transaction, see “Other Items – Duncan
Energy Partners Transactions” within this Item 7
EPO
Issues $500.0 Million of Senior Notes
In
December 2008, EPO sold $500.0 million in principal amount of 9.75% fixed-rate,
unsecured senior notes due January 2014 (“Senior Notes O”). Net
proceeds from this offering were used to temporarily reduce borrowings
outstanding under EPO’s Multi-Year Revolving Credit Facility and for general
partnership purposes. For additional information regarding this
issuance of debt, see Note 14 of the Notes to Consolidated Financial
Statements included under Item 8 of this annual report.
EPO
Executes $592.6 Million of Credit Facilities
In
November 2008, EPO executed two senior unsecured credit facilities that provide
the partnership with $592.6 million of incremental borrowing
capacity. The facilities are comprised of a $375.0 million credit
facility maturing in November 2009 and a 20.7 billion yen (approximately $217.6
million U.S. dollar equivalent) term loan maturing in March 2009. The
Japanese term loan has a funded cost of approximately 4.93%, including the cost
of related foreign exchange currency swaps. For additional
information regarding these issuances of debt, see Note 14 of the Notes to
Consolidated Financial Statements included under Item 8 of this annual
report.
Texas
Offshore Port System
In
August 2008, we, together with TEPPCO and Oiltanking Holding Americas, Inc.
(“Oiltanking”), announced the formation of the Texas Offshore Port System, a
joint venture to design, construct, operate and own a Texas offshore crude oil
port and a related onshore pipeline and storage system that would facilitate
delivery of waterborne crude oil to refining centers located along the upper
Texas Gulf Coast. Demand for such projects is being driven by planned and
expected refinery expansions along the Gulf Coast, expected increases in
shipping traffic and operating limitations of regional ship
channels.
The joint
venture’s primary project, referred to as “TOPS,” includes (i) an offshore port
(which will be located approximately 36 miles from Freeport, Texas), (ii)
an onshore storage facility with approximately 3.9 million barrels of crude
oil storage capacity, and (iii) an 85-mile crude oil pipeline system having a
transportation capacity of up to 1.8 million barrels per day, that will extend
from the offshore port to a storage facility near Texas City,
Texas. The joint venture’s complementary project, referred to as the
Port Arthur Crude Oil Express (or “PACE”) will transport crude oil from Texas
City, including crude oil from TOPS, and will consist of a 75-mile pipeline and
1.2 million barrels of crude oil storage capacity in the Port Arthur, Texas
area. Development of the TOPS and PACE projects is supported by
long-term contracts with affiliates of Motiva Enterprises LLC (“Motiva”) and
Exxon Mobil Corporation
(“Exxon
Mobil”), which have committed a combined 725 MBPD of crude oil to the
projects. The timing of the construction and related capital costs of the
TOPS and PACE projects will be affected by the acquisition of requisite
permits.
We,
TEPPCO and Oiltanking each own, through our respective subsidiaries, a one-third
interest in the joint venture. The aggregate cost of the TOPS and PACE
projects is expected to be approximately $1.8 billion (excluding
capitalized interest), with the majority of such capital expenditures currently
expected to occur in 2010 and 2011. We and TEPPCO have each guaranteed up
to approximately $700.0 million, which includes a contingency amount for
potential cost overruns, of the capital contribution obligations of our
respective subsidiary partners in the joint venture. As of December 31,
2008, our investment in the Texas Offshore Port System was $35.9
million.
Acquisition
of Remaining Interest in Dixie
In August
2008, we acquired the remaining 25.8% ownership interest in Dixie Pipeline
Company (“Dixie”) for $57.1 million. As a result of this transaction,
we own 100.0% of Dixie, which owns a 1,371-mile pipeline system that delivers
NGLs (primarily propane) to customers along the U.S. Gulf Coast and southeastern
United States.
Reorganization
of Commercial Management Team
In July 2008, Mr. A. J. Teague,
Executive Vice President, was elected as a Director to the Boards of both our
general partner and that of Duncan Energy Partners and as Chief Commercial
Officer responsible for managing all of the commercial activities of the two
partnerships. In connection with Mr. Teague’s appointment as Chief
Commercial Officer, certain members of our senior management team were realigned
to report to Mr. Teague. Mr. Teague will continue to report to
Michael A. Creel, President and Chief Executive Officer (“CEO”) of Enterprise
Products Partners.
Independence
Trail and Hub Resume Operations
In April 2008, production at the
Independence Hub natural gas platform was shut-in due to a leak in the
flex-joint assembly where the Independence Trail export pipeline connects to the
platform. In July 2008, repairs were completed and the Independence
Hub platform and Trail pipeline returned to operation. Our
Independence Trail export pipeline recorded $17.0 million of expense associated
with the flex-joint repairs. We have submitted a claim with our
insurance carriers regarding the flex-joint repair costs. To the
extent that we receive cash proceeds from this claim in the future, such amounts
would be recorded as income in the period of receipt.
EPO
Issues $1.10 Billion of Senior Notes
In April 2008, EPO sold $400.0 million
in principal amount of 5.65% fixed-rate, unsecured senior notes due April 2013
(“Senior Notes M”) and $700.0 million in principal amount of 6.50% fixed-rate,
unsecured senior notes due January 2019 (“Senior Notes N”). Net
proceeds from this offering were used to temporarily reduce borrowings
outstanding under EPO’s Multi-Year Revolving Credit Facility. For
additional information regarding this issuance of debt, see Note 14 of the Notes
to Consolidated Financial Statements included under Item 8 of this annual
report.
Duncan
Energy Partners’ Shelf Registration Statement
In March
2008, Duncan Energy Partners filed a universal shelf registration statement with
the SEC that authorized its issuance of up to $1.00 billion in debt and equity
securities. As of February 2, 2008, Duncan Energy Partners has issued
$0.5 million in equity securities under this registration
statement.
Pioneer
Cryogenic Natural Gas Processing Facility Commences Operations
In February 2008, we commenced
operations of the Pioneer cryogenic natural gas processing
facility. Located near the Opal Hub in southwestern Wyoming, this new
facility is designed to process up to 700 MMcf/d of natural gas and extract as
much as 30 MBPD of NGLs. We intend to maintain the operational
capability of our Pioneer silica gel natural gas processing plant, which is
located adjacent to the Pioneer cryogenic plant, as a back-up to provide
producers with additional assurance of our processing capability at the
complex. NGLs extracted at our Pioneer complex are transported on our
Mid-America Pipeline System and ultimately to our Hobbs and Mont Belvieu NGL
fractionators.
In late March 2008, operations at our
Pioneer cryogenic natural gas processing facility were temporarily suspended
following a release of natural gas and subsequent fire. No injuries
resulted from the incident, which was restricted to a small area within the
plant. The facility resumed operations in April 2008.
Results
of Operations
We have
four reportable business segments: NGL Pipelines & Services, Onshore Natural
Gas Pipelines & Services, Offshore Pipelines & Services and
Petrochemical Services. Our business segments are generally organized
and managed according to the type of services rendered (or technologies
employed) and products produced and/or sold.
We
evaluate segment performance based on the non-GAAP financial measure of gross
operating margin. Gross operating margin (either in total or by
individual segment) is an important performance measure of the core
profitability of our operations. This measure forms the basis of our
internal financial reporting and is used by senior management in deciding how to
allocate capital resources among business segments. We believe that
investors benefit from having access to the same financial measures that our
management uses in evaluating segment results. The GAAP financial
measure most directly comparable to total segment gross operating margin is
operating income. Our non-GAAP financial measure of total segment
gross operating margin should not be considered as an alternative to GAAP
operating income.
We define
total segment gross operating margin as consolidated operating income before (i)
depreciation, amortization and accretion expense; (ii) operating lease expenses
for which we do not have the payment obligation; (iii) gains and losses from
asset sales and related transactions; and (iv) general and administrative
costs. Gross operating margin is exclusive of other income and
expense transactions, provision for income taxes, minority interest,
extraordinary charges and the cumulative effect of change in accounting
principle. Gross operating margin by segment is calculated by
subtracting segment operating costs and expenses (net of the adjustments noted
above) from segment revenues, with both segment totals before the elimination of
intersegment and intrasegment transactions. Intercompany accounts and
transactions are eliminated in consolidation.
We
include equity in earnings of unconsolidated affiliates in our measurement of
segment gross operating margin and operating income. Our equity
investments with industry partners are a vital component of our business
strategy. They are a means by which we conduct our operations to
align our interests with those of our customers and/or
suppliers. This method of operation also enables us to achieve
favorable economies of scale relative to the level of investment and business
risk assumed versus what we could accomplish on a stand alone
basis. Many of these businesses perform supporting or complementary
roles to our other business operations.
Our consolidated gross operating margin
amounts include the gross operating margin amounts of Duncan Energy Partners on
a 100.0% basis. Volumetric data associated with the operations of
Duncan Energy Partners are also included on a 100.0% basis in our consolidated
statistical data.
For
additional information regarding our business segments, see Note 16 of the Notes
to Consolidated Financial Statements included under Item 8 of this annual
report.
Selected
Price and Volumetric Data
The
following table illustrates selected annual and quarterly industry index prices
for natural gas, crude oil and selected NGL and petrochemical products for the
periods presented.
|
|
|
|
|
|
|
|
|
Polymer
|
Refinery
|
|
|
Natural
|
|
|
|
Normal
|
|
Natural
|
Grade
|
Grade
|
|
|
Gas,
|
Crude
Oil,
|
Ethane,
|
Propane,
|
Butane,
|
Isobutane,
|
Gasoline,
|
Propylene,
|
Propylene,
|
|
|
$/MMBtu
|
$/barrel
|
$/gallon
|
$/gallon
|
$/gallon
|
$/gallon
|
$/gallon
|
$/pound
|
$/pound
|
|
|
(1)
|
(2)
|
(1)
|
(1)
|
(1)
|
(1)
|
(1)
|
(1)
|
(1)
|
|
2006
Averages
|
$7.24
|
$66.09
|
$0.66
|
$1.01
|
$1.20
|
$1.24
|
$1.44
|
$0.47
|
$0.41
|
|
2007
Averages
|
$6.86
|
$72.30
|
$0.79
|
$1.21
|
$1.42
|
$1.49
|
$1.68
|
$0.52
|
$0.47
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
1st
Quarter
|
$8.03
|
$97.91
|
$1.01
|
$1.47
|
$1.80
|
$1.87
|
$2.12
|
$0.61
|
$0.54
|
|
2nd
Quarter
|
$10.94
|
$123.88
|
$1.05
|
$1.70
|
$2.05
|
$2.08
|
$2.64
|
$0.70
|
$0.67
|
|
3rd
Quarter
|
$10.25
|
$118.01
|
$1.09
|
$1.68
|
$1.97
|
$1.99
|
$2.52
|
$0.78
|
$0.66
|
|
4th
Quarter
|
$6.95
|
$58.32
|
$0.42
|
$0.80
|
$0.90
|
$0.96
|
$1.09
|
$0.37
|
$0.22
|
|
2008
Averages
|
$9.04
|
$99.53
|
$0.89
|
$1.41
|
$1.68
|
$1.72
|
$2.09
|
$0.62
|
$0.52
|
|
|
|
|
|
(1)
Natural
gas, NGL, polymer grade propylene and refinery grade propylene prices
represent an average of various commercial index prices including Oil
Price Information Service (“OPIS”) and Chemical Market Associates, Inc.
(“CMAI”). Natural gas price is representative of Henry-Hub
I-FERC. NGL prices are representative of Mont Belvieu Non-TET
pricing. Refinery grade propylene represents a weighted-average
of CMAI spot prices. Polymer-grade propylene represents average
CMAI contract pricing.
(2)
Crude
oil price is representative of an index price for West Texas
Intermediate.
|
The
following table presents our significant average throughput, production and
processing volumetric data. These statistics are reported on a net
basis, taking into account our ownership interests in certain joint ventures and
reflect the periods in which we owned an interest in such
operations. These statistics include volumes for newly constructed
assets since the dates such assets were placed into service and for recently
purchased assets since the date of acquisition.
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
NGL
Pipelines & Services, net:
|
|
|
|
|
|
|
|
|
|
|
NGL
transportation volumes (MBPD)
|
|
|
1,819 |
|
|
|
1,666 |
|
|
|
1,577 |
|
|
NGL
fractionation volumes (MBPD)
|
|
|
429 |
|
|
|
394 |
|
|
|
312 |
|
|
Equity
NGL production (MBPD)
|
|
|
108 |
|
|
|
88 |
|
|
|
63 |
|
|
Fee-based
natural gas processing (MMcf/d)
|
|
|
2,524 |
|
|
|
2,565 |
|
|
|
2,218 |
|
|
Onshore
Natural Gas Pipelines & Services, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas transportation volumes (BBtus/d)
|
|
|
7,477 |
|
|
|
6,632 |
|
|
|
6,012 |
|
|
Offshore
Pipelines & Services, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas transportation volumes (BBtus/d)
|
|
|
1,408 |
|
|
|
1,641 |
|
|
|
1,520 |
|
|
Crude
oil transportation volumes (MBPD)
|
|
|
169 |
|
|
|
163 |
|
|
|
153 |
|
|
Platform
natural gas processing (MMcf/d)
|
|
|
632 |
|
|
|
494 |
|
|
|
159 |
|
|
Platform
crude oil processing (MBPD)
|
|
|
15 |
|
|
|
24 |
|
|
|
15 |
|
|
Petrochemical
Services, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Butane
isomerization volumes (MBPD)
|
|
|
86 |
|
|
|
90 |
|
|
|
81 |
|
|
Propylene
fractionation volumes (MBPD)
|
|
|
58 |
|
|
|
68 |
|
|
|
56 |
|
|
Octane
additive production volumes (MBPD)
|
|
|
9 |
|
|
|
9 |
|
|
|
9 |
|
|
Petrochemical
transportation volumes (MBPD)
|
|
|
108 |
|
|
|
105 |
|
|
|
97 |
|
|
Total,
net:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL,
crude oil and petrochemical transportation volumes (MBPD)
|
|
|
2,096 |
|
|
|
1,934 |
|
|
|
1,827 |
|
|
Natural
gas transportation volumes (BBtus/d)
|
|
|
8,885 |
|
|
|
8,273 |
|
|
|
7,532 |
|
|
Equivalent
transportation volumes (MBPD) (1)
|
|
|
4,434 |
|
|
|
4,111 |
|
|
|
3,809 |
|
|
(1) Reflects
equivalent energy volumes where 3.8 MMBtus of natural gas are equivalent
to one barrel of NGLs.
|
|
Comparison
of Results of Operations
The
following table summarizes the key components of our results of operations for
the periods indicated (dollars in thousands):
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Revenues
|
|
$ |
21,905,656 |
|
|
$ |
16,950,125 |
|
|
$ |
13,990,969 |
|
|
Operating
costs and expenses
|
|
|
20,460,964 |
|
|
|
16,009,051 |
|
|
|
13,089,091 |
|
|
General
and administrative costs
|
|
|
90,550 |
|
|
|
87,695 |
|
|
|
63,391 |
|
|
Equity
in earnings of unconsolidated affiliates
|
|
|
59,104 |
|
|
|
29,658 |
|
|
|
21,565 |
|
|
Operating
income
|
|
|
1,413,246 |
|
|
|
883,037 |
|
|
|
860,052 |
|
|
Interest
expense
|
|
|
400,686 |
|
|
|
311,764 |
|
|
|
238,023 |
|
|
Provision
for income taxes
|
|
|
26,401 |
|
|
|
15,257 |
|
|
|
21,323 |
|
|
Minority
interest
|
|
|
41,376 |
|
|
|
30,643 |
|
|
|
9,079 |
|
|
Net
income
|
|
|
954,021 |
|
|
|
533,674 |
|
|
|
601,155 |
|
Our gross operating margin by segment
and in total is as follows for the periods indicated (dollars in
thousands):
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Gross
operating margin by segment:
|
|
|
|
|
|
|
|
|
|
|
NGL
Pipelines & Services
|
|
$ |
1,290,458 |
|
|
$ |
812,521 |
|
|
$ |
752,548 |
|
|
Onshore
Natural Gas Pipelines & Services
|
|
|
411,344 |
|
|
|
335,683 |
|
|
|
333,399 |
|
|
Offshore
Pipeline & Services
|
|
|
188,083 |
|
|
|
171,551 |
|
|
|
103,407 |
|
|
Petrochemical
Services
|
|
|
167,584 |
|
|
|
172,313 |
|
|
|
173,095 |
|
|
Total
segment gross operating margin
|
|
$ |
2,057,469 |
|
|
$ |
1,492,068 |
|
|
$ |
1,362,449 |
|
For a
reconciliation of non-GAAP gross operating margin to GAAP operating income and
further to GAAP income before provision for income taxes, minority interest and
the cumulative effect of change in accounting principles, see “Other Items –
Non-GAAP Reconciliations” included within this Item 7.
The
following table summarizes the contribution to revenues from each business
segment (including the effects of eliminations and adjustments) during the
periods indicated (dollars in thousands):
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
NGL
Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
Sales
of NGLs
|
|
$ |
14,680,607 |
|
|
$ |
11,757,895 |
|
|
$ |
9,442,403 |
|
|
Sales
of other petroleum and related products
|
|
|
2,387 |
|
|
|
3,027 |
|
|
|
2,353 |
|
|
Midstream
services
|
|
|
698,957 |
|
|
|
710,447 |
|
|
|
745,187 |
|
|
Total
|
|
|
15,381,951 |
|
|
|
12,471,369 |
|
|
|
10,189,943 |
|
|
Onshore
Natural Gas Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
of natural gas
|
|
|
3,091,296 |
|
|
|
1,481,569 |
|
|
|
1,103,169 |
|
|
Midstream
services
|
|
|
480,802 |
|
|
|
588,526 |
|
|
|
595,726 |
|
|
Total
|
|
|
3,572,098 |
|
|
|
2,070,095 |
|
|
|
1,698,895 |
|
|
Offshore
Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
of natural gas
|
|
|
100 |
|
|
|
101 |
|
|
|
307 |
|
|
Sales
of other petroleum and related products
|
|
|
11,144 |
|
|
|
12,086 |
|
|
|
4,562 |
|
|
Midstream
services
|
|
|
257,166 |
|
|
|
211,624 |
|
|
|
140,994 |
|
|
Total
|
|
|
268,410 |
|
|
|
223,811 |
|
|
|
145,863 |
|
|
Petrochemical
Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
of other petroleum and related products
|
|
|
2,593,856 |
|
|
|
2,115,429 |
|
|
|
1,873,722 |
|
|
Midstream
services
|
|
|
89,341 |
|
|
|
69,421 |
|
|
|
82,546 |
|
|
Total
|
|
|
2,683,197 |
|
|
|
2,184,850 |
|
|
|
1,956,268 |
|
|
Total
consolidated revenues
|
|
$ |
21,905,656 |
|
|
$ |
16,950,125 |
|
|
$ |
13,990,969 |
|
Our
revenues are derived from a wide customer base. During 2008, our
largest customer was LyondellBasell Industries (“LBI”) and its affiliates, which
accounted for 9.6% of our consolidated revenues. In 2007 and 2006,
our largest customer was The Dow Chemical Company and its affiliates, which
accounted for 6.9% and 6.1%, respectively, of our consolidated
revenues.
On
January 6, 2009, LBI announced that its U.S. operations had voluntarily filed to
reorganize under Chapter 11 of the U.S. Bankruptcy Code. At the time
of the bankruptcy filing, we had approximately $17.3 million of credit exposure
to LBI, which was reduced to approximately $10.0 million through remedies
provided under certain pipeline tariffs. In addition, we are seeking
to have LBI accept certain contracts and have filed claims pursuant to current
Bankruptcy Court Orders that we expect will allow us to recover the majority of
the remaining credit exposure.
For 2008,
LBI accounted for 10.2%, or $1.6 billion, of revenues attributable to our NGL
Pipelines & Services business segment and 19.2%, or $516.2 million, of
revenues attributable to our Petrochemical Services business
segment.
Comparison
of 2008 with 2007
Revenues
for 2008 were $21.91 billion compared to $16.95 billion for 2007. The
$4.96 billion year-to-year increase in consolidated revenues is primarily due to
higher energy commodity sales volumes and prices during 2008 relative to
2007. These factors accounted for $5.01 billion of the year-to-year
increase in consolidated revenues associated with our NGL, natural gas and
petrochemical marketing activities. Equity NGLs we produced at our
newly constructed Meeker and Pioneer natural gas plants and sold in connection
with our NGL marketing activities contributed $731.3 million of the year-to-year
increase in marketing activity revenues.
Operating
costs and expenses were $20.46 billion for 2008 versus $16.01 billion for
2007. The $4.45 billion year-to-year increase in consolidated
operating costs and expenses is primarily due to higher cost of sales associated
with our marketing activities. The cost of sales of our marketing
activities increased $3.57 billion year-to-year primarily due to higher energy
commodity sales volumes and prices. Likewise, the operating costs and
expenses of our natural gas processing plants increased $306.3 million
year-to-year primarily due to higher energy commodity prices. Consolidated
operating costs and expenses attributable to newly constructed assets we placed
into service after January 1, 2007 increased $414.3 million
year-to-year. General and administrative costs increased $2.9 million
year-to-year.
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 $1.40 per gallon during 2008 versus $1.19 per gallon
during 2007. 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, Texas, which is the primary industry hub for domestic NGL
production. The market price of natural gas (as measured at Henry
Hub) averaged $9.04 per MMBtu during 2008 versus $6.86 per MMBtu during
2007. See “Results of Operations - Selected Price and Volumetric
Data” within this Item 7 for additional historical energy commodity pricing
information.
Equity in
earnings from our unconsolidated affiliates was $59.1 million for 2008 compared
to $29.7 million for 2007, a $29.4 million year-to-year
increase. Equity in earnings from our investment in Cameron Highway
Oil Pipeline Company (“Cameron Highway”) increased $27.6 million year-to-year
due to higher transportation volumes and lower interest expense. On a
100.0% basis, Cameron Highway had crude oil transportation volumes of 161 MBPD
during 2008 compared to 88 MBPD during 2007. Equity in earnings from
our investment in Jonah Gas Gathering Company (“Jonah”) increased $12.1 million
year-to-year. We earned a fixed 19.4% interest in Jonah during the
third quarter of 2007 upon completion of certain achievements with respect to
the Phase V Expansion of the Jonah Gathering System. Equity in
earnings from our investment in Nemo Gathering Company, LLC (“Nemo”) increased
$5.0 million year-to-year due to the recognition of a non-cash impairment charge
in the second quarter of 2007. Collectively, equity earnings from our
other investments decreased $15.3 million year-to-year primarily due to higher
repair
and maintenance expenses during 2008 relative to 2007 as well as the effects of
downtime and reduced volumes attributable to Hurricanes Gustav and
Ike.
Operating
income for 2008 was $1.41 billion compared to $883.0 million for
2007. Collectively, the aforementioned changes in revenues, costs and
expenses and equity earnings contributed to the $530.2 million increase in
operating income year-to-year.
Interest
expense increased to $400.7 million for 2008 from $311.8 million for
2007. The $88.9 million year-to-year increase in interest expense is
primarily due to our issuance of Senior Notes M and N in the second quarter of
2008 and Senior Notes L in the third quarter of 2007. Average debt
principal outstanding during 2008 was $7.93 billion compared to $6.18 billion
during 2007.
Provision
for income taxes increased $11.1 million year-to-year primarily due to higher
expenses associated with the Texas Margin Tax. The increase in
expenses for the Texas Margin Tax primarily reflects a higher taxable margin in
the State of Texas during 2008 relative to 2007. In addition we
recognized a $4.4 million benefit with respect to the Texas Margin Tax during
2007 due to the reorganization of certain of our entities from partnerships to
limited liability companies. Minority interest expense increased
$10.7 million year-to-year attributable to the public unitholders of Duncan
Energy Partners and third-party ownership interests in the Independence Hub
platform.
As a
result of items noted in the previous paragraphs, our consolidated net income
increased $420.3 million year-to-year to $954.0 million for 2008 compared to
$533.7 million for 2007.
In
general, Hurricanes Gustav and Ike had an adverse effect across our operations
in the Gulf of Mexico and along the U.S. Gulf Coast during
2008. Storm-related disruptions in natural gas, NGL and crude oil
production in these regions resulted in reduced volumes available to our
pipeline systems, natural gas processing plants, NGL fractionators and offshore
platforms, which in turn caused a decrease in gross operating margin for certain
operations. In addition, property damage caused by Hurricanes Gustav
and Ike resulted in lower revenues due to facility downtime as well as higher
operating costs and expenses at certain of our plants and
pipelines. As a result of our allocated share of EPCO’s insurance
deductibles for windstorm coverage, gross operating margin for 2008 includes
$47.9 million of repair expenses for property damage sustained by our assets as
a result of the hurricanes.
We
estimate that gross operating margin was reduced by $77.0 million during 2008
due to the effects of Hurricanes Gustav and Ike as a result of supply
interruptions and facility downtime. For more information regarding
our insurance program and claims related to these storms, see “Other Items –
Insurance Matters” 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 $1.29 billion for 2008 compared to $812.5 million for
2007. The $478.0 million year-to-year increase in segment gross
operating margin is due to strong natural gas processing margins and
petrochemical demand for NGLs as well as an increase in equity NGL production
attributable to our Meeker and Pioneer natural gas processing
facilities. Results for 2007 include $32.7 million of proceeds from
business interruption insurance claims compared to $1.1 million for
2008. The following paragraphs provide a discussion of segment
results excluding proceeds from business interruption insurance
claims.
Gross
operating margin from our natural gas processing and related NGL marketing
business was $815.3 million for 2008 compared to $389.1 million for
2007. Equity NGL production increased to 108 MBPD during 2008 from 88
MBPD during 2007. The $426.2 million year-to-year increase in gross
operating margin is largely due to contributions from our Meeker and Pioneer
cryogenic natural gas processing facilities, which commenced commercial
operations during October 2007 and February 2008, respectively. These
facilities contributed $274.5 million of the year-to-year increase in gross
operating margin and produced 49 MBPD of equity NGLs during 2008 compared to 23
MBPD during 2007.
Collectively,
gross operating margin from the remainder of this business increased $151.7
million year-to-year primarily due improved results from our NGL marketing
activities attributable to higher NGL sales margins and volumes in 2008 relative
to 2007. Results for 2008 include $6.8 million of hurricane-related
property damage repair expenses associated with our natural gas processing
plants in southern Louisiana.
Gross
operating margin from our NGL pipelines and related storage business was $369.2
million for 2008 compared to $302.2 million for 2007. Total NGL
transportation volumes increased to 1,819 MBPD during 2008 from 1,666 MBPD
during 2007. The $67.0 million year-to-year increase in gross operating
margin from this business is primarily due to improved results from our
Mid-America and Seminole Pipeline Systems and our Mont Belvieu storage
complex. Gross operating margin from our Mid-America and Seminole
Pipeline Systems increased $43.6 million year-to-year due to higher
transportation volumes and an increase in the system-wide
tariff. These pipeline systems contributed 116 MBPD of the
year-to-year increase in NGL transportation volumes. Gross operating
margin from our Mont Belvieu storage complex increased $15.5 million as a result
of higher storage revenues during 2008 relative to 2007.
Gross
operating margin from the remainder of our NGL pipeline and storage assets
increased $7.9 million year-to-year attributable to (i) higher transportation
volumes on our Dixie Pipeline System and our Lou-Tex NGL Pipeline and (ii) lower
maintenance and pipeline integrity expenses on our Dixie Pipeline and South
Louisiana Pipeline System. In general the improved results from our NGL pipeline
and storage assets were partially offset by downtime and reduced volumes as a
result of Hurricanes Gustav and Ike during 2008. Results for 2008
include $0.9 million of hurricane-related property damage repair
expenses.
Gross
operating margin from our NGL fractionation business was $104.8 million for 2008
compared to $88.4 million for 2007. Fractionation volumes increased
from 394 MBPD during 2007 to 429 MBPD during 2008. Gross operating
margin from our Hobbs fractionator increased $26.7 million
year-to-year. Our Hobbs fractionator was placed into service during
August 2007 and contributed a 41 MBPD year-to-year increase in NGL fractionation
volumes. Collectively, gross operating margin from our other NGL
fractionators decreased $10.3 million year-to-year primarily due to downtime and
lower volumes at our Norco, South Texas and Baton Rouge fractionators and a
combined $0.9 million of hurricane-related property damage repair expenses in
2008.
Onshore
Natural Gas Pipelines & Services. Gross operating margin
from this business segment was $411.3 million for 2008 compared to $335.7
million for 2007, a $75.6 million year-to-year increase. Our onshore
natural gas transportation volumes were 7,477 BBtus/d during 2008 compared to
6,632 BBtus/d during 2007. Gross operating margin from our onshore
natural gas pipeline and related natural gas marketing business increased $64.7
million year-to-year to $371.9 million for 2008 from $307.2 million for
2007. Collectively, gross operating margin from our natural gas pipelines
increased $75.1 million year-to-year primarily due to (i) higher revenues from
our San Juan Gathering System, (ii) higher transportation activity on our Texas
Intrastate System, (iii) higher natural gas sales margins on our Acadian Gas
System and (iv) increased equity earnings from our investment in
Jonah. Results for 2008 include $1.3 million of hurricane-related
property damage repair expenses attributable to Hurricanes Gustav and
Ike. Gross operating margin from our natural gas marketing activities
decreased $10.4 million year-to-year primarily due to non-cash mark-to-market
related charges that are expected to be recouped in cash in future periods
extending through 2009.
Our
natural gas marketing business increased significantly during
2008. These marketing activities have four primary objectives: (i) to
mitigate risk; (ii) maximize the use of our natural gas assets; (iii) to provide
real-time market intelligence; and (iv) to link our noncontiguous natural gas
assets together to enhance the profitability of such operations. To achieve
these objectives, our natural gas marketing activities transact with various
parties to provide transportation, balancing, storage, supply and sales
services. The majority of our natural gas marketing activities are
focused on the Gulf Coast and Rocky Mountain regions.
Our
natural gas marketing business acquires a significant portion of the natural gas
it sells from our processing plants and additional supplies from third parties
at pipeline interconnects to facilitate
incremental
throughput on our natural gas transportation pipelines. This purchased gas is
then sold to industrial consumers, utilities and power plants at prices that
include a transportation fee. In addition, sales are made to third
party marketing companies at industry hub locations in order to balance our
supply/demand portfolio. Our purchase and sale transactions are
typically based on published daily or monthly index prices. We
utilize financial instruments to hedge various transactions within our natural
gas marketing business.
We use
third party transportation and storage capacity to link together our
non-contiguous natural gas assets. Our natural gas marketing business
contracts with third party transportation and storage providers to provide
services on both a firm and interruptible basis. This strategy allows
us to complement and strengthen our portfolio of natural gas
assets.
Gross
operating margin from our natural gas storage business was $39.4 million for
2008 compared to $28.4 million for 2007. The $11.0 million
year-to-year increase in gross operating margin is primarily due to increased
storage activity at our Petal natural gas storage facility and improved results
at our Wilson facility. We placed additional natural gas storage
caverns in operation during the third quarters of 2007 and 2008 at our Petal
facility, which provided an additional 1.6 Bcf and 4.2 Bcf of subscribed
capacity, respectively.
Offshore
Pipelines & Services. Gross operating margin from this
business segment was $188.1 million for 2008 compared to $171.6 million for
2007. The $16.5 million year-to-year increase in segment gross
operating margin is primarily due to contributions from our Independence Hub and
Trail project and improved results from our Cameron Highway Oil
Pipeline. Results from this business segment for 2008 were negatively
impacted by (i) downtime and $17.0 million of repair expenses associated with a
leak on the Independence Trail pipeline and (ii) the effects of Hurricanes
Gustav and Ike including downtime, reduced volumes and $37.2 million of property
damage repair expenses. Results for 2008 include $0.2 million of
proceeds from business interruption insurance claims compared to $3.4 million of
proceeds during 2007. The following paragraphs provide a discussion
of segment results excluding proceeds from business interruption
insurance.
Gross
operating margin from our offshore platform services business was $144.8 million
for 2008 compared to $111.7 million for 2007, a $33.1 million year-to-year
increase. Our Independence Hub platform, which was completed in March
2007, provided a $49.5 million year-to-year increase in gross operating
margin. Gross operating margin increased year-to-year despite the
platform being shut-in for 66 days during the second quarter of 2008 due to a
leak on the Independence Trail export pipeline. While the
Independence Hub platform did not earn volumetric fees during the period of
suspended operations, the platform continued to earn its fixed demand revenues
of approximately $4.6 million per month. Gross operating margin from the
remainder of this business decreased $16.4 million year-to-year primarily due to
the effects of Hurricanes Gustav and Ike and upstream supply
disruptions. Results for our offshore platform services business
include $5.0 million of hurricane-related property damage repair expenses in
2008. Our net platform natural gas processing volumes increased to
632 MMcf/d during 2008 compared to 494 MMcf/d during 2007.
Gross
operating margin from our offshore crude oil pipeline business was $36.2 million
for 2008 versus $21.1 million for 2007, a $15.1 million year-to-year
increase. Gross operating margin increased $27.6 million year-to-year
due to increased equity in earnings from Cameron Highway, which benefited from
higher crude oil transportation volumes and lower interest expense in 2008
relative to 2007. Net to our ownership interest, crude oil
transportation volumes on the Cameron Highway Oil Pipeline System were 80 MBPD
in 2008 compared to 44 MBPD in 2007. Gross operating margin from the
remainder of this business decreased $12.5 million year-to-year due to the
effects of Hurricanes Gustav and Ike, which include (i) downtime resulting from
damage sustained by our pipelines as well as downstream assets owned by
third-party and (ii) reduced volumes available to our pipelines as a result of
upstream supply disruptions. Results for our offshore crude oil
pipeline business include $2.3 million of hurricane-related property damage
repair expenses in 2008. Total offshore crude oil transportation
volumes were 169 MBPD during 2008 versus 163 MBPD during 2007.
Gross
operating margin from our offshore natural gas pipeline business was $6.9
million for 2008 compared to $35.4 million for 2007. Offshore natural gas
transportation volumes were 1,408 BBtus/d during 2008 versus 1,641 BBtus/d
during 2007. Gross operating margin from our Independence Trail pipeline,
which first received production in July 2007, increased $28.4 million
year-to-year on a 241 BBtus/d increase in transportation
volumes. Collectively, gross operating margin from our other offshore
natural gas pipelines decreased $56.9 million year-to-year primarily due to the
effects of Hurricanes Gustav and Ike. Results for 2008 include $29.9
million of hurricane-related property damage repair expenses.
Petrochemical
Services. Gross operating margin from this business segment
was $167.6 million for 2008 compared to $172.3 million for
2007. Gross operating margin from our propylene fractionation and
pipeline business was $83.1 million for 2008 compared to $62.6 million for
2007. The $20.5 million year-to-year increase in gross operating
margin is largely due to higher propylene sales margins during 2008 relative to
2007. Results for our propylene fractionation and related pipeline
business for 2008 include $0.8 million of hurricane-related property damage
repair expenses.
Gross
operating margin from our butane isomerization business was $95.9 million for
2008 compared to $91.4 million for 2007. The $4.5 million
year-to-year increase in gross operating margin is primarily due to strong
demand for high-purity isobutane and higher NGL prices, which resulted in higher
by-product sales revenues during 2008 relative to 2007. Butane
isomerization volumes decreased to 86 MBPD during 2008 compared to 90 MBPD
during 2007 due to production interruptions resulting from Hurricane Ike and
operational issues at our octane enhancement facility during the third quarter
of 2008.
Gross
operating margin from our octane enhancement business was a loss of $11.3
million for 2008 compared to $18.3 million of earnings for 2007. The
$29.6 million year-to-year decrease in gross operating margin is primarily due
to downtime, reduced volumes and higher operating expenses as a result of
operational issues during the third quarter of 2008 and the effects of Hurricane
Ike.
Comparison
of 2007 with 2006
Revenues
for 2007 were $16.95 billion compared to $13.99 billion for 2006. The
$2.96 billion year-to-year increase in consolidated revenues is primarily due to
higher sales volumes and energy commodity prices in 2007 relative to
2006. These factors accounted for a $2.94 billion increase in
consolidated revenues associated with our marketing
activities. Revenues from business interruption insurance proceeds
totaled $36.1 million in 2007 compared to $63.9 million in 2006.
Operating
costs and expenses were $16.01 billion for 2007 versus $13.09 billion for
2006. The $2.92 billion year-to-year increase in consolidated
operating costs and expenses is primarily due to an increase in the cost of
sales associated with our marketing activities. The cost of sales of
our NGL, natural gas and petrochemical products increased $2.45 billion
year-to-year as a result of an increase in volumes and higher energy commodity
prices. Operating costs and expenses associated with our natural gas
processing plants increased $185.7 million year-to-year as a result of higher
energy commodity prices in 2007 relative to 2006. Operating costs and
expenses associated with assets we constructed and placed into service or
acquired since January 1, 2006 increased $188.1 million
year-to-year.
General
and administrative costs were $87.7 million for 2007 compared to $63.4 million
for 2006. The $24.3 million year-to-year increase in general and administrative
costs is primarily due to the recognition of a severance obligation during 2007
and an increase in legal fees.
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 $1.19 per gallon during 2007 versus $1.00 per gallon
during 2006. The Henry Hub market price of natural gas averaged $6.86
per MMBtu during 2007 versus $7.24 per MMBtu during 2006. For
additional historical energy commodity pricing information, see “Results of
Operations – Selected Price and Volumetric Data” within this Item
7.
Equity in
earnings from unconsolidated affiliates were $29.7 million for 2007 compared to
$21.6 million for 2006. Equity in earnings from our investment in
Jonah increased $9.1 million year-to-year due to an increase in our ownership
interest in Jonah effective during the third quarter of 2007. Equity
in earnings for 2007 include a non-cash impairment charge of $7.0 million
associated with our investment in Nemo compared to a non-cash impairment charge
of $7.4 million in 2006 related to our investment in Neptune Pipeline Company,
L.L.C. (“Neptune”). Collectively, equity in earnings from our other
unconsolidated affiliates decreased $1.4 million year-to-year primarily due to
the sale of our investment in Coyote Gas Treating, LLC in August
2006.
Operating
income for 2007 was $883.0 million compared to $860.1 million for
2006. Collectively, the aforementioned changes in revenues, costs and
expenses and equity in earnings from unconsolidated affiliates contributed to
the $22.9 million increase in operating income year-to-year.
Interest
expense increased $73.7 million year-to-year primarily due to our issuance of
junior subordinated notes in the second quarter of 2007 and third quarter of
2006 and the issuance of Senior Notes L in the third quarter of
2007. Our consolidated interest expense for 2007 includes $11.6
million associated with Duncan Energy Partners’ credit facility. Our
average debt principal outstanding was $6.18 billion in 2007 compared to $4.92
billion in 2006. Minority interest increased $21.6 million
year-to-year attributable to the public unit holders of Duncan Energy Partners
and third-party ownership interests in the Independence Hub
platform.
As a
result of items noted in the previous paragraphs, our consolidated net income
decreased $67.5 million year-to-year to $533.7 million in 2007 compared to
$601.2 million in 2006. Net income for 2006 includes a $1.5 million
benefit relating to the cumulative effect of change in accounting
principle. For additional information regarding the cumulative effect
of change in accounting principle we recorded in 2006, see Note 8 of the Notes
to Consolidated Financial Statements included under Item 8 of
this annual report.
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 $812.5 million for 2007 compared to $752.5 million for
2006. Gross operating margin for 2007 includes $32.7 million of
proceeds from business interruption insurance claims compared to $40.4 million
of proceeds during 2006. Strong demand for NGLs in 2007 compared to 2006
led to higher natural gas processing margins, increased volumes of natural gas
processed under fee-based contracts and higher NGL throughput volumes at certain
of our pipelines and fractionation facilities. The following
paragraphs provide a discussion of segment results excluding proceeds from
business interruption insurance claims.
Gross
operating margin from NGL pipelines and storage was $302.2 million for 2007
compared to $265.7 million for 2006. Total NGL transportation volumes
increased to 1,666 MBPD during 2007 from 1,577 MBPD during 2006. The
$36.5 million year-to-year increase in gross operating margin is primarily due
to higher pipeline transportation and NGL storage volumes at certain of our
facilities and higher transportation fees charged to shippers on our Mid-America
Pipeline System. Our DEP South Texas NGL Pipeline contributed $21.1
million of gross operating margin and 73 MBPD of NGL transportation volumes
during 2007. The increase in gross operating margin year-to-year was
partially offset by lower volumes and higher costs resulting from the November
2007 rupture of the Dixie Pipeline and a one-time benefit in 2006 for the
settlement of a pipeline contamination incident.
Gross
operating margin from our natural gas processing and related NGL marketing
business was $389.1 million for 2007 compared to $359.7 million for
2006. The $29.4 million increase in gross operating margin
year-to-year is largely due to improved results from our South Texas, Louisiana
and Chaco natural gas processing facilities attributable to higher volumes and
equity NGL sales revenues, all of which were partially offset by expenses
associated with start-up delays at our Meeker and Pioneer natural gas processing
plants. Fee-based processing volumes increased to 2.6 Bcf/d during
2007 from 2.2 Bcf/d during 2006. Equity NGL production increased to 88 MBPD
during 2007 from 63 MBPD during 2006.
Gross
operating margin from NGL fractionation was $88.4 million for 2007 compared to
$86.8 million for 2006. Fractionation volumes increased from 312 MBPD
during 2006 to 394 MBPD during 2007. The year-to-year increase in gross
operating margin of $1.6 million is primarily due to higher volumes at our Norco
NGL fractionator during 2007 relative to 2006. Our Norco NGL
fractionator returned to normal operating rates in the second quarter of 2006
after suffering a reduction of fractionation volumes due to the effects of
Hurricane Katrina. Gross operating margin attributable to our Hobbs
NGL fractionator, which became operational in August 2007, was largely offset by
start-up expenses. Fractionation volumes for 2007 include 36 MBPD from our Hobbs
fractionator.
Onshore
Natural Gas Pipelines & Services. Gross operating margin
from this business segment was $335.7 million for 2007 compared to $333.4
million for 2006. Our total onshore natural gas transportation
volumes were 6,632 BBtus/d for 2007 compared to 6,012 BBtus/d for
2006. Gross operating margin from our onshore natural gas pipeline business
was $307.2 million for 2007 compared to $312.3 million for 2006. The
$5.1 million year-to-year decrease in gross operating margin from this business
is largely due to higher operating costs on our Acadian Gas System, Carlsbad
Gathering System and our Texas Intrastate System.
Results
from our onshore natural gas pipeline business for 2007 include $5.5 million of
gross operating margin from our Piceance Creek Gathering System, which we
acquired in December 2006. Equity in earnings from our investment in
Jonah increased $9.1 million year-to-year. The Piceance Creek
Gathering System and our net share of the gathering volumes on the Jonah
Gathering System contributed 789 BBtus/d, collectively, of natural gas gathering
volumes during 2007.
Gross
operating margin from our natural gas storage business was $28.4 million for
2007 compared to $21.1 million for 2006. The $7.3 million
year-to-year increase in gross operating margin is largely due to our Wilson
natural gas storage facility attributable to lower repair costs in 2007 relative
to 2006 and a 2006 loss on the sale of cushion gas. Our Wilson
natural gas storage facility remained out of operation through 2007 due to
ongoing repairs. Gross operating margin from our Petal facility
includes an $8.4 million benefit in 2006 for a well measurement
gain.
Offshore
Pipelines & Services. Gross operating margin from this
business segment was $171.6 million for 2007 compared to $103.4 million for
2006, a year-to-year increase of $68.2 million. Our Independence
project contributed $85.0 million of gross operating margin during 2007 on
average natural gas throughput of 423 BBtus/d. Segment gross
operating margin for 2007 includes $3.4 million of proceeds from business
interruption insurance claims compared to $23.5 million of proceeds in
2006. The following paragraphs provide a discussion of segment
results excluding proceeds from business interruption insurance
claims.
Gross
operating margin from our offshore platform services business was $111.7 million
for 2007 compared to $34.6 million for 2006. The $77.1 million
year-to-year increase in gross operating margin is primarily due to our start up
of the Independence Hub Platform in 2007, which contributed $63.6 million of
gross operating margin in 2007. In addition, gross operating margin
from the remainder of this business increased $13.5 million year-to-year
primarily due to higher volumes during 2007 versus 2006. Our net
platform natural gas processing volumes increased to 494 MMcf/d in 2007 from 159
MMcf/d in 2006.
Gross
operating margin from our offshore natural gas pipeline business was $35.4
million for 2007 compared to $22.4 million for 2006. Offshore natural
gas transportation volumes were 1,641 BBtus/d during 2007 versus 1,520 BBtus/d
during 2006. Our Independence Trail Pipeline reported $21.4 million
of gross operating margin and 423 BBtus/d of transportation volumes for
2007. Results from our Independence Trail Pipeline were partially
offset by a decrease in volumes and revenues from our Viosca Knoll Gathering
System and Constitution Gas Pipeline. Gross operating margin for 2007
includes a non-cash impairment charge of $7.0 million associated with our
investment in Nemo compared to charge of $7.4 million in 2006 related to our
investment in Neptune.
Gross
operating margin from our offshore crude oil pipeline business was $21.1 million
for 2007 versus $23.0 million for 2006. The $1.9 million year-to-year
decrease in gross operating margin is
primarily
due to lower transportation volumes on our certain of our offshore crude oil
pipelines and higher operating costs on our Poseidon Oil Pipeline System during
2007 relative to 2006. An increase in revenues year-to-year on our
Cameron Highway Oil Pipeline System attributable to higher volumes was more than
offset by a one-time expense of $8.8 million associated with the early
termination of Cameron Highway’s credit facility. Crude oil
transportation volumes on our Cameron Highway Oil Pipeline System net to our
ownership interest were 44 MBPD during 2007 compared to 32 MBPD during
2006. Total offshore crude oil transportation volumes were 163 MBPD
during 2007 versus 153 MBPD during 2006.
Petrochemical
Services. Gross operating margin from this business segment
was $172.3 million for 2007 compared to $173.1 million for
2006. Gross operating margin from our butane isomerization business
was $91.4 million for 2007 compared to $73.2 million for 2006. The
$18.2 million year-to-year increase in gross operating margin is attributable to
higher processing volumes and by-products sales revenues. Butane
isomerization volumes were 90 MBPD for 2007 compared to 81 MBPD for
2006.
Gross
operating margin from our propylene fractionation and pipeline activities was
$62.6 million for 2007 versus $63.4 million for 2006. The $0.8
million year-to-year decrease in gross operating margin is primarily
attributable to higher operating costs and expenses attributable to our
propylene pipelines and our propylene storage and export
facility. Petrochemical transportation volumes were 105 MBPD during 2007
compared to 97 MBPD during 2006. Gross operating margin from octane
enhancement was $18.3 million for 2007 compared to $36.6 million for
2006. The year-to-year decrease of $18.3 million is primarily due to
lower sales margins in 2007 relative to 2006. Octane enhancement
production was 9 MBPD during 2007 and 2006.
Liquidity
and Capital Resources
Our
primary cash requirements, in addition to normal operating expenses and debt
service, are for working capital, capital expenditures, business acquisitions
and distributions to 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
business expansion projects and acquisitions are expected to be funded by a
variety of sources (either separately or in combination) including operating
cash flows, borrowings under credit facilities, the issuance of additional
equity and debt securities and proceeds from divestitures of ownership interests
in assets to affiliates or third parties. 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, 2008, we had $35.4 million of unrestricted cash on hand and
approximately $1.30 billion of available credit under EPO’s Multi-Year Revolving
Credit Facility and a new credit facility executed in November
2008. We had approximately $9.05 billion in principal outstanding
under consolidated debt agreements at December 31, 2008. In total,
our consolidated liquidity at December 31, 2008 was approximately
$1.49 billion, which includes the available borrowing capacity of our
consolidated subsidiaries such as Duncan Energy Partners.
Registration
Statements
We may
issue equity or debt securities to assist us in meeting our liquidity and
capital spending requirements. Duncan Energy Partners may do likewise in
meeting its liquidity and capital spending requirements. We have a
universal shelf registration statement on file with the SEC that would allow us
to issue an unlimited amount of debt and equity securities for general
partnership purposes. In April 2008, EPO issued $1.10 billion in
principal amount of fixed-rate, unsecured senior notes under this registration
statement.
In
December 2008, EPO also issued $500.0 million in principal amount of fixed-rate,
unsecured senior notes. Net proceeds from these senior note offerings
were used to temporarily reduce borrowings outstanding under EPO’s Multi-Year
Revolving Credit Facility and for general partnership purposes.
In
January 2009, we sold 10,590,000 common units (including an over-allotment of
990,000 common units) to the public at an offering price of $22.20 per
unit. We used the net proceeds of $225.6 million from the offering to
temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving
Credit Facility, which may be reborrowed to fund capital expenditures and other
growth projects, and for general partnership purposes.
During
2003, we instituted a distribution reinvestment plan (“DRIP”). We
have a registration statement on file with the SEC authorizing the issuance of
up to 25,000,000 common units in connection with the 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 of our partnership. During the
year ended December 31, 2008, we issued 5,368,310 common units in connection
with our DRIP, which generated proceeds of $134.7 million from plan
participants. In November 2008, affiliates of EPCO reinvested $67.0
million in connection with the DRIP.
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 10.0% discount
through payroll deductions. During the year ended December 31, 2008,
we issued 155,636 common units to employees under this plan, which generated
proceeds of $4.5 million.
In March
2008, Duncan Energy Partners filed a universal shelf registration statement with
the SEC that authorized its issuance of up to $1.00 billion in debt and equity
securities. In December 2008, Duncan Energy Partners issued $0.5
million in equity securities under its registration statement.
For information regarding our public
debt obligations or partnership equity, see Notes 14 and
15, respectively, of the Notes to Consolidated Financial
Statements included under Item 8 of this annual report.
Letter
of Credit Facility
In
October 2008, EPO entered into a $100.0 million letter of credit
facility. EPO issued a $70.0 million letter of credit under this new
facility, which remained outstanding at December 31, 2008. This
letter of credit facility does not reduce the amount available under our
Multi-Year Revolving Credit Facility.
Credit
Ratings of EPO
At March
2, 2009, the investment-grade credit ratings of EPO’s senior unsecured debt
securities remain unchanged from 2008 at Baa3 by Moody’s Investor Services; BBB-
by Fitch Ratings; and BBB- by Standard and Poor’s. Such ratings
reflect only the view of a rating agency and should not be interpreted as a
recommendation to buy, sell or hold any security. Any rating can be
revised upward or downward or withdrawn at any time by a rating agency if it
determines that the circumstances warrant such a change and should be evaluated
independently of any other rating.
Based on
the characteristics of the $1.25 billion of fixed/floating unsecured junior
subordinated notes that EPO issued in 2006 and 2007, the rating agencies
assigned partial equity treatment to the notes. Moody’s Investor
Services and Standard and Poor’s each assigned 50.0% equity treatment and Fitch
Ratings assigned 75.0% equity treatment.
In
connection with the construction of our Pascagoula, Mississippi natural gas
processing plant, EPO entered into a $54.0 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
EPO’s credit rating by Moody’s Investor Services declines below Baa3 in
combination with our credit rating at Standard & Poor’s declining below
BBB-, the $54.0 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, EPO would have to either
redeem the Pascagoula MBFC Loan or provide an alternative credit agreement to
support its obligation under this loan.
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
millions). For information regarding the individual components of our
cash flow amounts, see the Statements of Consolidated Cash Flows.
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Net
cash flows provided by operating activities
|
|
$ |
1,237.1 |
|
|
$ |
1,590.9 |
|
|
$ |
1,175.1 |
|
|
Cash
used in investing activities
|
|
|
2,411.9 |
|
|
|
2,553.6 |
|
|
|
1,689.3 |
|
|
Cash
provided by financing activities
|
|
|
1,171.0 |
|
|
|
979.4 |
|
|
|
495.0 |
|
Net cash
flows provided by operating activities are 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, crude oil and certain petrochemicals. The products that we
process, sell or transport are principally used as fuel for residential,
agricultural and commercial heating; feedstock in petrochemical manufacturing;
and in the production of motor gasoline. Reduced demand for our
services or products by industrial customers, whether because of a decline in
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 operating cash flows. For a more complete
discussion of these and other risk factors pertinent to our business, see “Risk
Factors” under Item 1A of this annual report.
Our Statements of Consolidated Cash
Flows are prepared 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 similar
transactions, (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, (iii) other non-cash amounts such as depreciation, amortization,
operating lease expense paid by EPCO, changes in the fair market value of
financial instruments and equity in earnings from unconsolidated affiliates (net
cash flows provided by operating activities reflect the actual cash
distributions we receive from such investees), and (iv) the effects of all items
classified as investing or financing cash flows, such as proceeds from asset
sales and related transactions or 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 each period. Increases or decreases in inventory are
influenced by the quantity of products held in connection with our marketing
activities and changes in energy commodity prices.
Cash used in investing activities
primarily represents expenditures for additions to property, plant and
equipment, business combinations and investments in unconsolidated
affiliates. Cash provided by 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 2008 with 2007
Operating
Activities. Net cash flows
provided by operating activities were $1.24 billion for 2008 compared to
$1.59 billion for 2007. The $353.9 million decrease in net cash flows
provided by operating activities was primarily due to the
following:
|
§
|
Net
cash flows from consolidated operations (excluding distributions received
from unconsolidated affiliates and cash payments for interest) decreased
$262.6 million year-to-year. Although our gross operating
margin increased year-to-year (see “Results of Operations” within this
Item 7), the reduction in operating cash flow is generally due to the
timing of related cash receipts and disbursements. The $262.6 million
total year-to-year decrease also reflects a $127.3 million decrease in
cash proceeds we received from insurance claims related to certain named
storms. For information regarding proceeds from business
interruption and property damage claims, see Note 21 of the Notes to
Consolidated Financial Statements included under Item 8 of this annual
report.
|
|
§
|
Cash
distributions received from unconsolidated affiliates increased
$25.0 million year-to-year primarily due to increased distributions
from Jonah and Cameron Highway.
|
|
§
|
Cash
payments for interest increased $116.3 million year-to-year primarily due
to increased borrowings to finance our capital spending
program.
|
Investing
Activities. Cash used in investing activities was $2.41
billion for 2008 compared to $2.55 billion for 2007. The $141.7
million decrease in cash used for investing activities was primarily due to
the following:
|
§
|
Capital
spending for property, plant and equipment, net of contributions in aid of
construction costs, decreased $174.6 million year-to-year. For
additional information related to our capital spending program, see
“Capital Spending” included within this Item
7.
|
|
§
|
Cash
outlays for investments in and advances to unconsolidated affiliates
decreased by $208.9 million year-to-year. Expenditures for 2007
include the $216.5 million we contributed to Cameron Highway during the
second quarter of 2007. Cameron Highway used these funds, along
with an equal contribution from our 50.0% joint venture partner in Cameron
Highway, to repay approximately $430.0 million of its outstanding
debt. In addition, cash contributions to Jonah decreased $83.0
million year-to-year as a result of the completion of an expansion
project in June 2008. Expenditures for 2008 include $22.5
million in contributions to White River Hub, LLC, $36.0 million to acquire
a 49.0% interest in Skelly-Belvieu Pipeline Company, L.L.C., and $35.9
million in contributions to the Texas Offshore Port System joint
venture.
|
|
§
|
An
$85.4 million increase in restricted cash (a cash outflow) due to margin
requirements primarily due to our hedging activities. See
Item 7A of this annual report for information regarding our interest rate
and commodity risk hedging
portfolios.
|
|
§
|
Cash
used for business combinations increased $166.4 million year-to-year
primarily due to the acquisition of a 100.0% membership interest in Great
Divide Gathering LLC for $125.2 million, the acquisition of the remaining
interests in Dixie for $57.1 million and the acquisition of additional
interests in Tri-States NGL Pipeline, L.L.C (“Tri-States”) for $18.7
million.
|
Financing
Activities. Cash provided by financing activities was $1.17
billion for 2008 compared to $979.4 million for 2007. This $191.6
million increase in cash provided by financing activities was primarily due to
the following:
|
§
|
Net
borrowings under our consolidated debt agreements increased $588.9 million
year-to-year. In April 2008, EPO sold $400.0 million in
principal amount of fixed-rate unsecured senior notes (“Senior Notes M”)
and $700.0 million in principal amount of fixed-rate unsecured senior
notes (“Senior Notes N”). In November 2008, EPO executed a
Japanese yen term loan agreement in the amount of 20.7 billion yen
(approximately $217.6 million U.S. dollar equivalent). In
December 2008, EPO sold $500.0 million in principal amount of fixed-rate
unsecured senior notes (“Senior Notes O”). We used the
proceeds from these borrowings primarily to repay amounts borrowed under
our Multi-Year Revolving Credit Facility and, to a lesser extent, for
general partnership purposes. For information regarding our
consolidated debt obligations, see Note 14 of the Notes to Consolidated
Financial Statements included under Item 8 of this annual
report.
|
|
§
|
Net
proceeds from the issuance of our common units increased $73.6 million
year-to-year due to increased participation in our
DRIP.
|
|
§
|
Contributions
from minority interests decreased $302.9 million
year-to-year primarily due to the initial public offering of Duncan
Energy Partners in February 2007, which generated proceeds of $290.5
million.
|
|
§
|
Cash
distributions to our partners and minority interests increased $103.2
million year-to-year primarily due to increases in our common units
outstanding and quarterly distribution rates, increases in the
quarterly distribution rates of Duncan Energy Partners and distributions
paid to Independence Hub’s joint venture
partner.
|
|
§
|
The
early termination and settlement of interest rate hedging financial
instruments during 2008 resulted in net cash payments of $14.4 million
compared to net cash receipts of $48.9 million during the same period in
2007, which resulted in a $63.3 million decrease in financing cash flows
between years.
|
Comparison
of 2007 with 2006
Operating
activities. Net cash flows provided by operating activities
was $1.59 billion for 2007 compared to $1.18 billion for 2006. The
$415.9 million year-to-year increase in net cash flows provided by operating
activities was primarily due to the following:
|
§
|
Our
net cash flows from consolidated businesses (excluding distributions
received from unconsolidated affiliates and cash payments for interest and
taxes) increased $436.8 million year-to-year. The improvement
in cash flow is generally due to increased gross operating margin and the
timing of related cash collections and disbursements between
periods. The $436.8 million total year-to-year increase also
reflects a $42.1 million increase in cash proceeds we received from
insurance claims related to certain named
storms.
|
|
§
|
Cash
distributions received from unconsolidated affiliates increased $30.6
million year-to-year primarily due to improved earnings from our Gulf of
Mexico investments, which were negatively impacted during 2006 as a result
of the lingering effects of Hurricanes Katrina and
Rita.
|
|
§
|
Cash
payments for interest increased $56.2 million year-to-year primarily due
to increased borrowings to finance our capital spending
program. Our average debt balance for 2007 was $6.26 billion
compared to $4.93 billion for 2006.
|
|
§
|
Cash
payments for taxes decreased $4.7 million
year-to-year.
|
Investing
activities. Cash used in investing activities was $2.55
billion for 2007 compared to $1.69 billion for 2006. The $864.3
million year-to-year increase in cash used for investing activities was
primarily due to the following:
|
§
|
An
$847.7 million increase in capital spending for property, plant and
equipment (net of contributions in aid of construction costs) and a $194.6
million increase in investments in unconsolidated affiliates, partially
offset by a $240.7 million decrease in cash outlays for business
combinations.
|
|
§
|
We
contributed $216.5 million to Cameron Highway during the second quarter of
2007. Cameron Highway used these funds, along with an equal
contribution from our 50.0% joint venture partner in Cameron Highway, to
repay approximately $430.0 million of its outstanding
debt.
|
|
§
|
During
2006, we paid $100.0 million for Piceance Creek Pipeline, LLC and $145.2
million for the Encinal acquisition. Our spending for business
combinations during 2007 was limited and primarily due to the $35.0
million we paid to acquire the South Monco pipeline
business.
|
|
§
|
Restricted
cash increased $38.6 million (a cash outflow)
year-to-year.
|
Financing
activities. Cash provided by
financing activities was $979.4 million for 2007 versus $495.0 million for
2006. The $484.4 million year-to-year increase in cash provided by
financing activities was primarily due to the following:
|
§
|
Net
borrowings under our consolidated debt agreements increased $1.10 billion
year-to-year. In May 2007, EPO sold $700.0 million in principal
amount of fixed/floating unsecured junior subordinated notes (Junior Notes
B”). In September 2007, EPO sold $800.0 million in principal
amount of fixed-rate unsecured senior notes (“Senior Notes L”) and in
October 2007, EPO repaid $500.0 million in principal amount of fixed-rate
unsecured senior notes (“Senior Notes
E”).
|
|
§
|
Net
proceeds from the issuance of our common units decreased $788.0 million
year-to-year. We completed underwritten equity offerings in
March and September of 2006 that generated net proceeds of $750.8 million
reflecting the sale of 31,050,000 common
units.
|
|
§
|
Contributions
from minority interests increased $275.4 million year-to-year primarily
due to the initial public offering of Duncan Energy Partners in February
2007, which generated net proceeds of $290.5 million from the sale of
14,950,000 of its common units. See “Other Items
– Duncan Energy Partners Transactions” within this Item 7 for
additional information regarding Duncan Energy
Partners.
|
|
§
|
Cash
distributions to our partners and minority interests increased $137.9
million year-to-year primarily due to an increase in common units
outstanding and our quarterly cash distribution
rates.
|
|
§
|
We
received $48.9 million from the settlement of treasury lock financial
instruments during 2007 related to our interest rate risk hedging
activities.
|
Capital
Spending
An
integral part of our business strategy involves expansion through business
combinations, growth capital projects and investments in joint
ventures. We believe that we are positioned to continue to grow our
system of assets through the construction of new facilities and to capitalize on
expected increases in natural gas and/or crude oil production from resource
basins such as the Piceance Basin of western Colorado, the Greater Green River
Basin in Wyoming, Barnett Shale in North Texas, and the deepwater Gulf of
Mexico.
Management
continues to analyze potential acquisitions, joint ventures and similar
transactions with businesses that operate in complementary markets or geographic
regions. In past 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.
The following table summarizes
our capital spending by activity for the periods indicated (dollars in
thousands):
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Capital
spending for business combinations:
|
|
|
|
|
|
|
|
|
|
|
Great
Divide Gathering System acquisition
|
|
$ |
125,175 |
|
|
$ |
-- |
|
|
$ |
-- |
|
|
Encinal
acquisition, excluding non-cash consideration (1)
|
|
|
-- |
|
|
|
114 |
|
|
|
145,197 |
|
|
Piceance
Basin Gathering System acquisition
|
|
|
-- |
|
|
|
368 |
|
|
|
100,000 |
|
|
South
Monco Pipeline System acquisition
|
|
|
1 |
|
|
|
35,000 |
|
|
|
-- |
|
|
Canadian
Enterprise Gas Products, Ltd. acquisition
|
|
|
-- |
|
|
|
-- |
|
|
|
17,690 |
|
|
Additional
ownership interests in Dixie
|
|
|
57,089 |
|
|
|
311 |
|
|
|
12,913 |
|
|
Additional
ownership interests in Belle Rose NGL Pipeline, LLC
|
|
|
1,200 |
|
|
|
-- |
|
|
|
-- |
|
|
Additional
ownership interests in Tri-States
|
|
|
18,695 |
|
|
|
-- |
|
|
|
-- |
|
|
Other
business combinations
|
|
|
-- |
|
|
|
-- |
|
|
|
700 |
|
|
Total
|
|
|
202,160 |
|
|
|
35,793 |
|
|
|
276,500 |
|
|
Capital spending for property,
plant and equipment, net: (2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Growth
capital projects (3)
|
|
|
1,773,000 |
|
|
|
1,986,157 |
|
|
|
1,148,123 |
|
|
Sustaining
capital projects (4)
|
|
|
180,676 |
|
|
|
142,096 |
|
|
|
132,455 |
|
|
Total
|
|
|
1,953,676 |
|
|
|
2,128,253 |
|
|
|
1,280,578 |
|
|
Capital
spending for intangible assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition
of intangible assets (5)
|
|
|
5,126 |
|
|
|
11,232 |
|
|
|
-- |
|
|
Capital
spending attributable to unconsolidated affiliates:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments
in unconsolidated affiliates (6)
|
|
|
129,816 |
|
|
|
332,909 |
|
|
|
138,266 |
|
|
Total
capital spending
|
|
$ |
2,290,778 |
|
|
$ |
2,508,187 |
|
|
$ |
1,695,344 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Excludes
$181.1 million of non-cash consideration paid to the seller in the form of
7,115,844 of our common units. See Note 12 of the Notes to
Consolidated Financial Statements included under Item 8 of this annual
report for additional information regarding our business
combinations.
(2)
On
certain of our capital projects, third parties are 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. Contributions in aid of construction
costs were $25.8 million, $57.5 million and $60.5 million for the years
ended December 31, 2008, 2007 and 2006, respectively.
(3)
Growth
capital projects either result in additional revenue streams from existing
assets or expand our asset base through construction of new facilities
that will generate additional revenue streams.
(4)
Sustaining
capital expenditures are capital expenditures (as defined by GAAP)
resulting from improvements to and major renewals of existing
assets. Such expenditures serve to maintain existing operations but
do not generate additional revenues.
(5)
Amount
for 2008 represents the acquisition of permits for our Mont Belvieu
storage facility. Amount for 2007 represents the acquisition of
nitric oxide credits at our Morgan’s Point Facility.
(6)
Fiscal
2007 includes $216.5 million in cash contributions to Cameron Highway to
fund our share of the repayment of its debt
obligations.
|
|
Based on
information currently available, we estimate our consolidated capital spending
for 2009 will approximate $1.00 billion, which includes estimated expenditures
of $820.0 million for growth capital projects and acquisitions and $180.0
million for sustaining capital expenditures.
Our
forecast of consolidated capital expenditures is based on our current announced
strategic operating and growth plans, which are dependent upon our ability to
generate the required funds from either operating cash flows or from other
means, including borrowings under debt agreements, issuance of equity, and
potential divestitures of certain assets to third and/or related
parties. Our forecast of capital expenditures may change due to
factors beyond our control, such as weather related issues, changes in supplier
prices or adverse economic conditions. Furthermore, our forecast may
change as a result of decisions made by management 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 a principal factor that determines how much
capital we can invest. 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.
At
December 31, 2008, we had approximately $521.3 million in purchase commitments
outstanding that relate to our capital spending for property, plant and
equipment. These commitments primarily relate to construction of our
Barnett Shale natural gas pipeline projects and Meeker natural gas processing
plant expansion.
Significant
Ongoing Growth Capital Projects
The
following table summarizes information regarding certain ongoing significant
announced growth capital projects (dollars in millions). Actual costs noted for
each project reflects our share of cash expenditures as of December 31, 2008,
excluding capitalized interest. The current forecast amount noted for
each project also reflects our share of project expenditures, excluding
estimated capitalized interest.
|
|
|
|
|
|
|
Current
|
|
|
|
Estimated
|
|
|
|
|
Forecast
|
|
|
|
Date
of
|
|
Actual
|
|
|
Total
|
|
|
Project
Name
|
Completion
|
|
Costs
|
|
|
Cost
|
|
|
|
|
|
|
|
|
|
|
|
Sherman
Extension Pipeline (Barnett Shale)
|
2009
|
|
$ |
457.0 |
|
|
$ |
489.2 |
|
|
Shenzi
Oil Pipeline
|
2009
|
|
|
135.8 |
|
|
|
153.5 |
|
|
Marathon
Piceance Basin pipeline projects
|
2009
|
|
|
36.6 |
|
|
|
151.3 |
|
|
Trinity
River Basin Extension
|
2009
|
|
|
16.4 |
|
|
|
232.6 |
|
|
Expansion
of Wilson natural gas storage facility
|
2010
|
|
|
51.1 |
|
|
|
119.6 |
|
|
Texas
Offshore Port System
|
To
be determined
|
|
|
30.0 |
|
|
|
600.0 |
|
Sherman
Extension Pipeline (Barnett Shale). In November 2006, we
announced an expansion of our Texas Intrastate System with the construction of
the Sherman Extension that will transport up to 1.1 Bcf/d of natural gas from
the growing Barnett Shale area of North Texas. The Sherman Extension
is supported by long-term contracts with Devon Energy Corporation, the largest
producer in the Barnett Shale area, and significant indications of interest from
leading producers and gatherers in the Fort Worth basin, as well as other
shippers on our Texas Intrastate Pipeline system. At its terminus,
the new pipeline system will make deliveries into Boardwalk Pipeline Partners
L.P.’s Gulf Crossing Expansion Project, which will provide export capacity for
Barnett Shale natural gas production to multiple delivery points in Louisiana,
Mississippi and Alabama that offer access to attractive markets in the Northeast
and Southeast United States. In addition, the Sherman Extension will
provide natural gas producers in East Texas and the Waha area of West Texas with
access to these higher value markets through our Texas Intrastate Pipeline
system. The Sherman Extension will originate near Morgan Mill, Texas and extend
through the center of the current Barnett Shale development area to Sherman,
Texas. In 2008, we placed into service portions of the Sherman
Extension. The Sherman Extension is scheduled for final completion in
March 2009.
The
Barnett Shale is considered to be one of the largest unconventional natural gas
resource plays in North America, covering approximately 14 counties and over
seven million acres in the Fort Worth basin in North Texas. Current
natural gas production is estimated at 3.4 Bcf/d from approximately 7,800
wells. Approximately 190 rigs are currently estimated to be working
to develop Barnett Shale acreage in the region. According to the
United States Geological Survey, the Barnett Shale has the resource potential of
approximately 26 trillion cubic feet of natural gas.
Shenzi
Oil Pipeline. In October 2006, we announced the execution of
definitive agreements with producers to construct, own and operate an oil export
pipeline that will provide firm gathering services from the BHP Billiton
Plc-operated Shenzi production field located in the South Green Canyon area of
the central Gulf of Mexico. The Shenzi oil export pipeline will
originate at the Shenzi Field, located in 4,300 feet of water at Green Canyon
Block 653, approximately 120 miles off the coast of Louisiana. The
83-mile, 20-inch diameter pipeline will have the capacity to transport up to 230
MBPD of crude oil and will connect the Shenzi Field to our Cameron Highway Oil
Pipeline and Poseidon Oil Pipeline System at our Ship Shoal 332B junction
platform. We own a 50.0% interest in the Cameron Highway Oil Pipeline
and a 36.0% interest in the Poseidon Oil Pipeline System and operate both
pipelines. The Shenzi oil export pipeline will connect to a platform
being constructed by BHP Billiton Plc to develop the Shenzi Field, which is
expected to commence operations during the second quarter of 2009.
Marathon Piceance Basin
pipeline projects. In December 2006, we entered into a
long-term contract with Marathon Oil Company (“Marathon”) to provide a range of
midstream energy services, including natural gas gathering, compression,
treating and processing, for Marathon’s natural gas production in the
Piceance Basin of northwest Colorado. Under the terms of the
contract, we are
constructing
50 miles of gathering lines and related assets to connect Marathon’s multi-well
drilling sites, production from which is expected to peak at approximately 180
MMcf/d, to our Piceance Creek Gathering System. From there the
natural gas will be delivered to our Meeker natural gas processing
facility.
Trinity River
Basin
Extension. In August 2008,
we announced the development of a new 40-mile supply lateral that will extend
from the Trinity River Basin north of Arlington, Texas to an interconnect with
the Sherman Extension pipeline near Justin, Texas to accommodate growing natural
gas production from the Barnett Shale. This new pipeline will consist
of 30-inch and 36-inch diameter pipeline designed to provide up to 1.0 Bcf/d of
natural gas takeaway capacity for producers in Tarrant and Denton
counties. This new pipeline will also have a lateral to provide
transportation services for natural gas produced from the Newark East field in
Wise County. These new pipeline laterals are anchored by
long-term agreements with major producers and are expected to be in-service by
year end 2009.
Expansion
of Wilson natural
gas storage facility. We are developing a new natural gas
storage cavern located on the Boling Salt Dome near Boling,
Texas. The cavern is designed to store approximately 7.9 Bcf of
natural gas, of which approximately 5.0 Bcf will be working gas capacity and 2.9
Bcf will be the base gas requirements needed to support minimum
pressures. This expansion project was approved by the Texas Railroad
Commission and is projected to commence operations in 2010. We expect
to secure binding precedent agreements on all capacity before the cavern
commences operations.
Texas
Offshore Port System (TOPS and PACE). In August 2008,
we, together with TEPPCO and Oiltanking, announced the formation of a joint
venture to design, construct, operate and own a Texas offshore crude oil port
and a related onshore pipeline and storage system that would facilitate delivery
of waterborne crude oil to refining centers located along the upper Texas Gulf
Coast. We, TEPPCO and Oiltanking each own, through our respective
subsidiaries, a one-third interest in the joint venture. For additional
information regarding this joint venture and its capital projects, see “Recent
Developments – Texas Offshore Port System” within this Item 7.
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 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 April
2002, a subsidiary of ours acquired several midstream energy assets located in
Texas and New Mexico from El Paso Corporation (“El Paso”). These
assets included the Texas Intrastate System and the Carlsbad Gathering
Systems. With respect to such assets, El Paso agreed to indemnify our
subsidiary for any pipeline integrity costs it incurred (whether paid or
payable) for five years following the acquisition date. The indemnity
provisions did not take effect until such costs exceeded $3.3 million annually;
however, the amount reimbursable by El Paso was capped at $50.2 million in the
aggregate. In 2007 and 2006, we recovered $31.1 million and $13.7
million, respectively from El Paso related to our 2006 and 2005
expenditures. During 2007, we received a final amount of $5.4 million
from El Paso related to this indemnity.
The
following table summarizes our pipeline integrity costs, net of indemnity
payments from El Paso, for the periods indicated (dollars in
thousands):
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Expensed
|
|
$ |
48,664 |
|
|
$ |
43,499 |
|
|
$ |
26,397 |
|
|
Capitalized
|
|
|
63,976 |
|
|
|
52,420 |
|
|
|
38,180 |
|
|
Total
|
|
$ |
112,640 |
|
|
$ |
95,919 |
|
|
$ |
64,577 |
|
We expect
our cash outlay for the pipeline integrity program, irrespective of whether such
costs are capitalized or expensed, to approximate $107.0 million in
2009.
Critical
Accounting Policies and Estimates
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 currently
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 asset’s
cost, less its residual value (if any), to the periods it
benefits. The majority of our property, plant and equipment is
depreciated using the straight-line method, which results in depreciation
expense being incurred evenly over the life of 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 prospectively.
Examples
of such circumstances include:
|
§
|
changes
in laws and regulations that limit the estimated economic life of an
asset;
|
|
§
|
changes
in technology that render an asset
obsolete;
|
|
§
|
changes
in expected salvage values; or
|
|
§
|
changes
in the forecast life of applicable resource basins, if
any.
|
At
December 31, 2008 and 2007, the net book value of our property, plant and
equipment was $13.15 billion and $11.59 billion, respectively. We
recorded $466.1 million, $414.9 million, and $350.8 million in depreciation
expense for the years ended December 31, 2008, 2007 and 2006, respectively.
For
additional information regarding our property, plant and equipment, see 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 expected future
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 asset’s 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.
An equity
method investment is evaluated for impairment whenever events or changes in
circumstances indicate that there is a possible loss in value of 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
investee’s industry. Equity method investments with carrying values
that are not expected to be recovered through expected future cash flows are
written down to their estimated fair values. 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; 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.
We
recognized a non-cash asset impairment charge related to property, plant and
equipment of $0.1 million in 2006, which is reflected as a component of
operating costs and expenses. No such asset impairment charges were
recorded in 2008 or 2007.
During
2007, we evaluated our equity method investment in Nemo for
impairment. As a result of this evaluation, we recorded a $7.0
million non-cash impairment charge that is a component of equity in earnings
from unconsolidated affiliates for the year ended December 31,
2007. Similarly, during the year ended December 31, 2006, we
evaluated our equity method investment in Neptune for impairment and
recorded a $7.4 million non-cash impairment charge. During 2008 there
were no such impairment charges.
For
additional information regarding impairment charges associated with our
long-lived assets and equity method investments, see 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 business combinations and asset
purchases. 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 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:
|
§
|
the
expected useful life of the related tangible assets (e.g., fractionation
facility, pipeline, etc.);
|
|
§
|
any
legal or regulatory developments that would impact such contractual
rights; and
|
|
§
|
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 asset’s 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, 2008 and 2007, the carrying value of our intangible asset portfolio
was $855.4 million and $917.0 million, respectively. We recorded
$88.4 million, $89.7 million, and $88.8 million in amortization expense
associated with our intangible assets for the years ended December 31, 2008,
2007 and 2006, respectively.
For
additional information regarding our intangible assets, see Notes 2 and 13 of
the Notes to Consolidated Financial Statements included under Item 8 of
this annual report.
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. 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 unit’s fair value, which is predicated on our assumptions regarding
the future economic prospects of the reporting unit.
Such assumptions include:
|
§
|
discrete
financial forecasts for the assets contained within the reporting unit,
which rely on management’s estimates of operating margins and
transportation volumes;
|
|
§
|
long-term
growth rates for cash flows beyond the discrete forecast period;
and
|
|
§
|
appropriate
discount rates.
|
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, 2008 and 2007, the carrying value of our
goodwill was $706.9 million and $591.7 million, respectively. We did not
record any goodwill impairment charges during the periods
presented.
For
additional information regarding our goodwill, see 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:
|
§
|
persuasive
evidence of an exchange arrangement
exists;
|
|
§
|
delivery
has occurred or services have been
rendered;
|
|
§
|
the
buyer’s price is fixed or determinable;
and
|
|
§
|
collectability
is reasonably assured.
|
We record revenue when sales contracts
are settled (i.e., either physical delivery of product has taken place or the
services designated in the contract have been performed). We record any
necessary allowance for doubtful accounts as required by our established
policy.
Our use
of certain estimates for revenues and expenses has increased as a result of SEC
regulations that require us to submit financial information on accelerated time
frames. Such estimates are necessary due to the timing to compile
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. On an
ongoing basis, we review our estimates based on currently available
information. Changes in facts and circumstances may result in revised
estimates and could affect our reported financial statements and accompanying
notes.
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. In accruing for environmental remediation
liabilities, costs of future expenditures for environmental remediation are not
discounted to their present value, unless the amount and timing of the
expenditures are fixed or reliably determinable. At December 31, 2008,
none of our estimated environmental remediation liabilities are discounted to
present value since the ultimate amount and timing of cash payments for such
liabilities are not readily determinable.
At December 31, 2008 and 2007, we had a
liability for environmental remediation of $15.4 million and $26.5 million,
respectively, which was derived from a range of reasonable estimates based upon
studies and site surveys. We follow the provisions of American
Institute of Certified Public Accountants Statement of Position 96-1, which
provides key guidance on recognition, measurement and disclosure of remediation
liabilities. We have recorded our best estimate of the cost of
remediation activities.
See Item 3 of this annual report for
recent developments regarding environmental matters.
Natural
gas imbalances
In the
pipeline transportation business, imbalances frequently result from differences
in natural gas volumes received from and delivered to our customers. Such
differences occur when a customer delivers more or less gas into our pipelines
than is physically redelivered back to them during a particular time
period. The vast majority of our settlements are through in-kind
arrangements whereby incremental volumes are delivered to a customer (in the
case of an imbalance payable) or received from a customer (in the case of an
imbalance receivable). Such in-kind deliveries are on-going and take place over
several months. In some cases, settlements of imbalances accumulated
over a period of time are ultimately cashed out and are generally negotiated at
values which approximate average market prices over a period of
time. As a result, for gas imbalances that are ultimately settled
over future periods, we estimate the value of such current assets and
liabilities using average market prices, which is representative of the
estimated value of the imbalances upon final settlement. Changes in
natural gas prices may impact our estimates.
At
December 31, 2008 and 2007, our imbalance receivables, net of allowance for
doubtful accounts, were $48.4 million and $60.9 million, respectively, and are
reflected as a component of “Accounts and notes receivable – trade” on our
Consolidated Balance Sheets included in this annual report. At
December 31, 2008 and 2007, our imbalance payables were $40.7 million and $38.3
million, respectively, and are reflected as a component of “Accrued product
payables” on our Consolidated Balance Sheets included in this annual
report.
Other
Items
Duncan
Energy Partners Transactions
Duncan
Energy Partners was formed in September 2006 and did not acquire any assets
prior to February 5, 2007, which was the date it completed its initial public
offering of 14,950,000 common units and acquired controlling interests in
certain midstream energy businesses of EPO. The business purpose of
Duncan Energy Partners is to acquire, own and operate a diversified portfolio of
midstream energy assets and to support the growth objectives of EPO and other
affiliates under common control. Duncan Energy Partners is
engaged in the business of transporting and storing NGLs and petrochemical
products and gathering, transporting, storing and marketing of natural
gas.
At December 31, 2008, Duncan Energy
Partners is owned 99.3% by its limited partners and 0.7% by its general partner,
DEP GP, which is a wholly owned subsidiary of EPO. DEP GP is
responsible for managing the business and operations of Duncan Energy
Partners. DEP Operating Partnership L.P. (“DEP OLP”), a wholly
owned subsidiary of Duncan Energy Partners, conducts substantially all of Duncan
Energy Partners’ business.
At December 31, 2008, EPO owned
approximately 74.1% of Duncan Energy Partners’ limited partner interests and
100.0% of its general partner.
DEP I
Midstream Businesses. On February 5, 2007, EPO contributed a
66.0% controlling equity interest in each of the DEP I Midstream Businesses
(defined below) to Duncan Energy Partners in a dropdown of
assets. EPO retained the remaining 34.0% equity interest in each of
the DEP I Midstream Businesses. The DEP I Midstream Businesses
consist of (i) Mont Belvieu Caverns, LLC (“Mont Belvieu Caverns”); (ii) Acadian
Gas, LLC (“Acadian Gas”); (iii) Enterprise Lou-Tex Propylene Pipeline L.P.
(“Lou-Tex Propylene”), including its general partner; (iv) Sabine Propylene
Pipeline L.P. (“Sabine Propylene’), including its general partner; and (v) South
Texas NGL Pipelines, LLC (“South Texas NGL”).
As consideration for controlling equity
interests in the DEP I Midstream Businesses and reimbursement for capital
expenditures related to these businesses, Duncan Energy Partners distributed to
EPO (i) $260.6 million of the $290.5 million of net proceeds from its initial
public offering to EPO, (ii) $198.9 million in borrowings under its revolving
credit facility and (iii) a net 5,351,571 common units of Duncan Energy
Partners. See Note 14 of the Notes to Consolidated Financial
Statements included under Item 8 of this annual report for information regarding
the debt obligations of Duncan Energy Partners.
DEP II
Midstream Businesses. On December 8, 2008,
Duncan Energy Partners entered into a Purchase and Sale Agreement (the “DEP II
Purchase Agreement”) with EPO and Enterprise GTM Holdings L.P. (“Enterprise
GTM,” a wholly owned subsidiary of EPO). Pursuant to the DEP II
Purchase Agreement, DEP OLP acquired 100.0% of the membership interests in
Enterprise Holding III, LLC (“Enterprise III”) from Enterprise GTM, thereby
acquiring a 66.0% general partner interest in Enterprise GC, a 51.0% general
partner interest in Enterprise Intrastate and a 51.0% membership interest in
Enterprise Texas. Collectively, we refer to Enterprise GC, Enterprise
Intrastate and Enterprise Texas as the “DEP II Midstream
Businesses.” EPO was the sponsor of this second dropdown
transaction. Enterprise GTM retained the remaining limited partner
and member interests in the DEP II Midstream Businesses.
As consideration for controlling equity
interests in the DEP II Midstream Businesses, EPO received $280.5 million in
cash and 37,333,887 Class B limited partner units having a market value of
$449.5 million from Duncan Energy Partners. The Class B limited
partner units automatically converted to
common
units of Duncan Energy Partners on February 1, 2009. The total value
of the consideration provided to EPO and Enterprise GTM was $730.0
million. The cash portion of the consideration provided by Duncan
Energy Partners in this dropdown transaction was derived from borrowings under a
term loan. See Note 14 of the Notes to Consolidated Financial
Statements included under Item 8 of this annual report for information regarding
the debt obligations of Duncan Energy Partners.
Generally, the DEP II dropdown
transaction documents provide that to the extent that the DEP II Midstream
Businesses generate cash sufficient to pay distributions to their partners or
members, such cash will be distributed to Enterprise III (a wholly owned by
Duncan Energy Partners) and Enterprise GTM (our wholly owned subsidiary) in an
amount sufficient to generate an aggregate annualized return on their respective
investments of 11.85%. Distributions in excess of this amount will be
distributed 98.0% to Enterprise GTM and 2.0% to Enterprise
III. The initial annual fixed return amount of 11.85% will be
increased by 2.0% each calendar year beginning January 1, 2010. For example, the
fixed return in 2010, assuming no other adjustments, would be 102% of 11.85%, or
12.087%.
Duncan
Energy Partners paid a pro rated cash distribution of $0.1115 per unit on the
Class B units with respect to the fourth quarter of 2008.
Insurance
Matters
We
participate as a named insured in EPCO’s insurance program, which provides us
with property damage, business interruption and other coverages, the scope and
amounts of which are customary and sufficient for the nature and extent of our
operations. While we believe EPCO maintains adequate insurance
coverage on our behalf, insurance will not cover every type of damages or
interruption that might occur. If we were to incur a significant
liability for which we were not fully insured, it could have a material impact
on our consolidated financial position, results of operations and cash
flows. In addition, the proceeds of any such insurance may not be
paid in a timely manner and may be insufficient to reimburse us for our repair
costs or lost income. Any event that interrupts the revenues generated by
our consolidated operations, or which causes us to make significant expenditures
not covered by insurance, could reduce our ability to pay distributions to our
partners and, accordingly, adversely affect the market price of our common
units.
For
windstorm events such as hurricanes and tropical storms, EPCO’s deductible for
onshore physical damage is $10.0 million per storm. For offshore
assets, the windstorm deductible is $10.0 million per storm plus a one-time
$15.0 million aggregate deductible per policy period. For
non-windstorm events, EPCO’s deductible for onshore and offshore physical damage
is $5.0 million per occurrence. In meeting the deductible amounts,
property damage costs are aggregated for EPCO and its affiliates, including
us. Accordingly, our exposure with respect to the deductibles may be
equal to or less than the stated amounts depending on whether other EPCO or
affiliate assets are also affected by an event.
To
qualify for business interruption coverage in connection with a windstorm event,
covered assets must be out-of-service in excess of 60 days for onshore assets
and 75 days for offshore assets. To qualify for business interruption
coverage in connection with a non-windstorm event, covered onshore and offshore
assets must be out-of-service in excess of 60 days.
In the
third quarter of 2008, our onshore and offshore facilities located along the
Gulf Coast of Texas and Louisiana were adversely impacted by Hurricanes Gustav
and Ike. The disruptions in natural gas, NGL and crude oil production
caused by these storms resulted in decreased volumes for some of our pipeline
systems, natural gas processing plants, NGL fractionators and offshore
platforms, which, in turn, caused a decrease in gross operating margin from
these operations. As a result of our allocated share of EPCO’s
insurance deductibles for windstorm coverage, we expensed a combined $47.9
million of repair costs for property damage in connection with these two
storms. We expect to file property damage insurance claims to the
extent repair costs exceed deductible amounts. Due to the recent
nature of these storms, we are still evaluating the total cost of repairs and
the potential for business interruption claims on certain assets.
See Note
21 of the Notes to Consolidated Financial Statements included under Item 8 of
this annual report for more information regarding insurance
matters.
Contractual
Obligations
The
following table summarizes our significant contractual obligations at December
31, 2008 (dollars in thousands).
|
|
|
|
|
|
Payment
or Settlement due by Period
|
|
|
|
|
|
|
|
Less
than
|
|
|
1-3
|
|
|
4-5
|
|
|
More
than
|
|
|
Contractual
Obligations
|
|
Total
|
|
|
1
year
|
|
|
years
|
|
|
years
|
|
|
5
years
|
|
|
Scheduled
maturities of long-term debt (1)
|
|
$ |
9,046,046 |
|
|
$ |
-- |
|
|
$ |
1,488,250 |
|
|
$ |
2,267,596 |
|
|
$ |
5,290,200 |
|
|
Estimated
cash payments for interest (2)
|
|
$ |
9,351,928 |
|
|
$ |
544,658 |
|
|
$ |
993,886 |
|
|
$ |
821,123 |
|
|
$ |
6,992,261 |
|
|
Operating
lease obligations (3)
|
|
$ |
331,419 |
|
|
$ |
32,299 |
|
|
$ |
55,372 |
|
|
$ |
51,547 |
|
|
$ |
192,201 |
|
|
Purchase
obligations: (4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product
purchase commitments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
payment obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
$ |
5,225,141 |
|
|
$ |
323,309 |
|
|
$ |
1,150,102 |
|
|
$ |
1,148,610 |
|
|
$ |
2,603,120 |
|
|
NGLs
|
|
$ |
1,923,792 |
|
|
$ |
969,870 |
|
|
$ |
272,672 |
|
|
$ |
272,500 |
|
|
$ |
408,750 |
|
|
Petrochemicals
|
|
$ |
1,746,138 |
|
|
$ |
685,643 |
|
|
$ |
624,393 |
|
|
$ |
268,418 |
|
|
$ |
167,684 |
|
|
Other
|
|
$ |
37,455 |
|
|
$ |
19,202 |
|
|
$ |
6,781 |
|
|
$ |
5,970 |
|
|
$ |
5,502 |
|
|
Underlying
major volume commitments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (in BBtus)
|
|
|
981,955 |
|
|
|
56,650 |
|
|
|
209,075 |
|
|
|
214,730 |
|
|
|
501,500 |
|
|
NGLs
(in MBbls)
|
|
|
56,622 |
|
|
|
23,576 |
|
|
|
9,446 |
|
|
|
9,440 |
|
|
|
14,160 |
|
|
Petrochemicals
(in MBbls)
|
|
|
67,696 |
|
|
|
24,949 |
|
|
|
23,848 |
|
|
|
11,665 |
|
|
|
7,234 |
|
|
Service
payment commitments
|
|
$ |
529,402 |
|
|
$ |
52,614 |
|
|
$ |
100,403 |
|
|
$ |
93,167 |
|
|
$ |
283,218 |
|
|
Capital
expenditure commitments (5)
|
|
$ |
521,262 |
|
|
$ |
521,262 |
|
|
$ |
-- |
|
|
$ |
-- |
|
|
$ |
-- |
|
|
Other
long-term liabilities, as reflected
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
in
our Consolidated Balance Sheet (6)
|
|
$ |
81,277 |
|
|
$ |
-- |
|
|
$ |
14,710 |
|
|
$ |
7,573 |
|
|
$ |
58,994 |
|
|
Total
|
|
$ |
28,793,860 |
|
|
$ |
3,148,857 |
|
|
$ |
4,706,569 |
|
|
$ |
4,936,504 |
|
|
$ |
16,001,930 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Represents
our scheduled future maturities of consolidated debt obligations for the
periods indicated. See Note 14 of the Notes to Consolidated Financial
Statements included under Item 8 of this annual report for information
regarding our debt obligations.
(2)
Our
estimated cash payments for interest are based on the principle amount of
consolidated debt obligations outstanding at December 31, 2008. With
respect to variable-rate debt, we applied the weighted-average interest
rates paid during 2008. See Note 14 of the Notes to Consolidated
Financial Statements included under Item 8 of this annual report for
information regarding variable interest rates charged in 2008 under our
credit agreements. In addition, our estimate of cash payments for
interest gives effect to interest rate swap agreements in place at
December 31, 2008. See Note 7 of the Notes to Consolidated Financial
Statements included under Item 8 of this annual report. Our estimated
cash payments for interest are significantly influenced by the long-term
maturities of our $550.0 million Junior Notes A (due August 2066) and
$682.7 million Junior Notes B (due January 2068). Our estimated cash
payments for interest assume that the Junior Note obligations are not
called prior to maturity.
(3)
Primarily
represents operating leases for (i) underground caverns for the storage of
natural gas and NGLs, (ii) leased office space with an affiliate of EPCO,
(iii) a railcar unloading terminal in Mont Belvieu, Texas, and (iv) land
held pursuant to right-of-way agreements.
(4)
Represents
enforceable and legally binding agreements to purchase goods or services
based on the contractual terms of each agreement at December 31,
2008.
(5)
Represents
our short-term unconditional payment obligations relating to our capital
projects.
(6)
As
presented on our Consolidated Balance Sheet at December 31, 2008, other
long-term liabilities consist primarily of (i) liabilities for our asset
retirement obligations and (ii) liabilities for environmental remediation
costs. For information regarding our environmental remediation costs
and asset retirement obligations, see Notes 2 and 10 respectively, of the
Notes to Consolidated Financial Statements included
under Item 8 of this annual report.
|
|
For
additional information regarding our significant contractual obligations
involving operating leases and purchase obligations, see Note 20 of the Notes to
Consolidated Financial Statements included under Item 8 of this annual
report.
Off-Balance
Sheet Arrangements
Except
for the following information regarding debt obligations of certain
unconsolidated affiliates, 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. The following information summarizes the significant terms
of such unconsolidated debt obligations.
Poseidon. At December 31,
2008, Poseidon’s debt obligations consisted of $109.0 million outstanding under
its $150.0 million revolving credit facility. Amounts borrowed under
this facility mature in May 2011 and are secured by substantially all of
Poseidon’s assets.
Evangeline. At
December 31, 2008, Evangeline’s debt obligations consisted of (i) $8.2 million
in principal amount of 9.90% fixed rate Series B senior secured notes due
December 2010 and (ii) a $7.5 million subordinated note
payable. Duncan Energy Partners had $1.0 million of letters of credit
outstanding on December 31, 2008 that were furnished on behalf of Evangeline’s
debt.
Summary
of Related Party Transactions
The
following table summarizes our related party transactions for the periods
indicated (dollars in thousands).
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Revenues
from consolidated operations
|
|
|
|
|
|
|
|
|
|
|
EPCO
and affiliates
|
|
$ |
121,201 |
|
|
$ |
67,635 |
|
|
$ |
98,671 |
|
|
Energy
Transfer Equity and subsidiaries
|
|
|
561,727 |
|
|
|
294,441 |
|
|
|
-- |
|
|
Unconsolidated
affiliates
|
|
|
396,879 |
|
|
|
290,640 |
|
|
|
304,559 |
|
|
Total
|
|
$ |
1,079,807 |
|
|
$ |
652,716 |
|
|
$ |
403,230 |
|
|
Cost
of sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EPCO
and affiliates
|
|
$ |
59,173 |
|
|
$ |
33,827 |
|
|
$ |
86,050 |
|
|
Energy
Transfer Equity and subsidiaries
|
|
|
173,883 |
|
|
|
26,889 |
|
|
|
-- |
|
|
Unconsolidated
affiliates
|
|
|
90,836 |
|
|
|
41,474 |
|
|
|
42,166 |
|
|
Total
|
|
$ |
323,892 |
|
|
$ |
102,190 |
|
|
$ |
128,216 |
|
|
Operating
costs and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EPCO
and affiliates
|
|
$ |
314,612 |
|
|
$ |
260,716 |
|
|
$ |
225,487 |
|
|
Energy
Transfer Equity and subsidiaries
|
|
|
18,284 |
|
|
|
8,267 |
|
|
|
-- |
|
|
Unconsolidated
affiliates
|
|
|
(10,388 |
) |
|
|
(8,709 |
) |
|
|
(10,560 |
) |
|
Total
|
|
$ |
322,508 |
|
|
$ |
260,274 |
|
|
$ |
214,927 |
|
|
General
and administrative expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EPCO
and affiliates
|
|
$ |
59,058 |
|
|
$ |
56,518 |
|
|
$ |
41,265 |
|
|
Unconsolidated
affiliates
|
|
|
(51 |
) |
|
|
-- |
|
|
|
-- |
|
|
Total
|
|
$ |
59,007 |
|
|
$ |
56,518 |
|
|
$ |
41,265 |
|
|
Other
income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EPCO
and affiliates
|
|
$ |
(274 |
) |
|
$ |
(170 |
) |
|
$ |
680 |
|
|
Unconsolidated
affiliates
|
|
|
-- |
|
|
|
-- |
|
|
|
262 |
|
|
Total
|
|
$ |
(274 |
) |
|
$ |
(170 |
) |
|
$ |
942 |
|
For
additional information regarding our related party transactions, see Note 17 of
the Notes to Consolidated Financial Statements included under Item 8 of
this annual report. For information regarding certain business
relationships and related transactions, see 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 and
affiliates are primarily due to (i) reimbursements we pay EPCO in connection
with an administrative services agreement (the “ASA”) and (ii) purchases of NGL
products. TEPPCO is an affiliate of ours due to the common control
relationship of both entities. Enterprise GP Holdings acquired
non-controlling ownership interests in both ETE GP and Energy Transfer Equity in
May 2007. As a result of this transaction, ETE GP and Energy Transfer
Equity became related parties to us.
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 we make to K/D/S Promix, L.L.C. for NGL transportation, storage and
fractionation services and to Jonah for natural gas purchases.
On February 5, 2007, our consolidated
subsidiary, Duncan Energy Partners, completed an underwritten initial public
offering of its common units. Duncan Energy Partners was formed in
September 2006 as a Delaware limited partnership to, among other things, acquire
ownership interests in certain of our midstream energy
businesses. For additional information regarding Duncan Energy
Partners, see “Other Items – Duncan Energy Partners Transactions”
within this section.
Non-GAAP
Reconciliations
The
following table presents 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 change in
accounting principle (dollars in thousands):
|
|
|
For
the Year the Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Total
segment gross operating margin
|
|
$ |
2,057,469 |
|
|
$ |
1,492,068 |
|
|
$ |
1,362,449 |
|
|
Adjustments
to reconcile total gross operating margin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
to
operating income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
amortization and accretion in
|
|
|
|
|
|
|
|
|
|
|
|
|
|
operating
costs and expenses
|
|
|
(555,370 |
) |
|
|
(513,840 |
) |
|
|
(440,256 |
) |
|
Operating
lease expense paid by EPCO
|
|
|
(2,038 |
) |
|
|
(2,105 |
) |
|
|
(2,109 |
) |
|
Gain
(loss) from asset sales and related transactions in
|
|
|
|
|
|
|
|
|
|
|
|
|
|
operating
costs and expenses
|
|
|
3,735 |
|
|
|
(5,391 |
) |
|
|
3,359 |
|
|
General
and administrative costs
|
|
|
(90,550 |
) |
|
|
(87,695 |
) |
|
|
(63,391 |
) |
|
Operating
income
|
|
|
1,413,246 |
|
|
|
883,037 |
|
|
|
860,052 |
|
|
Other
expense, net
|
|
|
(391,448 |
) |
|
|
(303,463 |
) |
|
|
(229,967 |
) |
|
Income
before provision for income taxes, minority interest
|
|
|
|
|
|
|
|
|
|
|
|
|
|
and
the cumulative effect of change in accounting principle
|
|
$ |
1,021,798 |
|
|
$ |
579,574 |
|
|
$ |
630,085 |
|
EPCO subleases to us 100 railcars for
$1 per year (the “retained leases”). These subleases are part of the
ASA 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. We exercised our election under the
retained leases to purchase a cogeneration unit in December 2008 for $2.3
million. For additional information regarding the ASA and the
retained leases, see Item 13 of this annual report.
Recent
Accounting Pronouncements
The
accounting standard setting bodies have recently issued the following accounting
guidance that will affect our future financial statements:
|
§
|
Statement
of Financial Accounting Standards (“SFAS”) 141(R), Business
Combinations;
|
|
§
|
FASB Staff Position SFAS 142-3, Determination of
the Useful Life of Intangible
Assets;
|
|
§
|
SFAS
157, Fair Value Measurements;
|
|
§
|
SFAS
160, Noncontrolling Interests in Consolidated Financial Statements – An
amendment of ARB 51;
|
|
§
|
SFAS
161, Disclosures about Derivative Instruments and Hedging Activities – An
Amendment of SFAS 133;
|
|
§
|
Emerging
Issues Task Force (“EITF”) 08-6, Equity Method Investment Accounting
Considerations; and
|
|
§
|
EITF
07-4, Application of the Two Class Method Under SFAS 128, Earnings Per
Share, to Master Limited
Partnerships.
|
For
additional information regarding recent accounting pronouncements, see Note 3 of
the Notes to Consolidated Financial Statements included under Item 8 of
this annual report.
We are
exposed to financial market risks, including changes in commodity prices,
interest rates and foreign exchange rates. We may use financial
instruments (e.g., futures, forwards, swaps, options and other financial
instruments with similar characteristics) to mitigate the risks of certain
identifiable and anticipated transactions. In general, the types of
risks we attempt to hedge are those related to (i) the variability of future
earnings, (ii) fair values of certain debt obligations and (iii) cash flows
resulting from changes in applicable interest rates, commodity prices or
exchange rates.
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 hedging
criteria. When this occurs, we may enter into a new financial
instrument to reestablish the hedge to which the closed instrument
relates.
The following table presents gains
(losses) recorded in net income attributable to our interest rate risk and
commodity risk hedging transactions for the periods indicated (dollars in
thousands). These amounts do not present the corresponding gains
(losses) attributable to the underlying hedged items.
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Interest
Rate Risk Hedging Portfolio:
|
|
|
|
|
|
|
|
|
|
|
EPO:
|
|
|
|
|
|
|
|
|
|
|
Reclassification
of cash flow hedge amounts from AOCI, net
|
|
$ |
4,409 |
|
|
$ |
5,429 |
|
|
$ |
4,234 |
|
|
Other
gains (losses) from derivative transactions
|
|
|
5,340 |
|
|
|
(8,934 |
) |
|
|
(5,195 |
) |
|
Duncan
Energy Partners:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ineffective
portion of cash flow hedges
|
|
|
(5 |
) |
|
|
(155 |
) |
|
|
-- |
|
|
Reclassification
of cash flow hedge amounts from AOCI, net
|
|
|
(2,008 |
) |
|
|
350 |
|
|
|
-- |
|
|
Total
hedging gains (losses), net, in consolidated interest
expense
|
|
$ |
7,736 |
|
|
$ |
(3,310 |
) |
|
$ |
(961 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
Risk Hedging Portfolio:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EPO:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reclassification
of cash flow hedge amounts from
AOCI,
net - natural gas marketing activities
|
|
$ |
(30,175 |
) |
|
$ |
(3,299 |
) |
|
$ |
(1,327 |
) |
|
Reclassification
of cash flow hedge amounts from
AOCI,
net - NGL and petrochemical operations
|
|
|
(28,232 |
) |
|
|
(4,564 |
) |
|
|
13,891 |
|
|
Other
gains (losses) from derivative transactions
|
|
|
29,772 |
|
|
|
(20,712 |
) |
|
|
(2,307 |
) |
|
Total
hedging gains (losses), net, in consolidated operating costs and
expenses
|
|
$ |
(28,635 |
) |
|
$ |
(28,575 |
) |
|
$ |
10,257 |
|
The
following table provides additional information regarding derivative instruments
as presented in our Consolidated Balance Sheets at the dates indicated (dollars
in thousands):
|
|
|
At
December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Current
assets:
|
|
|
|
|
|
|
|
Derivative
assets:
|
|
|
|
|
|
|
|
Interest
rate risk hedging portfolio
|
|
$ |
7,780 |
|
|
$ |
-- |
|
|
Commodity
risk hedging portfolio
|
|
|
185,762 |
|
|
|
341 |
|
|
Foreign
currency risk hedging portfolio
|
|
|
9,284 |
|
|
|
1,308 |
|
|
Total
derivative assets – current
|
|
$ |
202,826 |
|
|
$ |
1,649 |
|
|
Other
assets:
|
|
|
|
|
|
|
|
|
|
Interest
rate risk hedging portfolio
|
|
$ |
38,939 |
|
|
$ |
14,744 |
|
|
Total
derivative assets – long-term
|
|
$ |
38,939 |
|
|
$ |
14,744 |
|
|
|
|
|
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
|
|
|
Derivative
liabilities:
|
|
|
|
|
|
|
|
|
|
Interest
rate risk hedging portfolio
|
|
$ |
5,910 |
|
|
$ |
22,209 |
|
|
Commodity
risk hedging portfolio
|
|
|
281,142 |
|
|
|
19,575 |
|
|
Foreign
currency risk hedging portfolio
|
|
|
109 |
|
|
|
27 |
|
|
Total
derivative liabilities – current
|
|
$ |
287,161 |
|
|
$ |
41,811 |
|
|
Other
liabilities:
|
|
|
|
|
|
|
|
|
|
Interest
rate risk hedging portfolio
|
|
$ |
3,889 |
|
|
$ |
3,080 |
|
|
Commodity
risk hedging portfolio
|
|
|
233 |
|
|
|
-- |
|
|
Total
derivative liabilities– long-term
|
|
$ |
4,122 |
|
|
$ |
3,080 |
|
The following table presents gains
(losses) recorded in other comprehensive income (loss) for cash flow hedges
associated with our interest rate risk, commodity risk and foreign currency risk
hedging portfolios (dollars in thousands). These amounts do not
present the corresponding gains (losses) attributable to the underlying hedged
items.
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Interest
Rate Risk Hedging Portfolio:
|
|
|
|
|
|
|
|
|
|
|
EPO:
|
|
|
|
|
|
|
|
|
|
|
Gains
(losses) on cash flow hedges
|
|
$ |
(20,772 |
) |
|
$ |
17,996 |
|
|
$ |
11,196 |
|
|
Reclassification
of cash flow hedge amounts to net income, net
|
|
|
(4,409 |
) |
|
|
(5,429 |
) |
|
|
(4,234 |
) |
|
Duncan
Energy Partners:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Losses
on cash flow hedges
|
|
|
(7,989 |
) |
|
|
(3,271 |
) |
|
|
-- |
|
|
Reclassification
of cash flow hedge amounts to net income, net
|
|
|
2,008 |
|
|
|
(350 |
) |
|
|
-- |
|
|
Total
interest rate risk hedging gains (losses), net
|
|
|
(31,162 |
) |
|
|
8,946 |
|
|
|
6,962 |
|
|
Commodity
Risk Hedging Portfolio:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EPO:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas marketing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Losses
on cash flow hedges
|
|
|
(30,642 |
) |
|
|
(3,125 |
) |
|
|
(1,034 |
) |
|
Reclassification
of cash flow hedge amounts to net income, net
|
|
|
30,175 |
|
|
|
3,299 |
|
|
|
1,327 |
|
|
NGL
and petrochemical operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains
(losses) on cash flow hedges
|
|
|
(120,223 |
) |
|
|
(22,735 |
) |
|
|
9,976 |
|
|
Reclassification
of cash flow hedge amounts to net income, net
|
|
|
28,232 |
|
|
|
4,564 |
|
|
|
(13,891 |
) |
|
Total
commodity risk hedging gains (losses), net
|
|
|
(92,458 |
) |
|
|
(17,997 |
) |
|
|
(3,622 |
) |
|
Foreign
Currency Risk Hedging Portfolio:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains
on cash flow hedges
|
|
|
9,286 |
|
|
|
1,308 |
|
|
|
-- |
|
|
Total
foreign currency risk hedging gains (losses), net
|
|
|
9,286 |
|
|
|
1,308 |
|
|
|
-- |
|
|
Total
cash flow hedge amounts in other comprehensive income
|
|
$ |
(114,334 |
) |
|
$ |
(7,743 |
) |
|
$ |
3,340 |
|
The following information summarizes
the principal elements of our interest rate risk, commodity risk and foreign
currency risk hedging portfolios. For amounts recorded in net income and other
comprehensive
income and on our balance sheet related to our consolidated hedging activities,
please refer to the preceding tables.
Interest
Rate Risk Hedging Portfolio
Our interest rate exposure results from
variable and fixed rate borrowings under various debt agreements. The following
information summarizes significant components of our interest rate risk hedging
portfolio:
Fair
value hedges – EPO interest rate swaps
We manage
a portion of our interest rate exposure 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.
At December 31, 2008, we had four interest rate swap agreements outstanding
having an aggregate notional value of $400.0 million that were accounted
for as fair value hedges. The aggregate fair value of these interest
rate swaps at December 31, 2008, was $46.7 million (an asset), with an
offsetting increase in the fair value of the underlying debt. There
were eleven interest rate swaps outstanding at December 31, 2007 having an
aggregate fair value of $12.9 million (an asset).
The following table summarizes our
interest rate swaps outstanding at December 31, 2008.
|
|
Number
|
Period
Covered
|
Termination
|
Fixed
to
|
Notional
|
|
|
Hedged
Fixed Rate Debt
|
of
Swaps
|
by
Swap
|
Date
of Swap
|
Variable Rate
(1)
|
Value
|
|
|
Senior
Notes C, 6.375% fixed rate, due Feb. 2013
|
1
|
Jan.
2004 to Feb. 2013
|
Feb.
2013
|
6.375% to
5.015%
|
$100.0
million
|
|
|
Senior
Notes G, 5.60% fixed rate, due Oct. 2014
|
3
|
4th
Qtr. 2004 to Oct. 2014
|
Oct.
2014
|
5.60%
to 5.297%
|
$300.0
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.
The
following table shows 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
millions).
|
|
|
|
Swap
Fair Value at
|
|
|
Scenario
|
Resulting
Classification
|
|
December
31,
2007
|
|
|
December
31,
2008
|
|
|
February
3,
2009
|
|
|
FV
assuming no change in underlying interest rates
|
Asset
|
|
$ |
12.9 |
|
|
$ |
46.7 |
|
|
$ |
36.3 |
|
|
FV
assuming 10% increase in underlying interest rates
|
Asset
(Liability)
|
|
|
(7.4 |
) |
|
|
42.4 |
|
|
|
31.1 |
|
|
FV
assuming 10% decrease in underlying interest rates
|
Asset
|
|
|
33.1 |
|
|
|
51.1 |
|
|
|
41.5 |
|
The fair
value of the interest rate swaps excludes related hedged amounts we have
recorded in earnings. The change in fair value between December 31,
2008 and February 3, 2009 is primarily due to an increase in market interest
rates relative to the interest rates used to determine the fair value of our
financial instruments at December 31, 2008. The underlying floating
LIBOR forward interest rate curve used to determine the February 3, 2009 fair
values ranged from approximately 1.3% to 3.8% using 6-month reset periods
ranging from February 2008 to March 2014.
Cash
flow hedges – EPO treasury locks
We may
enter into treasury rate lock transactions (“treasury locks”) to hedge U.S.
treasury rates related to its anticipated issuances of debt. Each of our
treasury lock transactions was designated as a cash flow hedge. Gains or
losses on the termination of such instruments are reclassified into net income
(as a component of interest expense) using the effective interest method over
the estimated term of the underlying fixed-rate debt. At December 31,
2008, we had no treasury lock financial instruments outstanding. At
December 31, 2007, the aggregate notional value of our treasury lock financial
instruments was $600.0 million, which had a total fair value (a liability) of
$19.6 million. We terminated a number of treasury lock
financial instruments during 2008 and 2007. These terminations
resulted in realized losses of $40.4 million in 2008 and gains of $48.8 million
in 2007.
We expect
to reclassify $1.6 million of cumulative net gains from our interest rate risk
cash flow hedges into net income (as a decrease to interest expense) during
2009.
Cash
flow hedges – Duncan Energy Partners’ interest rate swaps
At
December 31, 2008, Duncan Energy Partners had interest rate swap agreements
outstanding having an aggregate notional value of $175.0
million. These swaps were accounted for as cash flow
hedges. The purpose of these financial instruments is to reduce the
sensitivity of Duncan Energy Partners’ earnings to the variable interest rates
charged under its revolving credit facility. The aggregate fair value
of these interest rate swaps at December 31, 2008 and 2007 was a liability of
$9.8 million and $3.8 million, respectively. Duncan Energy Partners
expects to reclassify $6.0 million of cumulative net losses from its interest
rate risk cash flow hedges into net income (as an increase to interest expense)
during 2009.
The following table summarizes Duncan
Energy Partners’ interest rate swaps outstanding at December 31,
2008.
|
|
Number
|
Period
Covered
|
Termination
|
Variable
to
|
Notional
|
|
|
Hedged
Variable Rate Debt
|
of
Swaps
|
by
Swap
|
Date
of Swap
|
Fixed Rate
(1)
|
Value
|
|
|
DEP
I Revolving Credit Facility, due Feb. 2011
|
3
|
Sep.
2007 to Sep. 2010
|
Sep.
2010
|
1.47% to
4.62%
|
$175.0
million
|
|
|
(1) Amounts
receivable from or payable to the swap counterparties are settled every
three months (the “settlement
period”). |
As cash flow hedges, any increase or
decrease in fair value (to the extent effective) would be recorded in other
comprehensive income (loss) and amortized into earnings based on the settlement
period hedged. Any ineffectiveness is recorded directly into earnings
as an increase in interest expense.
The
following table shows the effect of hypothetical price movements on the
estimated fair value of Duncan Energy Partners’ interest rate swap portfolio
(dollars in millions).
|
|
|
|
Swap
Fair Value at
|
|
|
Scenario
|
Resulting
Classification
|
|
December
31,
2007
|
|
|
December
31,
2008
|
|
|
February
3,
2009
|
|
|
FV
assuming no change in underlying interest rates
|
Liability
|
|
$ |
(3.8 |
) |
|
$ |
(9.8 |
) |
|
$ |
(9.4 |
) |
|
FV
assuming 10% increase in underlying interest rates
|
Liability
|
|
|
(2.2 |
) |
|
|
(9.4 |
) |
|
|
(9.0 |
) |
|
FV
assuming 10% decrease in underlying interest rates
|
Liability
|
|
|
(5.3 |
) |
|
|
(10.2 |
) |
|
|
(9.8 |
) |
Commodity
Risk Hedging Portfolio
Our
commodity risk hedging portfolio was impacted by a significant decline in
natural gas prices during the second half of 2008. As a result
of the global recession, commodity prices have continued to be volatile during
the first quarter of 2009. We may experience additional losses
related to our commodity risk hedging portfolio in 2009.
The
prices of natural gas, NGLs and certain 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 price risks associated with such products, we may enter into
commodity financial instruments.
The
primary purpose of our commodity risk management activities is to reduce our
exposure to price risks associated with (i) natural gas purchases, (ii) the
value of 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, NGLs or certain petrochemical products. From time
to time, we inject natural gas into storage and may utilize hedging instruments
to lock in the value of its inventory positions. The commodity
financial instruments we utilize are settled in cash.
We have segregated our commodity
financial instruments portfolio between those financial instruments utilized in
connection with our natural gas marketing activities and those used in
connection with its NGL and petrochemical operations.
A
significant number of the financial instruments in this portfolio hedge the
purchase of physical natural gas. If natural gas prices fall below
the price stipulated in such financial instruments, we recognize a liability for
the difference; however, if prices partially or fully recover, this liability
would be reduced or eliminated, as appropriate. Our restricted cash
balance at December 31, 2008 was $203.8 million in order to meet commodity
exchange deposit requirements and the negative change in the fair value of
our natural gas hedge positions.
Natural
gas marketing activities
At
December 31, 2008 and 2007, the aggregate fair value of those financial
instruments utilized in connection with our natural gas marketing activities was
an asset of $6.5 million and a liability of $0.3 million,
respectively. Almost all of the financial instruments within this
portion of the commodity financial instruments portfolio are accounted for using
mark-to-market accounting, with a small number accounted for as cash flow
hedges. We did not have any cash flow hedges related to our natural
gas marketing activities at December 31, 2008.
The
following table shows the effect of hypothetical price movements on the
estimated fair value of this component of the overall portfolio at the dates
presented (dollars in millions):
|
|
|
|
Portfolio
Fair Value at
|
|
|
Scenario
|
Resulting
Classification
|
|
December
31,
2007
|
|
|
December
31,
2008
|
|
|
February
3,
2009
|
|
|
FV
assuming no change in underlying commodity prices
|
Asset
(Liability)
|
|
$ |
(0.3 |
) |
|
$ |
6.5 |
|
|
$ |
13.9 |
|
|
FV
assuming 10% increase in underlying commodity prices
|
Asset
(Liability)
|
|
|
(1.4 |
) |
|
|
2.7 |
|
|
|
9.4 |
|
|
FV
assuming 10% decrease in underlying commodity prices
|
Asset
|
|
|
0.7 |
|
|
|
9.9 |
|
|
|
18.3 |
|
The
change in fair value of the instruments between December 31, 2008 and February
3, 2009 is primarily due to a decrease in natural gas prices.
NGL
and petrochemical operations
At
December 31, 2008 and 2007, the aggregate fair value of those financial
instruments utilized in connection with our NGL and petrochemical operations
were liabilities of $102.1 million and $19.0 million,
respectively. Almost all of the financial instruments within this
portion of the commodity financial instruments portfolio are accounted for as
cash flow hedges, with a small number accounted for using mark-to-market
accounting. We expect to reclassify $114.0 million of
cumulative net losses from these cash flow hedges into net income (as an
increase in operating costs and expenses) during 2009.
We have employed a program to
economically hedge a portion of our earnings from natural gas processing in the
Rocky Mountain region. This program consists of (i) the forward
sale of a portion of our expected equity NGL production volumes at fixed prices
through 2009 and (ii) the purchase, using commodity financial instruments, of
the amount of natural gas expected to be consumed as plant thermal
reduction
(“PTR”) in the production of such equity NGL volumes. The objective of this
strategy is to hedge a level of gross margins (i.e., NGL sales revenues less
actual costs for PTR and the gain or loss on the PTR hedge) associated with the
forward sales contracts by fixing the cost of natural gas used for PTR, through
the use of commodity financial instruments. At December 31, 2008,
this hedging program had hedged future expected gross margins (before plant
operating expenses) of $483.9 million on 22.5 million barrels of forecasted NGL
forward sales transactions extending through 2009.
Our NGL forward sales contracts are not
accounted for as financial instruments under SFAS 133 since they meet normal
purchase and sale exception criteria; therefore, changes in the aggregate
economic value of these sales contracts are not reflected in net income and
other comprehensive income until the volumes are delivered to
customers. On the other hand, the commodity financial instruments
used to purchase the related quantities of PTR (i.e., “PTR hedges”) are
accounted for as cash flow hedges; therefore, changes in the aggregate fair
value of the PTR hedges are presented in other comprehensive income
(loss). Once the forecasted NGL forward sales transactions occur, any
realized gains and losses on the cash flow hedges would be reclassified into net
income in that period.
Prior to actual settlement, if the
market price of natural gas is less than the price stipulated in a commodity
financial instrument, we recognize an unrealized loss in other comprehensive
loss for the excess of the natural gas price stated in the hedge over the market
price. To the extent that we realize such financial losses upon
settlement of the instrument, the losses are added to the actual cost we pay for
PTR, which would then be based on the lower market price. Conversely,
if the market price of natural gas is greater than the price stipulated in such
hedges, we recognize an unrealized gain in other comprehensive income for the
excess of the market price over the natural gas price stated in the PTR
hedge. If realized, the gains on the financial instrument would
serve to reduce the actual cost paid for PTR, which would then be based on the
higher market price. The net effect of these hedging relationships is
that our total cost of natural gas used for PTR approximates the amount it
originally hedged under this program.
The
following table shows the effect of hypothetical price movements on the
estimated fair value of this component of the overall portfolio at the dates
presented (dollars in millions):
|
|
|
|
Portfolio
Fair Value at
|
|
|
Scenario
|
Resulting
Classification
|
|
December
31,
2007
|
|
|
December
31,
2008
|
|
|
February
3,
2009
|
|
|
FV
assuming no change in underlying commodity prices
|
Liability
|
|
$ |
(19.0 |
) |
|
$ |
(102.1 |
) |
|
$ |
(111.6 |
) |
|
FV
assuming 10% increase in underlying commodity prices
|
Asset
(Liability)
|
|
|
11.3 |
|
|
|
(94.0 |
) |
|
|
(109.2 |
) |
|
FV
assuming 10% decrease in underlying commodity prices
|
Liability
|
|
|
(49.2 |
) |
|
|
(110.1 |
) |
|
|
(114.1 |
) |
The
change in fair value of the NGL and petrochemical portfolio between December 31,
2008 and February 3, 2009 is primarily due to a decrease in natural gas
prices.
Foreign
Currency Hedging Portfolio
We are exposed to foreign currency
exchange rate risk primarily through a Canadian NGL marketing
subsidiary. As a result, we could be adversely affected by
fluctuations in the foreign currency exchange rate between the U.S. dollar and
the Canadian dollar. We attempt to hedge this risk using foreign
exchange purchase contracts to fix the exchange rate. Mark-to-market
accounting is utilized for these contracts, which typically have a duration of
one month. For the year ended December 31, 2008, we recorded minimal
gains from these financial instruments.
In
addition, we are exposed to foreign currency exchange rate risk through our
Japanese Yen Term Loan Agreement (“Yen Term Loan”) that EPO entered into in
November 2008. As a result, we could be adversely affected by
fluctuations in the foreign currency exchange rate between the U.S. dollar and
the Japanese yen. We hedged this risk by entering into a foreign
exchange purchase contract to fix the exchange rate. This purchase
contract was designated as a cash flow hedge. At December 31, 2008,
the fair value of this contract was $9.3 million. This contract will
be settled in March 2009 upon repayment of the Yen Term Loan. Total
interest expense under this loan agreement was $4.0 million, of which $1.7
million is the expected foreign currency loss, which will be recorded as
interest expense.
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, see “Contractual Obligations” included under Item 7 of this
annual report.
Fair
Value Information
On
January 1, 2008, we adopted the provisions of SFAS 157 that apply to
financial assets and liabilities. SFAS 157 defines fair value as the
price that would be received to sell an asset or paid to transfer a liability in
an orderly transaction between market participants at a specified measurement
date. See Note 8 of the Notes to Consolidated Financial Statements included
under Item 8 of this annual report for information regarding fair value
disclosures pertaining to our financial assets and liabilities.
Accumulated
Other Comprehensive Income (Loss)
Accumulated other comprehensive income
(loss) primarily includes the effective portion of the gain or loss on financial
instruments designated and qualified as a cash flow hedge, foreign currency
adjustments and Dixie’s minimum pension liability
adjustments. Amounts accumulated in other comprehensive income (loss)
from cash flow hedges are reclassified into earnings in the same period(s) in
which the hedged forecasted transactions (such as a forecasted forward sale of
NGLs) affect earnings. If it becomes probable that the forecasted
transaction will not occur, the net gain or loss in accumulated other
comprehensive income (loss) must be immediately reclassified.
The
following table presents the components of accumulated other comprehensive
income (loss) at the dates indicated:
|
|
|
At
December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Commodity
financial instruments – cash flow hedges (1)
|
|
$ |
(114,077 |
) |
|
$ |
(21,619 |
) |
|
Interest
rate financial instruments – cash flow hedges (1)
|
|
|
3,818 |
|
|
|
34,980 |
|
|
Foreign
currency cash flow hedges (1)
|
|
|
10,594 |
|
|
|
1,308 |
|
|
Foreign
currency translation adjustment (2)
|
|
|
(1,301 |
) |
|
|
1,200 |
|
|
Pension
and postretirement benefit plans (3)
|
|
|
(751 |
) |
|
|
588 |
|
|
Total
accumulated other comprehensive income (loss)
|
|
$ |
(101,717 |
) |
|
$ |
16,457 |
|
|
|
|
|
|
|
|
|
|
|
|
(1) See
Note 7 for additional information regarding these components of
accumulated other comprehensive income (loss).
(2) Relates
to transactions of our Canadian NGL marketing
subsidiary.
(3) See
Note 6 for additional information regarding pension and postretirement
benefit plans.
|
|
The
following table summarizes the components of other comprehensive income (loss)
for the periods indicated:
|
|
|
For
Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Other
comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
Cash
flow hedges
|
|
$ |
(114,334 |
) |
|
$ |
(7,743 |
) |
|
$ |
3,340 |
|
|
Change
in funded status of pension and postretirement plans, net of
tax
|
|
|
(1,339 |
) |
|
|
(52 |
) |
|
|
-- |
|
|
Foreign
currency translation adjustment
|
|
|
(2,501 |
) |
|
|
2,007 |
|
|
|
(807 |
) |
|
Total
other comprehensive income (loss)
|
|
$ |
(118,174 |
) |
|
$ |
(5,788 |
) |
|
$ |
2,533 |
|
Our
consolidated financial statements, together with the independent registered
public accounting firm’s report of Deloitte & Touche LLP (“Deloitte &
Touche”) begin on page F-1 of this annual report.
None.
Disclosure
Controls and Procedures
As of the end of the period covered by
this Report, our management carried out an evaluation, with the participation of
our general partner’s chief executive officer (the “CEO”) and our general
partner’s chief financial officer (the “CFO”), of the effectiveness of our
disclosure controls and procedures pursuant to Rule 13a-15 of the Securities
Exchange Act of 1934. Based on this evaluation, as of the end of the
period covered by this Report, the CEO and CFO concluded:
|
(i)
|
that
our disclosure controls and procedures are designed to ensure that
information required to be disclosed by us in the reports that we file or
submit under the Securities Exchange Act of 1934 is recorded, processed,
summarized and reported within the time periods specified in the SEC’s
rules and forms, and that such information is accumulated and communicated
to our management, including the CEO and CFO, as appropriate to allow
timely decisions regarding required disclosure;
and
|
|
(ii)
|
that
our disclosure controls and procedures are
effective.
|
Changes
in Internal Control over Financial Reporting
There
were no changes in our internal controls over financial reporting (as defined in
Rule 13a-15(f) under the Securities Exchange Act of 1934) or in other factors
during the fourth quarter of 2008, that have materially affected, or are
reasonably likely to materially affect, our internal controls over financial
reporting.
The
certifications of our general partner’s CEO and CFO required under Sections 302
and 906 of the Sarbanes-Oxley Act of 2002 have been included as exhibits to this
annual report.
MANAGEMENT’S
ANNUAL REPORT ON INTERNAL CONTROL
OVER
FINANCIAL REPORTING AS OF DECEMBER 31, 2008
The management of Enterprise Products
Partners L.P. and its consolidated subsidiaries, including its chief
executive officer and chief financial officer, is responsible for establishing
and maintaining adequate internal control over financial reporting, as defined
in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as
amended. Our internal control system was designed to provide
reasonable assurance to Enterprise Products Partners’ management and Board of
Directors regarding the preparation and fair presentation of published financial
statements. However, our management does not represent that our
disclosure controls and procedures or internal controls over financial reporting
will prevent all error and all fraud. A control system, no matter how
well conceived and operated, can provide only a reasonable, not an absolute,
assurance that the objectives of the control system are met.
Our management assessed the
effectiveness of Enterprise Products Partners’ internal control over financial
reporting as of December 31, 2008. In making this assessment, it used the
criteria set forth by the Committee of Sponsoring Organizations of the Treadway
Commission (“COSO”) in Internal Control—Integrated
Framework. This assessment included a review of the design and
operating effectiveness of internal controls over financial reporting as well as
the safeguarding of assets. Based on our assessment, we believe that, as of
December 31, 2008, Enterprise Products Partners’ internal control over financial
reporting is effective based on those criteria.
Our Audit, Conflicts and Governance
Committee is composed of directors who are not officers or employees of our
general partner. It meets regularly with members of management, the internal
auditors and the representatives of the independent registered public accounting
firm to discuss the adequacy of Enterprise Products Partners’ internal controls
over financial reporting, financial statements and the nature, extent and
results of the audit effort. Management reviews with the Audit, Conflicts and
Governance Committee all of Enterprise Products Partners’ significant accounting
policies and assumptions affecting the results of operations. Both the
independent registered public accounting firm and internal auditors have direct
access to the Audit, Conflicts and Governance Committee without the presence of
management.
Our
independent registered public accounting firm has issued an attestation report
on our internal control over financial reporting. That report is
included within this
Item 9A.
Pursuant
to the requirements of Rules 13a-15(f) and 15d-15(f) of the Securities Exchange
Act of 1934, as amended, this Annual Report on Internal Control Over Financial
Reporting has been signed below by the following persons on behalf of the
registrant and in the capacities indicated below on March 2, 2009.
|
/s/
Michael A. Creel
|
|
/s/
W. Randall Fowler
|
|
Name:
|
Michael
A. Creel
|
|
Name:
|
W.
Randall Fowler
|
|
Title:
|
Chief
Executive Officer of
|
|
Title:
|
Chief
Financial Officer of
|
|
|
our
general partner,
|
|
|
our
general partner,
|
|
|
Enterprise
Products GP, LLC
|
|
|
Enterprise
Products GP, LLC
|
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 internal control
over financial reporting of Enterprise Products Partners L.P. and subsidiaries
(the "Company") as of December 31, 2008, based on criteria established in Internal Control — Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission. The Company's management is responsible for
maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting,
included in the accompanying Management’s Annual Report on Internal Control over
Financial Reporting as of December 31, 2008. Our responsibility is to
express an opinion on the Company's internal control over financial reporting
based on our audit.
We conducted our audit 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 effective internal control over
financial reporting was maintained in all material respects. Our audit
included obtaining an understanding of internal control over financial
reporting, assessing the risk that a material weakness exists, testing and
evaluating the design and operating effectiveness of internal control based on
the assessed risk, and performing such other procedures as we considered
necessary in the circumstances. We believe that our audit provides a
reasonable basis for our opinion.
A company's internal control over
financial reporting is a process designed by, or under the supervision of, the
company's principal executive and principal financial officers, or persons
performing similar functions, and effected by the company's Board of Directors,
management, and other personnel to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements
for external purposes in accordance with generally accepted accounting
principles. A company's internal control over financial reporting includes
those policies and procedures that (1) pertain to the maintenance of records
that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that
receipts and expenditures of the company are being made only in accordance with
authorizations of management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the company's assets that could have a
material effect on the financial statements.
Because of the inherent limitations of
internal control over financial reporting, including the possibility of
collusion or improper management override of controls, material misstatements
due to error or fraud may not be prevented or detected on a timely basis.
Also, projections of any evaluation of the effectiveness of the internal control
over financial reporting to future periods are subject to the risk that the
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may
deteriorate.
In our opinion, the Company maintained,
in all material respects, effective internal control over financial reporting as
of December 31, 2008, based on the criteria established in Internal Control — Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission.
We have also audited, in
accordance with the standards of the Public Company Accounting Oversight Board
(United States), the consolidated balance sheet and the related consolidated
statements of operations, comprehensive income, cash flows, and
partners’ equity as of and
for the year ended December 31, 2008 of the Company and our report dated March
2, 2009 expressed an unqualified opinion on those financial
statements.
/s/
DELOITTE & TOUCHE LLP
Houston,
Texas
March 2,
2009
None.
Partnership
Management
As is
commonly the case with publicly traded limited partnerships, we do not directly
employ any of the persons responsible for the management or operations of our
business. These functions are performed by the employees of EPCO pursuant to the
ASA under the direction of the Board of Directors (the “Board”) and executive
officers of EPGP. For a description of the ASA, see “Certain Relationships
and Related Transactions – Relationship with EPCO” under Item 13 of this annual
report.
The
executive officers of our general partner are elected for one-year terms and may
be removed, with or without cause, only by the Board. Our unitholders do
not elect the officers or directors of our general partner. Dan. L.
Duncan, through his indirect control of EPGP, has the ability to elect, remove
and replace at any time, all of the officers and directors of our general
partner. Each member of the Board of our general partner serves until such
member’s death, resignation or removal. The employees of EPCO who
served as directors of EPGP were Messrs. Dan L. Duncan, Michael A. Creel, W.
Randall Fowler, Ralph S. Cunningham, Richard H. Bachmann and A.J.
Teague.
Because
we are a limited partnership and meet the definition of a “controlled company”
under the listing standards of the NYSE, we are not required to comply with
certain requirements of the NYSE. Accordingly, we have elected to not
comply with Section 303A.01 of the NYSE Listed Company Manual, which would
require that the Board of our general partner be comprised of a majority of
independent directors. In addition, we have elected to not comply with
Sections 303A.04 and 303A.05 of the NYSE Listed Company Manual, which would
require that the Board of our general partner maintain a Nominating Committee
and a Compensation Committee, each consisting entirely of independent
directors.
Notwithstanding
any contractual limitation on its obligations or duties, EPGP is liable for all
debts we incur (to the extent not paid by us), except to the extent that such
indebtedness or other obligations are non-recourse to EPGP. Whenever
possible, EPGP intends to make any such indebtedness or other obligations
non-recourse to itself.
Under our
limited partnership agreement and subject to specified limitations, we will
indemnify to the fullest extent permitted by Delaware law, from and against all
losses, claims, damages or similar events any director or officer, or while
serving as director or officer, any person who is or was serving as a tax
matters member or as a director, officer, tax matters member, employee, partner,
manager, fiduciary or trustee of our partnership or any of our
affiliates. Additionally, we will indemnify to the fullest extent
permitted by law, from and against all losses, claims, damages or similar events
any person who is or was an employee (other than an officer) or agent of our
partnership.
Corporate
Governance
We are
committed to sound principles of governance. Such principles are critical
for us to achieve our performance goals, and maintain the trust and confidence
of investors, employees, suppliers, business partners and
stakeholders.
A key
element for strong governance is independent members of the Board of Directors.
Pursuant to the NYSE listing standards, a director will be considered
independent if the Board determines that he or she does not have a material
relationship with EPGP or us (either directly or as a partner, unitholder or
officer of an organization that has a material relationship with EPGP or
us). Based on the foregoing, the Board has affirmatively determined that
Messrs. Rex C. Ross, Charles M. Rampacek and E. William Barnett are
“independent” directors under the NYSE rules.
Code
of Conduct and Ethics and Corporate Governance Guidelines
EPGP has
adopted a “Code of Conduct” that applies to all directors, officers and
employees. This code sets out our requirements for compliance with legal
and ethical standards in the conduct of our business, including general business
principles, legal and ethical obligations, compliance policies for specific
subjects, obtaining guidance, the reporting of compliance issues and discipline
for violations of the code.
Our Code
of Conduct also establishes policies applicable to our CEO, CFO, principal
accounting officer and senior financial and other managers to prevent wrongdoing
and to promote honest and ethical conduct, including ethical handling of actual
and apparent conflicts of interest, compliance with applicable laws, rules and
regulations, full, fair, accurate, timely and understandable disclosure in
public communications and prompt internal reporting of violations of the
code.
Governance
guidelines, together with committee charter, provide the framework for
effective governance. The Board has adopted the “Governance
Guidelines of Enterprise Products Partners,” which address several matters,
including qualifications for directors, responsibilities of directors,
retirement of directors, the composition and responsibility of the Audit,
Conflicts and Governance (“ACG”) Committee, the conduct and frequency of board
and committee meetings, management succession, director access to management and
outside advisors, director compensation, director orientation and continuing
education, and annual self-evaluation of the board. The Board recognizes
that effective governance is an on-going process, and thus, the Board will
review the Governance Guidelines of Enterprise Products Partners annually or
more often as deemed necessary.
We
provide access through our website at www.epplp.com to
current information relating to governance, including the Code of Conduct, the
Governance Guidelines of Enterprise Products Partners and other matters
impacting our governance principles. You may also contact our investor relations
department at (866) 230-0745 for printed copies of these documents free of
charge.
ACG
Committee
The sole
committee of the Board is its ACG Committee. In accordance with NYSE
rules and Section 3(a)(58)(A) of the Securities Exchange Act of 1934, the
Board has named three of its members to serve on its ACG Committee. The
members of the ACG Committee are independent directors, free from any
relationship with us or any of our subsidiaries that would interfere with the
exercise of independent judgment.
The
members of the ACG Committee must have a basic understanding of finance and
accounting and be able to read and understand fundamental financial statements,
and at least one member of the ACG Committee shall have accounting or related
financial management expertise. The members of the ACG Committee are
Messrs. Ross, Rampacek and Barnett. The Board has affirmatively
determined that Mr. Rampacek satisfies the definition of “audit committee
financial expert” as defined in Item 407(d) of Regulation S-K promulgated by the
SEC.
The ACG
Committee’s duties are addressing audit and conflicts-related items and general
corporate governance. From an audit and conflicts standpoint, the
primary responsibilities of the ACG Committee include:
|
§
|
review
potential conflicts of interest, including related party
transactions;
|
|
§
|
monitoring
the integrity of our financial reporting process and related systems of
internal control;
|
|
§
|
ensuring
our legal and regulatory compliance and that of
EPGP;
|
|
§
|
overseeing
the independence and performance of our independent public
accountant;
|
|
§
|
approving
all services performed by our independent public
accountant;
|
|
§
|
providing
for an avenue of communication among the independent public accountant,
management, internal audit function and the
Board;
|
|
§
|
encouraging
adherence to and continuous improvement of our policies, procedures and
practices at all levels;
|
|
§
|
reviewing
areas of potential significant financial risk to our businesses;
and
|
|
§
|
approving
awards granted under our long-term incentive
plans.
|
If the
Board believes that a particular matter presents a conflict of interest and
proposes a resolution, the ACG Committee has the authority to review such matter
to determine if the proposed resolution is fair and reasonable to
us. Any matters approved by the ACG Committee are conclusively deemed
to be fair and reasonable to our business, approved by all of our partners and
not a breach by EPGP or the Board of any duties they may owe us or our
unitholders.
Pursuant
to its formal written charter, the ACG Committee has the authority to conduct
any investigation appropriate to fulfilling its responsibilities, and it has
direct access to our independent public accountants as well as any EPCO
personnel whom it deems necessary in fulfilling its responsibilities. The
ACG Committee has the ability to retain, at our expense, special legal,
accounting or other consultants or experts it deems necessary in the performance
of its duties.
From a
governance standpoint, the ACG Committee’s primary duties and responsibilities
are to develop and recommend to the Board a set of governance principles
applicable to us and review such guidelines from time to time, making any
changes that the ACG Committee deems necessary. The ACG Committee
assists the Board in fulfilling its oversight responsibilities.
A copy of
the ACG Committee charter is available on our website, www.epplp.com. You
may also contact our investor relations department at (866) 230-0745 for a
printed copy of this document free of charge.
NYSE
Corporate Governance Listing Standards
On March
6, 2008, Michael A. Creel, our Chief Executive Officer, certified to the NYSE
(as required by Section 303A.12(a) of the NYSE Listed Company Manual) that he
was not aware of any violation by us of the NYSE’s Corporate Governance listing
standards as of March 6, 2008.
Executive
Sessions of Non-Management Directors
The Board
holds regular executive sessions in which non-management directors meet without
any members of management present. The purpose of these executive sessions
is to promote open and candid discussion among the non-management directors.
During such executive sessions, one director is
designated
as the “presiding director,” who is responsible for leading and facilitating
such executive sessions. Currently, the presiding director is Mr.
Barnett.
In
accordance with NYSE rules, we have established a toll-free, confidential
telephone hotline (the “Hotline”) so that interested parties may communicate
with the presiding director or with all the non-management directors as a
group. All calls to this Hotline are reported to the chairman of the
ACG Committee, who is responsible for communicating any necessary information to
the other non-management directors. The number of our confidential
Hotline is (877) 888-0002.
Directors
and Executive Officers of EPGP
The
following table sets forth the name, age and position of each of the directors
and executive officers of EPGP at March 2, 2009. Each executive
officer holds the same respective office shown below in the general partner of
the Operating Partnership.
|
Name
|
Age
|
Position
with EPGP
|
|
Dan
L. Duncan (1)
|
76
|
Director
and Chairman
|
|
Michael
A. Creel (1)
|
55
|
Director,
President and Chief Executive Officer
|
|
W.
Randall Fowler (1)
|
52
|
Director,
Executive Vice President and Chief Financial Officer
|
|
Richard
H. Bachmann (1)
|
56
|
Director,
Executive Vice President and Chief Legal Officer and
Secretary
|
|
A.J.
Teague (1)
|
63
|
Director,
Executive Vice President and Chief Commercial Officer
|
|
Dr.
Ralph S. Cunningham
|
68
|
Director
|
|
E.
William Barnett (2,3)
|
76
|
Director
|
|
Rex
C. Ross (2)
|
65
|
Director
|
|
Charles
M. Rampacek (2)
|
65
|
Director
|
|
William
Ordemann (1)
|
49
|
Executive
Vice President and Chief Operating Officer
|
|
Michael
J. Knesek (1)
|
54
|
Senior
Vice President, Controller and Principal Accounting
Officer
|
|
Christopher
Skoog (1)
|
45
|
Senior
Vice President
|
|
Thomas
M. Zulim (1)
|
51
|
Senior
Vice President
|
|
G.
R. Cardillo (1)
|
51
|
Vice
President
|
|
(1) Executive
officer
(2) Member
of ACG Committee
(3) Chairman
of ACG Committee
|
The following information presents a
brief history of the business experience of our directors and executive officers
serving as of December 31, 2008:
Dan L.
Duncan. Mr.
Duncan was elected Chairman and a Director of EPGP in April 1998, Chairman and a
Director of the general partner of EPO in December 2003, Chairman and a Director
of EPE Holdings in August 2005 and Chairman and a Director of DEP GP in October
2006. Mr. Duncan served as the sole Chairman of EPCO from 1979 to
December 2007. Mr. Duncan now serves as Group Co-Chairman of EPCO
with his daughter, Ms. Randa Duncan Williams, who is also a Director of EPE
Holdings. He also serves as an Honorary Trustee of the Board of
Trustees of the Texas Heart Institute at Saint Luke’s Episcopal
Hospital.
Michael
A. Creel. Mr. Creel was elected President and Chief Executive
Officer of EPGP in August 2007. From June 2000 to August 2007,
Mr. Creel served as Chief Financial Officer of EPGP and an Executive Vice
President of EPGP from January 2001 to August 2007. Mr. Creel, a
Certified Public Accountant, also served as a Senior Vice President of EPGP from
November 1999 to January 2001.
In
December 2007, Mr. Creel was elected Group Vice Chairman and Chief Financial
Officer of EPCO. Prior to these elections in EPCO, Mr. Creel served
as Chief Operating Officer from April 2005 to December 2007 and Chief Financial
Officer from June 2000 to April 2005 for EPCO. He also serves as
a Director of DEP GP and EPGP since October 2006 and 2005,
respectively. Mr. Creel served as President, Chief Executive Officer
and a Director of EPE Holdings from August 2005 through August
2007. In October 2005, Mr. Creel was elected a Director of Edge
Petroleum Corporation, a publicly traded oil and natural gas exploration and
production company.
W.
Randall Fowler. Mr. Fowler was elected Executive Vice
President and Chief Financial Officer of EPGP, EPE Holdings and DEP GP in August
2007. Mr. Fowler served as Senior Vice President and Treasurer of
EPGP from February 2005 to August 2007 and of DEP GP from October 2006 to August
2007. In February 2006, Mr. Fowler became a Director of EPGP, EPE
Holdings and of DEP. Mr. Fowler also served as Senior Vice President
and Chief Financial Officer of EPE Holdings from August 2005 to August
2007.
Mr. Fowler
was elected President and Chief Executive Officer of EPCO in December
2007. Prior to these elections, he served as Chief Financial Officer
of EPCO from April 2005 to December 2007. Mr. Fowler, a Certified
Public Accountant (inactive), joined Enterprise Products Partners as Director of
Investor Relations in January 1999.
Richard
H. Bachmann. Mr. Bachmann was elected an Executive Vice
President, Chief Legal Officer and Secretary of EPGP and a Director of EPGP in
February 2006. He previously served as a Director of EPGP from June
2000 to January 2004. Mr. Bachmann has served as a Director of EPO’s
general partner since December 2003 and has served as Executive Vice President,
Chief Legal Officer and Secretary of EPE Holdings since August
2005.
Mr.
Bachmann was elected Group Vice Chairman, Chief Legal Officer and Secretary of
EPCO in December 2007. In October 2006, Mr. Bachmann was elected
President, Chief Executive Officer and a Director of DEP GP. Mr.
Bachmann was also elected a Director of EPE Holdings in February
2006. Since January 1999, Mr. Bachmann has served as a Director of
EPCO. In November 2006, Mr. Bachmann was appointed an independent
manager of Constellation Energy Partners LLC. Mr. Bachmann also
serves as a member of the Audit, Compensation, Conflicts and Nominating and
Governance Committees of Constellation Energy Partners LLC.
A.J.
Teague. Mr.
Teague was elected an Executive Vice President of EPGP in November 1999 and
additionally as our Chief Commercial Officer and a Director in July
2008. Mr. Teague joined us in connection with our purchase of certain
midstream energy assets from affiliates of Shell Oil Company in
1999. From 1998 to 1999, Mr. Teague served as President of Tejas
Natural Gas Liquids, LLC.
Dr.
Ralph S. Cunningham. Dr. Cunningham was elected a Director of
EPGP in February 2006 and also served as a Director of EPGP from 1998 until
March 2005. In addition to these duties, Dr. Cunningham served as
Group Executive Vice President and Chief Operating Officer of EPGP from December
2005 to August 2007 and Interim President and Interim Chief Executive Officer
from June 2007 to August 2007. Dr. Cunningham was elected President
and Chief Executive Officer of EPE Holdings in August 2007. He served
as Chairman and a Director of TEPPCO GP from March 2005 until November
2005.
Dr. Cunningham was elected a Group Vice
Chairman of EPCO in December 2007 and served as a Director from 1987 to
1997. He serves as a Director of Tetra Technologies, Inc. (a publicly
traded energy services and chemical company), EnCana Corporation (a Canadian
publicly traded independent oil and natural gas company) and Agrium, Inc. (a
Canadian publicly traded agricultural chemicals company). Dr.
Cunningham retired in 1997 from CITGO Petroleum Corporation, where he had served
as President and Chief Executive Officer since 1995.
E.
William Barnett.
Mr. Barnett was elected a Director of EPGP in March 2005. Mr.
Barnett is a member of our ACG Committee and serves as its
Chairman. Mr. Barnett practiced law with Baker Botts L.L.P. from 1958
until his retirement in 2004. In 1984, he became Managing Partner of
Baker Botts L.L.P. and continued in that role for fourteen years until
1998. He was Senior Counsel to the firm from 1998 until June 2004,
when he retired from the firm. Mr. Barnett served as Chairman of the
Board of Trustees of Rice University from 1996 to July 2005.
Mr.
Barnett is a Life Trustee of The University of Texas Law School Foundation; a
Director of St. Luke’s Episcopal Health System; and a Director and former
Chairman of the Houston Zoo, Inc. (the operating arm of the Houston
Zoo). He is a Director of Reliant Energy, Inc. (a publicly traded
electric
services
company) and Westlake Chemical Corporation (a publicly traded chemical
company). Mr. Barnett is Chairman of the Advisory Board of the Baker
Institute for Public Policy at Rice University and a Director and former
Chairman of the Greater Houston Partnership. Mr. Barnett served as a
Trustee of the Baylor College of Medicine from 1993 until 2004.
Rex C.
Ross. Mr. Ross was
elected a Director of EPGP in October 2006 and is a member of its ACG
Committee. Mr. Ross serves as a Director of Schlumberger Technology
Corporation, the holding company for all Schlumberger Limited assets and
entities in the United States. Prior to his executive retirement from
Schlumberger Limited in May 2004, Mr. Ross held a number of executive management
positions during his 11-year career with the company, including President of
Schlumberger Oilfield Services North America; President, Schlumberger GeoQuest;
and President of SchlumbergerSema North & South America. Mr. Ross
also serves on the Board of Directors of Gulfmark Offshore, Inc. (a publicly
traded offshore marine services company) and is a member of its Governance
Committee.
Charles
M. Rampacek. Mr.
Rampacek was elected a Director of EPGP in October 2006 and is a member of its
ACG Committee. Mr. Rampacek is currently a business and management
consultant in the energy industry. Mr. Rampacek served as Chairman, Chief
Executive Officer and President of Probex Corporation (“Probex”), an energy
technology company that developed a proprietary used oil recovery process, from
2000 until his retirement in 2003. Prior to joining Probex, Mr.
Rampacek was President and Chief Executive Officer of Lyondell-Citgo Refining
L.P, a manufacturer of petroleum products, from 1996 through
2000. From 1982 to 1995, he held various executive positions with
Tenneco Inc. and its energy-related subsidiaries, including President of Tenneco
Gas Transportation Company, Executive Vice President of Tenneco Gas Operations
and Senior Vice President of Refining and Supply. Mr. Rampacek also spent 16
years with Exxon Company USA, where he held various supervisory and management
positions. Mr. Rampacek has been a Director of Flowserve Corporation
since 1998 and is Chairman of its Corporate Governance and Nominating Committee
and a member of its Organization and Compensation Committee.
In 2005,
two complaints requesting recovery of certain costs were filed against former
officers and directors of Probex as a result of the bankruptcy of Probex in
2003. These complaints were defended under Probex’s director and officer
insurance with American International Group, Inc. (“AIG”) and settlement was
reached and paid by AIG with bankruptcy court approval in the first half of
2006. An additional complaint was filed in 2005 against noteholders of certain
Probex debt of which Mr. Rampacek was one. A settlement of $2
thousand was reached and approved by the bankruptcy court in the first half of
2006.
William
Ordemann. Mr. Ordemann was elected an Executive Vice President
and the Chief Operating Officer of EPGP in August 2007. He
previously served as a Senior Vice President of EPGP from September 2001 to
August 2007 and was a Vice President of EPGP from October 1999 to September
2001. Mr. Ordemann joined us in connection with our purchase of
certain midstream energy assets from affiliates of Shell Oil Company in
1999. Prior to joining us, he was a Vice President of Shell Midstream
Enterprises, LLC from January 1997 to February 1998, and Vice President of Tejas
Natural Gas Liquids, LLC from February 1998 to September 1999.
Michael
J. Knesek. Mr.
Knesek, a Certified Public Accountant, was elected a Senior Vice President of
EPGP in February 2005, having served as a Vice President of EPGP since August
2000. Mr. Knesek has been the Principal Accounting Officer and
Controller of EPGP since August 2000, EPE Holdings since August 2005 and DEP GP
since October 2006. He has served as Senior Vice President of EPE
Holdings since August 2005 and of DEP GP since October 2006. Mr.
Knesek has been the Controller of EPCO since 1990 and currently serves as one of
its Senior Vice Presidents.
Christopher
R. Skoog. Mr. Skoog joined the partnership in July 2007 as
Senior Vice President of EPGP to develop and lead Enterprise Product Partners'
Natural Gas Services and Marketing group. In July 2008, he also assumed
responsibility for Enterprise Product Partners' non-regulated and intrastate
natural gas pipeline and storage businesses. From 1995 to July 2007 he served in
various executive positions at ONEOK, Inc. and ONEOK Partners L.P. He
led ONEOK Energy Services from 1995 to 2005, and held senior executive positions
in the partnership from 2005 to 2007.
Thomas
M. Zulim. Since July 2008, Mr. Zulim has served as a Senior
Vice President of EPGP and EPCO, Inc., with responsibility for the partnership's
unregulated natural gas liquids (NGL) business. From March 2006 to
July 2008, Mr. Zulim served as Senior Vice President, Human Resources, for both
EPGP and EPCO, and served as Vice President, Human Resources, for both EPGP and
EPCO from December 2004 to March 2006. He joined EPCO in 1999 as
Director of Business Management for the NGL Fractionation
business. Mr. Zulim came to EPCO from Shell Oil Company where, as an
attorney, he practiced labor and employment law nationally for several years
before joining Shell Midstream Enterprises in 1996 as Director of Business
Development for its natural gas processing and NGL fractionation
businesses. Mr. Zulim resumed practicing law with EPCO's Legal group
in January 2002 until December 2004.
G. R.
Cardillo. Mr. Cardillo
joined us in connection with our purchase of certain petrochemical storage and
propylene fractionation assets from affiliates of Ultramar Diamond Shamrock
Corp. and Koch Industries Inc. (“Diamond Koch”) in 2002. From 2000 to
2002, Mr. Cardillo served as a Vice President in charge of propylene commercial
activities for Diamond Koch. Mr. Cardillo was elected a Vice
President of EPGP in November 2004 and of DEP Holdings in September 2006.
Mr. Cardillo has been an integral part of our Petrochemicals management team
since joining us in 2002 and assumed leadership of this commercial function in
June 2008.
Section
16(a) Beneficial Ownership Reporting Compliance
Under
federal securities laws, EPGP, directors and executive officers of EPGP, and
certain other officers, and any persons holding more than 10.0% of our common
units are required to report their beneficial ownership of common units and any
changes in their beneficial ownership levels to us and the
SEC. Specific due dates for these reports have been established by
regulation, and we are required to disclose in this annual report any failure to
file this information within the specified timeframes. With the exception
of the following late filing, all such reporting was done in a timely manner in
2008. Rex C. Ross filed a late Form 4 on February 29, 2008 for a
transaction entered into in November 2007 by a Trust deemed beneficially owned
by him.
Executive
Officer Compensation
We do not directly employ any of the
persons responsible for managing our partnership. Instead, we are
managed by our general partner, the executive officers of which are employees of
EPCO. Our reimbursement of EPCO’s compensation costs is governed by the ASA
(see Item 13 of this annual report).
Summary
Compensation Table
The following table presents
consolidated compensation amounts paid, accrued or otherwise expensed by us with
respect to the years ended December 31, 2008, 2007 and 2006 for our CEO, CFO and
three other most highly compensated executive officers as of December 31,
2008. Collectively, these five individuals were our “Named Executive
Officers” for 2008. Compensation paid or awarded by us with respect to
such Named Executive Officers reflects only that portion of compensation paid by
EPCO allocated to us pursuant to the ASA, including an allocation of a portion
of the cost of EPCO’s equity-based long-term incentive plans.
|
Name
and
|
|
|
|
|
|
|
|
|
Unit
|
|
|
Option
|
|
|
All
Other
|
|
|
|
|
|
Principal
|
|
|
Salary
|
|
|
Bonus
|
|
|
Awards
|
|
|
Awards
|
|
|
Compensation
|
|
|
Total
|
|
|
Position
|
Year
|
|
($)
|
|
|
($)
(1)
|
|
|
($)
(2)
|
|
|
($)
(3)
|
|
|
($)
(4)
|
|
|
($)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Michael
A. Creel (CEO)
|
2008
|
|
$ |
563,200 |
|
|
$ |
552,000 |
|
|
$ |
1,115,948 |
|
|
$ |
90,902 |
|
|
$ |
200,241 |
|
|
$ |
2,522,291 |
|
|
|
2007
|
|
|
361,808 |
|
|
|
365,370 |
|
|
|
517,707 |
|
|
|
44,449 |
|
|
|
108,017 |
|
|
|
1,397,351 |
|
|
|
2006
|
|
|
306,000 |
|
|
|
125,000 |
|
|
|
303,622 |
|
|
|
23,613 |
|
|
|
71,812 |
|
|
|
830,047 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
W.
Randall Fowler (CFO)
|
2008
|
|
|
190,781 |
|
|
|
131,250 |
|
|
|
386,864 |
|
|
|
31,390 |
|
|
|
62,646 |
|
|
|
802,931 |
|
|
|
2007
|
|
|
213,145 |
|
|
|
129,720 |
|
|
|
297,976 |
|
|
|
25,033 |
|
|
|
53,425 |
|
|
|
719,299 |
|
|
|
2006
|
|
|
215,875 |
|
|
|
70,000 |
|
|
|
173,874 |
|
|
|
14,242 |
|
|
|
40,601 |
|
|
|
514,592 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
A.J.
Teague
|
2008
|
|
|
558,333 |
|
|
|
500,000 |
|
|
|
1,005,532 |
|
|
|
102,783 |
|
|
|
176,651 |
|
|
|
2,343,299 |
|
|
|
2007
|
|
|
445,660 |
|
|
|
300,000 |
|
|
|
587,905 |
|
|
|
77,980 |
|
|
|
110,336 |
|
|
|
1,521,881 |
|
|
|
2006
|
|
|
428,480 |
|
|
|
250,000 |
|
|
|
299,984 |
|
|
|
47,227 |
|
|
|
69,563 |
|
|
|
1,095,254 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
James
H. Lytal (5)
|
2008
|
|
|
401,700 |
|
|
|
-- |
|
|
|
1,083,798 |
|
|
|
111,221 |
|
|
|
216,574 |
|
|
|
1,813,293 |
|
|
|
2007
|
|
|
386,250 |
|
|
|
210,000 |
|
|
|
730,634 |
|
|
|
77,980 |
|
|
|
162,494 |
|
|
|
1,567,358 |
|
|
|
2006
|
|
|
367,500 |
|
|
|
187,500 |
|
|
|
455,462 |
|
|
|
47,227 |
|
|
|
101,639 |
|
|
|
1,159,328 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Richard
H. Bachmann
|
2008
|
|
|
351,313 |
|
|
|
233,750 |
|
|
|
725,317 |
|
|
|
56,531 |
|
|
|
129,921 |
|
|
|
1,496,832 |
|
|
|
2007
|
|
|
306,900 |
|
|
|
186,000 |
|
|
|
454,130 |
|
|
|
38,990 |
|
|
|
94,752 |
|
|
|
1,080,772 |
|
|
|
2006
|
|
|
177,420 |
|
|
|
75,000 |
|
|
|
182,174 |
|
|
|
14,168 |
|
|
|
43,088 |
|
|
|
491,850 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Amounts
represent discretionary annual cash awards accrued with respect to the
years presented. Cash awards are paid in February of the following
year (e.g., the cash awards for 2008 were paid in February
2009).
(2)
Amounts
represent expense recognized in accordance with SFAS 123(R) with respect
to restricted unit awards issued under the EPCO 1998 Plan and Employee
Partnership profits interests awards.
(3)
Amounts
represent expense recognized in accordance with SFAS 123(R) with respect
to unit options issued under the EPCO 1998 Plan and EPD 2008
LTIP.
(4)
Amounts
primarily represent (i) matching contributions under funded, qualified,
defined contribution retirement plans, (ii) quarterly distributions paid
on incentive plan awards and (iii) the imputed value of life insurance
premiums paid on behalf of the officer.
(5)
Mr.
Lytal resigned from the company in January 2009.
|
|
Compensation
Discussion and Analysis
With respect to our Named Executive
Officers, compensation paid or awarded by us for the last three fiscal years
reflects only that portion of compensation paid by EPCO allocated to us pursuant
to the ASA, including an allocation of a portion of the cost of equity-based
long-term incentive plans of EPCO. Dan L. Duncan controls EPCO and has ultimate
decision-making authority with respect to the
compensation
of our Named Executive Officers. The following elements of compensation, and
EPCO’s decisions with respect to determination of payments, are not subject to
approvals by our Board or the ACG Committee of our general
partner. Equity awards under EPCO’s long-term incentive plans are
approved by the ACG Committee of the respective issuer. We do not
have a separate compensation committee.
As discussed below, the elements of
EPCO’s compensation program, along with EPCO’s other rewards (e.g., benefits,
work environment, career development), are intended to provide a total rewards
package to employees. The compensation package is designed to reward
contributions by employees in support of the business strategies of EPCO and its
affiliates at both the partnership and individual levels. With respect to the
three years ended December 31, 2008, EPCO’s compensation package for Named
Executive Officers did not include any elements based on targeted
performance-related criteria.
The primary elements of EPCO’s
compensation program are a combination of annual cash and long-term equity-based
incentive compensation. For the three years ended December 31, 2008,
the elements of compensation for the Named Executive Officers consisted of the
following:
|
§
|
Discretionary
annual cash awards;
|
|
§
|
Awards
under long-term incentive arrangements;
and
|
|
§
|
Other
compensation, including very limited
perquisites.
|
In order to assist Mr. Duncan and EPCO
with compensation decisions, our CEO and the senior vice president of Human
Resources for EPCO formulate preliminary compensation recommendations for all of
the Named Executive Officers other than our CEO. Mr. Duncan, after
consulting with the senior vice president of Human Resources for EPCO,
independently makes compensation decisions with respect to our Named Executive
Officers. In making these compensation decisions, EPCO considers market data for
determining relevant compensation levels and compensation program elements
through the review of and, in certain cases, participation in, relevant
compensation surveys and reports. These surveys and reports are
conducted and prepared by a third party compensation consultant.
Periodically,
EPCO will engage a third party consultant to review compensation elements
provided to our executive officers. In 2006, EPCO engaged Towers Perrin to
review executive compensation relative to our industry. Towers Perrin
provided comparative market data on compensation practices and programs for
executive level positions based on an analysis of industry
competitors. Neither we nor EPCO, which engages the consultant, are
aware of the identity of the component companies who supply data to the
consultant. EPCO uses the data provided in the Towers Perrin analysis
to gauge whether compensation levels reported by the consultant are within the
general ranges of compensation for EPCO employees in similar positions, but that
comparison is only a factor taken into consideration and may or may not impact
compensation of our executive officers, for which Dan L. Duncan has the ultimate
decision-making authority. EPCO does not otherwise engage in
benchmarking executive level positions.
Mr. Duncan and EPCO do not use any
formula or specific performance-based criteria for our Named Executive Officers
in connection with determining compensation for services performed for us;
rather, Mr. Duncan and EPCO determine an appropriate level and mix of
compensation on a case-by-case basis. Further, there is no
established policy or target for the allocation between either cash and non-cash
or short-term and long-term incentive compensation. However, some
considerations that Mr. Duncan may take into account in making the case-by-case
compensation determinations include total value of wealth accumulated and the
appropriate balance of internal pay equity among executive
officers. Mr. Duncan and EPCO also consider individual performance,
levels of responsibility, skills and experience. All compensation determinations
are discretionary and, as noted above, subject to Mr. Duncan’s ultimate
decision-making authority except for equity awards under EPCO’s long-term
incentive plans, as discussed below.
We believe the absence of specific
performance-based criteria associated with our salary compensation and equity
awards, and the long-term nature of our equity awards, has the effect of not
encouraging excessive risk taking by our executive officers in order to reach
certain targets. Further, the practice of making compensation
decisions on a case-by-case basis permits consideration of flexible criteria,
including current overall market conditions. Because our 2008 annual
base salaries and the majority of our 2008 equity awards were made in the first
half of 2008, recent market volatility and market declines did not have a
material impact on 2008 compensation decisions. However, current
market conditions may impact 2009 compensation decisions regarding annual base
salaries and equity award grants.
The discretionary cash awards paid to
each of our Named Executive Officers were determined by consultation among Mr.
Duncan, our CEO and the senior vice president of Human Resources for EPCO,
subject to Mr. Duncan’s final determination. These cash awards, in
combination with annual base salaries, are intended to yield competitive total
cash compensation levels for the Named Executive Officers and drive performance
in support of our business strategies, as well as the performance of other EPCO
affiliates for which the Named Executive Officers perform
services. It is EPCO’s general policy to pay these awards in February
of each year.
The incentive awards granted under
EPCO’s long-term incentive plans to our Named Executive Officers were determined
by consultation among Mr. Duncan, our CEO and the senior vice president of Human
Resources for EPCO. Incentive awards issued under
EPCO’s long-term incentive plans involving our securities are also approved
by the ACG Committee of our general partner. In addition, our Named
Executive Officers are Class B limited partners in certain of the Employee
Partnerships. Mr. Duncan approves the issuance of all limited
partnership interests in the Employee Partnerships to our Named Executive
Officers. See “Summary of Long-Term Incentive Arrangements Underlying 2008
Award Grants” within this Item 11 for information regarding the long-term
incentive plans. See Note 5 of the Notes to Consolidated Financial
Statements included under Item 8 of this annual report for information regarding
the accounting for such awards.
EPCO generally does not pay for
perquisites for any of our Named Executive Officers, other than reimbursement of
certain parking expenses, and expects to continue its policy of covering very
limited perquisites allocable to our Named Executive Officers. EPCO also makes
matching contributions under its 401(k) plan for the benefit of our Named
Executive Officers in the same manner as it does for other EPCO
employees.
EPCO does not offer our Named Executive
Officers a defined benefit pension plan. Also, none of our Named
Executive Officers had nonqualified deferred compensation during the three years
ended December 31, 2008.
We believe that each of the base
salary, cash awards, and incentive awards fit the overall compensation
objectives of us and of EPCO, as stated above (i.e., to provide competitive
compensation opportunities to align and drive employee performance toward the
creation of sustained long-term unitholder value, which will also allow us to
attract, motivate and retain high quality talent with the skills and
competencies required by us).
Compensation
Committee Report
We do not have a separate compensation
committee. In addition, we do not directly employ or compensate our
Named Executive Officers. Rather, under the ASA with EPCO, we reimburse EPCO for
the compensation of our executive officers. Accordingly, to the
extent that decisions are made regarding the compensation policies pursuant to
which our Named Executive Officers are compensated, they are made by Mr. Duncan
and EPCO alone (except for equity awards, as previously noted), and not by our
Board.
In light of the foregoing, the Board
has reviewed and discussed the Compensation Discussion and Analysis with
management and determined that the Compensation Discussion and Analysis be
included in the Company’s annual report on Form 10-K for the year ended December
31, 2008.
| Submitted
by: |
Dan L.
Duncan |
| |
Michael A.
Creel |
| |
W. Randall
Fowler |
| |
Richard H.
Bachmann |
| |
Dr. Ralph S.
Cunningham |
| |
E. William
Barnett |
| |
Charles M.
Rampacek |
| |
Rex C.
Ross |
| |
A.J.
Teague |
Notwithstanding anything to the
contrary set forth in any previous filings under the Securities Act, as amended,
or the Exchange Act, as amended, that incorporate future filings, including this
annual report, in whole or in part, the foregoing report shall not be
incorporated by reference into any such filings.
Grants
of Plan-Based Awards in Fiscal Year 2008
The following table presents
information concerning grants of plan-based awards to the Named Executive
Officers in 2008. The restricted unit and unit option awards granted
during 2008 were under the EPCO 1998 Plan and EPD 2008 LTIP.
|
|
|
|
|
|
|
|
|
|
Grant
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise
|
|
|
Date
Fair
|
|
|
|
|
|
|
|
|
or
Base
|
|
|
Value
of
|
|
|
|
|
|
Estimated
Future Payouts Under
|
|
|
Price
of
|
|
|
Unit
and
|
|
|
|
|
|
Equity
Incentive Plan Awards
|
|
|
Option
|
|
|
Option
|
|
|
|
Grant
|
|
Threshold
|
|
|
Target
|
|
|
Maximum
|
|
|
Awards
|
|
|
Awards
|
|
|
Name
|
Date
|
|
(#)
|
|
|
(#)
|
|
|
(#)
|
|
|
($/Unit)
|
|
|
($) (1)
|
|
|
Restricted unit awards:
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Michael
A. Creel (CEO)
|
5/22/08
|
|
|
-- |
|
|
|
40,000 |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
989,760 |
|
|
W.
Randall Fowler (CFO)
|
5/22/08
|
|
|
-- |
|
|
|
28,100 |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
325,925 |
|
|
A.J.
Teague
|
5/22/08
|
|
|
-- |
|
|
|
28,100 |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
869,133 |
|
|
James
H. Lytal
|
5/22/08
|
|
|
-- |
|
|
|
28,100 |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
869,133 |
|
|
Richard
H. Bachmann
|
5/22/08
|
|
|
-- |
|
|
|
28,100 |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
478,023 |
|
|
Unit option awards:
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Michael
A. Creel (CEO)
|
5/22/08
|
|
|
-- |
|
|
|
90,000 |
|
|
|
-- |
|
|
$ |
30.93 |
|
|
$ |
171,360 |
|
|
W.
Randall Fowler (CFO)
|
5/22/08
|
|
|
-- |
|
|
|
60,000 |
|
|
|
-- |
|
|
$ |
30.93 |
|
|
$ |
53,550 |
|
|
A.J.
Teague
|
5/22/08
|
|
|
-- |
|
|
|
60,000 |
|
|
|
-- |
|
|
$ |
30.93 |
|
|
$ |
142,800 |
|
|
James
H. Lytal
|
5/22/08
|
|
|
-- |
|
|
|
60,000 |
|
|
|
-- |
|
|
$ |
30.93 |
|
|
$ |
142,800 |
|
|
Richard
H. Bachmann
|
5/22/08
|
|
|
-- |
|
|
|
60,000 |
|
|
|
-- |
|
|
$ |
30.93 |
|
|
$ |
78,540 |
|
|
Profits interest awards:
(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Enterprise
Unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Michael
A. Creel (CEO)
|
2/20/08
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
586,622 |
|
|
W.
Randall Fowler (CFO)
|
2/20/08
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
121,198 |
|
|
A.J.
Teague
|
2/20/08
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
407,143 |
|
|
James
H. Lytal
|
2/20/08
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
162,857 |
|
|
Richard
H. Bachmann
|
2/20/08
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
223,929 |
|
|
EPCO
Unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Michael
A. Creel (CEO)
|
11/13/08
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
1,119,899 |
|
|
W.
Randall Fowler (CFO)
|
11/13/08
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
524,953 |
|
|
A.J.
Teague
|
11/13/08
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
1,399,873 |
|
|
James
H. Lytal
|
11/13/08
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
Richard
H. Bachmann
|
11/13/08
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
769,930 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Amounts
presented reflect that portion of grant date fair value allocable to us
based on the percentage of time each Named Executive Officer spent on our
consolidated business activities during 2008. Based on current
allocations, we estimate that the consolidated compensation expense we
record for each Named Executive Officer with respect to these awards will
equal these amounts over time.
(2)
For
the period in which the restricted unit awards were outstanding during
2008, we recognized a total of $0.5 million of consolidated compensation
expense related to these awards. The remaining portion of grant date
fair value will be recognized as expense in future
periods.
(3)
For
the period in which the unit option awards were outstanding during 2008,
we recognized a total of $0.1 million of consolidated compensation expense
related to these awards. The remaining portion of grant date fair
value will be recognized as expense in future periods.
(4)
For
the period in which the profits interest awards were outstanding during
2008, we recognized a total of $0.3 million of consolidated compensation
expense related to these awards. The remaining portion of grant date
fair value will be recognized as expense in future
periods.
|
|
The fair
value amounts presented in the table are based on certain assumptions and
considerations made by management. See Note 5 of the Notes to
Consolidated Financial Statements included under Item 8 of this annual report
for additional information regarding our fair value assumptions.
Summary
of Long-Term Incentive Arrangements Underlying 2008 Award Grants
The
following information summarizes the types of awards granted to our Named
Executive Officers during the year ended December 31, 2008. For
detailed information regarding our accounting for equity awards, see Note 5 of
the Notes to Consolidated Financial Statements included under Item 8 of this
annual report.
As used
in the context of the EPCO, the term “restricted unit” represents a time-vested
unit under SFAS 123(R). Such awards are non-vested until the required
service period expires.
EPCO
1998 Plan. The
EPCO 1998 Plan provides for incentive awards to EPCO’s key employees who perform
management, administrative or operational functions for us or our
affiliates. Awards granted under the EPCO 1998 Plan may be in the
form of unit options, restricted units, phantom units and distribution
equivalent rights (“DERs”).
When issued, the exercise price of each
option grant is equivalent to the market price per unit of our common units on
the date of grant. In general, options granted under the EPCO 1998
Plan have a vesting period of four years and remain exercisable for ten years
from the date of grant.
A total of 152,400 restricted units
were granted under this plan to the Named Executive Officers in May
2008. Restricted unit awards under the EPCO 1998 Plan allow
recipients to acquire our common units (at no cost to the recipient) once a
defined vesting period expires, subject to certain forfeiture
provisions. The restrictions on such awards generally lapse four
years from the date of grant. The fair value of restricted units is
based on the market price per unit of our common units on the date of grant less
an allowance for estimated forfeitures. Each recipient is also
entitled to cash distributions equal to the product of the number of restricted
units outstanding for the participant and the cash distribution per unit paid by
us to our unitholders.
The EPCO 1998 Plan also provides for
the issuance of phantom unit awards, including related DERs. No
phantom unit awards or associated DERs have been granted under the EPCO 1998
Plan.
EPD 2008
LTIP. The EPD 2008 LTIP provides for incentive awards to
EPCO’s key employees who perform management, administrative or operational
functions for us or our affiliates. Awards granted under the EPD 2008
LTIP may be in the form of unit options, restricted units, phantom units and
DERs.
A total
of 330,000 options were granted under this plan to the Named Executive Officers
in May 2008. When issued, the exercise price of each option grant was
equivalent to the market price per unit of our common units on the date of
grant. In general, these options have a vesting period of four years
and are exercisable during specified periods within the calendar year
immediately following the year in which vesting occurs. At December 31, 2008, no
restricted units or DERs had been issued under this plan. There were
a total of 4,400 phantom units granted under the EPD 2008 LTIP outstanding at
December 31, 2008.
Profits
interests awards. Our
Named Executive Officers were granted awards consisting of profits interests, or
Class B limited partner interests, in Enterprise Unit in February 2008 and EPCO
Unit in November 2008. In addition, the Named Executive Officers have
received profits interests awards in the other Employee Partnerships in prior
years. Profits interest awards entitle each holder to participate in
the expected long-term appreciation in value of the equity securities owned by
each Employee Partnership. The Employee Partnerships in which the
Named Executive Officers participate own either Enterprise GP Holdings units or
our common units or a combination of both. Such awards are subject to
forfeiture. For additional information regarding the Employee Partnerships,
including the assumptions we used to estimate the fair value of these awards,
see Note 5 of the Notes to Financial Statements included under Item 8 of this
annual report.
The
following table presents each Named Executive Officer’s share of the total
profits interest in the Employee Partnerships at December 31, 2008:
|
|
Percentage
Ownership of Class B Interests
|
|
|
EPE
|
EPE
|
Enterprise
|
EPCO
|
|
Named
Executive Officer
|
Unit
I
|
Unit
III
|
Unit
|
Unit
|
|
Michael
A. Creel (CEO)
|
8.2%
|
7.8%
|
17.5%
|
20.0%
|
|
W.
Randall Fowler (CFO)
|
5.5%
|
7.8%
|
7.8%
|
20.0%
|
|
A.J.
Teague
|
5.5%
|
6.5%
|
9.7%
|
20.0%
|
|
James
H. Lytal
|
5.5%
|
6.5%
|
3.9%
|
--
|
|
Richard
H. Bachmann
|
8.2%
|
7.8%
|
9.7%
|
20.0%
|
Equity
Awards Outstanding at December 31, 2008
The
following tables present information concerning each Named Executive Officer’s
long-term incentive awards outstanding at December 31, 2008. We
expect to be allocated our pro rata share of the cost of such awards under the
ASA. As a result, the gross amounts listed in the table do not
represent the amount of expense we will recognize in connection with these
awards.
The following table presents
information concerning each Named Executive Officer’s nonvested restricted units
and unexercised unit options at December 31, 2008:
|
|
|
|
Option
Awards
|
|
|
Unit
Awards
|
|
|
|
|
|
Number
of
|
|
|
|
|
|
|
|
|
|
|
|
Market
|
|
|
|
|
|
Units
|
|
|
|
|
|
|
|
|
Number
|
|
|
Value
|
|
|
|
|
|
Underlying
|
|
|
Option
|
|
|
|
|
|
of
Units
|
|
|
of
Units
|
|
|
|
|
|
Options
|
|
|
Exercise
|
|
|
Option
|
|
|
That
Have
|
|
|
That
Have
|
|
|
|
Vesting
|
|
Unexercisable
|
|
|
Price
|
|
|
Expiration
|
|
|
Not
Vested
|
|
|
Not
Vested
|
|
|
Name
|
Date
|
|
(#)
|
|
|
($/Unit)
|
|
|
Date
|
|
|
(#)(2)
|
|
|
($)(3)
|
|
|
Restricted
unit awards:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Michael
A. Creel (CEO)
|
Various
(1)
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
88,500 |
|
|
$ |
1,834,605 |
|
|
W.
Randall Fowler (CFO)
|
Various
(1)
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
63,100 |
|
|
$ |
1,308,063 |
|
|
A.J.
Teague
|
Various
(1)
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
76,600 |
|
|
$ |
1,587,918 |
|
|
James
H. Lytal
|
Various
(1)
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
76,600 |
|
|
$ |
1,587,918 |
|
|
Richard
H. Bachmann
|
Various
(1)
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
76,600 |
|
|
$ |
1,587,918 |
|
|
Unit
option awards:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Michael
A. Creel (CEO):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
May
10, 2004 option grant
|
5/10/08
|
|
|
35,000 |
|
|
|
20.00 |
|
|
5/10/14
|
|
|
|
-- |
|
|
|
-- |
|
|
August
4, 2005 option grant
|
8/04/09
|
|
|
35,000 |
|
|
|
26.47 |
|
|
8/04/15
|
|
|
|
-- |
|
|
|
-- |
|
|
May
1, 2006 option grant
|
5/01/10
|
|
|
40,000 |
|
|
|
24.85 |
|
|
5/01/16
|
|
|
|
-- |
|
|
|
-- |
|
|
May
29, 2007 option grant
|
5/29/11
|
|
|
60,000 |
|
|
|
30.96 |
|
|
5/29/17
|
|
|
|
-- |
|
|
|
-- |
|
|
May
22, 2008 option grant
|
5/22/12
|
|
|
90,000 |
|
|
|
30.93 |
|
|
12/31/13
|
|
|
|
-- |
|
|
|
-- |
|
|
W.
Randall Fowler (CFO):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
May
10, 2004 option grant
|
5/10/08
|
|
|
10,000 |
|
|
|
20.00 |
|
|
5/10/14
|
|
|
|
-- |
|
|
|
-- |
|
|
August
4, 2005 option grant
|
8/04/09
|
|
|
25,000 |
|
|
|
26.47 |
|
|
8/04/15
|
|
|
|
-- |
|
|
|
-- |
|
|
May
1, 2006 option grant
|
5/01/10
|
|
|
40,000 |
|
|
|
24.85 |
|
|
5/01/16
|
|
|
|
-- |
|
|
|
-- |
|
|
May
29, 2007 option grant
|
5/29/11
|
|
|
45,000 |
|
|
|
30.96 |
|
|
5/29/17
|
|
|
|
-- |
|
|
|
-- |
|
|
May
22, 2008 option grant
|
5/22/12
|
|
|
60,000 |
|
|
|
30.93 |
|
|
12/31/13
|
|
|
|
-- |
|
|
|
-- |
|
|
A.J.
Teague:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
May
10, 2004 option grant
|
5/10/08
|
|
|
35,000 |
|
|
|
20.00 |
|
|
5/10/14
|
|
|
|
-- |
|
|
|
-- |
|
|
August
4, 2005 option grant
|
8/04/09
|
|
|
35,000 |
|
|
|
26.47 |
|
|
8/04/15
|
|
|
|
-- |
|
|
|
-- |
|
|
May
1, 2006 option grant
|
5/01/10
|
|
|
40,000 |
|
|
|
24.85 |
|
|
5/01/16
|
|
|
|
-- |
|
|
|
-- |
|
|
May
29, 2007 option grant
|
5/29/11
|
|
|
60,000 |
|
|
|
30.96 |
|
|
5/29/17
|
|
|
|
-- |
|
|
|
-- |
|
|
May
22, 2008 option grant
|
5/22/12
|
|
|
60,000 |
|
|
|
30.93 |
|
|
12/31/13
|
|
|
|
-- |
|
|
|
-- |
|
|
James
H. Lytal:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September
30, 2004 option grant
|
9/30/08
|
|
|
35,000 |
|
|
|
23.18 |
|
|
9/30/14
|
|
|
|
-- |
|
|
|
-- |
|
|
August
4, 2005 option grant
|
8/04/09
|
|
|
35,000 |
|
|
|
26.47 |
|
|
8/04/15
|
|
|
|
-- |
|
|
|
-- |
|
|
May
1, 2006 option grant
|
5/01/10
|
|
|
40,000 |
|
|
|
24.85 |
|
|
5/01/16
|
|
|
|
-- |
|
|
|
-- |
|
|
May
29, 2007 option grant
|
5/29/11
|
|
|
60,000 |
|
|
|
30.96 |
|
|
5/29/17
|
|
|
|
-- |
|
|
|
-- |
|
|
May
22, 2008 option grant
|
5/22/12
|
|
|
60,000 |
|
|
|
30.93 |
|
|
12/31/13
|
|
|
|
-- |
|
|
|
-- |
|
|
Richard
H. Bachmann:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
May
10, 2004 option grant
|
5/10/08
|
|
|
35,000 |
|
|
|
20.00 |
|
|
5/10/14
|
|
|
|
-- |
|
|
|
-- |
|
|
August
4, 2005 option grant
|
8/04/09
|
|
|
35,000 |
|
|
|
26.47 |
|
|
8/04/15
|
|
|
|
-- |
|
|
|
-- |
|
|
May
1, 2006 option grant
|
5/01/10
|
|
|
40,000 |
|
|
|
24.85 |
|
|
5/01/16
|
|
|
|
-- |
|
|
|
-- |
|
|
May
29, 2007 option grant
|
5/29/11
|
|
|
60,000 |
|
|
|
30.96 |
|
|
5/29/17
|
|
|
|
-- |
|
|
|
-- |
|
|
May
22, 2008 option grant
|
5/22/12
|
|
|
60,000 |
|
|
|
30.93 |
|
|
12/31/13
|
|
|
|
-- |
|
|
|
-- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Of
the 381,400 restricted unit awards presented in the table, 46,000 vest in
2009, 60,000 vest in 2010, 123,000 vest in 2011 and 152,400 vest in
2012.
(2) Amounts
represent total number of restricted unit awards granted to Named
Executive Officer.
(3) Amounts
derived by multiplying the total number of restricted unit awards granted
to the Named Executive Officer by the closing price of our common units at
December 31, 2008 of $20.73 per unit.
|
|
The following table presents
information concerning each Named Executive Officer’s nonvested profits interest
awards at December 31, 2008:
|
|
|
Option
Awards
|
Unit
Awards
|
|
|
|
|
Number
of
|
|
|
|
|
|
|
|
|
|
|
|
Market
|
|
|
|
|
|
Units
|
|
|
|
|
|
|
|
|
Number
|
|
|
Value
|
|
|
|
|
|
Underlying
|
|
|
Option
|
|
|
|
|
|
of
Units
|
|
|
of
Units
|
|
|
|
|
|
Options
|
|
|
Exercise
|
|
|
Option
|
|
|
That
Have
|
|
|
That
Have
|
|
|
|
Vesting
|
|
Unexercisable
|
|
|
Price
|
|
|
Expiration
|
|
|
Not
Vested
|
|
|
Not
Vested
|
|
|
Name
|
Date
|
|
(#)
|
|
|
($/Unit)
|
|
|
Date
|
|
|
(#)
|
|
|
($)
|
|
|
EPE
Unit I:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Michael
A. Creel (CEO)
|
11/09/12
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
0 |
|
|
W.
Randall Fowler (CFO)
|
11/09/12
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
0 |
|
|
A.J.
Teague
|
11/09/12
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
0 |
|
|
James
H. Lytal
|
11/09/12
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
0 |
|
|
Richard
H. Bachmann
|
11/09/12
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
0 |
|
|
EPE
Unit III:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Michael
A. Creel (CEO)
|
5/09/14
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
0 |
|
|
W.
Randall Fowler (CFO)
|
5/09/14
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
0 |
|
|
A.J.
Teague
|
5/09/14
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
0 |
|
|
James
H. Lytal
|
5/09/14
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
0 |
|
|
Richard
H. Bachmann
|
5/09/14
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
0 |
|
|
Enterprise
Unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Michael
A. Creel (CEO)
|
2/20/14
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
0 |
|
|
W.
Randall Fowler (CFO)
|
2/20/14
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
0 |
|
|
A.J.
Teague
|
2/20/14
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
0 |
|
|
James
H. Lytal
|
2/20/14
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
0 |
|
|
Richard
H. Bachmann
|
2/20/14
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
0 |
|
|
EPCO
Unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Michael
A. Creel (CEO)
|
11/13/13
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
0 |
|
|
W.
Randall Fowler (CFO)
|
11/13/13
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
0 |
|
|
A.J.
Teague
|
11/13/13
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
0 |
|
|
James
H. Lytal
|
11/13/13
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
0 |
|
|
Richard
H. Bachmann
|
11/13/13
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
$ |
0 |
|
The profits interest awards had no
market (or assumed liquidation) value at December 31, 2008 due to a decrease in
the market value of the limited partner interests owned by each Employee
Partnership since the formation
Option
Exercises and Stock Vested Table
The
following table presents the exercise of unit options by and vesting of
restricted units to our Named Executive Officers during the year ended December
31, 2008 for which we were historically responsible for a share of the related
cost of such awards.
|
|
Option
Awards
|
Unit
Awards
|
|
|
|
Number
of
|
|
|
|
|
|
Number
of
|
|
|
Gross
|
|
|
|
|
Units
|
|
|
Value
|
|
|
Units
|
|
|
Value
|
|
|
|
|
Acquired
on
|
|
|
Realized
on
|
|
|
Acquired
on
|
|
|
Realized
on
|
|
|
|
|
Exercise
|
|
|
Exercise
|
|
|
Vesting
|
|
|
Vesting
|
|
|
Name
|
|
(#)
|
|
|
($)
|
|
|
(#)
|
|
|
($)
(1)
|
|
|
Michael
A. Creel (CEO)
|
|
|
-- |
|
|
|
-- |
|
|
|
54,553 |
|
|
$ |
1,146,990 |
|
|
W.
Randall Fowler (CFO)
|
|
|
-- |
|
|
|
-- |
|
|
|
23,777 |
|
|
$ |
467,209 |
|
|
A.J.
Teague
|
|
|
-- |
|
|
|
-- |
|
|
|
12,000 |
|
|
$ |
364,440 |
|
|
James
H. Lytal
|
|
|
-- |
|
|
|
-- |
|
|
|
37,532 |
|
|
$ |
1,084,647 |
|
|
Richard
H. Bachmann
|
|
|
-- |
|
|
|
-- |
|
|
|
54,553 |
|
|
$ |
1,146,990 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Amount
determined by multiplying the number of restricted unit awards that vested
during 2008 by the closing price of our common units on the date of
vesting.
|
|
No options were exercised by the Named
Executive Officers during 2008.
Nonqualified
Deferred Compensation for the 2008 Fiscal Year
During 2008, no Named Executive Officer
received deferred compensation (other than incentive awards described elsewhere)
on a basis that was not tax-qualified with respect to any defined contribution
or other plan.
Director
Compensation
The following table presents
information regarding compensation to the independent directors of our general
partner during 2008.
|
|
|
Fees
Earned
|
|
|
|
|
|
Unit
|
|
|
|
|
|
|
|
or
Paid
|
|
|
Unit
|
|
|
Appreciation
|
|
|
|
|
|
|
|
in
Cash
|
|
|
Awards
|
|
|
Rights
|
|
|
Total
|
|
|
Name
|
|
($)
|
|
|
($)
|
|
|
($) (1)
|
|
|
($)
|
|
|
E.
William Barnett
|
|
$ |
90,000 |
|
|
|
-- |
|
|
$ |
(3,886 |
) |
|
$ |
86,114 |
|
|
Rex
C. Ross
|
|
$ |
75,000 |
|
|
|
-- |
|
|
|
(2,859 |
) |
|
$ |
72,141 |
|
|
Charles
M. Rampacek
|
|
$ |
75,000 |
|
|
|
-- |
|
|
|
(2,859 |
) |
|
$ |
72,141 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Amounts
presented reflect compensation expense recognized in accordance with SFAS
123(R) by EPGP. Expense credits were recognized in 2008 as a result
of a decrease in the price of Enterprise GP Holdings’ units during the
period.
|
|
Neither we nor EPGP provide any
additional compensation to employees of EPCO who serve as directors of EPGP. The
employees of EPCO who served as directors of EPGP during 2008 were Messrs.
Duncan, Creel, Fowler, Bachmann, Cunningham and Teague.
Currently,
EPGP’s three independent directors, Messrs. Barnett, Ross and Rampacek, are
provided cash compensation for their services as follows:
|
§
|
Each
independent director receives $75,000 in cash
annually. Prior to August 2007, the annual retainer was
$50,000 in cash and $25,000 worth of restricted
units.
|
|
§
|
If
the individual serves as chairman of a committee of the Board of
Directors, then he receives an additional $15,000 in cash
annually.
|
The
independent directors of our general partner have also received equity-based
compensation in the form of Unit Appreciation Rights (“UARs”). These
awards consist of letter agreements with each of the independent directors and
are not part of any long-term incentive plan of the EPCO group of
companies. The awards are based upon an incentive plan of EPE
Holdings, and are made in the form of UAR grants for non-employee
directors. The compensation expense associated with these awards is
recognized by EPGP. These UARs entitle the independent directors
to receive a cash amount in the future equal to the excess, if any, of the fair
market value of Enterprise GP Holdings’ units (determined as of a future vesting
date) over the grant date price of such units. If a director resigns
or is removed prior to vesting, his UAR awards are forfeited.
In August
2006, Mr. Barnett was granted 10,000 UARs under the letter agreement
format. The grant date price of these rights was $35.71 per
unit. These awards vest in August 2011 or on the date of certain
qualifying events (as set forth in the form of grant). At December
31, 2008, the estimated fair value of these 10,000 UARs was $2
thousand. In November 2006, Mr. Barnett was issued an additional
20,000 UARs and Mr. Ross and Mr. Rampacek were each granted 30,000 UARs under
the letter agreement format. The grant date price of these UARs was
$34.10 per unit. These awards vest in November 2011 or on the date of
certain qualifying events (as set forth in the form of grant). At
December 31, 2008, the total fair value of these 80,000 UARs was $28
thousand. Our estimates of the fair values of the UARs were based on
the following assumptions: (i) remaining life of awards of three years; (ii)
risk-free interest rate of 1.0%; (iii) an expected distribution yield on
Enterprise GP Holdings’ units of 5.4%; and (iv) an expected unit price
volatility of Enterprise GP Holdings’ units of 30.3%.
and Related Unitholder
Matters.
Security
Ownership of Certain Beneficial Owners
The
following table sets forth certain information as of February 2, 2009, regarding
each person known by our general partner to beneficially own more than 5.0% of
our common units.
|
|
|
|
Amount
and
|
|
|
|
|
|
|
|
|
Nature
of
|
|
|
|
|
|
Title
of
|
Name
and Address
|
|
Beneficial
|
|
|
Percent
|
|
|
Class
|
of
Beneficial Owner
|
|
Ownership
|
|
|
of
Class
|
|
|
Common
units
|
Dan
L. Duncan
|
|
|
152,506,527
(1) |
|
|
33.8%
|
|
|
|
1100
Louisiana Street, 10th Floor
|
|
|
|
|
|
|
|
|
|
|
Houston,
Texas 77002
|
|
|
|
|
|
|
|
|
|
(1)
For
a detailed listing of ownership amounts that comprise Mr. Duncan’s total
beneficial ownership of our common units, see the table presented in the
following section, “Security Ownership of Management,” within this Item
12.
|
|
Security
Ownership of Management
Enterprise
Products Partners L.P. and Enterprise GP Holdings L.P.
The
following sets forth certain information regarding the beneficial ownership of
our common units and the units of Enterprise GP Holdings L.P. as of February 2,
2009 by:
|
§
|
our
Named Executive Officers;
|
|
§
|
the
current Directors of EPGP; and
|
|
§
|
the
current directors and executive officers of EPGP as a
group.
|
If an individual does not own any
securities in the foregoing registrants, he is not listed in the following
table.
Enterprise GP Holdings owns 100.0% of
the membership interests of EPGP. All information with respect to
beneficial ownership has been furnished by the respective directors or
officers. Each person has sole voting and dispositive power over the
securities shown unless otherwise indicated below. The beneficial
ownership amounts of certain individuals include options to acquire our common
units that are exercisable within 60 days of the filing date of this annual
report.
Mr.
Duncan owns 50.4% of the voting stock of EPCO and, accordingly, exercises sole
voting and dispositive power with respect to our common units beneficially owned
by EPCO and its affiliates. The remaining shares of EPCO capital
stock are owned primarily by trusts for the benefit of members of Mr. Duncan’s
family. The address of EPCO is 1100 Louisiana Street, 10th Floor,
Houston, Texas 77002.
|
|
|
Enterprise
Products Partners L.P.
Common
Units
|
|
|
Enterprise
GP Holdings L.P.
Units
|
|
|
|
|
Amount
and
|
|
|
|
|
|
Amount
and
|
|
|
|
|
|
|
|
Nature
of
|
|
|
|
|
|
Nature
of
|
|
|
|
|
|
Name
of
|
|
Beneficial
|
|
|
Percent
of
|
|
|
Beneficial
|
|
|
Percent
of
|
|
|
Beneficial
Owner
|
|
Ownership
|
|
|
Class
|
|
|
Ownership
|
|
|
Class
|
|
|
Dan
L. Duncan:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Units
owned by EPCO:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Through
DFI Delaware Holdings, L.P.
|
|
|
121,990,717 |
|
|
|
27.0 |
% |
|
|
-- |
|
|
|
-- |
|
|
Through
Duncan Family Interests, Inc.
|
|
|
-- |
|
|
|
-- |
|
|
|
71,860,405 |
|
|
|
51.6 |
% |
|
Through
DFI GP Holdings L.P.
|
|
|
-- |
|
|
|
-- |
|
|
|
25,162,804 |
|
|
|
18.1 |
% |
|
Through
Enterprise GP Holdings L.P.
|
|
|
13,670,925 |
|
|
|
3.0 |
% |
|
|
-- |
|
|
|
-- |
|
|
Through
EPCO Holdings, Inc.
|
|
|
1,037,037 |
|
|
|
* |
|
|
|
-- |
|
|
|
-- |
|
|
Units
owned by DD Securities LLC
|
|
|
487,100 |
|
|
|
* |
|
|
|
3,745,673 |
|
|
|
2.7 |
% |
|
Units
owned by Employee Partnerships (1)
|
|
|
1,623,654 |
|
|
|
* |
|
|
|
7,165,315 |
|
|
|
5.1 |
% |
|
Units
owned by family trusts (2)
|
|
|
12,517,338 |
|
|
|
2.8 |
% |
|
|
243,071 |
|
|
|
* |
|
|
Units
owned directly
|
|
|
1,179,756 |
|
|
|
* |
|
|
|
110,700 |
|
|
|
* |
|
|
Total
for Dan L. Duncan
|
|
|
152,506,527 |
|
|
|
33.8 |
% |
|
|
108,287,968 |
|
|
|
77.8 |
% |
|
Michael
A. Creel (3)
|
|
|
195,842 |
|
|
|
* |
|
|
|
35,000 |
|
|
|
* |
|
|
W.
Randall Fowler (3)
|
|
|
105,300 |
|
|
|
* |
|
|
|
3,000 |
|
|
|
* |
|
|
Richard
H. Bachmann (3)
|
|
|
190,822 |
|
|
|
* |
|
|
|
18,968 |
|
|
|
* |
|
|
A.J.
Teague (3)
|
|
|
260,442 |
|
|
|
* |
|
|
|
17,000 |
|
|
|
* |
|
|
Dr.
Ralph S. Cunningham
|
|
|
76,847 |
|
|
|
* |
|
|
|
4,000 |
|
|
|
* |
|
|
E.
William Barnett
|
|
|
2,154 |
|
|
|
* |
|
|
|
-- |
|
|
|
* |
|
|
Rex
C. Ross
|
|
|
54,875 |
|
|
|
* |
|
|
|
7,448 |
|
|
|
* |
|
|
Charles
M. Rampacek
|
|
|
9,615 |
|
|
|
* |
|
|
|
-- |
|
|
|
* |
|
|
All
current directors and executive officers of EPGP, as a
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
group,
(14 individuals in total) (4)
|
|
|
153,677,694 |
|
|
|
34.0 |
% |
|
|
108,381,604 |
|
|
|
77.9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
The beneficial ownership of each individual is less than 1.0% of the
registrant’s common units outstanding.
|
|
|
(1)
As
a result of EPCO’s ownership of the general partners of the Employee
Partnerships, Mr. Duncan is deemed beneficial owner of the limited partner
interests held by these entities.
(2)
Mr.
Duncan is deemed beneficial owner of the limited partner interests held by
certain family trusts, the beneficiaries of which are shareholders of
EPCO.
(3)
These
individuals are Named Executive Officers.
(4)
Cumulatively,
this group’s beneficial ownership amount includes 150,000 options to
acquire our common units that were issued under the EPCO 1998
Plan. These options vested in prior periods and remain exercisable
within 60 days of the filing date of this annual
report.
|
|
Essentially
all of the ownership interests in us and Enterprise GP Holdings that are owned
or controlled by EPCO are pledged as security under the credit facility of an
EPCO affiliate. This credit facility contains customary and other
events of default relating to EPCO and certain of its affiliates, including
Enterprise GP Holdings, TEPPCO and us. In the event of a default
under this credit facility, a change in control of Enterprise GP Holdings or us
could occur, including a change in control of our respective general
partners.
Duncan
Energy Partners L.P.
Certain
of our directors and executive officers purchased common units of Duncan Energy
Partners in this offering. The following table presents the beneficial
ownership of common units of Duncan Energy Partners by our directors, Named
Executive Officers and all directors and officers of our general partner (as a
group) at February 2, 2009.
|
|
|
Duncan
Energy Partners L.P. Common Units
|
|
|
|
|
Amount
|
|
|
|
|
|
|
|
and
Nature of
|
|
|
|
|
|
Name
of
|
|
Beneficial
|
|
|
Percent
of
|
|
|
Beneficial
Owner
|
|
Ownership
|
|
|
Class
|
|
|
Dan
L. Duncan:
|
|
|
|
|
|
|
|
Units
owned by EPO (1)
|
|
|
42,726,987 |
|
|
|
74.1 |
% |
|
Units
owned by DD Securities LLC
|
|
|
103,100 |
|
|
|
* |
|
|
Units
owned directly
|
|
|
282,500 |
|
|
|
* |
|
|
Total
for Dan L. Duncan
|
|
|
43,112,587 |
|
|
|
74.7 |
% |
|
Richard
H. Bachmann (2,3)
|
|
|
10,171 |
|
|
|
* |
|
|
W.
Randall Fowler (3,4)
|
|
|
2,000 |
|
|
|
* |
|
|
Michael
A. Creel (3)
|
|
|
7,500 |
|
|
|
* |
|
|
A.J.
Teague (3)
|
|
|
6,000 |
|
|
|
* |
|
|
Rex
C. Ross
|
|
|
3,800 |
|
|
|
* |
|
|
All
current directors and executive officers of EPGP,
|
|
|
|
|
|
|
|
|
|
as
a group (14 individuals in total)
|
|
|
43,163,808 |
|
|
|
74.8 |
% |
|
|
|
|
|
|
|
|
|
|
|
*
The beneficial ownership of each individual is less than 1.0% of the
registrant’s units outstanding.
|
|
|
(1)
Amount
includes 37,333,887 Class B units of Duncan Energy Partners L.P. that
converted to common units on a one-for-one basis on February 1,
2009. EPO was issued the Class B units as partial consideration for a
December 2008 asset dropdown transaction with Duncan Energy
Partners.
(2)
Mr.
Bachmann is the Chief Executive Officer of Duncan Energy
Partners.
(3)
These
individuals are Named Executive Officers.
(4)
Mr.
Fowler is the Chief Financial Officer of Duncan Energy
Partners.
|
|
The
preceding tables do not present any beneficial ownership information for James
H. Lytal, who was one of our Named Executive Officers for
2008. Mr. Lytal resigned from EPCO in January
2009.
Securities
Authorized for Issuance Under Equity Compensation Plans
The following table sets forth certain
information as of December 31, 2008 regarding the long-term incentive plans of
EPCO under which our common units are authorized for issuance.
|
|
|
|
|
|
|
|
|
Number
of
|
|
|
|
|
|
|
|
|
|
|
units
|
|
|
|
|
|
|
|
|
|
|
remaining
|
|
|
|
|
|
|
|
|
|
|
available
for
|
|
|
|
|
Number
of
|
|
|
|
|
|
future
issuance
|
|
|
|
|
units
to
|
|
|
Weighted-
|
|
|
under
equity
|
|
|
|
|
be
issued
|
|
|
average
|
|
|
compensation
|
|
|
|
|
upon
exercise
|
|
|
exercise
price
|
|
|
plans
(excluding
|
|
|
|
|
of
outstanding
|
|
|
of
outstanding
|
|
|
securities
|
|
|
|
|
common
unit
|
|
|
common
unit
|
|
|
reflected
in
|
|
|
Plan
Category
|
|
options
|
|
|
options
|
|
|
column
(a)
|
|
|
|
|
(a)
|
|
|
(b)
|
|
|
(c)
|
|
|
Equity
compensation plans approved by unitholders:
|
|
|
|
|
|
|
|
|
|
|
EPCO
1998 Plan (1)
|
|
|
2,168,500 |
|
|
$ |
26.32 |
|
|
|
814,674 |
|
|
EPD
2008 LTIP (2)
|
|
|
795,000 |
|
|
$ |
30.93 |
|
|
|
9,205,000 |
|
|
Equity
compensation plans not approved by unitholders:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
None
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
Total
for equity compensation plans
|
|
|
2,963,500 |
|
|
$ |
27.56 |
|
|
|
10,019,674 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Of the 2,168,500 unit options outstanding at December 31, 2008,
548,500 were immediately exercisable and an additional 365,000, 480,000
and 775,000 options are exercisable in 2009, 2010 and 2012,
respectively.
(2)
The 795,000 unit options outstanding at December 31, 2008 are
exercisable in 2013.
|
|
EPCO
1998 Plan
The EPCO 1998 Plan is effective until
either all available common units under the plan have been issued to
participants or the earlier termination of the EPCO 1998 Plan by
EPCO. The EPCO 1998 Plan also provides for the issuance of restricted
common units, of which 2,080,600 were outstanding at December 31,
2008. During 2008, a total of 766,200 restricted unit awards were
issued to key employees of EPCO and our independent directors.
EPD
2008 LTIP
On January 29, 2008, our
unitholders approved the EPD 2008 LTIP, which provides for awards of our common
units and other rights to our non-employee directors and to consultants and
employees of EPCO and its affiliates providing services to us. Awards
under the EPD 2008 LTIP may be granted in the form of unit options, restricted
units, phantom units, UARs and DERs. The EPD 2008 LTIP is
administered by the ACG Committee of our general partner. The EPD
2008 LTIP provides for the issuance of up to 10,000,000 of our common
units. After giving effect to option awards outstanding at December
31, 2008, a total of 9,205,000 additional common units could be issued under the
EPD 2008 LTIP.
The EPD
2008 LTIP may be amended or terminated at any time by the Board of Directors of
EPCO or ACG Committee of our general partner; however, the rules of the NYSE
require that any material amendment, such as a significant increase in the
number of common units available under the plan or a change in the types of
awards available under the plan, would require the approval of our
unitholders. The ACG Committee is also authorized to make adjustments
in the terms and conditions of, and the criteria included in, awards under the
plan in specified circumstances. The EPD 2008 LTIP is effective until
the earlier of January 29, 2018 or the time which all available units under
the incentive plan have been delivered to participants or the time of
termination of the plan by EPCO or the ACG Committee of our general
partner.
For
additional information regarding the EPCO 1998 Plan and EPD 2008 LTIP, see Note
5 of the Notes to Consolidated Financial Statements included under Item 8 of
this annual report.
Certain
Relationships and Related Transactions
The following information summarizes
our business relationships and transactions with related parties during the year
ended December 31, 2008. We believe that the terms and
provisions of our related party agreements are fair to us; however, such
agreements and transactions may not be as favorable to us as we could have
obtained from unaffiliated third parties. For additional information
regarding our related party transactions, see Note 17 of the Notes to
Consolidated Financial Statements included under Item 8 of this annual
report.
Relationship
with EPCO and affiliates
We have an extensive and ongoing
relationship with EPCO and its affiliates, which include the following
significant entities that are not a part of our consolidated group of
companies:
|
§
|
EPCO
and its private company
subsidiaries;
|
|
§
|
EPGP,
our sole general partner;
|
|
§
|
Enterprise
GP Holdings, which owns and controls our general
partner;
|
|
§
|
TEPPCO,
which is owned and controlled by Enterprise GP Holdings;
and
|
|
§
|
the
Employee Partnerships.
|
We also
have an ongoing relationship with Duncan Energy Partners, the financial
statements of which are consolidated with those of our own. Our
transactions with Duncan Energy Partners are eliminated in
consolidation.
EPCO is a
private company controlled by Dan L. Duncan, who is also a Director and Chairman
of EPGP, our general partner. At December 31, 2008, EPCO and its
affiliates beneficially owned 152,506,527 (or 34.5%) of our outstanding common
units, which includes 13,670,925 of our common units owned by Enterprise GP
Holdings. In addition, at December 31, 2008, EPCO and its affiliates
beneficially owned 77.8% of the limited partner interests of Enterprise GP
Holdings and 100.0% of its general partner, EPE Holdings. Enterprise
GP Holdings owns all of the membership interests of EPGP. The
principal business activity of EPGP is to act as our managing
partner. The executive officers and certain of the directors of EPGP
and EPE Holdings are employees of EPCO.
As our
general partner, EPGP received cash distributions of $144.1 million from us
during the year ended December 31, 2008. This amount includes
incentive distributions of $125.9 million.
We and
EPGP are both separate legal entities apart from each other and apart from EPCO,
Enterprise GP Holdings and their respective other affiliates, with assets and
liabilities that are separate from those of EPCO, Enterprise GP Holdings and
their respective other affiliates. EPCO and its private company
affiliates depend on the cash distributions they receive from us, Enterprise GP
Holdings and other investments to fund their other operations and to meet their
debt obligations. EPCO and its private company affiliates received
$405.2 million in cash distributions from us and Enterprise GP Holdings during
the year ended December 31, 2008. Also, we issued $67.0 million in
common units to EPCO and its private company affiliates under our DRIP during
the year ended December 31, 2008.
The ownership interests in us that are
owned or controlled by Enterprise GP Holdings are pledged as security under its
credit facility. In addition, substantially all of the ownership
interests in us that are owned or controlled by EPCO and its affiliates, other
than those interests owned by Enterprise GP Holdings, Dan Duncan LLC and certain
trusts affiliated with Dan L. Duncan, are pledged as security under the credit
facility of a private company affiliate of EPCO. This credit facility
contains customary and other
events of
default relating to EPCO and certain affiliates, including Enterprise GP
Holdings, TEPPCO and us.
An affiliate of EPCO provides us
trucking services for the transportation of NGLs and other products. For
the year ended December 31, 2008, we paid this trucking affiliate $21.7 million
for such services.
We lease office space in various
buildings from affiliates of EPCO. The rental rates in these lease
agreements approximate market rates. For the year ended December 31,
2008, we paid EPCO $5.3 million for office space leases.
Historically,
we entered into transactions with a Canadian affiliate of EPCO for the purchase
and sale of NGL products in the normal course of business. These
transactions were at market-related prices. We acquired this
affiliate in October 2006 and began consolidating its financial statements with
those of our own from the date of acquisition. For the nine months
ended September 30, 2006, our revenues from this former unconsolidated affiliate
were $55.8 million and our purchases were $43.4 million.
EPCO
ASA. We
have no employees. All of our operating functions and general and
administrative support services are provided by employees of EPCO pursuant to an
ASA. We, Duncan Energy Partners, Enterprise GP Holdings, TEPPCO and
our respective general partners are parties to the ASA. The
significant terms of the ASA are as follows:
|
§
|
EPCO
will provide selling, general and administrative services, and management
and operating services, as may be necessary to manage and operate our
businesses, properties and assets (all in accordance with prudent industry
practices). EPCO will employ or otherwise retain the services
of such personnel as may be necessary to provide such
services.
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We
are required to reimburse EPCO for its services in an amount equal to the
sum of all costs and expenses incurred by EPCO which are directly or
indirectly related to our business or activities (including expenses
reasonably allocated to us by EPCO). In addition, we have
agreed to pay all sales, use, excise, value added or similar taxes, if
any, that may be applicable from time to time in respect of the services
provided to us by EPCO.
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EPCO
will allow us to participate as a named insured in its overall insurance
program, with the associated premiums and other costs being allocated to
us.
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Under the ASA, EPCO subleases to us
(for $1 per year) certain equipment which it holds pursuant to operating leases
and has assigned to us its purchase option under such leases (the “retained
leases”). EPCO remains liable for the actual cash lease payments
associated with these agreements. We record the full value of these
payments made by EPCO on our behalf as a non-cash related party operating lease
expense, with the offset to partners’ equity accounted for as a general
contribution to our partnership. We exercised our election under the
retained leases to purchase a cogeneration unit in December 2008 for $2.3
million. Should we decide to exercise the purchase option associated
with the remaining agreement, we would pay the original lessor $3.1 million in
June 2016.
Our operating costs and expenses for
the year ended December 31, 2008 include reimbursement payments to EPCO for the
costs it incurs to operate our facilities, including compensation of
employees. We reimburse EPCO for actual direct and indirect expenses
it incurs related to the operation of our assets. Such reimbursements
were $329.7 million during the year ended December 31, 2008.
Likewise, our general and
administrative costs for the year ended December 31, 2008 include amounts we
reimburse to EPCO for administrative services, including compensation of
employees. In general, our reimbursement to EPCO for administrative
services is either (i) on an actual basis for direct expenses it may incur on
our behalf (e.g., the purchase of office supplies) or (ii) based on an
allocation of such charges between the various parties to ASA based on the
estimated use of such services by each party
(e.g.,
the allocation of general legal or accounting salaries based on estimates of
time spent on each entity’s business and affairs). Such
reimbursements were $59.1 million during the year ended December 31,
2008.
Since the
vast majority of such expenses are charged to us on an actual basis (i.e. no
mark-up or subsidy is charged or received by EPCO), we believe that such
expenses are representative of what the amounts would have been on a stand-alone
basis. With respect to allocated costs, we believe that the proportional
direct allocation method employed by EPCO is reasonable and reflective of the
estimated level of costs we would have incurred on a stand-alone
basis.
The ASA
also addresses potential conflicts that may arise among Enterprise Products
Partners (including EPGP), Enterprise GP Holdings (including EPE Holdings),
Duncan Energy Partners (including DEP GP), and the EPCO Group. The
EPCO Group includes EPCO and its other affiliates, but excludes Enterprise
Products Partners, Enterprise GP Holdings, Duncan Energy Partners and their
respective general partners. With respect to potential conflicts, the
ASA provides, among other things, that:
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If
a business opportunity to acquire “equity securities” (as defined
below) is
presented to the EPCO Group, Enterprise Products Partners (including
EPGP), Enterprise GP Holdings (including EPE Holdings), Duncan Energy
Partners (including DEP GP), then Enterprise GP Holdings will have the
first right to pursue such opportunity. The term “equity
securities” is defined to
include:
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general
partner interests (or securities which have characteristics similar to
general partner interests) or interests in “persons” that own or control
such general partner or similar interests (collectively, “GP Interests”)
and securities convertible, exercisable, exchangeable or otherwise
representing ownership or control of such GP Interests;
and
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incentive
distribution rights and limited partner interests (or securities which
have characteristics similar to incentive distribution rights or limited
partner interests) in publicly traded partnerships or interests in
“persons” that own or control such limited partner or similar interests
(collectively, “non-GP Interests”); provided that such non-GP Interests
are associated with GP Interests and are owned by the owners of GP
Interests or their respective
affiliates.
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Enterprise
GP Holdings will be presumed to want to acquire the equity securities until such
time as EPE Holdings advises the EPCO Group, EPGP and DEP GP that it has
abandoned the pursuit of such business opportunity. In the event that
the purchase price of the equity securities is reasonably likely to equal or
exceed $100.0 million, the decision to decline the acquisition will be made
by the chief executive officer of EPE Holdings after consultation with and
subject to the approval of the ACG Committee of EPE Holdings. If the
purchase price is reasonably likely to be less than $100.0 million, the chief
executive officer of EPE Holdings may make the determination to decline the
acquisition without consulting the ACG Committee of EPE
Holdings.
In the
event that Enterprise GP Holdings abandons the acquisition and so notifies the
EPCO Group, EPGP and DEP GP, Enterprise Products Partners will have the second
right to pursue such acquisition. Enterprise Products Partners will
be presumed to want to acquire the equity securities until such time as EPGP
advises the EPCO Group and DEP GP that Enterprise Products Partners has
abandoned the pursuit of such acquisition. In determining whether or
not to pursue the acquisition, Enterprise Products Partners will follow the same
procedures applicable to Enterprise GP Holdings, as described above but
utilizing EPGP’s chief executive officer and ACG Committee.
In its
sole discretion, Enterprise Products Partners may affirmatively direct such
acquisition opportunity to Duncan Energy Partners. In the event this
occurs, Duncan Energy Partners may pursue such acquisition.
In the event Enterprise Products Partners abandons the acquisition
opportunity for the equity securities and so notifies the EPCO Group and DEP GP,
the EPCO Group may pursue the
acquisition
or offer the opportunity to TEPPCO (including TEPPCO GP) and their controlled
affiliates, in either case, without any further obligation to any other party or
offer such opportunity to other affiliates.
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If
any business opportunity not covered by the preceding bullet point (i.e.
not involving “equity securities”) is presented to the EPCO Group,
Enterprise Products Partners (including EPGP), Enterprise GP Holdings
(including EPE Holdings), or Duncan Energy Partners (including DEP GP),
Enterprise Products Partners will have the first right to pursue such
opportunity either for itself or, if desired by Enterprise Products
Partners in its sole discretion, for the benefit of Duncan Energy
Partners. It will be presumed that Enterprise Products Partners will
pursue the business opportunity until such time as its general partner
advises the EPCO Group, EPE Holdings and DEP GP that it has abandoned the
pursuit of such business
opportunity.
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In the
event the purchase price or cost associated with the business opportunity is
reasonably likely to equal or exceed $100.0 million, any decision to
decline the business opportunity will be made by the chief executive officer of
EPGP after consultation with and subject to the approval of the ACG Committee of
EPGP. If the purchase price or cost is reasonably likely to be less
than $100.0 million, the chief executive officer of EPGP may make the
determination to decline the business opportunity without consulting EPGP’s ACG
Committee.
In its
sole discretion, Enterprise Products Partners may affirmatively direct such
acquisition opportunity to Duncan Energy Partners. In the event this
occurs, Duncan Energy Partners may pursue such acquisition.
In the
event that Enterprise Products Partners abandons the business opportunity for
itself and Duncan Energy Partners and so notifies the EPCO Group, EPE Holdings
and DEP GP, Enterprise GP Holdings will have the second right to pursue such
business opportunity. It will be presumed that Enterprise GP Holdings
will pursue such acquisition until such time as its general partner declines
such opportunity (in accordance with the procedures described above for
Enterprise Products Partners) and advises the EPCO Group that it has abandoned
the pursuit of such business opportunity. Should this occur, the EPCO
Group may either pursue the business opportunity or offer the business
opportunity to TEPPCO (including TEPPCO GP) and their controlled affiliates
without any further obligation to any other party or offer such opportunity to
other affiliates.
None of Enterprise Products Partners,
Enterprise GP Holdings, Duncan Energy Partners or their respective general
partners or the EPCO Group have any obligation to present business opportunities
to TEPPCO (including TEPPCO GP) or their controlled affiliates. Likewise,
TEPPCO (including TEPPCO GP) and their controlled affiliates have no obligation
to present business opportunities to Enterprise Products Partners, Enterprise GP
Holdings, Duncan Energy Partners or their respective general partners or the
EPCO Group.
The ASA was amended on January 30,
2009 to provide for the cash reimbursement by us and Enterprise GP Holdings to
EPCO of distributions of cash or securities, if any, made by EPCO Unit to
its Class B limited partners. The ASA amendment also extended the term
under which EPCO provides services to the partnership entities from December
2010 to December 2013 and made other updating and conforming
changes.
Employee
Partnerships. EPCO formed the
Employee Partnerships to serve as an incentive arrangement for key employees of
EPCO by providing them a “profits interest” in such
partnerships. Certain EPCO employees who work on behalf of us and
EPCO were issued Class B limited partner interests and admitted as Class B
limited partners without any capital contribution. The profits
interest awards (i.e., the Class B limited partner interests) in the
Employee Partnerships entitles each holder to participate in the appreciation in
value of our common units, Enterprise GP Holdings’ units, or both. For
information regarding the Employee Partnerships, see Note 5 of the Notes to
Consolidated Financial Statements included under Item 8 of this annual
report.
Relationship
with TEPPCO
TEPPCO
became a related party to us in February 2005 when its general partner was
acquired by private company affiliates of EPCO. Our relationship was
further reinforced by the acquisition of TEPPCO’s general partner by Enterprise
GP Holdings in May 2007. Enterprise GP Holdings also owns our general
partner.
We
received $121.2 million from TEPPCO during the year ended December 31, 2008 from
the sale of hydrocarbon products. We paid TEPPCO $42.0 million for NGL
pipeline transportation and storage services during the year ended December 31,
2008.
Purchase
of Pioneer I
plant
from TEPPCO. In
March 2006, we paid TEPPCO $38.2 million for its Pioneer I natural gas
processing plant located in Opal, Wyoming and certain natural gas processing
rights related to natural gas production from the Jonah and Pinedale fields
located in the Greater Green River Basin in Wyoming. After an
in-depth consideration of all relevant factors, this transaction was approved by
the ACG Committee of our general partner and the Audit and Conflicts Committee
of the general partner of TEPPCO. TEPPCO has no continued involvement
in the contracts or in the operations of the Pioneer facility.
Jonah
Joint Venture with TEPPCO. In August 2006,
we became a joint venture partner with TEPPCO in its Jonah Gas Gathering Company
(“Jonah”), which owns the Jonah Gas Gathering System located in the Greater
Green River Basin of southwestern Wyoming. The Jonah Gathering System
gathers and transports natural gas produced from the Jonah and Pinedale fields
to regional natural gas processing plants and major interstate pipelines that
deliver natural gas to end-user markets.
Prior to
entering into the Jonah joint venture, we managed the construction of the Phase
V expansion and funded the initial construction costs under a letter of intent
we entered into in February 2006. In connection with the joint
venture arrangement, we and TEPPCO shared equally in the costs of the Phase V
expansion, which increased the capacity of the Jonah Gathering System from 1.5
billion cubic feet per day (“Bcf/d”) to 2.4 Bcf/d and significantly reduced
system operating pressures, which we anticipate will lead to increased
production rates and ultimate reserve recoveries. The first portion
of the expansion, which has increased the system gathering capacity to 2.0
Bcf/d, was completed in July 2007 and the final phase of this expansion was
completed in June 2008. We managed the Phase V construction
project. Currently, the gathering capacity of this system is 2.4
Bcf/d.
Since
August 1, 2006, we and TEPPCO have equally shared in the construction costs of
the Phase V expansion. TEPPCO has reimbursed us $306.5 million, which
represents 50.0% of total Phase V costs incurred through December 31,
2008. We had a receivable of $1.0 million from TEPPCO at December 31,
2008 for Phase V expansion costs.
During
the first quarter of 2008, Jonah initiated a separate project to increase
gathering capacity on that portion of its system that serves the Pinedale
production field. This new project is expected to increase overall
capacity of the Jonah Gas Gathering System by an additional 0.2
Bcf/d. The total anticipated cost of this new project is $125.0
million, of which we will be responsible for our share of the construction
costs.
TEPPCO
was entitled to all distributions from the joint venture until specified
milestones were achieved, at which point, we became entitled to receive 50.0% of
the incremental cash flow from portions of the system placed in-service as part
of the expansion. Since the first phase of this expansion was reached
in July 2007, we and TEPPCO have shared earnings based on a formula that takes
into account our respective capital contributions, including expenditures by
TEPPCO prior to the expansion.
At
December 31, 2008, we owned an approximate 19.4% interest in Jonah and TEPPCO
owns 80.6%. We operate the Jonah system. We account for our
investment in the Jonah joint venture using the equity method.
The Jonah
joint venture is governed by a management committee comprised of two
representatives approved by us and two appointed by TEPPCO, each with equal
voting power. After an in-depth consideration of all relevant
factors, this transaction was approved by the ACG Committee of our general
partner and the Audit and Conflicts Committee of the general partner of
TEPPCO.
We have
agreed to indemnify TEPPCO from any and all losses, claims, demands, suits,
liabilities, costs and expenses arising out of or related to breaches of our
representations, warranties, or covenants related to the Jonah joint
venture. A claim for indemnification cannot be filed until the losses
suffered by TEPPCO exceed $1.0 million. The maximum potential amount
of future payments under the indemnity agreement is limited to $100.0
million. All indemnity payments are net of insurance recoveries that
TEPPCO may receive from third-party insurance carriers. We carry
insurance coverage that may offset any payments required under the
indemnification.
Purchase
of Houston-area pipelines from TEPPCO. In October 2006, we
purchased certain idle pipeline assets in the Houston, Texas area from TEPPCO
for $11.7 million in cash. The acquired pipelines became part of our
Texas Intrastate System. The purchase of this asset was in accordance
with the Board-approved management authorization policy.
Purchase
and lease of pipelines for DEP South Texas NGL Pipeline System from
TEPPCO. In
January 2007, we purchased a 10-mile segment of pipeline from TEPPCO located in
the Houston area for $8.0 million. This pipeline segment is part of
the DEP South Texas NGL Pipeline System that commenced operations in January
2007. In addition, we entered into a lease with TEPPCO for an 11-mile
interconnecting pipeline located in the Houston area that is part of the DEP
South Texas NGL Pipeline System. Although the primary term of
the lease expired in September 2007, it was renewed on a month-to-month basis
until construction of a parallel pipeline was completed in early
2008. These transactions were in accordance with the Board-approved
management authorization policy.
Texas Offshore
Port
System Joint
Venture. In
August 2008, we, together with TEPPCO and Oiltanking Holding Americas, Inc.
(“Oiltanking”), announced the formation of the Texas Offshore Port System, a
joint venture to design, construct, operate and own a Texas offshore crude oil
port and a related onshore pipeline and storage system that would facilitate
delivery of waterborne crude oil to refining centers located along the upper
Texas Gulf Coast. The joint venture’s primary project, referred to as
“TOPS,” includes (i) an offshore port (which will be located approximately
36 miles from Freeport, Texas), (ii) an onshore storage facility with
approximately 3.9 million barrels of crude oil storage capacity, and (iii)
an 85-mile crude oil pipeline system having a transportation capacity of up to
1.8 million barrels per day, that will extend from the offshore port to a
storage facility near Texas City, Texas. The joint venture’s
complementary project, referred to as the Port Arthur Crude Oil Express (or
“PACE”) will transport crude oil from Texas City, including crude oil from TOPS,
and will consist of a 75-mile pipeline and 1.2 million barrels of crude oil
storage capacity in the Port Arthur, Texas area. The timing of the
construction and related capital costs of the TOPS and PACE projects will be
affected by the expansion plans of Motiva and the acquisition of requisite
permits.
We,
TEPPCO and Oiltanking each own, through our respective subsidiaries, a one-third
interest in the joint venture. The aggregate cost of the TOPS and PACE
projects is expected to be approximately $1.8 billion (excluding
capitalized interest), with the majority of such capital expenditures currently
expected to occur in 2010 and 2011. We and TEPPCO have each
guaranteed up to approximately $700.0 million, which includes a contingency
amount for potential cost overruns, of the capital contribution obligations of
our respective subsidiary partners in the joint venture. As of December
31, 2008, our investment in the Texas Offshore Port System was $35.9
million.
Relationship
with Energy Transfer Equity
Enterprise
GP Holdings acquired equity method investments in Energy Transfer Equity and its
general partner in May 2007. As a result, Energy Transfer Equity and
its consolidated subsidiaries became related parties to our consolidated
businesses.
For the
year ended December 31, 2008, we recorded $618.4 million of revenues from Energy
Transfer Partners, L.P. (“ETP”), primarily from NGL marketing
activities. We incurred $192.2 million in costs of sales and
operating costs and expenses for the year ended December 31, 2008. We
have a long-term revenue generating contract with Titan Energy Partners, L.P.
(“Titan”), a consolidated subsidiary of ETP. Titan purchases
substantially all of its propane requirements from us. The contract
continues until March 31, 2010 and contains renewal and extension
options. We and Energy Transfer Company (“ETC OLP”) transport natural
gas on each other’s systems and share operating expenses on certain
pipelines. ETC OLP also sells natural gas to us.
Relationship
with Duncan Energy Partners
Duncan
Energy Partners was formed in September 2006 and did not acquire any assets
prior to February 5, 2007, which was the date it completed its initial public
offering of 14,950,000 common units and acquired controlling interests in
certain midstream energy businesses of EPO. The business purpose of Duncan
Energy Partners is to acquire, own and operate a diversified portfolio of
midstream energy assets and to support the growth objectives of EPO and other
affiliates under common control. Duncan Energy Partners is
engaged in the business of transporting and storing NGLs and petrochemical
products and gathering, transporting, storing and marketing of natural
gas.
At December 31, 2008, Duncan Energy
Partners is owned 99.3% by its limited partners and 0.7% by its general partner,
DEP GP, which is a wholly owned subsidiary of EPO. DEP GP is
responsible for managing the business and operations of Duncan Energy
Partners. DEP Operating Partnership L.P. (“DEP OLP”), a wholly owned
subsidiary of Duncan Energy Partners, conducts substantially all of Duncan
Energy Partners’ business.
At December 31, 2008, EPO owned
approximately 74.1% of Duncan Energy Partners’ limited partner interests and
100.0% of its general partner.
DEP I
Midstream Businesses. On February 5, 2007, EPO contributed a
66.0% controlling equity interest in each of the DEP I Midstream Businesses
(defined below) to Duncan Energy Partners in a dropdown of assets (the “DEP I
dropdown”). EPO retained the remaining 34.0% equity interest in each
of the DEP I Midstream Businesses. The DEP I Midstream Businesses
consist of (i) Mont Belvieu Caverns, LLC (“Mont Belvieu Caverns”); (ii) Acadian
Gas, LLC (“Acadian Gas”); (iii) Enterprise Lou-Tex Propylene Pipeline L.P.
(“Lou-Tex Propylene”), including its general partner; (iv) Sabine Propylene
Pipeline L.P. (“Sabine Propylene’), including its general partner; and (v) South
Texas NGL Pipelines, LLC (“South Texas NGL”).
As consideration for controlling equity
interests in the DEP I Midstream Businesses and reimbursement for capital
expenditures related to these businesses, Duncan Energy Partners distributed to
EPO (i) $260.6 million of the $290.5 million of net proceeds from its initial
public offering to EPO, (ii) $198.9 million in borrowings under its
revolving credit facility and (iii) a net 5,351,571 common units of Duncan
Energy Partners. See Note 14 of the Notes to Consolidated Financial
Statements included under Item 8 of this annual report for information regarding
the debt obligations of Duncan Energy Partners.
DEP II
Midstream Businesses. On December 8, 2008, Duncan Energy
Partners entered into a Purchase and Sale Agreement (the “DEP II Purchase
Agreement”) with EPO and Enterprise GTM Holdings L.P. (“Enterprise GTM,” a
wholly owned subsidiary of EPO). Pursuant to the DEP II Purchase
Agreement, DEP OLP acquired 100.0% of the membership interests in Enterprise
Holding III, LLC (“Enterprise III”) from Enterprise GTM, thereby acquiring a
66.0% general partner interest in Enterprise GC, L.P. (“Enterprise GC”), a 51.0%
general partner interest in Enterprise Intrastate L.P. (“Enterprise Intrastate”)
and a 51.0% membership interest in Enterprise Texas Pipeline LLC (“Enterprise
Texas”). Collectively, we refer to Enterprise GC, Enterprise
Intrastate and Enterprise Texas as the “DEP II Midstream
Businesses.” EPO was the sponsor of this second dropdown transaction
(the “DEP II dropdown”). Enterprise GTM retained the remaining
limited partner and member interests in the DEP II Midstream
Businesses.
As consideration for controlling equity
interests in the DEP II Midstream Businesses, EPO received $280.5 million in
cash and 37,333,887 Class B limited partner units having a market value of
$449.5 million from Duncan Energy Partners. The Class B limited
partner units automatically converted to common units of Duncan Energy Partners
on February 1, 2009. The total value of the consideration provided to
EPO and Enterprise GTM was $730.0 million. The cash portion of the
consideration provided by Duncan Energy Partners in this dropdown transaction
was derived from borrowings under a term loan. See Note 14 of the
Notes to Consolidated Financial Statements included under Item 8 of this annual
report for information regarding the debt obligations of Duncan Energy
Partners.
Generally, the DEP II dropdown
transaction documents provide that to the extent that the DEP II Midstream
Businesses generate cash sufficient to pay distributions to their partners or
members, such cash will be distributed to Enterprise III (a wholly owned by
Duncan Energy Partners) and Enterprise GTM (our wholly owned subsidiary) in an
amount sufficient to generate an aggregate annualized return on their respective
investments of 11.85%. Distributions in excess of this amount will be
distributed 98.0% to Enterprise GTM and 2.0% to Enterprise
III. The initial annual fixed return amount of 11.85% will be
increased by 2.0% each calendar year beginning January 1, 2010. For example, the
fixed return in 2010, assuming no other adjustments, would be 102% of 11.85%, or
12.087%.
Duncan
Energy Partners paid a pro rated cash distribution of $0.1115 per unit on the
Class B units with respect to the fourth quarter of 2008.
The borrowings of Duncan Energy
Partners are presented as part of our consolidated debt; however, we do not have
any obligation for the payment of interest or repayment of borrowings incurred
by Duncan Energy Partners.
We may contribute other equity
interests in our subsidiaries to Duncan Energy Partners and use the proceeds we
receive from Duncan Energy Partners to fund our capital spending
program.
Omnibus
Agreement. On December 8, 2008, we entered into an amended and
restated Omnibus Agreement with Duncan Energy Partners. The key
provisions of this agreement are summarized as follows:
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indemnification
for certain environmental liabilities, tax liabilities and right-of-way
defects with respect to the DEP I and DEP II Midstream Businesses we
contributed to Duncan Energy Partners in connection with the
respective dropdown transactions;
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funding
by EPO of 100.0% of post-February 5, 2007 capital expenditures incurred by
South Texas NGL and Mont Belvieu Caverns with respect to certain expansion
projects under construction at the time of Duncan Energy Partners’ initial
public offering;
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funding
by EPO of 100.0% of post-December 8, 2008 capital expenditures (estimated
at $1.4 million) to complete the Sherman Extension natural gas
pipeline;
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a
right of first refusal to EPO in our current and future subsidiaries and a
right of first refusal on the material assets of such subsidiaries, other
than sales of inventory and other assets in the ordinary course of
business; and
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a
preemptive right with respect to equity securities issued by certain of
our subsidiaries, other than as consideration in an acquisition or in
connection with a loan or debt
financing.
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We and Duncan Energy Partners have also
agreed to negotiate in good faith any necessary amendments to the partnership or
company agreements of the DEP II Midstream Businesses when either party believes
that business circumstances have changed.
Our general partner’s ACG Committee
must approve amendments to the Omnibus Agreement when such amendments would
adversely affect our unitholders.
EPO has indemnified Duncan Energy
Partners against certain environmental liabilities, tax liabilities and
right-of-way defects associated with the assets EPO contributed to Duncan Energy
Partners in connection with the DEP I and DEP II dropdown
transactions. These liabilities include both known and unknown
environmental and related liabilities. These indemnifications
terminate on February 5, 2010. There is an aggregate cap of $15.0
million on the amount of indemnity coverage and Duncan Energy Partners is not
entitled to indemnification until the aggregate amount of claims it incurs
exceeds $250 thousand. Environmental liabilities resulting from a
change of law after February 5, 2007 are excluded from the
indemnity. In addition, EPO has indemnified Duncan Energy Partners
for liabilities related to:
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certain
defects in the easement rights or fee ownership interests in and to the
lands on which any assets contributed to Duncan Energy Partners in
connection with its initial public offering are located and failure to
obtain certain consents and permits necessary to conduct its business that
arise through February 5, 2010; and
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certain
income tax liabilities attributable to the operation of the assets
contributed to Duncan Energy Partners in connection with its initial
public offering prior to February 5,
2007.
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The Omnibus Agreement may not be
amended without the prior approval of the ACG Committee if the proposed
amendment will, in the reasonable discretion of DEP GP, adversely affect holders
of its common units.
Neither we, nor EPO and any of its
affiliates are restricted under the Omnibus Agreement from competing with Duncan
Energy Partners. Except as otherwise expressly agreed in the EPCO
ASA, EPO and any of its affiliates may acquire, construct or dispose of
additional midstream energy or other assets in the future without any obligation
to offer Duncan Energy Partners the opportunity to purchase or construct those
assets. These agreements are in addition to other agreements relating
to business opportunities and potential conflicts of interest set forth in the
ASA with EPO, EPCO and other affiliates of EPCO.
Under the Omnibus Agreement, EPO agreed
to make additional contributions to Duncan Energy Partners as reimbursement for
Duncan Energy Partners’ 66.0% share of any excess construction costs above the
(i) $28.6 million of estimated capital expenditures to complete the Phase II
expansions of the DEP South Texas NGL Pipeline System and (ii) $14.1 million of
estimated construction costs for additional brine production capacity and
above-ground storage reservoir projects at Mont Belvieu, Texas. Both
projects were underway at the time of Duncan Energy Partners’ initial public
offering. EPO made cash contributions to Duncan Energy Partners of
$32.5 million and $9.9 million in connection with the Omnibus Agreement during
the years ended December 31, 2008 and 2007, respectively. The
majority of these contributions related to funding the Phase II expansion costs
of the DEP South Texas NGL Pipeline System. EPO will not receive an
increased allocation of earnings or cash flows as a result of these
contributions to South Texas NGL and Mont Belvieu Caverns.
Mont
Belvieu Caverns’ LLC Agreement. The Mont Belvieu Caverns’ LLC
Agreement (the “Caverns LLC Agreement”) states that if Duncan Energy Partners
elects to not participate in certain projects of Mont Belvieu Caverns, then EPO
is responsible for funding 100.0% of such projects. To the extent
such non-participated projects generate identifiable incremental cash flows for
Mont Belvieu Caverns in the future, the earnings and cash flows of Mont Belvieu
Caverns will be adjusted to allocate such incremental amounts to EPO by special
allocation or otherwise. Under the terms of the Caverns LLC
Agreement, Duncan Energy Partners may elect to acquire a 66.0% share of these
projects from EPO within 90 days of such projects being placed in
service.
EPO made
cash contributions of $99.5 million and $38.1 million under the Caverns LLC
Agreement during the years ended December 31, 2008 and 2007, respectively, to
fund 100.0% of certain storage-related projects for the benefit of EPO’s NGL
marketing activities. At present, Mont Belvieu Caverns is not
expected to generate any identifiable incremental cash flows in connection with
these projects; thus, the sharing ratio for Mont Belvieu Caverns is not expected
to change from the current sharing ratio of 66.0% for Duncan Energy Partners and
34.0% for EPO. EPO expects to make additional
contributions
of approximately $27.5 million to fund such projects in 2009. The
constructed assets will be the property of Mont Belvieu Caverns.
In
November 2008, the Caverns LLC Agreement was amended to provide that EPO would
prospectively receive a special allocation of 100.0% of the depreciation related
to projects that it has fully funded. For the two-month period
in 2008 covered by the amendment, EPO was allocated depreciation expense of $1.0
million related to such projects.
The
Caverns LLC Agreement also requires the allocation to EPO of operational
measurement gains and losses. Operational measurement gains and
losses are created when product is moved between storage wells and are
attributable to pipeline and well connection measurement variances.
Company
and Limited Partnership Agreements – DEP II Midstream
Businesses. On December 8, 2007, the DEP II Midstream
Businesses amended and restated their governing documents in connection with the
DEP II dropdown transaction. Collectively, these amended and restated
agreements provide for the following:
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§
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the
acquisition by Enterprise III (a wholly owned subsidiary of Duncan Energy
Partners) from Enterprise GTM (our wholly owned subsidiary) of a 66.0%
general partner interest in Enterprise GC, a 51.0% general partner
interest in Enterprise Intrastate and a 51.0% member interest in
Enterprise Texas;
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§
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the
payment of distributions in accordance with an overall “waterfall”
approach that stipulates that to the extent that the DEP II Midstream
Businesses collectively generate cash sufficient to pay distributions to
their partners or members, such cash will be distributed first to
Enterprise III (based on an initial defined investment of $730.0 million,
the “Enterprise III Distribution Base”) and then to Enterprise GTM (based
on an initial defined investment of $452.1 million, the “Enterprise GTM
Distribution Base”) in amounts sufficient to generate an aggregate
annualized fixed return on their respective investments of
11.85%. Distributions in excess of these amounts will be
distributed 98.0% to Enterprise GTM and 2.0% to Enterprise
III. The initial annual fixed return amount of 11.85% will be
increased by 2.0% each calendar year beginning January 1, 2010. For
example, the fixed return in 2010, assuming no other adjustments, would be
102% of 11.85%, or 12.087%;
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§
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the
funding of operating cash flow deficits in accordance with each owner’s
respective partner or member interest;
and
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§
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the
election by either owner to fund cash calls associated with expansion
capital projects. Since December 8, 2008, Enterprise III has
elected to not participate in such cash calls and, as a result, Enterprise
GTM has funded 100.0% of the expansion project costs of the DEP II
Midstream Businesses. If Enterprise III later elects to
participate in an expansion projects, then Enterprise III will be required
to make a capital contribution for its share of the project
costs.
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Any
capital contributions to fund expansion projects made by either Enterprise III
or Enterprise GTM will increase such partner’s Distribution Base (and hence
future priority return amounts) under the Company Agreement of Enterprise Texas.
As noted, Enterprise III has declined participation in expansion project
spending since December 8, 2008. As a result, Enterprise GTM has funded 100.0%
of such growth capital spending and its Distribution Base has increased from
$452.1 million at December 8, 2008 to $473.4 million at December 31,
2008. The Enterprise III Distribution Base was unchanged at $730.0
million at December 31, 2008.
Relationships
with Unconsolidated Affiliates
Many of
our unconsolidated affiliates perform supporting or complementary roles to our
other business operations. Since we and our affiliates hold ownership
interests in these entities and directly or indirectly benefit from our related
party transactions with such entities, they are presented here. The
following information summarizes significant related party transactions with our
current unconsolidated affiliates:
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§
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We
sell natural gas to Evangeline, which, in turn, uses the natural gas to
satisfy supply commitments it has with a major Louisiana
utility. Revenues from Evangeline were $362.9 million for the
year ended December 31, 2008. In addition, Duncan Energy Partners
furnished $1.0 million in letters of credit on behalf of Evangeline at
December 31, 2008.
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§
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We
pay Promix for the transportation, storage and fractionation of
NGLs. In addition, we sell natural gas to Promix for its plant
fuel requirements. For the year ended December 31, 2008, we
recorded revenues of $24.5 million from Promix and paid Promix $38.7
million for its services to us.
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§
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We
pay Jonah for natural gas purchases from its gathering
system. Expenses with Jonah were $38.3 million and $4.9 million
for the years ended December 31, 2008 and 2007. We were not
entitled to our 19.4% interest in Jonah until July
2007.
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§
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We
perform management services for certain of our unconsolidated
affiliates. We charged such affiliates $9.9 million for such
services during the year ended December 31,
2008.
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Review
and Approval of Transactions with Related Parties
We
generally consider transactions between us and our subsidiaries, on the one
hand, and our executive officers and directors (or their immediate family
members), our general partner or its affiliates (including companies owned or
controlled by Mr. Duncan such as EPCO), on the other hand, to be related party
transactions. As further described below, our partnership agreement sets
forth procedures by which related party transactions and conflicts of interest
may be approved or resolved by the general partner or the ACG Committee.
In addition, our ACG Committee Charter, our general partner’s written
internal review and approval policies and procedures, or “management
authorization policy,” and the amended and restated ASA with EPCO govern
specified related party transactions, as further described below.
The ACG
Committee Charter provides that the ACG Committee is established to review and
approve related party transactions:
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for
which Board approval is required by our management authorization policy,
as such policy may be amended from time to
time;
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§
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where
an officer or director of the general partner or any of our subsidiaries
is a party, without regard to the size of the
transaction;
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§
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when
requested to do so by management or the Board;
or
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§
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pursuant
to our partnership agreement or the limited liability company agreement of
the general partner, as such agreements may be amended from time to
time.
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As
discussed in more detail in “Partnership Management,” “Corporate Governance” and
“ACG Committee” within Item 10, the ACG Committee is comprised of three
directors: Rex C. Ross, Charles M. Rampacek and E. William Barnett. During the
year ended December 31, 2008, the ACG Committee reviewed and approved the: (a)
Second Amended and Restated Limited Liability Company Agreement of Mont Belvieu
Caverns; and (b) the Texas Offshore Port System joint venture
transaction.
Our
management authorization policy currently requires board approval for the
following types of transactions to the extent such transactions have a value in
excess of $100.0 million thus triggering ACG Committee review under our ACG
Committee Charter if such transaction is also a related party
transaction:
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§
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asset
purchase or sale transactions;
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§
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capital
expenditures; and
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§
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purchase
orders and operating and administrative expenses not governed by the
ASA.
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The ASA
governs numerous day-to-day transactions between us and our subsidiaries, our
general partner and EPCO and its affiliates, including the provision by EPCO of
administrative and other services to us and our subsidiaries and our
reimbursement of costs, without markup or discount, for those
services. The ACG Committee reviewed and recommended the
ASA, and the Board approved it upon receiving such recommendation.
Related
party transactions that do not occur under the ASA and that are not reviewed by
the ACG Committee, as described above, are subject to the management
authorization policy. This policy, which applies to related party
transactions as well as transactions with unrelated parties, specifies
thresholds for our general partner’s officers and chairman of the Board to
authorize various categories of transactions, including purchases and sales of
assets, expenditures, commercial and financial transactions and legal
agreements.
Partnership
Agreement Standards for ACG Committee Review
Under our partnership agreement,
whenever a potential conflict of interest exists or arises between our general
partner or any of its affiliates and us, any of our subsidiaries or any partner
any resolution or course of action by our general partner or its affiliates in
respect to such conflict of interest is permitted and deemed approved by all of
our partners, and will not constitute a breach of our partnership agreement or
any agreement contemplated by such agreement, or of any duty stated or implied
by law or equity, if the resolution or course of action is or, by operation of
the partnership agreement is deemed to be, fair and reasonable to us; provided
that, any conflict of interest and any resolution of such conflict of interest
will be conclusively deemed fair and reasonable to us if such conflict of
interest or resolution is (i) approved by a majority of the members of our
ACG Committee (“Special Approval”), or (ii) on terms objectively
demonstrable to be no less favorable to us than those generally being provided
to or available from unrelated third parties.
The ACG Committee (in connection with
Special Approval) is authorized in connection with its resolution of any
conflict of interest to consider:
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§
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the
relative interests of any party to such conflict, agreement, transaction
or situation and the benefits and burdens relating to such
interest;
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§
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the
totality of the relationships between the parties involved (including
other transactions that may be particularly favorable or advantageous to
us);
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§
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any
customary or accepted industry practices and any customary or historical
dealings with a particular person;
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§
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any
applicable generally accepted accounting or engineering practices or
principles;
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§
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the
relative cost of capital of the parties and the consequent rates of return
to the equity holders of the parties;
and
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§
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such
additional factors as the committee determines in its sole discretion to
be relevant, reasonable or appropriate under the
circumstances.
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The
review and approval process of the ACG Committee, including factual matters that
may be considered in determining whether a transaction is fair and reasonable,
is generally governed by Section 7.9 of our partnership agreement. As
discussed above, the ACG Committee’s Special Approval is conclusively deemed
fair and reasonable to us under the partnership agreement.
The
review and work performed by the ACG Committee with respect to a transaction
varies depending upon the nature of the transaction and the scope of the ACG
Committee’s charge. Examples of functions the ACG Committee may, as
it deems appropriate, perform in the course of reviewing a transaction include
(but are not limited to):
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assessing
the business rationale for the
transaction;
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§
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reviewing
the terms and conditions of the proposed transaction, including
consideration and financing requirements, if
any;
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§
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assessing
the effect of the transaction on our earnings and distributable cash flow
per unit, and on our results of operations, financial condition,
properties or prospects;
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§
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conducting
due diligence, including by interviews and discussions with management and
other representatives and by reviewing transaction materials and findings
of management and other
representatives;
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§
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considering
the relative advantages and disadvantages of the transactions to the
parties;
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engaging
third party financial advisors to provide financial advice and assistance,
including by providing fairness opinions if
requested;
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§
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engaging
legal advisors; and
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§
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evaluating
and negotiating the transaction and recommending for approval or approving
the transaction, as the case may
be.
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Nothing
contained in the partnership agreement requires the ACG Committee to consider
the interests of any person other than the partnership. In the
absence of bad faith by the ACG Committee or our general partner, the
resolution, action or terms so made, taken or provided (including granting
Special Approval) by the ACG Committee or our general partner with respect to
such matter are conclusive and binding on all persons (including all of our
partners) and do not constitute a breach of the partnership agreement, or any
other agreement contemplated thereby, or a breach of any standard of care or
duty imposed in the partnership agreement or under the Delaware Revised Uniform
Limited Partnership Act or any other law, rule or regulation. The
partnership agreement provides that it is presumed that the resolution, action
or terms made, taken or provided by the ACG Committee or our general partner
were not made, taken or provided in bad faith, and in any proceeding brought by
any limited partner or by or on behalf of such limited partner or any other
limited partner or us challenging such resolution, action or terms, the person
bringing or prosecuting such proceeding will have the burden of overcoming such
presumption.
Director
Independence
Messrs.
Barnett, Ross and Rampacek have been determined to be independent under the
applicable NYSE listing standards and are independent under the rules of the SEC
applicable to audit committees. For a discussion of independence
standards applicable to the Board and factors considered by the Board in making
its independence determinations, please refer to “Corporate Governance” and “ACG
Committee” under Item 10 of this annual report.
We have
engaged Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu,
and their respective affiliates (collectively, “Deloitte & Touche”) as our
independent registered public accounting firm and principal
accountants. The following table summarizes fees we paid Deloitte
& Touche for independent auditing, tax and related services for each of the
last two fiscal years (dollars in thousands):
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For
Year Ended December 31,
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2008
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2007
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Audit
Fees (1)
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$ |
4,387 |
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$ |
4,772 |
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Audit-Related
Fees (2)
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-- |
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79 |
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Tax
Fees (3)
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569 |
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341 |
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All
Other Fees (4)
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-- |
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-- |
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(1)
Audit
fees represent amounts billed for each of the years presented for
professional services rendered in connection with (i) the audit of our
annual financial statements and internal controls over financial
reporting, (ii) the review of our quarterly financial statements or (iii)
those services normally provided in connection with statutory and
regulatory filings or engagements including comfort letters, consents and
other services related to SEC matters. This information is presented
as of the latest practicable date for this annual
report.
(2)
Audit-related
fees represent amounts we were billed in each of the years presented for
assurance and related services that are reasonably related to the
performance of the annual audit or quarterly reviews. This category
primarily includes services relating to internal control assessments and
accounting-related consulting.
(3)
Tax
fees represent amounts we were billed in each of the years presented for
professional services rendered in connection with tax compliance, tax
advice and tax planning. This category primarily includes services
relating to the preparation of unitholder annual K-1 statements and
partnership tax planning. In 2008, PricewaterhouseCoopers
International Limited was engaged to perform the majority of tax related
services.
(4)
All
other fees represent amounts we were billed in each of the years presented
for services not classifiable under the other categories listed in the
table above. No such services were rendered by Deloitte & Touche
during the last two years.
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The ACG
Committee of our general partner has approved the use of Deloitte & Touche
as our independent principal accountant. In connection with its
oversight responsibilities, the ACG Committee has adopted a pre-approval policy
regarding any services proposed to be performed by Deloitte &
Touche. The pre-approval policy includes four primary service
categories: Audit, Audit-related, Tax and Other.
In
general, as services are required, management and Deloitte & Touche submit a
detailed proposal to the ACG Committee discussing the reasons for the request,
the scope of work to be performed, and an estimate of the fee to be charged by
Deloitte & Touche for such work. The ACG Committee discusses the
request with management and Deloitte & Touche, and if the work is deemed
necessary and appropriate for Deloitte & Touche to perform, approves the
request subject to the fee amount presented (the initial “pre-approved” fee
amount). As part of these discussions, the ACG Committee must
determine whether or not the proposed services are permitted under the rules and
regulations concerning auditor independence under the Sarbanes-Oxley Act of 2002
as well as rules of the American Institute of Certified Public
Accountants. If at a later date, it appears that the initial
pre-approved fee amount may be insufficient to complete the work, then
management and Deloitte & Touche must present a request to the ACG Committee
to increase the approved amount and the reasons for the increase.
Under the
pre-approval policy, management cannot act upon its own to authorize an
expenditure for services outside of the pre-approved amounts. On a
quarterly basis, the ACG Committee is provided a schedule showing Deloitte &
Touche’s pre-approved amounts compared to actual fees billed for each of the
primary service categories. The ACG Committee’s pre-approval process
helps to ensure the independence of our principal accountant from
management.
In order
for Deloitte & Touche to maintain its independence, we are prohibited from
using them to perform general bookkeeping, management or human resource
functions, and any other service not permitted by the Public Company Accounting
Oversight Board. The ACG Committee’s pre-approval policy also
precludes Deloitte & Touche from performing any of these services for
us.
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(a)
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The
following documents are filed as a part of this
Report:
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(1)
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Financial
Statements: See Index to Consolidated Financial Statements on
page F-1 of this Report for financial statements filed as part of this
Report.
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(2)
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Financial
Statement Schedules: All schedules have been omitted because
they are either not applicable, not required or the information called for
therein appears in the consolidated financial statements or notes
thereto.
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(3)
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Exhibits. The
agreements included as exhibits are included only to provide information
to investors regarding their terms. The agreements listed below
may contain representations, warranties and other provisions that were
made, among other things, to provide the parties thereto with specified
rights and obligations and to allocate risk among them, and such
agreements should not be relied upon as constituting or providing any
factual disclosures about us, any other persons, any state of affairs or
other matters.
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Exhibit
Number
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Exhibit*
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2.1
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Merger
Agreement, dated as of December 15, 2003, by and among Enterprise Products
Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management
LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C.
(incorporated by reference to Exhibit 2.1 to Form 8-K filed December 15,
2003).
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2.2
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Amendment
No. 1 to Merger Agreement, dated as of August 31, 2004, by and among
Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise
Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra
Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form
8-K filed September 7, 2004).
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2.3
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Parent
Company Agreement, dated as of December 15, 2003, by and among Enterprise
Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products
GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine
River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra
GP Holding Company (incorporated by reference to Exhibit 2.2 to Form 8-K
filed December 15, 2003).
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2.4
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Amendment
No. 1 to Parent Company Agreement, dated as of April 19, 2004, by and
among Enterprise Products Partners L.P., Enterprise Products GP, LLC,
Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors
I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments,
L.L.C. and GulfTerra GP Holding Company (incorporated by reference to
Exhibit 2.1 to the Form 8-K filed April 21, 2004).
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2.5
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Purchase
and Sale Agreement (Gas Plants), dated as of December 15, 2003, by and
between El Paso Corporation, El Paso Field Services Management, Inc., El
Paso Transmission, L.L.C., El Paso Field Services Holding Company and
Enterprise Products Operating L.P. (incorporated by reference to Exhibit
2.4 to Form 8-K filed December 15, 2003).
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3.1
|
Certificate
of Limited Partnership of Enterprise Products Partners L.P. (incorporated
by reference to Exhibit 3.6 to Form 10-Q filed November 9,
2007).
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3.2
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Fifth
Amended and Restated Agreement of Limited Partnership of Enterprise
Products Partners L.P., dated effective as of August 8, 2005 (incorporated
by reference to Exhibit 3.1 to Form 8-K filed August 10,
2005).
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3.3
|
First
Amendment to the Fifth Amended and Restated Partnership Agreement of
Enterprise Products Partners L.P. dated as of December 27, 2007
(incorporated by reference to Exhibit 3.1 to Form 8-K/A filed January 3,
2008).
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3.4
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Second
Amendment to the Fifth Amended and Restated Partnership Agreement of
Enterprise Products Partners L.P. dated as of April 14, 2008 (incorporated
by reference to Exhibit 10.1 to Form 8-K filed April 16,
2008).
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3.5
|
Third
Amendment to the Fifth Amended and Restated Partnership Agreement of
Enterprise Products Partners L.P. dated as of November 6, 2008
(incorporated by reference to Exhibit 3.5 to Form 10-Q filed on November
10, 2008).
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3.6
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Fifth
Amended and Restated Limited Liability Company Agreement of Enterprise
Products GP, LLC, dated as of November 7, 2007 (incorporated by reference
to Exhibit 3.2 to Form 10-Q filed November 9, 2007).
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3.7
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First
Amendment to Fifth Amended and Restated Limited Liability Company
Agreement of Enterprise Products GP, LLC, dated as of November 6, 2008
(incorporated by reference to Exhibit 3.7 to Form 10-Q filed on November
10, 2008).
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3.8
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Limited
Liability Company Agreement of Enterprise Products Operating LLC dated as
of June 30, 2007 (incorporated by reference to Exhibit 3.3 to Form 10-Q
filed on August 8, 2007).
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3.9
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Certificate
of Incorporation of Enterprise Products OLPGP, Inc., dated December 3,
2003 (incorporated by reference to Exhibit 3.5 to Form S-4 Registration
Statement, Reg. No. 333-121665, filed December 27,
2004).
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3.10
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Bylaws
of Enterprise Products OLPGP, Inc., dated December 8, 2003 (incorporated
by reference to Exhibit 3.6 to Form S-4 Registration Statement, Reg. No.
333-121665, filed December 27, 2004).
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3.11
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Certificate
of Limited Partnership of Duncan Energy Partners L.P. (incorporated by
reference to Exhibit 3.1 to Duncan Energy Partners L.P.’s Form S-1
Registration Statement, Reg. No. 333-138371, filed November 2,
2006).
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3.12
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Amended
and Restated Agreement of Limited Partnership of Duncan Energy Partners
L.P., dated February 5, 2007 (incorporated by reference to Exhibit
3.1 to Duncan Energy Partners L.P.’s Form 8-K filed February 5,
2007).
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3.13
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First
Amendment to Amended and Restated Partnership Agreement of Duncan Energy
Partners L.P. dated as of December 27, 2007 (incorporated by
reference to Exhibit 3.1 to Duncan Energy Partners L.P.’s Form 8-K/A filed
on January 3, 2008).
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4.1
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Form
of Common Unit certificate (incorporated by reference to Exhibit 4.1 to
Registration Statement on Form S-1/A; File No. 333-52537, filed July 21,
1998).
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4.2
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Indenture
dated as of March 15, 2000, among Enterprise Products Operating L.P., as
Issuer, Enterprise Products Partners L.P., as Guarantor, and First Union
National Bank, as Trustee (incorporated by reference to Exhibit 4.1 to
Form 8-K filed March 10, 2000).
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4.3
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First
Supplemental Indenture dated as of January 22, 2003, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Guarantor, and Wachovia Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.2 to Registration Statement on
Form S-4, Reg. No. 333-102776, filed January 28, 2003).
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4.4
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Second
Supplemental Indenture dated as of February 14, 2003, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Guarantor, and Wachovia Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.3 to Form 10-K filed March 31,
2003).
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4.5
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Third
Supplemental Indenture dated as of June 30, 2007, among Enterprise
Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as
Guarantor, and U.S. Bank National Association, as successor Trustee
(incorporated by reference to Exhibit 4.55 to Form 10-Q filed on August 8,
2007).
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4.6
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Amended
and Restated Revolving Credit Agreement dated as of November 19, 2007
among Enterprise Products Operating LLC, the financial institutions party
thereto as lenders, Wachovia Bank, National Association, as Administrative
Agent, Issuing Bank and Swingline Lender, Citibank, N.A. and JPMorgan
Chase Bank, as Co-Syndication Agents, and SunTrust Bank, Mizuho Corporate
Bank, Ltd. and The Bank of Nova Scotia, as Co-Documentation Agents
(incorporated by reference to Exhibit 10.1 to Form 8-K filed on November
20, 2007).
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4.7
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Amended
and Restated Guaranty Agreement dated as of November 19, 2007
executed by Enterprise Products Partners L.P. in favor of Wachovia Bank,
National Association, as Administrative Agent (incorporated by reference
to Exhibit 10.2 to Form 8-K filed on November 20,
2007).
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4.8
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Indenture
dated as of October 4, 2004, among Enterprise Products Operating L.P., as
Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo
Bank, National Association, as Trustee (incorporated by reference to
Exhibit 4.1 to Form 8-K filed on October 6, 2004).
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4.9
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First
Supplemental Indenture dated as of October 4, 2004, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.2 to Form 8-K filed on October 6,
2004).
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4.10
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Second
Supplemental Indenture dated as of October 4, 2004, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.3 to Form 8-K filed on October 6,
2004).
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4.11
|
Third
Supplemental Indenture dated as of October 4, 2004, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.4 to Form 8-K filed on October 6,
2004).
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4.12
|
Fourth
Supplemental Indenture dated as of October 4, 2004, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.5 to Form 8-K filed on October 6,
2004).
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4.13
|
Fifth
Supplemental Indenture dated as of March 2, 2005, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.2 to Form 8-K filed on March 3,
2005).
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4.14
|
Sixth
Supplemental Indenture dated as of March 2, 2005, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.3 to Form 8-K filed on March 3,
2005).
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4.15
|
Seventh
Supplemental Indenture dated as of June 1, 2005, among Enterprise Products
Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.46 to Form 10-Q filed November 4,
2005).
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4.16
|
Eighth
Supplemental Indenture dated as of July 18, 2006 to Indenture dated
October 4, 2004 among Enterprise Products Operating L.P., as issuer,
Enterprise Products Partners L.P., as parent guarantor, and Wells Fargo
Bank, National Association, as trustee (incorporated by reference to
Exhibit 4.2 to Form 8-K filed July 19, 2006).
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4.17
|
Ninth
Supplemental Indenture, dated as of May 24, 2007, by and among
Enterprise Products Operating L.P., as issuer, Enterprise Products
Partners L.P., as parent guarantor, and Wells Fargo Bank, National
Association, as trustee (incorporated by reference to Exhibit 4.2 to
the Current Report on Form 8-K filed by Enterprise Products Partners
L.P. on May 24, 2007).
|
|
4.18
|
Tenth
Supplemental Indenture, dated as of June 30, 2007, by and among Enterprise
Products Operating LLC, as issuer, Enterprise Products Partners L.P., as
parent guarantor, and Wells Fargo Bank, National Association, as trustee
(incorporated by reference to Exhibit 4.54 to Form 10-Q filed August 8,
2007).
|
|
4.19
|
Eleventh
Supplemental Indenture, dated as of September 4, 2007, by and among
Enterprise Products Operating LLC, as issuer, Enterprise Products Partners
L.P., as parent guarantor, and Wells Fargo Bank, National Association, as
trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed on
September 5, 2007).
|
|
4.20
|
Twelfth
Supplemental Indenture, dated as of April 3, 2008, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.3 to Form 8-K filed April 3,
2008).
|
|
4.21
|
Thirteenth
Supplemental Indenture, dated as of April 3, 2008, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.4 to Form 8-K filed April 3,
2008).
|
|
4.22
|
Fourteenth
Supplemental Indenture, dated as of December 8, 2008, among Enterprise
Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Guarantor, and Wells Fargo Bank, National Association, as Trustee
(incorporated by reference to Exhibit 4.3 to Form 8-K filed December 8,
2008).
|
|
4.23
|
Global
Note representing $350.0 million principal amount of 6.375% Series B
Senior Notes due 2013 with attached Guarantee (incorporated by reference
to Exhibit 4.4 to Registration Statement on Form S-4, Reg. No. 333-102776,
filed January 28, 2003).
|
|
4.24
|
Global
Note representing $500.0 million principal amount of 6.875% Series B
Senior Notes due 2033 with attached Guarantee (incorporated by reference
to Exhibit 4.8 to Form 10-K filed March 31, 2003).
|
|
4.25
|
Global
Notes representing $450.0 million principal amount of 7.50% Senior Notes
due 2011 (incorporated by reference to Exhibit 4.1 to Form 8-K filed
January 25, 2001).
|
|
4.26
|
Global
Note representing $500.0 million principal amount of 4.00% Series B Senior
Notes due 2007 with attached Guarantee (incorporated by reference to
Exhibit 4.14 to Form S-3 Registration Statement Reg. No. 333-123150 filed
on March 4, 2005).
|
|
4.27
|
Global
Note representing $500.0 million principal amount of 5.60% Series B Senior
Notes due 2014 with attached Guarantee (incorporated by reference to
Exhibit 4.17 to Form S-3 Registration Statement Reg. No. 333-123150 filed
on March 4, 2005).
|
|
4.28
|
Global
Note representing $150.0 million principal amount of 5.60% Series B Senior
Notes due 2014 with attached Guarantee (incorporated by reference to
Exhibit 4.18 to Form S-3 Registration Statement Reg. No. 333-123150 filed
on March 4, 2005).
|
|
4.29
|
Global
Note representing $350.0 million principal amount of 6.65% Series B Senior
Notes due 2034 with attached Guarantee (incorporated by reference to
Exhibit 4.19 to Form S-3 Registration Statement Reg. No. 333-123150 filed
on March 4, 2005).
|
|
4.30
|
Global
Note representing $500.0 million principal amount of 4.625% Series B
Senior Notes due 2009 with attached Guarantee (incorporated by reference
to Exhibit 4.27 to Form 10-K for the year ended December 31, 2004 filed on
March 15, 2005).
|
|
4.31
|
Global
Note representing $250.0 million principal amount of 5.00% Series B Senior
Notes due 2015 with attached Guarantee (incorporated by reference to
Exhibit 4.31 to Form 10-Q filed on November 4, 2005).
|
|
4.32
|
Global
Note representing $250.0 million principal amount of 5.75% Series B Senior
Notes due 2035 with attached Guarantee (incorporated by reference to
Exhibit 4.32 to Form 10-Q filed on November 4, 2005).
|
|
4.33
|
Global
Note representing $500.0 million principal amount of 4.95% Senior Notes
due 2010 with attached Guarantee (incorporated by reference to Exhibit
4.47 to Form 10-Q filed November 4, 2005).
|
|
4.34
|
Form
of Junior Subordinated Note, including Guarantee (incorporated by
reference to Exhibit 4.3 to Form 8-K filed July 19,
2006).
|
|
4.35
|
Global
Note representing $800.0 million principal amount of 6.30% Senior Notes
due 2017 with attached Guarantee (incorporated by reference to Exhibit
4.38 to Form 10-Q filed November 9, 2007).
|
|
4.36
|
Form
of Global Note representing $400.0 million principal amount of 5.65%
Senior Notes due 2013 with attached Guarantee (incorporated by reference
to Exhibit 4.3 to Form 8-K filed April 3,
2008).
|
|
4.37
|
Form
of Global Note representing $700.0 million principal amount of 6.50%
Senior Notes due 2019 with attached Guarantee (incorporated by reference
to Exhibit 4.4 to Form 8-K filed April 3,
2008).
|
|
4.38
|
Form
of Global Note representing $500.0 million principal amount of 9.75%
Senior Notes due 2014 with attached Guarantee (incorporated by reference
to Exhibit 4.3 to Form 8-K filed December 8,
2008).
|
|
4.39
|
Amended
and Restated Credit Agreement dated as of June 29, 2005, among
Cameron Highway Oil Pipeline Company, the Lenders party thereto, and
SunTrust Bank, as Administrative Agent and Collateral Agent (incorporated
by reference to Exhibit 4.1 to Form 8-K filed on July 1,
2005).
|
|
4.40
|
Replacement
Capital Covenant, dated May 24, 2007, executed by Enterprise Products
Operating L.P. and Enterprise Products Partners L.P. in favor of the
covered debtholders described therein (incorporated by reference to
Exhibit 99.1 to the Current Report on Form 8-K filed by
Enterprise Products Partners L.P. on May 24,
2007).
|
|
4.41
|
First
Amendment to Replacement Capital Covenant dated August 25, 2006,
executed by Enterprise Products Operating L.P. in favor of the covered
debtholders described therein (incorporated by reference to Exhibit 99.2
to Form 8-K filed August 25, 2006).
|
|
4.42
|
Purchase
Agreement, dated as of July 12, 2006 between Cerrito Gathering Company,
Ltd., Cerrito Gas Marketing, Ltd., Encinal Gathering, Ltd., as Sellers,
Lewis Energy Group, L.P. as Guarantor, and Enterprise Products Partners
L.P., as buyer (incorporated by reference to Exhibit 4.6 to Form 10-Q
filed August 8, 2006).
|
|
10.1
|
Transportation
Contract between Enterprise Products Operating L.P. and Enterprise
Transportation Company dated June 1, 1998 (incorporated by reference to
Exhibit 10.3 to Registration Statement Form S-1/A filed July 8,
1998).
|
|
10.2***
|
Enterprise
Products 1998 Long-Term Incentive Plan, amended and restated as of
November 9 2007 (incorporated by reference to Exhibit 10.1 to Form 10-Q
filed on November 9, 2007).
|
|
10.3***
|
Form
of Option Grant Award under Enterprise Products 1998 Long-Term Incentive
Plan for awards issued after May 7, 2008 (incorporated by reference to
Exhibit 10.4 to Form 10-Q filed on May 12, 2008).
|
|
10.4
|
Amendment
to Form of Option Grant Award under Enterprise Products 1998 Long-Term
Incentive Plan for awards issued after April 10, 2007 but before May 7,
2008 (incorporated by reference to Exhibit 10.5 to Form 10-Q filed on May
12, 2008).
|
|
10.5***
|
Form
of Restricted Unit Grant under the Enterprise Products 1998 Long-Term
Incentive Plan (incorporated by reference to Exhibit 10.3 to Form 10-Q
filed on November 9, 2007).
|
|
10.6***
|
EPE
Unit L.P. Agreement of Limited Partnership (incorporated by reference to
Exhibit 10.2 to the Current Report on Form 8-K filed by Enterprise GP
Holdings L.P., Commission file no. 1-32610, on September 1,
2005).
|
|
10.7***
|
First
Amendment to EPE Unit L.P. Agreement of Limited Partnership dated August
7, 2007 (incorporated by reference to Exhibit 10.3 to Form 10-Q filed by
Duncan Energy Partners L.P. on August 8, 2007).
|
|
10.8***
|
Second
Amendment to EPE Unit L.P. Agreement of Limited Partnership dated July 1,
2008 (incorporated by reference to Exhibit 10.1 to the Current Report on
Form 8-K filed by Enterprise GP Holdings L.P. on July 7,
2008).
|
|
10.9***
|
EPE
Unit II, L.P. Agreement of Limited Partnership (incorporated by reference
to Exhibit 10.13 to Form 10-K filed on February 28,
2007).
|
|
10.10***
|
First
Amendment to EPE Unit II, L.P. Agreement of limited partnership dated
August 7, 2007 (incorporated by reference to Exhibit 10.4 to Form 10-Q
filed by Duncan Energy Partners L.P. on August 8,
2007).
|
|
10.11***
|
Second
Amendment to EPE Unit II, L.P. Agreement of limited partnership dated July
1, 2008 (incorporated by reference to Exhibit 10.2 to the Current Report
on Form 8-K filed by Enterprise GP Holdings L.P. on July 7,
2008).
|
|
10.12***
|
EPE
Unit III, L.P. Agreement of Limited Partnership dated May 7, 2007
(incorporated by reference to Exhibit 10.6 to the Current Report on
Form 8-K filed by Enterprise GP Holdings L.P. on May 10,
2007).
|
|
10.13***
|
First
Amendment to EPE Unit III, L.P. Agreement of limited partnership dated
August 7, 2007 (incorporated by reference to Exhibit 10.5 to Form 10-Q
filed by Duncan Energy Partners L.P. on August 8,
2007).
|
|
10.14***
|
Second
Amendment to Agreement of Limited Partnership of EPE Unit III, L.P. dated
July 1, 2008 (incorporated by reference to Exhibit 10.3 to the Current
Report Form 8-K filed by Enterprise GP Holdings L.P. on July 7,
2008).
|
|
10.15
|
Enterprise
Unit L.P. Agreement of Limited Partnership dated February 20, 2008
(incorporated by reference to Exhibit 10.1 to the Form 8-K filed
on February 26, 2008).
|
|
10.16
|
EPCO
Unit L.P. Agreement of Limited Partnership dated November 13, 2008
(incorporated by reference to Exhibit 10.5 to the Form 8-K filed
on November 18, 2008).
|
|
10.17***
|
Enterprise
Products Company 2005 EPE Long-Term Incentive Plan (amended and restated)
(incorporated by reference to Exhibit 10.1 to Form 8-K filed by Enterprise
GP Holdings L.P. on May 8, 2006).
|
|
10.18***
|
Form
of Restricted Unit Grant under the Enterprise Products Company 2005 EPE
Long-Term Incentive Plan (incorporated by reference to Exhibit 10.29 to
Amendment No. 3 to Form S-1 Registration Statement (Reg. No. 333-124320)
filed by Enterprise GP Holdings L.P. on August 11,
2005).
|
|
10.19***
|
Form
of Phantom Unit Grant under the Enterprise Products Company 2005 EPE
Long-Term Incentive Plan (incorporated by reference to Exhibit 10.30 to
Amendment No. 3 to Form S-1 Registration Statement (Reg. No. 333-124320)
filed by Enterprise GP Holdings L.P. on August 11,
2005).
|
|
10.20***
|
Form
of Unit Appreciation Right Grant (Enterprise Products GP, LLC Directors)
based upon the Enterprise Products Company 2005 EPE Long-Term Incentive
Plan (incorporated by reference to Exhibit 10.3 to Form 8-K filed by
Enterprise GP Holdings on May 8, 2006).
|
|
10.21***
|
Amended
and Restated Enterprise Products 2008 Long-Term Incentive Plan
(incorporated by reference to Exhibit 4.1 to the Registration Statement on
Form S-8 filed on May 6, 2008).
|
|
10.22***
|
Form
of Restricted Unit Grant under the Amended and Restated Enterprise
Products 2008 Long-Term Incentive Plan (incorporated by reference to
Exhibit 4.2 to the Registration Statement on Form S-8 filed on May 6,
2008).
|
|
10.23***
|
Form
of Option Grant under the Amended and Restated Enterprise Products 2008
Long-Term Incentive Plan (incorporated by reference to Exhibit 4.3 to the
Registration Statement on Form S-8 filed on May 6,
2008).
|
|
10.24
|
Fifth
Amended and Restated Administrative Services Agreement by and among EPCO,
Inc., Enterprise GP Holdings L.P., EPE Holdings, LLC, Enterprise Products
Partners L.P., Enterprise Products Operating LLC, Enterprise Products GP,
LLC, Enterprise Products OLPGP, Inc., DEP Holdings, LLC, Duncan Energy
Partners L.P., DEP Operating Partnership L.P., TEPPCO Partners, L.P.,
Texas Eastern Products Pipeline Company, LLC, TE Products Pipeline
Company, LLC, TEPPCO Midstream Companies, LLC, TCTM, L.P. and TEPPCO GP,
Inc. dated effective as of January 30, 2009 (incorporated by reference to
Exhibit 10.1 to Form 8-K filed February 5, 2009).
|
|
10.25
|
Omnibus
Agreement, dated as of February 5, 2007 by and among Enterprise Products
Operating L.P., DEP Holdings, LLC, Duncan Energy Partners L.P., DEP OLPGP,
LLC, DEP Operating Partnership, L.P., Enterprise Lou-Tex Propylene
Pipeline L.P., Sabine Propylene Pipeline L.P., Acadian Gas, LLC, Mont
Belvieu Caverns, LLC, South Texas NGL Pipelines, LLC (incorporated by
reference to Exhibit 10.19 to Form 8-K filed February 5, 2007 by Duncan
Energy Partners).
|
|
10.26
|
Contribution,
Conveyance and Assumption Agreement dated as of February 5, 2007, by and
among Enterprise Products Operating L.P., DEP Holdings, LLC, Duncan Energy
Partners L.P., DEP OLPGP, LLC and DEP Operating Partnership, L.P.
(incorporated by reference to Exhibit 10.1 to Form 8-K filed February 5,
2007 by Duncan Energy Partners).
|
|
10.27
|
Agreement
and Release, dated May 31, 2007, between EPCO, Inc. and Robert G. Phillips
(incorporated by reference to Exhibit 10.3 to Form 10-Q filed on August 8,
2007).
|
|
10.28
|
Revolving
Credit Agreement, dated as of January 5, 2007, among Duncan Energy
Partners L.P., as borrower, Wachovia Bank, National Association, as
Administrative Agent, The Bank of Nova Scotia and Citibank, N.A., as
Co-Syndication Agents, JPMorgan Chase Bank, N.A. and Mizuho Corporate
Bank, Ltd., as Co-Documentation Agents, and Wachovia Capital Markets, LLC,
The Bank of Nova Scotia and Citigroup Global Markets Inc., as Joint Lead
Arrangers and Joint Book Runners (incorporated by reference to
Exhibit 10.20 to Amendment No. 2 to Duncan Energy Partners
L.P.’s Form S-1 Registration Statement (Reg. No. 333-138371)
filed January 12, 2007).
|
|
10.29
|
First
Amendment to Revolving Credit Agreement, dated as of June 30, 2007, among
Duncan Energy Partners L.P., as borrower, Wachovia Bank, National
Association, as Administrative Agent, The Bank of Nova Scotia and
Citibank, N.A., as Co-Syndication Agents, JPMorgan Chase Bank, N.A. and
Mizuho Corporate Bank, Ltd., as Co-Documentation Agents, and Wachovia
Capital Markets, LLC, The Bank of Nova Scotia and Citigroup Global Markets
Inc., as Joint Lead Arrangers and Joint Book Runners (incorporated
by reference to Exhibit 4.2 to Form 10-Q filed August 8, 2007 by
Duncan Energy Partners).
|
|
10.30
|
Term
Loan Credit Agreement dated as of November 12, 2008 among Enterprise
Products Operating LLC, the financial institutions party thereto as
lenders, Mizuho Corporate Bank, Ltd., as administrative agent, a lender
and as sole lead arranger (incorporated by reference to Exhibit 10.1
to Form 8-K on November 18, 2008).
|
|
10.31
|
Guaranty
Agreement dated as of November 12, 2008 executed by Enterprise
Products Partners L.P. in favor of Mizuho Corporate Bank, Ltd., as
administrative agent (incorporated by reference to Exhibit 10.2 to
Form 8-K on November 18, 2008).
|
|
10.32
|
364-Day
Revolving Credit Agreement dated as of November 17, 2008 among Enterprise
Products Operating LLC, the financial institutions party thereto as
lenders, The Royal Bank of Scotland plc, as administrative agent, and
Barclays Bank plc, The Bank of Nova Scotia, DnB NOR Bank ASA and Wachovia
Bank, National Association, as co-arrangers (incorporated by
reference to Exhibit 10.3 to Form 8-K on November 18,
2008).
|
|
10.33
|
Guaranty
Agreement dated as of November 17, 2008 executed by Enterprise
Products Partners L.P. in favor of The Royal Bank of Scotland plc, as
administrative agent (incorporated by reference to Exhibit 10.4 to
Form 8-K on November 18, 2008).
|
|
10.34*
|
Second
Amended and Restated Limited Liability Company Agreement of Mont Belvieu
Caverns, LLC, dated November 6, 2008 (incorporated by reference to
Exhibit 10.4 to Form 10-Q filed by Duncan Energy Partners L.P.
on November 10, 2008).
|
|
12.1#
|
Computation
of ratio of earnings to fixed charges for each of the five years ended
December 31, 2008, 2007, 2006, 2005 and 2004.
|
|
21.1#
|
List
of subsidiaries as of February 2, 2009.
|
|
23.1#
|
Consent
of Deloitte & Touche LLP.
|
|
31.1#
|
Sarbanes-Oxley
Section 302 certification of Michael A. Creel for Enterprise Products
Partners L.P. for the December 31, 2008 annual report on Form
10-K.
|
|
31.2#
|
Sarbanes-Oxley
Section 302 certification of W. Randall Fowler for Enterprise Products
Partners L.P. for the December 31, 2008 annual report on Form
10-K.
|
|
32.1#
|
Section
1350 certification of Michael A. Creel for the December 31, 2008 annual
report on Form 10-K.
|
|
32.2#
|
Section
1350 certification of W. Randall Fowler for the December 31, 2008 annual
report on Form 10-K.
|
|
*
|
With
respect to any exhibits incorporated by reference to any Exchange Act
filings, the Commission file number for Enterprise Products Partners L.P.,
Duncan Energy Partners L.P. and Enterprise GP Holdings L.P. are 1-14323,
1-33266 and 1-32610, respectively.
|
|
***
|
Identifies
management contract and compensatory plan arrangements.
|
|
#
|
Filed
with this report.
|
Pursuant to the requirements of Section
13 or 15(d) of the Securities Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned thereunto duly authorized
on March 2, 2009.
|
|
|
|
|
|
ENTERPRISE
PRODUCTS PARTNERS L.P.
|
|
|
|
|
|
|
(A
Delaware Limited Partnership)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
By: Enterprise
Products GP, LLC, as General Partner
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
By:
|
/s/
Michael J. Knesek
|
|
|
|
|
|
|
Name:
|
Michael
J. Knesek
|
|
|
|
|
|
|
Title:
|
Senior
Vice President, Controller
and
Principal Accounting Officer
of
the General Partner
|
Pursuant to the requirements of the
Securities Act of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities indicated below on
March 2, 2009.
|
Signature
|
|
Title
(Position with Enterprise Products GP, LLC)
|
|
/s/
Dan L. Duncan
|
|
Director
and Chairman
|
|
Dan
L. Duncan
|
|
|
|
/s/
Michael A. Creel
|
|
Director,
President and Chief Executive Officer
|
|
Michael
A. Creel
|
|
|
|
/s/
W. Randall Fowler
|
|
Director,
Executive Vice President and Chief Financial Officer
|
|
W.
Randall Fowler
|
|
|
|
/s/
Richard H. Bachmann
|
|
Director,
Executive Vice President, Chief Legal Officer and
Secretary
|
|
Richard
H. Bachmann
|
|
|
|
/s/
A. J. Teague
|
|
Director,
Executive Vice President and Chief Commercial Officer
|
|
A.
J. Teague
|
|
|
|
/s/
Dr. Ralph S. Cunningham
|
|
Director
|
|
Dr.
Ralph S. Cunningham
|
|
|
|
/s/
E. William Barnett
|
|
Director
|
|
E.
William Barnett
|
|
|
|
/s/
Rex C. Ross
|
|
Director
|
|
Rex
C. Ross
|
|
|
|
/s/
Charles M. Rampacek
|
|
Director
|
|
Charles
M. Rampacek
|
|
|
|
/s/
Michael J. Knesek
|
|
Senior
Vice President, Controller and Principal Accounting
Officer
|
|
Michael
J. Knesek
|
|
|
ENTERPRISE
PRODUCTS PARTNERS L.P.
INDEX TO
FINANCIAL STATEMENTS
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, 2008 and 2007, and the
related consolidated statements of operations, comprehensive income, cash flows,
and partners’ equity for each of the three years in the period ended December
31, 2008. These financial statements are the responsibility of the
Company’s management. Our responsibility is to express an opinion on
the financial statements 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,
2008 and 2007, and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 2008, in conformity with
accounting principles generally accepted in the United States of
America.
We have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the Company's internal control over financial
reporting as of December 31, 2008, based on the criteria established in Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission and our report dated March 2, 2009 expressed an unqualified
opinion on the Company's internal control over financial reporting.
/s/
DELOITTE & TOUCHE LLP
Houston,
Texas
March 2,
2009
CONSOLIDATED
BALANCE SHEETS
(Dollars
in thousands)
|
|
|
December
31,
|
|
|
ASSETS
|
|
2008
|
|
|
2007
|
|
|
Current
assets:
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
35,373 |
|
|
$ |
39,722 |
|
|
Restricted
cash
|
|
|
203,789 |
|
|
|
53,144 |
|
|
Accounts
and notes receivable – trade, net of allowance for doubtful
accounts
of
$15,123 at December 31, 2008 and $21,659 at December 31,
2007
|
|
|
1,185,515 |
|
|
|
1,930,762 |
|
|
Accounts
receivable – related parties
|
|
|
61,629 |
|
|
|
79,782 |
|
|
Inventories
|
|
|
362,815 |
|
|
|
354,282 |
|
|
Derivative
assets
|
|
|
202,826 |
|
|
|
1,649 |
|
|
Prepaid
and other current assets
|
|
|
111,773 |
|
|
|
78,544 |
|
|
Total
current assets
|
|
|
2,163,720 |
|
|
|
2,537,885 |
|
|
Property,
plant and equipment, net
|
|
|
13,154,774 |
|
|
|
11,587,264 |
|
|
Investments
in and advances to unconsolidated affiliates
|
|
|
949,526 |
|
|
|
858,339 |
|
|
Intangible
assets, net of accumulated amortization of $429,872 at
December
31, 2008 and $341,494 at December 31, 2007
|
|
|
855,416 |
|
|
|
917,000 |
|
|
Goodwill
|
|
|
706,884 |
|
|
|
591,652 |
|
|
Deferred
tax asset
|
|
|
355 |
|
|
|
3,522 |
|
|
Other
assets, including restricted cash of $17,871 at December 31,
2007
|
|
|
126,860 |
|
|
|
112,345 |
|
|
Total
assets
|
|
$ |
17,957,535 |
|
|
$ |
16,608,007 |
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES
AND PARTNERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
|
|
|
Accounts
payable – trade
|
|
$ |
300,532 |
|
|
$ |
324,999 |
|
|
Accounts
payable – related parties
|
|
|
39,558 |
|
|
|
24,432 |
|
|
Accrued
product payables
|
|
|
1,142,370 |
|
|
|
2,227,489 |
|
|
Accrued
expenses
|
|
|
48,772 |
|
|
|
47,756 |
|
|
Accrued
interest
|
|
|
151,873 |
|
|
|
130,971 |
|
|
Derivative
liabilities
|
|
|
287,161 |
|
|
|
41,811 |
|
|
Other
current liabilities
|
|
|
252,883 |
|
|
|
247,225 |
|
|
Total
current liabilities
|
|
|
2,223,149 |
|
|
|
3,044,683 |
|
|
Long-term debt: (see
Note 14)
|
|
|
|
|
|
|
|
|
|
Senior
debt obligations – principal
|
|
|
7,813,346 |
|
|
|
5,646,500 |
|
|
Junior
subordinated notes – principal
|
|
|
1,232,700 |
|
|
|
1,250,000 |
|
|
Other
|
|
|
62,364 |
|
|
|
9,645 |
|
|
Total
long-term debt
|
|
|
9,108,410 |
|
|
|
6,906,145 |
|
|
Deferred
tax liabilities
|
|
|
66,062 |
|
|
|
21,364 |
|
|
Other
long-term liabilities
|
|
|
81,277 |
|
|
|
73,748 |
|
|
Minority
interest
|
|
|
393,649 |
|
|
|
430,418 |
|
|
Commitments
and contingencies
|
|
|
|
|
|
|
|
|
|
Partners’ equity: (see
Note 15)
|
|
|
|
|
|
|
|
|
|
Limited
Partners:
|
|
|
|
|
|
|
|
|
|
Common
units (439,354,731 units outstanding at December 31, 2008
and
433,608,763 units outstanding at December 31, 2007)
|
|
|
6,036,887 |
|
|
|
5,976,947 |
|
|
Restricted
common units (2,080,600 units outstanding at December 31,
2008
and
1,688,540 units outstanding at December 31, 2007)
|
|
|
26,219 |
|
|
|
15,948 |
|
|
General
partner
|
|
|
123,599 |
|
|
|
122,297 |
|
|
Accumulated
other comprehensive income (loss)
|
|
|
(101,717 |
) |
|
|
16,457 |
|
|
Total
partners’ equity
|
|
|
6,084,988 |
|
|
|
6,131,649 |
|
|
Total
liabilities and partners’ equity
|
|
$ |
17,957,535 |
|
|
$ |
16,608,007 |
|
See Notes
to Consolidated Financial Statements.
STATEMENTS OF
CONSOLIDATED OPERATIONS
(Dollars
in thousands, except per unit amounts)
|
|
|
For
Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
Third
parties
|
|
$ |
20,769,206 |
|
|
$ |
16,297,409 |
|
|
$ |
13,587,739 |
|
|
Related
parties
|
|
|
1,136,450 |
|
|
|
652,716 |
|
|
|
403,230 |
|
|
Total
revenues (see Note 16)
|
|
|
21,905,656 |
|
|
|
16,950,125 |
|
|
|
13,990,969 |
|
|
Costs
and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Third
parties
|
|
|
19,814,572 |
|
|
|
15,646,587 |
|
|
|
12,745,948 |
|
|
Related
parties
|
|
|
646,392 |
|
|
|
362,464 |
|
|
|
343,143 |
|
|
Total
operating costs and expenses
|
|
|
20,460,964 |
|
|
|
16,009,051 |
|
|
|
13,089,091 |
|
|
General
and administrative costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Third
parties
|
|
|
31,543 |
|
|
|
31,177 |
|
|
|
22,126 |
|
|
Related
parties
|
|
|
59,007 |
|
|
|
56,518 |
|
|
|
41,265 |
|
|
Total
general and administrative costs
|
|
|
90,550 |
|
|
|
87,695 |
|
|
|
63,391 |
|
|
Total
costs and expenses
|
|
|
20,551,514 |
|
|
|
16,096,746 |
|
|
|
13,152,482 |
|
|
Equity
in earnings of unconsolidated affiliates
|
|
|
59,104 |
|
|
|
29,658 |
|
|
|
21,565 |
|
|
Operating
income
|
|
|
1,413,246 |
|
|
|
883,037 |
|
|
|
860,052 |
|
|
Other
income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
|
(400,686 |
) |
|
|
(311,764 |
) |
|
|
(238,023 |
) |
|
Interest
income
|
|
|
5,523 |
|
|
|
8,601 |
|
|
|
7,589 |
|
|
Other,
net
|
|
|
3,715 |
|
|
|
(300 |
) |
|
|
467 |
|
|
Total
other expense, net
|
|
|
(391,448 |
) |
|
|
(303,463 |
) |
|
|
(229,967 |
) |
|
Income
before provision for income taxes, minority interest and
the
cumulative effect of change in accounting principle
|
|
|
1,021,798 |
|
|
|
579,574 |
|
|
|
630,085 |
|
|
Provision
for income taxes
|
|
|
(26,401 |
) |
|
|
(15,257 |
) |
|
|
(21,323 |
) |
|
Income
before minority interest and the cumulative effect
of
change in accounting principle
|
|
|
995,397 |
|
|
|
564,317 |
|
|
|
608,762 |
|
|
Minority
interest
|
|
|
(41,376 |
) |
|
|
(30,643 |
) |
|
|
(9,079 |
) |
|
Income
before the cumulative effect of change in accounting
principle
|
|
|
954,021 |
|
|
|
533,674 |
|
|
|
599,683 |
|
|
Cumulative
effect of change in accounting principle (see Note 8)
|
|
|
-- |
|
|
|
-- |
|
|
|
1,472 |
|
|
Net
income
|
|
$ |
954,021 |
|
|
$ |
533,674 |
|
|
$ |
601,155 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income allocation:
(see Note 15)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income available to limited partners
|
|
$ |
811,547 |
|
|
$ |
417,728 |
|
|
$ |
504,156 |
|
|
Net
income available to general partner
|
|
$ |
142,474 |
|
|
$ |
115,946 |
|
|
$ |
96,999 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per unit: (see
Note 19)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
and diluted income per unit before change in accounting
principle
|
|
$ |
1.85 |
|
|
$ |
0.96 |
|
|
$ |
1.22 |
|
|
Basic
and diluted income per unit
|
|
$ |
1.85 |
|
|
$ |
0.96 |
|
|
$ |
1.22 |
|
See Notes
to Consolidated Financial Statements.
STATEMENTS OF
CONSOLIDATED COMPREHENSIVE INCOME
(Dollars
in thousands)
|
|
|
For
Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$ |
954,021 |
|
|
$ |
533,674 |
|
|
$ |
601,155 |
|
|
Other
comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
financial instrument gains (losses) during period
|
|
|
(150,865 |
) |
|
|
(25,860 |
) |
|
|
8,942 |
|
|
Reclassification
adjustment for (gains) losses included in net income
related
to commodity financial instruments
|
|
|
58,407 |
|
|
|
7,863 |
|
|
|
(12,564 |
) |
|
Interest
rate financial instrument gains (losses) during period
|
|
|
(28,761 |
) |
|
|
14,725 |
|
|
|
11,196 |
|
|
Reclassification
adjustment for gains included in net income
related
to interest rate financial instruments
|
|
|
(2,401 |
) |
|
|
(5,779 |
) |
|
|
(4,234 |
) |
|
Foreign
currency hedge gains
|
|
|
9,286 |
|
|
|
1,308 |
|
|
|
-- |
|
|
Total
cash flow hedges
|
|
|
(114,334 |
) |
|
|
(7,743 |
) |
|
|
3,340 |
|
|
Foreign
currency translation adjustment
|
|
|
(2,501 |
) |
|
|
2,007 |
|
|
|
(807 |
) |
|
Change
in funded status of pension and postretirement plans, net of
tax
|
|
|
(1,339 |
) |
|
|
(52 |
) |
|
|
-- |
|
|
Total
other comprehensive income (loss)
|
|
|
(118,174 |
) |
|
|
(5,788 |
) |
|
|
2,533 |
|
|
Comprehensive
income
|
|
$ |
835,847 |
|
|
$ |
527,886 |
|
|
$ |
603,688 |
|
See Notes
to Consolidated Financial Statements.
STATEMENTS OF
CONSOLIDATED CASH FLOWS
(Dollars
in thousands)
|
|
|
For
Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Operating
activities:
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$ |
954,021 |
|
|
$ |
533,674 |
|
|
$ |
601,155 |
|
|
Adjustments
to reconcile net income to net cash
flows
provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
amortization and accretion in operating costs and expenses
|
|
|
555,370 |
|
|
|
513,840 |
|
|
|
440,256 |
|
|
Depreciation
and amortization in general and administrative costs
|
|
|
10,659 |
|
|
|
10,258 |
|
|
|
7,186 |
|
|
Amortization
in interest expense
|
|
|
(3,858 |
) |
|
|
(336 |
) |
|
|
766 |
|
|
Equity
in earnings of unconsolidated affiliates
|
|
|
(59,104 |
) |
|
|
(29,658 |
) |
|
|
(21,565 |
) |
|
Distributions
received from unconsolidated affiliates
|
|
|
98,553 |
|
|
|
73,593 |
|
|
|
43,032 |
|
|
Provision
for impairment of long-lived asset
|
|
|
-- |
|
|
|
-- |
|
|
|
88 |
|
|
Cumulative
effect of change in accounting principle
|
|
|
-- |
|
|
|
-- |
|
|
|
(1,472 |
) |
|
Operating
lease expense paid by EPCO, Inc.
|
|
|
2,038 |
|
|
|
2,105 |
|
|
|
2,109 |
|
|
Minority
interest
|
|
|
41,376 |
|
|
|
30,643 |
|
|
|
9,079 |
|
|
Loss
(gain) from asset sales and related transactions
|
|
|
(3,746 |
) |
|
|
5,391 |
|
|
|
(3,359 |
) |
|
Loss
(gain) on early extinguishment of debt
|
|
|
(7,093 |
) |
|
|
250 |
|
|
|
-- |
|
|
Deferred
income tax expense
|
|
|
6,199 |
|
|
|
8,306 |
|
|
|
14,427 |
|
|
Changes
in fair market value of financial instruments
|
|
|
198 |
|
|
|
981 |
|
|
|
(51 |
) |
|
Effect
of pension settlement recognition
|
|
|
(114 |
) |
|
|
588 |
|
|
|
-- |
|
|
Net
effect of changes in operating accounts (see Note 22)
|
|
|
(357,430 |
) |
|
|
441,306 |
|
|
|
83,418 |
|
|
Net
cash flows provided by operating activities
|
|
|
1,237,069 |
|
|
|
1,590,941 |
|
|
|
1,175,069 |
|
|
Investing
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
|
(1,979,459 |
) |
|
|
(2,185,800 |
) |
|
|
(1,341,070 |
) |
|
Contributions
in aid of construction costs
|
|
|
25,783 |
|
|
|
57,547 |
|
|
|
60,492 |
|
|
Proceeds
from asset sales and related transactions
|
|
|
15,999 |
|
|
|
12,027 |
|
|
|
3,927 |
|
|
Increase
in restricted cash
|
|
|
(132,775 |
) |
|
|
(47,347 |
) |
|
|
(8,715 |
) |
|
Cash
used for business combinations (see Note 12)
|
|
|
(202,160 |
) |
|
|
(35,793 |
) |
|
|
(276,500 |
) |
|
Acquisition
of intangible assets
|
|
|
(5,126 |
) |
|
|
(11,232 |
) |
|
|
-- |
|
|
Investments
in unconsolidated affiliates
|
|
|
(129,816 |
) |
|
|
(332,909 |
) |
|
|
(138,266 |
) |
|
Advances
from (to) unconsolidated affiliates
|
|
|
(4,315 |
) |
|
|
(10,100 |
) |
|
|
10,844 |
|
|
Cash
used in investing activities
|
|
|
(2,411,869 |
) |
|
|
(2,553,607 |
) |
|
|
(1,689,288 |
) |
|
Financing
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings
under debt agreements
|
|
|
8,683,450 |
|
|
|
6,024,518 |
|
|
|
3,378,285 |
|
|
Repayments
of debt
|
|
|
(6,528,126 |
) |
|
|
(4,458,141 |
) |
|
|
(2,907,000 |
) |
|
Debt
issuance costs
|
|
|
(17,584 |
) |
|
|
(16,511 |
) |
|
|
(8,955 |
) |
|
Distributions
paid to partners
|
|
|
(1,037,373 |
) |
|
|
(957,705 |
) |
|
|
(843,292 |
) |
|
Distributions
paid to minority interests
|
|
|
(55,851 |
) |
|
|
(32,326 |
) |
|
|
(8,831 |
) |
|
Proceeds
from initial public offering of Duncan Energy Partners
in
minority interests (see Notes 2 and 17)
|
|
|
-- |
|
|
|
290,466 |
|
|
|
-- |
|
|
Other
contributions from minority interests
|
|
|
28 |
|
|
|
12,506 |
|
|
|
27,578 |
|
|
Net
proceeds from issuance of common units
|
|
|
142,777 |
|
|
|
69,221 |
|
|
|
857,187 |
|
|
Repurchase
of restricted option awards
|
|
|
-- |
|
|
|
(1,568 |
) |
|
|
-- |
|
|
Acquisition
of treasury units
|
|
|
(1,911 |
) |
|
|
-- |
|
|
|
-- |
|
|
Monetization
of interest rate hedging financial instruments (see Note
7)
|
|
|
(14,444 |
) |
|
|
48,895 |
|
|
|
-- |
|
|
Cash
provided by financing activities
|
|
|
1,170,966 |
|
|
|
979,355 |
|
|
|
494,972 |
|
|
Effect
of exchange rate changes on cash
|
|
|
(515 |
) |
|
|
414 |
|
|
|
(232 |
) |
|
Net
change in cash and cash equivalents
|
|
|
(3,834 |
) |
|
|
16,689 |
|
|
|
(19,247 |
) |
|
Cash
and cash equivalents, January 1
|
|
|
39,722 |
|
|
|
22,619 |
|
|
|
42,098 |
|
|
Cash
and cash equivalents, December 31
|
|
$ |
35,373 |
|
|
$ |
39,722 |
|
|
$ |
22,619 |
|
See Notes
to Consolidated Financial Statements.
STATEMENTS OF
CONSOLIDATED PARTNERS’ EQUITY
(See
Note 15 for Unit History, Detail of Changes in Limited Partners’ Equity and
Accumulated Other Comprehensive Income (Loss))
(Dollars
in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
Limited
|
|
|
General
|
|
|
Deferred
|
|
|
Comprehensive
|
|
|
|
|
|
|
|
Partners
|
|
|
Partner
|
|
|
Compensation
|
|
|
Income
(Loss)
|
|
|
Total
|
|
|
Balance,
December 31, 2005
|
|
$ |
5,561,338 |
|
|
$ |
113,496 |
|
|
$ |
(14,597 |
) |
|
$ |
19,072 |
|
|
$ |
5,679,309 |
|
|
Net
income
|
|
|
504,156 |
|
|
|
96,999 |
|
|
|
-- |
|
|
|
-- |
|
|
|
601,155 |
|
|
Operating
leases paid by EPCO, Inc.
|
|
|
2,067 |
|
|
|
42 |
|
|
|
-- |
|
|
|
-- |
|
|
|
2,109 |
|
|
Cash
distributions to partners
|
|
|
(739,632 |
) |
|
|
(101,805 |
) |
|
|
-- |
|
|
|
-- |
|
|
|
(841,437 |
) |
|
Unit
option reimbursements to EPCO, Inc.
|
|
|
(1,818 |
) |
|
|
(41 |
) |
|
|
-- |
|
|
|
-- |
|
|
|
(1,859 |
) |
|
Net
proceeds from issuance of common units
|
|
|
830,825 |
|
|
|
16,943 |
|
|
|
-- |
|
|
|
-- |
|
|
|
847,768 |
|
|
Common
units issued to Lewis in connection
with
Encinal acquisition
|
|
|
181,112 |
|
|
|
3,705 |
|
|
|
-- |
|
|
|
-- |
|
|
|
184,817 |
|
|
Proceeds
from exercise of unit options
|
|
|
5,601 |
|
|
|
114 |
|
|
|
-- |
|
|
|
-- |
|
|
|
5,715 |
|
|
Change
in accounting method for
equity
awards (see Note 8)
|
|
|
(15,815 |
) |
|
|
(307 |
) |
|
|
14,597 |
|
|
|
-- |
|
|
|
(1,525 |
) |
|
Amortization
of equity awards
|
|
|
8,282 |
|
|
|
155 |
|
|
|
-- |
|
|
|
-- |
|
|
|
8,437 |
|
|
Change
in funded status of pension and
postretirement
plans, net of tax
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
(464 |
) |
|
|
(464 |
) |
|
Foreign
currency translation adjustment
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
(807 |
) |
|
|
(807 |
) |
|
Acquisition-related
disbursement of cash
|
|
|
(6,199 |
) |
|
|
(126 |
) |
|
|
-- |
|
|
|
-- |
|
|
|
(6,325 |
) |
|
Cash
flow hedges
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
3,340 |
|
|
|
3,340 |
|
|
Balance,
December 31, 2006
|
|
|
6,329,917 |
|
|
|
129,175 |
|
|
|
-- |
|
|
|
21,141 |
|
|
|
6,480,233 |
|
|
Net
income
|
|
|
417,728 |
|
|
|
115,946 |
|
|
|
-- |
|
|
|
-- |
|
|
|
533,674 |
|
|
Operating
leases paid by EPCO, Inc.
|
|
|
2,063 |
|
|
|
42 |
|
|
|
-- |
|
|
|
-- |
|
|
|
2,105 |
|
|
Cash
distributions to partners
|
|
|
(833,793 |
) |
|
|
(124,388 |
) |
|
|
-- |
|
|
|
-- |
|
|
|
(958,181 |
) |
|
Unit
option reimbursements to EPCO, Inc.
|
|
|
(2,999 |
) |
|
|
(58 |
) |
|
|
-- |
|
|
|
-- |
|
|
|
(3,057 |
) |
|
Net
proceeds from issuance of common units
|
|
|
60,445 |
|
|
|
1,232 |
|
|
|
-- |
|
|
|
-- |
|
|
|
61,677 |
|
|
Proceeds
from exercise of unit options
|
|
|
7,549 |
|
|
|
154 |
|
|
|
-- |
|
|
|
-- |
|
|
|
7,703 |
|
|
Repurchase
of restricted units and options
|
|
|
(1,568 |
) |
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
(1,568 |
) |
|
Amortization
of equity awards
|
|
|
13,553 |
|
|
|
194 |
|
|
|
-- |
|
|
|
-- |
|
|
|
13,747 |
|
|
Change
in funded status of pension and
postretirement
plans, net of tax
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
1,052 |
|
|
|
1,052 |
|
|
Foreign
currency translation adjustment
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
2,007 |
|
|
|
2,007 |
|
|
Cash
flow hedges
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
(7,743 |
) |
|
|
(7,743 |
) |
|
Balance,
December 31, 2007
|
|
|
5,992,895 |
|
|
|
122,297 |
|
|
|
-- |
|
|
|
16,457 |
|
|
|
6,131,649 |
|
|
Net
income
|
|
|
811,547 |
|
|
|
142,474 |
|
|
|
-- |
|
|
|
-- |
|
|
|
954,021 |
|
|
Operating
leases paid by EPCO, Inc.
|
|
|
1,997 |
|
|
|
41 |
|
|
|
-- |
|
|
|
-- |
|
|
|
2,038 |
|
|
Cash
distributions to partners
|
|
|
(892,693 |
) |
|
|
(144,130 |
) |
|
|
-- |
|
|
|
-- |
|
|
|
(1,036,823 |
) |
|
Unit
option reimbursements to EPCO, Inc.
|
|
|
(550 |
) |
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
(550 |
) |
|
Non-cash
distributions
|
|
|
(7,140 |
) |
|
|
(144 |
) |
|
|
-- |
|
|
|
-- |
|
|
|
(7,284 |
) |
|
Acquisition
of treasury units
|
|
|
(1,873 |
) |
|
|
(38 |
) |
|
|
-- |
|
|
|
-- |
|
|
|
(1,911 |
) |
|
Net
proceeds from issuance of common units
|
|
|
139,248 |
|
|
|
2,842 |
|
|
|
-- |
|
|
|
-- |
|
|
|
142,090 |
|
|
Proceeds
from exercise of unit options
|
|
|
679 |
|
|
|
8 |
|
|
|
-- |
|
|
|
-- |
|
|
|
687 |
|
|
Amortization
of equity awards
|
|
|
18,996 |
|
|
|
249 |
|
|
|
-- |
|
|
|
-- |
|
|
|
19,245 |
|
|
Change
in funded status of pension and
postretirement
plans, net of tax
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
(1,339 |
) |
|
|
(1,339 |
) |
|
Foreign
currency translation adjustment
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
(2,501 |
) |
|
|
(2,501 |
) |
|
Cash
flow hedges
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
|
(114,334 |
) |
|
|
(114,334 |
) |
|
Balance,
December 31, 2008
|
|
$ |
6,063,106 |
|
|
$ |
123,599 |
|
|
$ |
-- |
|
|
$ |
(101,717 |
) |
|
$ |
6,084,988 |
|
See Notes
to Consolidated Financial Statements.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
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.
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 business and operations of Enterprise Products Partners L.P. and its
consolidated 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 LLC (“EPO”), as successor in interest by merger to Enterprise Products
Operating L.P. We are owned 98.0% by our limited partners and 2.0% by
Enterprise Products GP, LLC (our general partner, referred to as
“EPGP”). EPGP is owned 100.0% by Enterprise GP Holdings L.P.
(“Enterprise GP Holdings”), a publicly traded affiliate, the 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 Dan Duncan LLC, the membership interests of which are owned by Dan
L. Duncan. We, EPGP, Enterprise GP Holdings, EPE Holdings and Dan
Duncan LLC are affiliates and under common control of Dan L. Duncan, the Group
Co-Chairman and controlling shareholder of EPCO.
References
to “TEPPCO” mean TEPPCO Partners, L.P., a publicly traded affiliate, the common
units of which are listed on the NYSE under the ticker symbol
“TPP.” References to “TEPPCO GP” refer to Texas Eastern Products
Pipeline Company, LLC, which is the general partner of TEPPCO and is wholly
owned by Enterprise GP Holdings.
References
to “Energy Transfer Equity” mean the business and operations of Energy Transfer
Equity, L.P. and its consolidated subsidiaries. References to “LE GP”
mean LE GP, LLC, which is the general partner of Energy Transfer
Equity. On May 7, 2007, Enterprise GP Holdings acquired
non-controlling interests in both LE GP and Energy Transfer
Equity. Enterprise GP Holdings accounts for its investments in LE GP
and Energy Transfer Equity using the equity method of accounting.
References
to “Employee Partnerships” mean EPE Unit L.P. (“EPE Unit I”), EPE Unit II, L.P.
(“EPE Unit II”), EPE Unit III, L.P. (“EPE Unit III”), Enterprise Unit L.P.
(“Enterprise Unit”) and EPCO Unit L.P. (“EPCO Unit”), collectively, all of
which are private company affiliates of EPCO.
On
February 5, 2007, a consolidated subsidiary of ours, Duncan Energy Partners L.P.
(“Duncan Energy Partners”), completed an initial public offering of its common
units (see Note 17). Duncan Energy Partners owns equity interests in
certain of our midstream energy businesses. References to “DEP GP”
mean DEP Holdings, LLC, which is the general partner of Duncan Energy
Partners and is wholly owned by EPO.
On
December 8, 2008, Duncan Energy Partners entered into a Purchase and Sale
Agreement (the “DEP II Purchase Agreement”) with EPO and Enterprise GTM Holdings
L.P. (“Enterprise GTM,” a wholly owned subsidiary of EPO). Pursuant
to the DEP II Purchase Agreement, DEP Operating Partnership L.P. (“DEP OLP”)
acquired 100.0% of the membership interests in Enterprise III, LLC (“Enterprise
III”) from Enterprise GTM, thereby acquiring a 66.0% general partner interest in
Enterprise GC, L.P. (“Enterprise GC”), a 51.0% general partner interest in
Enterprise Intrastate L.P. (“Enterprise Intrastate”) and a 51.0% membership
interest in Enterprise Texas Pipeline LLC (“Enterprise
Texas”). Collectively, we refer to Enterprise GC, Enterprise
Intrastate and Enterprise Texas as the “DEP II Midstream
Businesses.” EPO was
the
sponsor of this second dropdown transaction. Enterprise GTM retained
the remaining general partner and member interests in the DEP II Midstream
Businesses (see Note 17).
For
financial reporting purposes, we consolidate the financial statements of Duncan
Energy Partners with those of our own and reflect its operations in our business
segments. We control Duncan Energy Partners through our ownership of
its general partner. Also, due to common control of the entities by
Dan L. Duncan, the initial consolidated balance sheet of Duncan Energy Partners
reflects our historical carrying basis in each of the subsidiaries contributed
to Duncan Energy Partners. Public ownership of Duncan Energy
Partners’ net assets and earnings are presented as a component of minority
interest in our consolidated financial statements. The borrowings of
Duncan Energy Partners are presented as part of our consolidated debt; however,
neither Enterprise Products Partners L.P. nor EPO have any obligation for the
payment of interest or repayment of borrowings incurred by Duncan Energy
Partners.
Allowance
for Doubtful Accounts
Our
allowance for doubtful accounts is determined based on specific identification
and estimates of future uncollectible accounts. Our procedure for
determining the allowance for doubtful accounts is based on (i) historical
experience with customers, (ii) the perceived financial stability of customers
based on our research and (iii) the levels of credit we grant to
customers. In addition, we may increase the allowance account in
response to the specific identification of customers involved in bankruptcy
proceedings and similar financial difficulties. On a routine basis,
we review estimates associated with the allowance for doubtful accounts to
ensure that we have recorded sufficient reserves to cover potential
losses. Our allowance also includes estimates for uncollectible
natural gas imbalances based on specific identification of
accounts.
The
following table presents the activity of our allowance for doubtful accounts for
the periods indicated:
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Balance
at beginning of period
|
|
$ |
21,659 |
|
|
$ |
23,406 |
|
|
$ |
37,329 |
|
|
Charges
to expense
|
|
|
1,098 |
|
|
|
2,614 |
|
|
|
473 |
|
|
Deductions
|
|
|
(7,634 |
) |
|
|
(4,361 |
) |
|
|
(14,396 |
) |
|
Balance
at end of period
|
|
$ |
15,123 |
|
|
$ |
21,659 |
|
|
$ |
23,406 |
|
See
“Credit Risk Due to Industry Concentrations” in Note 21 for more
information.
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. The indirect method derives net cash flows provided by
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 similar transactions, (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, (iii)
other non-cash amounts such as depreciation, amortization, changes in the fair
market value of financial instruments and equity in earnings in unconsolidated
affiliates and (iv) the effects of all items classified as investing or
financing cash flows, such as proceeds from asset sales and related transactions
or extinguishment of debt.
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 also consolidate other entities and ventures in
which we possess a controlling financial interest as well as partnership
interests where we are the sole general partner of the
partnership. We evaluate our financial interests in business
enterprises to determine if they represent variable interest entities where we
are the primary beneficiary. If such criteria are met, we consolidate
the financial statements of such businesses with those of our own.
If the
entity is organized as a limited partnership or limited liability company and
maintains separate ownership accounts, we account for our investment using the
equity method if our ownership interest is between 3.0% and 50.0% and we
exercise significant influence over the entity’s operating and financial
policies. For all other types of investments, we apply the equity
method of accounting if our ownership interest is between 20.0% and 50.0% and we
exercise significant influence over the entity’s operating and financial
policies. In consolidation we eliminate our proportionate share of
profits and losses from transactions with equity method unconsolidated
affiliates to the extent such amounts are material and remain on our
Consolidated Balance Sheets (or those of our equity method investments) in
inventory or similar accounts.
If our ownership interest in an entity
does not provide us with either control or significant influence we account for
the investment using the cost method. We currently do not have any
investments accounted for 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 us 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 management and legal counsel evaluate 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.
Current
Assets and Current Liabilities
We
present, as individual captions in our Consolidated Balance Sheets, all
components of current assets and current liabilities that exceed 5.0% of total
current assets and liabilities, respectively.
Deferred
Revenues
Amounts
billed in advance of the period in which the service is rendered or product
delivered are recorded as deferred revenue. At December 31, 2008 and
2007, deferred revenues totaled $107.8 million and $74.4 million, respectively,
and were recorded as a component of other current and long-term liabilities, as
appropriate, on our Consolidated Balance Sheets. See Note 4 for
information regarding our revenue recognition policies.
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 19 for additional
information regarding our earnings per unit.
Employee
Benefit Plans
In 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.
Statement
of Financial Accounting Standards (“SFAS”) 158, Employers’ Accounting for
Defined Benefit Pension and Other Postretirement Plans, an amendment of
SFAS 87, 88, 106, and 132(R), requires businesses to record the
over-funded or under-funded status of defined benefit pension and other
postretirement plans as an asset or liability at a measurement date and to
recognize annual changes in the funded status of each plan through other
comprehensive income (loss). At December 31, 2006, Dixie adopted the
provisions of SFAS 158. See Note 6 for additional information
regarding Dixie’s employee benefit plans.
Environmental
Costs
Environmental
costs for remediation are accrued based on estimates of known remediation
requirements. Such accruals are based on management’s best estimate of the
ultimate cost to remediate a site and are adjusted as further information and
circumstances develop. Those estimates may change substantially depending
on information about the nature and extent of contamination, appropriate
remediation technologies and regulatory approvals. Expenditures to
mitigate or prevent future environmental contamination are capitalized.
Ongoing environmental compliance costs are charged to expense as incurred.
In accruing for environmental remediation liabilities, costs of future
expenditures for environmental remediation are not discounted to their present
value, unless the amount and timing of the expenditures are fixed or reliably
determinable. At December 31, 2008, none of our estimated environmental
remediation liabilities are discounted to present value since the ultimate
amount and timing of cash payments for such liabilities are not readily
determinable.
Environmental
costs and related accruals were not significant prior to the GulfTerra
Merger. As a result of the merger, we assumed an environmental liability
for remediation costs associated with mercury gas meters. The balance of
this environmental liability was $6.3 million and $17.2 million at December 31,
2008 and 2007, respectively. At December 31, 2008 and 2007, total reserves
for environmental liabilities, including those related to the mercury gas
meters, were $15.4 million and $26.5 million, respectively. At December
31, 2008 and 2007, $2.8 million and $6.3 million, respectively, of these amounts
are classified as current liabilities.
In
February 2007, we reserved $6.5 million in cash we received from a third party
to fund anticipated environmental remediation costs. These expected
costs are associated with assets acquired in connection with the GulfTerra
Merger. Previously, the third party had been obligated to indemnify
us for such costs. As a result of the settlement, this indemnification
arrangement was terminated.
The
following table presents the activity of our environmental reserves for the
periods indicated:
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Balance
at beginning of period
|
|
$ |
26,459 |
|
|
$ |
24,178 |
|
|
$ |
22,090 |
|
|
Charges
to expense
|
|
|
905 |
|
|
|
375 |
|
|
|
1,105 |
|
|
Acquisition-related
additions and other
|
|
|
-- |
|
|
|
6,499 |
|
|
|
8,811 |
|
|
Deductions
|
|
|
(12,002 |
) |
|
|
(4,593 |
) |
|
|
(7,828 |
) |
|
Balance
at end of period
|
|
$ |
15,362 |
|
|
$ |
26,459 |
|
|
$ |
24,178 |
|
Equity
Awards
See Note
5 for information regarding our accounting for equity awards.
Estimates
Preparing
our financial statements in conformity with generally accepted accounting
principles in the United States (“GAAP”) requires management to make
estimates and assumptions that affect amounts presented in the financial
statements (i.e. assets, liabilities, revenue and expenses) and
disclosures about contingent assets and liabilities. Our actual
results could differ from these estimates. On an ongoing basis,
management reviews its estimates based on currently available
information. Changes in facts and circumstances may result in revised
estimates.
We
revised the remaining useful lives of certain assets, most notably the assets
that constitute our Texas Intrastate System, effective January 1,
2008. This revision adjusted the remaining useful life of such assets
to incorporate recent data showing that proved natural gas reserves supporting
throughput and processing volumes for these assets have changed since our
original determination made in September 2004. These revisions will
prospectively reduce our depreciation expense on assets having carrying values
totaling $2.72 billion at January 1, 2008. For additional information
regarding this change in estimate, see Note 10.
Exchange
Contracts
Exchanges
are contractual agreements for the movements of NGLs and certain petrochemical
products between parties to satisfy timing and logistical needs of the
parties. Net exchange volumes borrowed from us under such agreements
are valued at market-based prices and included in accounts receivable, and net
exchange volumes loaned to us under such agreements are valued at market-based
prices and accrued as a liability in accrued product payables.
Receivables and payables arising from
exchange transactions are settled with movements of products rather than with
cash. When payment or receipt of monetary consideration is required
for product differentials and service costs, such items are recognized in our
consolidated financial statements on a net basis.
Exit
and Disposal Costs
Exit and
disposal costs are charges associated with an exit activity not associated with
a 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.
Financial
Instruments
We use
financial instruments such as swaps, forwards and other contracts to manage
price risks associated with inventories, firm commitments, interest rates,
foreign currency and certain anticipated transactions. We recognize
these transactions as assets or liabilities on our Consolidated Balance Sheets
based on the instrument’s 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.
Changes
in fair value of financial instrument contracts are recognized in earnings in
the current period (i.e., using mark-to-market accounting) unless specific hedge
accounting criteria are met. If the financial instrument meets the
criteria of a fair value hedge, gains and losses incurred on the instrument will
be recorded in earnings to offset corresponding losses and gains on the hedged
item. If the financial instrument meets the criteria of a cash flow
hedge, gains and losses incurred on the instrument are recorded in accumulated
other comprehensive income (loss), which is generally referred to as
“AOCI.” Gains and losses on cash flow hedges are reclassified from
accumulated other comprehensive income (loss) to earnings when the forecasted
transaction occurs or, as appropriate, over the economic life of the hedged
item. A contract designated as a hedge of an anticipated transaction
that is no longer likely to occur is immediately recognized in
earnings.
To qualify for hedge accounting, the
item to be hedged must expose us to risk and the related 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 its inception
and thereafter on a quarterly basis. Any hedge ineffectiveness is
immediately recognized in earnings. See Note 8 for additional
information regarding our financial instruments.
Foreign
Currency Translation
We own a
NGL marketing business located in Canada. The financial statements of
this foreign subsidiary are translated into U.S. dollars from the Canadian
dollar, which is the subsidiary’s functional currency, using the current rate
method. Its assets and liabilities are translated at the rate of
exchange in effect at the balance sheet date, while revenue and expense items
are translated at average rates of exchange during the reporting
period. Exchange gains and losses arising from foreign currency
translation adjustments are reflected as separate components of accumulated
other comprehensive income (loss) in the accompanying Consolidated Balance
Sheets. Our net cash flows from this Canadian subsidiary may be
adversely affected by changes in foreign currency exchange rates. See
Note 7 for information regarding our hedging of currency risk.
Impairment
Testing for Goodwill
Our
goodwill amounts are assessed for impairment (i) on a routine annual basis or
(ii) when impairment indicators are present. If such indicators occur
(e.g., the loss of a significant customer, economic obsolescence of plant
assets, etc.), the estimated fair value of the reporting unit to which the
goodwill is assigned is determined and compared to its book value. If
the fair value of the reporting unit exceeds its book value including associated
goodwill amounts, the goodwill is considered to be unimpaired and no impairment
charge is required. If the fair value of the reporting unit is less
than its book value including associated goodwill amounts, a charge to earnings
is recorded to reduce the carrying value of the goodwill to its implied fair
value. We have not recognized any impairment losses related to
goodwill for any of the periods presented. See Note 13 for additional
information regarding 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 when 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 asset
carrying value exceeds the sum of its undiscounted cash flows, a non-cash asset
impairment charge equal to the excess of the asset’s carrying value over its
estimated fair value is recorded. Fair value is defined as the amount
at which an asset or liability could be bought or settled in an arm’s-length
transaction. We measure fair value using market price indicators or,
in the absence of such data, appropriate valuation techniques.
We
recorded a non-cash asset impairment charge of $0.1 million in 2006, which
is reflected as a component of operating costs and expenses in our 2006
Statement of Consolidated Operations. No asset impairment charges
were recorded in 2008 and 2007.
Impairment
Testing for Unconsolidated Affiliates
We
evaluate our equity method investments for impairment when events or changes in
circumstances indicate that there is a loss in value of the investment
attributable to an other than temporary decline. Examples of such
events or changes in circumstances include continuing operating losses of the
entity and/or long-term negative changes in the entity’s
industry. In the event we determine that the loss in value of an
investment is other than a temporary decline, we record a charge to earnings to
adjust the carrying value of the investment to its estimated fair
value.
During
2007, we evaluated our equity method investment in Nemo Gathering Company, LLC
(“Nemo”) for impairment. As a result of this evaluation, we recorded
a $7.0 million non-cash impairment charge that is a component of “Equity in
earnings of unconsolidated affiliates” on our Consolidated Statement of
Operations for the year ended December 31, 2007. Similarly, during
2006, we evaluated our investment in Neptune Pipeline Company, L.L.C.
(“Neptune”) for impairment. As a result of this evaluation, we
recorded a $7.4 million non-cash impairment charge that is a component of
“Equity in earnings of unconsolidated affiliates” on our Consolidated
Statement of Operations for the year ended December 31, 2006. We had
no such impairment charges during the year ended December 31, 2008. See
Note 11 for additional information regarding our equity method
investments.
Income
Taxes
Provision
for income taxes is primarily applicable to our state tax obligations under the
Revised Texas Franchise Tax and certain federal and state tax obligations of
Seminole Pipeline Company (“Seminole”) and Dixie, both of which are consolidated
subsidiaries of ours. Deferred income tax assets and liabilities are
recognized for temporary differences between the assets and liabilities of our
tax paying entities for financial reporting and tax purposes.
In
general, legal entities that conduct business in Texas are subject to the
Revised Texas Franchise Tax. In May 2006, the State of Texas expanded
its pre-existing franchise tax, which applied to corporations and limited
liability companies, to include limited partnerships and limited liability
partnerships. As a result of the change in tax law, our tax status in the
State of Texas changed from non-taxable to taxable.
Since we
are structured as a pass-through entity, we are not subject to federal income
taxes. As a result, our partners are individually responsible for
paying federal income taxes on their share of our taxable
income. Since we do not have access to information regarding each
partner’s tax basis, we cannot readily determine the total difference in the
basis of our net assets for financial and tax reporting purposes.
In
accordance with Financial Accounting Standards Board Interpretation 48,
Accounting for Uncertainty in Income Taxes, we must recognize the tax effects of
any uncertain tax positions we may adopt, if the position taken by us is more
likely than not sustainable. If a tax position meets such criteria,
the tax effect to be recognized by us would be the largest amount of benefit
with more than a 50.0% chance of being realized upon settlement. This
guidance was effective January 1, 2007, and our adoption of this
guidance
had no material impact on our financial position, results of operations or cash
flows. See Note 18 for additional information regarding our income
taxes.
Inventories
Inventories
primarily consist of NGLs, certain petrochemical products and natural gas
volumes that 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 purchase from third parties or 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 (including
freight-in charges that 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 additional information regarding our
inventories.
Minority
Interest
As
presented in our Consolidated Balance Sheets, minority interest represents
third-party and affiliate ownership interests in the net assets of our
consolidated subsidiaries. For financial reporting purposes, the
assets and liabilities of our controlled subsidiaries, including Duncan Energy
Partners, are consolidated with those of our own, with any third-party or
affiliate ownership in such amounts presented as minority interest.
Minority
interest, as reflected on our December 31, 2008 and 2007 balance sheets,
consists of $281.1 million and $288.6 million, respectively, attributable to
third party owners of Duncan Energy Partners and the remainder to our other
consolidated affiliates.
Minority
interest expense for the year ended December 31, 2008 and 2007 includes $17.3
million and $13.9 million, respectively, attributable to third party owners of
Duncan Energy Partners. The remaining minority interest expense
amounts for 2008 and 2007 are attributable to our other consolidated
affiliates.
Contributions
from minority interests for the year ended December 31, 2007 include $290.5
million received from third parties in connection with the initial public
offering of Duncan Energy Partners in February 2007.
Natural
Gas Imbalances
In the
natural gas pipeline transportation business, imbalances frequently result from
differences in natural gas volumes received from and delivered to our customers.
Such differences occur when a customer delivers more or less gas into our
pipelines than is physically redelivered back to them during a particular time
period. We have various fee-based agreements with customers to
transport their natural gas through our pipelines. Our customers
retain ownership of their natural gas shipped through our
pipelines. As such, our pipeline transportation activities are not
intended to create physical volume differences that would result in significant
accounting or economic events for either our customers or us during the course
of the arrangement.
We settle
pipeline gas imbalances through either (i) physical delivery of in-kind gas or
(ii) in cash. These settlements follow contractual guidelines or common industry
practices. As imbalances occur, they may be settled (i) on a monthly
basis, (ii) at the end of the agreement or (iii) in accordance with industry
practice, including negotiated settlements. Certain of our natural
gas pipelines have a regulated tariff rate mechanism requiring customer
imbalance settlements each month at current market prices.
However,
the vast majority of our settlements are through in-kind arrangements whereby
incremental volumes are delivered to a customer (in the case of an imbalance
payable) or received from a customer (in the case of an imbalance
receivable). Such in-kind deliveries are on-going and take place over
several periods. In some cases, settlements of imbalances built up over a period
of time are ultimately
cashed
out and are generally negotiated at values which approximate average market
prices over a period of time. For those gas imbalances that are
ultimately settled over future periods, we estimate the value of such current
assets and liabilities using average market prices, which is representative of
the estimated value of the imbalances upon final settlement. Changes
in natural gas prices may impact our estimates.
At
December 31, 2008 and 2007, our natural gas imbalance receivables, net of
allowance for doubtful accounts, were $48.4 million and $60.9 million,
respectively, and are reflected as a component of “Accounts and notes receivable
– trade” on our Consolidated Balance Sheets. At December 31, 2008 and
2007, our imbalance payables were $40.7 million and $38.3 million, respectively,
and are reflected as a component of “Accrued product payables” on our
Consolidated Balance Sheets.
Property,
Plant and Equipment
Property,
plant and equipment is recorded at cost. Expenditures for additions,
improvements and other enhancements to property, plant and equipment are
capitalized and minor replacements, maintenance, and repairs that do not extend
asset life or add value are charged to expense as incurred. When
property, plant and equipment assets are retired or otherwise disposed of, the
related cost and accumulated depreciation is removed from the accounts and any
resulting gain or loss is included in the results of operations for the
respective period.
In
general, depreciation is the systematic and rational allocation of an asset’s
cost, less its residual value (if any), to the periods it benefits. The
majority of our property, plant and equipment is depreciated using the
straight-line method, which results in depreciation expense being incurred
evenly over the life of 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. Under our depreciation policy for midstream
energy assets, the remaining economic lives of such assets are limited to the
estimated life of the natural resource basins (based on proved reserves at the
time of the analysis) from which such assets derive their throughput or
processing volumes. Our forecast of the remaining life for the applicable
resource basins is based on several factors, including information published by
the U.S. Energy Information Administration. Where appropriate, we use
other depreciation methods (generally accelerated) for tax
purposes.
Leasehold improvements are recorded as
a component of property, plant and equipment. The cost of leasehold
improvements is charged to earnings using the straight-line method over the
shorter of the remaining lease term or the estimated useful lives of the
improvements. We consider renewal terms that are deemed reasonably assured
when estimating remaining lease terms.
Our assumptions regarding the useful
economic lives and residual values of our assets may change in response to new
facts and circumstances, which would change our depreciation amounts
prospectively. Examples of such circumstances include, but are not limited
to, the following: (i) changes in laws and regulations that limit the estimated
economic life of an asset; (ii) changes in technology that render an asset
obsolete; (iii) changes in expected salvage values; or (iv) significant
changes in the forecast life of proved reserves of applicable resource basins,
if any. See Note 10 for additional information regarding our
property, plant and equipment, including a change in depreciation expense
beginning January 1, 2008 resulting from a change in the estimated useful
life of certain assets.
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; however, the cost of annual planned
major maintenance projects are deferred and recognized ratably over the
remaining portion of the calendar year in which such projects
occur.
Asset retirement obligations (“AROs”)
are legal obligations associated with the retirement of tangible long-lived
assets that result from their acquisition, construction, development and/or
normal operation. When an ARO is incurred, we record a liability for
the ARO and capitalize an equal amount as
an
increase in the carrying value of the related long-lived asset. Over
time, the liability is accreted to its present value (accretion expense) and the
capitalized amount is depreciated over the remaining useful life of the related
long-lived asset. We will incur a gain or loss to the extent that our
ARO liabilities are not settled at their recorded amounts.
Restricted
Cash
Restricted
cash represents amounts held in connection with our commodity financial
instruments portfolio and New York Mercantile Exchange (“NYMEX”) physical
natural gas purchases. Additional cash may be restricted to maintain
our positions as commodity prices fluctuate or deposit requirements
change. At December 31, 2007, restricted cash also included amounts
held by a third party trustee responsible for disbursing proceeds from our Petal
GO Zone bond offering. During 2008, virtually all proceeds from the
Petal GO Zone bonds were released by the trustee to fund construction costs
associated with the expansion of our Petal, Mississippi storage
facility. The following table presents the components of our
restricted cash balances at the periods indicated:
|
|
|
At
December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Amounts
held in brokerage accounts related to
|
|
|
|
|
|
|
|
commodity
hedging activities and physical natural gas purchases
|
|
$ |
203,789 |
|
|
$ |
53,144 |
|
|
Proceeds
from Petal GO Zone bonds reserved for construction costs
|
|
|
1 |
|
|
|
17,871 |
|
|
Total
restricted cash
|
|
$ |
203,790 |
|
|
$ |
71,015 |
|
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 considered start-up costs. Organization
costs include legal fees, promotional costs and similar charges incurred in
connection with the formation of a business.
The accounting standard setting bodies
have recently issued the following accounting guidance that will affect our
future financial statements: SFAS 141(R), Business
Combinations; FASB Staff Position (“FSP”) SFAS 142-3,
Determination of the Useful Life of Intangible Assets; SFAS 157, Fair
Value Measurements; SFAS 160, Noncontrolling Interests in
Consolidated Financial Statements – An amendment of ARB 51; SFAS 161,
Disclosures about Derivative Instruments and Hedging Activities – An Amendment
of SFAS 133; Emerging Issues Task Force (“EITF”) 08-6, Equity Method
Investment Accounting Considerations; and EITF 07-4, Application of the Two
Class Method Under SFAS 128, Earnings Per Share, to Master Limited Partnerships
(“MLPs”).
SFAS
141(R), Business Combinations. SFAS 141(R) replaces SFAS
141, Business Combinations and was effective January 1, 2009. SFAS
141(R) retains the fundamental requirements of SFAS 141 in that the acquisition
method of accounting (previously termed the “purchase method”) be used for all
business combinations and for the “acquirer” to be identified in each business
combination. SFAS 141(R) defines the acquirer as the entity that
obtains control of one or more businesses in a business combination and
establishes the acquisition date as the date that the acquirer achieves
control. This new guidance also retains guidance in SFAS 141 for
identifying and recognizing intangible assets separately from
goodwill. SFAS 141(R) will have an impact on the way in which
we evaluate acquisitions.
The
objective of SFAS 141(R) is to improve the relevance, representational
faithfulness, and comparability of the information a reporting entity provides
in its financial reports about business combinations and their
effects. To accomplish this, SFAS 141(R) establishes principles and
requirements for how the acquirer:
|
§
|
Recognizes
and measures in its financial statements the identifiable assets acquired,
the liabilities assumed, and any noncontrolling interests in the
acquiree.
|
|
§
|
Recognizes
and measures any goodwill acquired in the business combination or a gain
resulting from a bargain purchase. SFAS 141(R) defines a
bargain purchase as a business combination in which the total
acquisition-date fair value of the identifiable net assets acquired
exceeds the fair value of the consideration transferred plus any
noncontrolling interest in the acquiree, and requires the acquirer to
recognize that excess in net income as a gain attributable to the
acquirer.
|
|
§
|
Determines
what information to disclose to enable users of the financial statements
to evaluate the nature and financial effects of the business
combination.
|
SFAS
141(R) also requires that direct costs of an acquisition (e.g. finder’s fees,
outside consultants, etc.) be expensed as incurred and not capitalized as part
of the purchase price.
FSP
FAS 142-3, Determination of the Useful Life of Intangible
Assets.
FSP 142-3 revised the factors that should be considered in developing
renewal or extension assumptions used in determining the useful life of
recognized intangible assets under SFAS 142, Goodwill and Other Intangible
Assets. These revisions are intended to improve consistency between
the useful life of a recognized intangible asset under SFAS 142 and the
period of expected cash flows used to measure the fair value of such assets
under SFAS 141(R) and other accounting guidance. The measurement and
disclosure requirements of this new guidance will be applied to intangible
assets acquired after January 1, 2009. Our adoption of this
guidance is not expected to have a material impact on our consolidated financial
statements.
SFAS
157,
Fair Value Measurements. SFAS 157 defines fair
value, establishes a framework for measuring fair value and expands disclosures
about fair value measurements. Although certain provisions of SFAS 157
were effective January 1, 2008, the remaining guidance of this new standard
applicable to nonfinancial assets and liabilities was effective January 1,
2009. See Note 7 for information regarding fair value-related
disclosures required for 2008 in connection with SFAS 157.
SFAS 157
applies to fair-value measurements that are already required (or permitted) by
other accounting standards and is expected to increase the consistency of those
measurements. SFAS 157 emphasizes that fair value is a market-based
measurement that should be determined based on the assumptions that market
participants would use in pricing an asset or liability. Companies are required
to disclose the extent to which fair value is used to measure assets and
liabilities, the inputs used to develop such measurements, and the effect of
certain of the measurements on earnings (or changes in net assets) during a
period. Our adoption of this guidance is not expected to have a material
impact on our consolidated financial statements. SFAS 157 will impact
the valuation of assets and liabilities (and related disclosures) in connection
with future business combinations and impairment testing.
SFAS
160, Noncontrolling Interests in Consolidated Financial Statements – an
amendment of ARB 51. SFAS 160
established accounting and reporting standards for noncontrolling interests,
which have been referred to as minority interests in prior accounting
literature. SFAS 160 was effective January 1, 2009. A
noncontrolling interest is that portion of equity in a consolidated subsidiary
not attributable, directly or indirectly, to a reporting entity. This
new standard requires, among other things, that (i) ownership interests of
noncontrolling interests be presented as a component of equity on the balance
sheet (i.e., elimination of the “mezzanine” presentation); (ii) elimination of
minority interest expense as a line item on the statement of income and, as a
result, that net income be allocated between the reporting entity and
noncontrolling interests on the face of the statement of income; and (iii)
enhanced disclosures regarding noncontrolling interests.
SFAS 160
will affect the presentation of minority interest on our financial statements
beginning with the first quarter of 2009. Minority interest in the
net assets of our consolidated subsidiaries will be presented as a component of
partners’ equity on our Consolidated Balance Sheets. With
respect to our Statements of Consolidated Operations, net income and
comprehensive income will be allocated between minority interests and us,
as applicable.
SFAS
161, Disclosures about Derivative Instruments and Hedging Activities - An
Amendment of SFAS
133. SFAS 161 revised
the disclosure requirements for financial instruments and related hedging
activities to provide users of financial statements with an enhanced
understanding of (i) why and how an entity uses financial instruments, (ii) how
an entity accounts for financial instruments and related hedged items under SFAS
133, Accounting for Derivative Instruments and Hedging Activities (including
related interpretations), and (iii) how financial instruments and related hedged
items affect an entity’s financial position, financial performance, and cash
flows.
SFAS 161
requires qualitative disclosures about objectives and strategies for using
financial instruments, quantitative disclosures about fair value amounts of and
gains and losses on financial instruments, and disclosures about credit
risk-related contingent features in financial instrument
agreements. SFAS 161 was effective January 1, 2009 and we will apply
its requirements beginning with the first quarter of 2009.
EITF
08-6, Equity Method Investment Accounting Considerations. EITF
08-6 clarifies the accounting for certain transactions and impairment
considerations involving equity method investments under SFAS 141(R) and SFAS
160. EITF 08-6 generally requires that (i) transaction costs should
be included in the initial carrying value of an equity method investment; (ii)
an equity method investor shall not test separately an investee’s underlying
assets for impairment, rather such testing should be performed in accordance
with Opinion 18 (i.e., on the equity method investment itself); (iii) an equity
method investor shall account for a share issuance by an investee as if the
investor had sold a proportionate share of its investment (any gain or loss to
the investor resulting from the investee’s share issuance shall be recognized in
earnings); and (iv) a gain or loss should not be recognized when
changing the method of accounting for an investment from the equity method to
the cost method. EITF 08-6 was effective January 1, 2009.
EITF
07-4, Application
of the Two Class Method Under SFAS 128,
Earnings Per Share, to MLPs. EITF 07-4
prescribes the manner in which a MLP should allocate and present earnings per
unit using the two-class method set forth in SFAS 128, Earnings Per Share.
Under the two-class method, current period earnings are allocated to the general
partner (including earnings attributable to any embedded incentive distribution
rights (“IDRs”)) and limited partners according to the distribution formula for
available cash set forth in the MLP’s partnership agreement. EITF
07-4 was effective for us on January 1, 2009. Our adoption of EITF
07-4 did not have a material impact on our earnings per unit computations and
disclosures.
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
buyer’s price is fixed or determinable and (iv) collectability is reasonably
assured. The following information provides a general description our
underlying revenue recognition policies by business segment:
NGL
Pipelines & Services
This
aspect of our business generates revenues primarily from the provision of
natural gas processing, NGL pipeline transportation, product storage and NGL
fractionation services and the sale of NGLs. 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
(i.e. 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 producer’s natural gas stream and recognize revenue when
the extracted NGLs are delivered and sold to customers under 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 sale
of the mixed NGLs we extract on the producer’s behalf. If a cash fee
for natural gas processing services is stipulated by the contract, we record
revenue when the natural gas has been processed and delivered to the
producer.
Our NGL
marketing activities generate revenues from the sale of NGLs obtained from
either our natural gas processing activities or purchased from third parties on
the open market. 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 and tariffs, revenue is recognized when
volumes have been delivered to customers. Revenue from these
contracts and tariffs is generally based upon a fixed fee per gallon of liquids
transported multiplied by the volume delivered. Transportation fees
charged under these arrangements are either contractual or regulated by
governmental agencies such as the Federal Energy Regulatory Commission
(“FERC”).
We
collect storage revenues under our NGL and related product storage contracts
based on the number of days a customer has volumes in storage multiplied by a
storage rate (as defined in each contract). Under these contracts,
revenue is recognized ratably over the length of the storage
period. With respect to capacity reservation agreements, we collect a
fee for reserving storage capacity for customers in our underground storage
wells. Under these agreements, revenue is recognized ratably over the
specified reservation period. Excess storage fees are collected when
customers exceed their reservation amounts and are recognized in the period of
occurrence.
Revenues
from product terminalling activities (applicable to our import and export
operations) are recorded in the period such services are
provided. Customers are typically billed a fee per unit of volume
loaded or unloaded. With respect to export operations, revenues may
also include demand payments charged to customers who reserve the use of our
export facilities and later fail to use them. Demand fee revenues are
recognized when the customer fails to utilize the specified export facility as
required by contract.
We enter
into fee-based arrangements and percent-of-liquids contracts for the NGL
fractionation services we provide to customers. Under such fee-based
arrangements, revenue is recognized in the period services are
provided. Such 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 (e.g. natural gas fuel
costs). Certain of our NGL fractionation facilities generate revenues
using percent-of-liquids contracts. Such contracts allow us to retain
a contractually determined percentage of the customer’s fractionated NGL
products as payment for services rendered. Revenue is recognized from
such arrangements when we sell and deliver the retained NGLs to
customers.
Onshore Natural Gas Pipelines &
Services
This
aspect of our business generates revenues primarily from the provision of
natural gas pipeline transportation and gathering services; natural gas storage
services; and from the sale of natural gas. Certain of our onshore
natural gas pipelines generate revenues from transportation and gathering
agreements as customers are billed a fee per unit of volume multiplied by the
volume delivered or gathered. Fees charged under these arrangements
are either contractual or regulated by governmental agencies such as the
FERC. Revenues associated with these fee-based contracts are
recognized when volumes have been delivered.
Revenues
from natural gas storage contracts typically have two components: (i) a monthly
demand payment, which is associated with storage capacity reservations, and (ii)
a storage fee per unit of volume
held at
each location. Revenues from demand payments are recognized during
the period the customer reserves capacity. Revenues from storage fees
are recognized in the period the services are provided.
Our
natural gas marketing activities generate revenues from the sale of natural gas
purchased from third parties on the open market. Revenues from these
sales contracts are recognized when the natural gas is 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.
Offshore
Pipelines & Services
This
aspect of our business generates revenues from the provision of offshore natural
gas and crude oil pipeline transportation services and related offshore platform
operations. Our offshore natural gas pipelines generate revenues
through fee-based contracts or tariffs where revenues are equal to the product
of a fee per unit of volume (typically in million British thermal units)
multiplied by the volume of natural gas transported. Revenues
associated with these fee-based contracts and tariffs are recognized when
natural gas volumes have been delivered.
The
majority of revenues from our offshore crude oil pipelines are generated based
upon a transportation fee per unit of volume (typically in barrels) multiplied
by the volume delivered to the customer. A substantial portion of the
revenues generated by our offshore crude oil pipeline systems are attributable
to long-term transportation agreements with producers. The revenues
we earn for our services are dependent on the volume of crude oil to be
delivered and the level of fees charged to customers.
Revenues
from offshore platform services generally consist of demand payments and
commodity charges. Revenues from platform services are recognized in
the period the services are provided. Demand fees represent charges
to customers served by our offshore platforms regardless of the volume the
customer delivers to the platform. Revenues from commodity charges
are based on a fixed-fee per unit of volume delivered to the platform (typically
per million cubic feet of natural gas or per barrel of crude oil) multiplied by
the total volume of each product delivered. Contracts for platform
services often include both demand payments and commodity charges, but demand
payments generally expire after a contractually fixed period of time and in some
instances may be subject to cancellation by customers. Our
Independence Hub and Marco Polo offshore platforms earn a significant amount of
demand revenues. The Independence Hub platform will earn $54.6
million of demand revenues annually through March 2012. The Marco
Polo platform will earn $2.1 million of demand revenues monthly through March
2009.
Petrochemical
Services
This
aspect of our business generates revenues from the provision of isomerization
and propylene fractionation services and the sale of certain petrochemical
products. Our isomerization and propylene fractionation operations generate
revenues through fee-based arrangements, which 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. Revenues resulting from such agreements are recognized in
the period the services are provided.
Our
petrochemical marketing activities generate revenues from the sale of propylene
and other petrochemicals obtained from either its processing activities or
purchased from third parties on the open market. Revenues from these
sales contracts are recognized when the petrochemicals 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.
We
account for equity awards in accordance with SFAS 123(R), Share-Based
Payment. SFAS 123(R) requires us to recognize compensation expense
related to equity awards based on the fair value of
the award
at grant date. The fair value of restricted unit awards is based on
the market price of the underlying common units on the date of grant. The fair
value of other equity awards is estimated using the
Black-Scholes option pricing model. The fair value of an
equity-classified award (such as a restricted unit award) is amortized to
earnings on a straight-line basis over the requisite service or vesting
period. Compensation expense for liability-classified awards (such as unit
appreciation rights (“UARs”)) is recognized over the requisite service or
vesting period of an award based on the fair value of the award remeasured at
each reporting period. Liability-classified awards are settled in
cash upon vesting.
As used
in the context of the EPCO plans, the term “restricted unit” represents a
time-vested unit under SFAS 123(R). Such awards are non-vested until
the required service period expires.
Upon our
adoption of SFAS 123(R), we recognized, as a benefit, a cumulative effect of a
change in accounting principle of $1.5 million based on the SFAS 123(R)
requirement to recognize compensation expense based upon the grant date fair
value of an equity award and the application of an estimated forfeiture rate to
unvested awards. In addition, previously recognized deferred
compensation expense of $14.6 million related to our restricted common units was
reversed on January 1, 2006.
Prior to
our adoption of SFAS 123(R), we did not recognize any compensation expense
related to unit options; however, compensation expense was recognized in
connection with awards granted by EPE Unit I and the issuance of restricted
units. The effects of applying SFAS 123(R) during the year ended
December 31, 2006 did not have a material effect on our net income or basic and
diluted earnings per unit. Since we adopted SFAS 123(R) using the modified
prospective method, we have not restated the financial statements of prior
periods to reflect this new standard.
The
following table summarizes our equity compensation amounts by plan during each
of the periods indicated:
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
EPCO
1998 Long-Term Incentive Plan (“EPCO 1998 Plan”)
|
|
|
|
|
|
|
|
|
|
|
Unit
options
|
|
$ |
439 |
|
|
$ |
4,447 |
|
|
$ |
701 |
|
|
Restricted
units
|
|
|
8,816 |
|
|
|
7,721 |
|
|
|
5,019 |
|
|
Total
EPCO 1998 Plan (1)
|
|
|
9,255 |
|
|
|
12,168 |
|
|
|
5,720 |
|
|
Enterprise
Products 2008 Long-Term Incentive Plan (“EPD 2008 LTIP”)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit
options
|
|
|
87 |
|
|
|
-- |
|
|
|
-- |
|
|
Total
EPD 2008 LTIP
|
|
|
87 |
|
|
|
-- |
|
|
|
-- |
|
|
Employee
Partnerships
|
|
|
5,535 |
|
|
|
3,911 |
|
|
|
2,146 |
|
|
DEP
GP UARs
|
|
|
1 |
|
|
|
69 |
|
|
|
-- |
|
|
Total
compensation expense
|
|
$ |
14,878 |
|
|
$ |
16,148 |
|
|
$ |
7,866 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Amounts
for the year ended December 31, 2007 include $4.6 million associated with
the resignation of our general partner’s former chief executive
officer.
|
|
EPCO
1998 Plan
Unit
option
awards. Under
the EPCO 1998 Plan, non-qualified incentive options to purchase a fixed number
of our common units may be granted to key employees of EPCO who perform
management, administrative or operational functions for us. When
issued, the exercise price of each option grant is equivalent to the market
price of the underlying equity on the date of grant. During 2008, in
response to changes in the federal tax code applicable to certain types of
equity awards, we amended the terms of certain of our outstanding unit
options. In general, the expiration dates of these awards were modified
from May and August 2017 to December 2012.
In order
to fund its obligations under the EPCO 1998 Plan, EPCO may purchase common units
at fair value either in the open market or directly from us. 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.
The fair
value of each unit option is estimated on the date of grant using the
Black-Scholes option pricing model, which incorporates various assumptions
including expected life of the options, risk-free interest rates, expected
distribution yield on our common units, and expected unit price volatility of
our common units. In general, our assumption of expected life of the
options represents the period of time that the options are expected to be
outstanding based on an analysis of historical option activity. Our
selection of the risk-free interest rate is based on published yields for U.S.
government securities with comparable terms. The expected
distribution yield and unit price volatility is estimated based on several
factors, which include an analysis of our historical unit price volatility and
distribution yield over a period equal to the expected life of the
option.
The EPCO
1998 Plan provides for the issuance of up to 7,000,000 of our common
units. After giving effect to outstanding option awards at
December 31, 2008 and the issuance and forfeiture of restricted unit awards
through December 31, 2008, a total of 814,674 additional common units could be
issued under the EPCO 1998 Plan.
The
following table presents option activity under the EPCO 1998 Plan for the
periods indicated:
|
|
|
|
|
|
|
|
|
Weighted-
|
|
|
|
|
|
|
|
|
|
|
Weighted-
|
|
|
Average
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Remaining
|
|
|
Aggregate
|
|
|
|
|
Number
of
|
|
|
Strike
Price
|
|
|
Contractual
|
|
|
Intrinsic
|
|
|
|
|
Units
|
|
|
(dollars/unit)
|
|
|
Term
(in years)
|
|
|
Value
(1)
|
|
|
Outstanding
at December 31, 2005
|
|
|
2,082,000 |
|
|
$ |
22.16 |
|
|
|
|
|
|
|
|
Granted
(2)
|
|
|
590,000 |
|
|
|
24.85 |
|
|
|
|
|
|
|
|
Exercised
|
|
|
(211,000 |
) |
|
|
15.95 |
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(45,000 |
) |
|
|
24.28 |
|
|
|
|
|
|
|
|
Outstanding
at December 31, 2006
|
|
|
2,416,000 |
|
|
|
23.32 |
|
|
|
|
|
|
|
|
Granted
(3)
|
|
|
895,000 |
|
|
|
30.63 |
|
|
|
|
|
|
|
|
Exercised
|
|
|
(256,000 |
) |
|
|
19.26 |
|
|
|
|
|
|
|
|
Settled
or forfeited (4)
|
|
|
(740,000 |
) |
|
|
24.62 |
|
|
|
|
|
|
|
|
Outstanding at December 31,
2007 (5)
|
|
|
2,315,000 |
|
|
|
26.18 |
|
|
|
|
|
|
|
|
Exercised
|
|
|
(61,500 |
) |
|
|
20.38 |
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(85,000 |
) |
|
|
26.72 |
|
|
|
|
|
|
|
|
Outstanding at December 31,
2008 (6)
|
|
|
2,168,500 |
|
|
|
26.32 |
|
|
|
5.19 |
|
|
$ |
-- |
|
|
Options
exercisable at:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December
31, 2006
|
|
|
591,000 |
|
|
$ |
20.85 |
|
|
|
5.11 |
|
|
$ |
4,808 |
|
|
December
31, 2007
|
|
|
335,000 |
|
|
$ |
22.06 |
|
|
|
3.96 |
|
|
$ |
3,291 |
|
|
December
31, 2008 (6)
|
|
|
548,500 |
|
|
$ |
21.47 |
|
|
|
4.08 |
|
|
$ |
-- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Aggregate
intrinsic value reflects fully vested unit options at the date
indicated.
(2)
The
total grant date fair value of these awards was $1.2 million based on the
following assumptions: (i) weighted-average expected life of options of
seven years; (ii) weighted-average risk-free interest rate of 5.0%; (iii)
weighted-average expected distribution yield on our common units of 8.9%;
and (iv) weighted-average expected unit price volatility on our common
units of 23.5%.
(3)
The
total grant date fair value of these awards was $2.4 million based on the
following assumptions: (i) expected life of options of seven years; (ii)
weighted-average risk-free interest rate of 4.8%; (iii) weighted-average
expected distribution yield on our common units of 8.4%; and (iv)
weighted-average expected unit price volatility on our common units of
23.2%.
(4)
Includes
the settlement of 710,000 options in connection with the resignation of
our general partner’s former chief executive officer.
(5)
During
2008, we amended the terms of certain of our outstanding unit
options. In general, the expiration dates of these awards were
modified from May and August 2017 to December 2012.
(6)
We
were committed to issue 2,168,500 and 2,315,000 of our common units at
December 31, 2008 and 2007, respectively, if all outstanding options
awarded under the EPCO 1998 Plan (as of these dates) were exercised. An
additional 365,000, 480,000 and 775,000 of these options are exercisable
in 2009, 2010 and 2012, respectively.
|
|
The total
intrinsic value of option awards exercised during the years ended December 31,
2008, 2007 and 2006 were $0.6 million, $3.0 million and $2.2 million,
respectively. At December 31, 2008, there
was an
estimated $1.7 million of total unrecognized compensation cost related to
nonvested unit option awards granted under the EPCO 1998 Plan. We
expect to recognize this cost over a weighted-average period of 2.1
years. We will recognize our share of these costs in accordance with
the EPCO administrative services agreement (the “ASA”) (see Note
17).
During
the years ended December 31, 2008 and 2007, we received cash of $0.7 million and
$7.5 million, respectively, from the exercise of option awards granted
under the EPCO 1998 Plan. Conversely, our option-related
reimbursements to EPCO were $0.6 million and $3.0 million,
respectively.
Restricted
unit
awards. Under
the EPCO 1998 Plan, we may also issue restricted common units to key employees
of EPCO and directors of our general partner. In general, the
restricted unit awards allow recipients to acquire the underlying common units
at no cost to the recipient once a defined cliff vesting period expires, subject
to certain forfeiture provisions. The restrictions on such units generally
lapse four years from the date of grant. Compensation expense is
recognized on a straight-line basis over the vesting period. Fair
value of such restricted units is based on the market price of the underlying
common units on the date of grant and an allowance for estimated
forfeitures.
Each
recipient is also entitled to cash distributions equal to the product of the
number of restricted units outstanding for the participant and the cash
distribution per unit paid by us to our unitholders. Since
restricted units are issued securities, such distributions are reflected as a
component of cash distributions to partners as shown on our Statements of
Consolidated Cash Flows. We paid $3.9 million, $2.6 million and $1.6
million in cash distributions with respect to restricted units during the years
ended December 31, 2008, 2007 and 2006, respectively.
The
following table summarizes information regarding our restricted unit awards for
the periods indicated:
|
|
|
|
|
|
Weighted-
|
|
|
|
|
|
|
|
Average
Grant
|
|
|
|
|
Number
of
|
|
|
Date
Fair Value
|
|
|
|
|
Units
|
|
|
per Unit
(1)
|
|
|
Restricted
units at December 31, 2005
|
|
|
751,604 |
|
|
|
|
|
Granted
(2)
|
|
|
466,400 |
|
|
$ |
25.21 |
|
|
Vested
|
|
|
(42,136 |
) |
|
$ |
24.02 |
|
|
Forfeited
|
|
|
(70,631 |
) |
|
$ |
22.86 |
|
|
Restricted
units at December 31, 2006
|
|
|
1,105,237 |
|
|
|
|
|
|
Granted
(3)
|
|
|
738,040 |
|
|
$ |
25.61 |
|
|
Vested
|
|
|
(4,884 |
) |
|
$ |
25.28 |
|
|
Forfeited
|
|
|
(36,800 |
) |
|
$ |
23.51 |
|
|
Settled
(4)
|
|
|
(113,053 |
) |
|
$ |
23.24 |
|
|
Restricted
units at December 31, 2007
|
|
|
1,688,540 |
|
|
|
|
|
|
Granted
(5)
|
|
|
766,200 |
|
|
$ |
24.93 |
|
|
Vested
|
|
|
(285,363 |
) |
|
$ |
23.11 |
|
|
Forfeited
|
|
|
(88,777 |
) |
|
$ |
26.98 |
|
|
Restricted
units at December 31, 2008
|
|
|
2,080,600 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Determined
by dividing the aggregate grant date fair value of awards by the number of
awards issued. The weighted-average grant date fair value per unit
for forfeited and vested awards is determined before an allowance for
forfeitures.
(2)
Aggregate
grant date fair value of restricted unit awards issued during 2006 was
$10.8 million based on grant date market prices of our common units
ranging from $24.85 to $27.45 per unit and estimated forfeiture rates
ranging from 7.8% to 9.8%.
(3)
Aggregate
grant date fair value of restricted unit awards issued during 2007 was
$18.9 million based on grant date market prices of our common units
ranging from $28.00 to $31.83 per unit and estimated forfeiture rates
ranging from 4.6% to 17.0%.
(4)
Reflects
the settlement of restricted units in connection with the resignation of
our general partner’s former chief executive officer.
(5)
Aggregate
grant date fair value of restricted unit awards issued during 2008 was
$19.1 million based on grant date market prices of our common units
ranging from $25.00 to $32.31 per unit and an estimated forfeiture rate
of 17.0%.
|
|
The total
fair value of restricted unit awards that vested during the year ended December
31, 2008 was $6.6 million. At December 31, 2008, there was an
estimated $31.5 million of total unrecognized compensation cost related to
restricted unit awards granted under the EPCO 1998 Plan, which we expect to
recognize over a weighted-average period of 2.3 years. We will recognize
our share of such costs in accordance with the ASA.
Phantom
unit
awards. The
EPCO 1998 Plan also provides for the issuance of phantom unit
awards. These liability awards are automatically redeemed for cash
based on the vested portion of the fair market value of the phantom units at
redemption dates in each award. The fair market value of each phantom
unit award is equal to the market closing price of our common units on the
redemption date. Each participant is required to redeem their phantom
units as they vest, which typically is four years from the date the award is
granted. No phantom unit awards have been issued to date under the
EPCO 1998 Plan.
The EPCO 1998 Plan also provides for
the award of distribution equivalent rights (“DERs”) in tandem with its phantom
unit awards. A DER entitles the participant to cash
distributions equal to the product of the number of phantom units outstanding
for the participant and the cash distribution rate paid by us to our
unitholders. No DERs have been issued as of December 31, 2008 under
the EPCO 1998 Plan.
EPD
2008 LTIP
On January 29, 2008, our
unitholders approved the EPD 2008 LTIP, which provides for awards of our common
units and other rights to our non-employee directors and to consultants and
employees of EPCO and its affiliates providing services to us. Awards
under the EPD 2008 LTIP may be granted in the form of unit options, restricted
units, phantom units, UARs and DERs. The EPD 2008 LTIP is
administered by EPGP’s Audit, Conflicts and Governance (“ACG”)
Committee. The EPD 2008 LTIP provides for the issuance of up to
10,000,000 of our common units. After giving effect to option awards
outstanding at December 31, 2008, a total of 9,205,000 additional common units
could be issued under the EPD 2008 LTIP.
The EPD
2008 LTIP may be amended or terminated at any time by the Board of Directors of
EPCO or EPGP’s ACG Committee; however, the rules of the NYSE require that any
material amendment, such as a significant increase in the number of common units
available under the plan or a change in the types of awards available under the
plan, would require the approval of our unitholders. The ACG
Committee is also authorized to make adjustments in the terms and conditions of,
and the criteria included in, awards under the plan in specified
circumstances. The EPD 2008 LTIP is effective until the earlier of
January 29, 2018 or the time which all available units under the incentive
plan have been delivered to participants or the time of termination of the plan
by EPCO or EPGP’s ACG Committee.
Unit
option awards. The exercise price of
unit options awarded to participants is determined by the ACG Committee (at its
discretion) at the date of grant and may be no less than the fair market value
of our common units at the date of grant. The following table
presents unit option activity under the EPD 2008 LTIP for the periods
indicated:
|
|
|
|
|
|
|
|
|
Weighted-
|
|
|
|
|
|
|
|
Weighted-
|
|
|
Average
|
|
|
|
|
|
|
|
Average
|
|
|
Remaining
|
|
|
|
|
Number
of
|
|
|
Strike
Price
|
|
|
Contractual
|
|
|
|
|
Units
|
|
|
(dollars/unit)
|
|
|
Term
(in years)
|
|
|
Outstanding
at January 1, 2008
|
|
|
-- |
|
|
|
|
|
|
|
|
Granted
(1)
|
|
|
795,000 |
|
|
$ |
30.93 |
|
|
|
|
|
Outstanding at December 31, 2008 (2)
|
|
|
795,000 |
|
|
$ |
30.93 |
|
|
|
5.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Aggregate
grant date fair value of these unit options issued during 2008 was $1.6
million based on the following assumptions: (i) a grant date market price
of our common units of $30.93 per unit; (ii) expected life of options of
4.7 years; (iii) risk-free interest rate of 3.3%; (iv) expected
distribution yield on our common units of 7.0%; (v) expected unit price
volatility on our common units of 19.8%; and (vi) an estimated forfeiture
rate of 17.0%.
(2)
The
795,000 units outstanding at December 31, 2008 will become exercisable in
2013.
|
|
At
December 31, 2008, there was an estimated $1.3 million of total unrecognized
compensation cost related to nonvested unit options granted under the EPD 2008
LTIP. We expect to recognize our share of this cost over a remaining
period of 3.4 years in accordance with the ASA.
Phantom
unit
awards. The
EPD 2008 LTIP also provides for the issuance of phantom unit
awards. These liability awards are automatically redeemed for cash
based on the vested portion of the fair market value of the phantom units at
redemption dates in each award. The fair market value of each phantom
unit award is equal to the market closing price of our common units on the
redemption date. Each participant is required to redeem their phantom
units as they vest, which typically is three years from the date the award is
granted. There were a total of 4,400 phantom units granted under the
EPD 2008 LTIP during the fourth quarter of 2008 and outstanding at December 31,
2008. These awards cliff vest in 2011. At December 31,
2008, we had an accrued liability of $5 thousand for compensation related to
these phantom unit awards.
Employee
Partnerships
As
long-term incentive arrangements, EPCO has granted its key employees who perform
services on behalf of us, EPCO and other affiliated companies, “profits
interests” in five limited partnerships. The employees were issued
Class B limited partner interests and admitted as Class B limited partners in
the Employee Partnerships without capital contributions. As discussed
and defined above, the Employee Partnerships are: EPE Unit I; EPE
Unit II; EPE Unit III; Enterprise Unit; and EPCO Unit. Enterprise
Unit and EPCO Unit were formed in 2008.
The
Class B limited partner interests entitle each holder to participate in the
appreciation in value of the publicly traded limited partner units owned by the
underlying Employee Partnership. The Employee Partnerships own either
Enterprise GP Holdings units (“EPE units”) or Enterprise Products Partners’
common units (“EPD units”) or both. The Class B limited partner
interests are subject to forfeiture if the participating employee’s employment
with EPCO is terminated prior to vesting, with customary exceptions for death,
disability and certain retirements and upon certain change of control
events.
We
account for the profits interest awards under SFAS 123(R). As a
result, the compensation expense attributable to these awards is based on the
estimated grant date fair value of each award. An allocated portion
of the fair value of these equity-based awards is charged to us under the ASA
(see Note 17). We are not responsible for reimbursing EPCO for any
expenses of the Employee Partnerships, including the value of any contributions
of cash or limited partner units made by private company affiliates of EPCO at
the formation of each Employee Partnership. However, pursuant to the
ASA, beginning in February 2009 we will reimburse EPCO for our allocated share
of distributions of cash or securities made to the Class B limited partners of
EPCO Unit.
Each
Employee Partnership has a single Class A limited partner, which is a
privately-held indirect subsidiary of EPCO, and a varying number of Class B
limited partners. At formation, the Class A limited partner
either contributes cash or limited partner units it owns to the Employee
Partnership. If cash is contributed, the Employee Partnership
uses these funds to acquire limited partner units on the open
market. In general, the Class A limited partner earns a preferred
return (either fixed or variable depending on the partnership agreement) on its
investment (“Capital Base”) in the Employee Partnership and any residual
quarterly cash amounts, if any, are distributed to the Class B limited
partners. Upon liquidation, Employee Partnership assets having a fair
market value equal to the Class A limited partner’s Capital Base, plus any
preferred return for the period in which liquidation occurs, will be distributed
to the Class A limited partner. Any remaining assets will be
distributed to the Class B limited partner(s) as a residual profits
interest.
The
following table summarizes key elements of each Employee Partnership as of
December 31, 2008:
|
|
|
Initial
|
Class
A
|
|
|
|
|
|
|
Class
A
|
Partner
|
Award
|
Grant
Date
|
Unrecognized
|
|
Employee
|
Description
|
Capital
|
Preferred
|
Vesting
|
Fair
Value
|
Compensation
|
|
Partnership
|
of
Assets
|
Base
|
Return
|
Date
(1)
|
of
Awards (2)
|
Cost
(3)
|
|
|
|
|
|
|
|
|
|
EPE
Unit I
|
1,821,428
EPE units
|
$51.0
million
|
4.50% to
5.725%
(4)
|
November
2012
|
$17.0
million
|
$9.3
million
|
|
|
|
|
|
|
|
|
|
EPE
Unit II
|
40,725
EPE units
|
$1.5
million
|
4.50% to
5.725%
(4)
|
February
2014
|
$0.3
million
|
$0.2
million
|
|
|
|
|
|
|
|
|
|
EPE
Unit III
|
4,421,326
EPE units
|
$170.0
million
|
3.80%
|
May
2014
|
$32.7
million
|
$25.1
million
|
|
|
|
|
|
|
|
|
|
Enterprise
Unit
|
881,836
EPE units
844,552
EPD units
|
$51.5
million
|
5.00%
|
February
2014
|
$4.2
million
|
$3.7
million
|
|
|
|
|
|
|
|
|
|
EPCO
Unit
|
779,102
EPD units
|
$17.0
million
|
4.87%
|
November
2013
|
$7.2
million
|
$7.0
million
|
|
(1)
The
vesting date may be accelerated for change of control and other events as
described in the underlying partnership agreements.
(2)
Our
estimated grant date fair values were determined using a Black-Scholes
option pricing model and reflect adjustments for forfeitures, regrants and
other modifications. See following table for information
regarding our fair value assumptions.
(3)
Unrecognized
compensation cost represents the total future expense to be recognized by
the EPCO group of companies as of December 31, 2008. We
will recognize our allocated share of such costs in the
future. The period over which the unrecognized
compensation cost will be recognized is as follows for each Employee
Partnership: 3.9 years, EPE Unit I; 5.1 years, EPE Unit II; 5.4
years, EPE Unit III; 5.1 years, Enterprise Unit; and 4.9 years, EPCO
Unit.
(4)
In
July 2008, the Class A preferred return was reduced from 6.25% to the
floating amounts presented.
|
The following table summarizes the
assumptions we used in deriving the estimated grant date fair value for each of
the Employee Partnerships using a Black-Scholes option pricing
model:
|
|
Expected
|
Risk-Free
|
Expected
|
Expected
|
|
Employee
|
Life
|
Interest
|
Distribution
Yield
|
Unit
Price Volatility
|
|
Partnership
|
of
Award
|
Rate
|
of
EPE/EPD units
|
of
EPE/EPD units
|
|
|
|
|
|
|
|
EPE
Unit I
|
3
to 5 years
|
2.7%
to 5.0%
|
3.0%
to 4.8%
|
16.6%
to 30.0%
|
|
EPE
Unit II
|
5
to 6 years
|
3.3%
to 4.4%
|
3.8%
to 4.8%
|
18.7%
to 19.4%
|
|
EPE
Unit III
|
4
to 6 years
|
3.2%
to 4.9%
|
4.0%
to 4.8%
|
16.6%
to 19.4%
|
|
Enterprise
Unit
|
6
years
|
2.7%
to 3.9%
|
4.5%
to 8.0%
|
15.3%
to 22.1%
|
|
EPCO
Unit
|
5
years
|
2.4%
|
11.1%
|
50.0%
|
DEP
GP UARs
The
non-employee directors of DEP GP, the general partner of Duncan Energy Partners,
have been granted UARs in the form of letter agreements. These
liability awards are not part of any established long-term incentive plan of
EPCO, Enterprise GP Holdings, Duncan Energy Partners or us. The
compensation expense associated with these awards is recognized by DEP GP, which
is our consolidated subsidiary. These UARs entitle each non-employee
director to receive a cash payment on the vesting date equal to the excess, if
any, of the fair market value of Enterprise GP Holdings’ units (determined as of
a future vesting date) over the grant date fair value. If a director
resigns prior to vesting, his UAR awards are forfeited. These UARs
are accounted for similar to liability awards under SFAS 123(R) since they will
be settled with cash.
As of December 31, 2008, a total of
90,000 UARs had been granted to non-employee directors of DEP GP that cliff vest
in 2012. If a director resigns prior to vesting, his UAR awards are
forfeited. The grant date fair value with respect to these UARs is
based on an Enterprise GP Holdings’ unit price of $36.68.
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
Dixie’s 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 for
each of the years ended December 31, 2008 and 2007.
Pension
and Postretirement Benefit Plans
Dixie’s 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. Dixie’s 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.
The
following table presents Dixie’s benefit obligations, fair value of plan assets
and funded status at December 31, 2008.
|
|
|
Pension
|
|
|
Postretirement
|
|
|
|
|
Plan
|
|
|
Plan
|
|
|
Projected
benefit obligation
|
|
$ |
7,733 |
|
|
$ |
4,976 |
|
|
Accumulated
benefit obligation
|
|
|
5,711 |
|
|
|
-- |
|
|
Fair
value of plan assets
|
|
|
4,035 |
|
|
|
-- |
|
|
Funded
status
|
|
|
(3,698 |
) |
|
|
(4,976 |
) |
Projected
benefit obligations and net periodic benefit costs are based on actuarial
estimates and assumptions. The weighted-average actuarial assumptions
used in determining the projected benefit obligation at December 31, 2008 were
as follows: discount rate of 6.4%; rate of compensation increase of
4.0% for both the pension and postretirement plans; and a medical trend rate of
8.5% for 2009 grading to an ultimate trend of 5.0% for 2015 and later
years. Dixie’s net pension and postretirement benefit costs for 2008
were $0.6 million and $0.4 million, respectively. Dixie’s net pension
and postretirement benefit costs for 2007 were $1.1 million (including
settlement loss of $0.6 million) and $0.4 million, respectively.
Future
benefits expected to be paid from Dixie’s pension and postretirement plans are
as follows for the periods indicated:
|
|
|
Pension
|
|
|
Postretirement
|
|
|
|
|
Plan
|
|
|
Plan
|
|
|
2009
|
|
$ |
289 |
|
|
$ |
357 |
|
|
2010
|
|
|
334 |
|
|
|
399 |
|
|
2011
|
|
|
535 |
|
|
|
427 |
|
|
2012
|
|
|
408 |
|
|
|
440 |
|
|
2013
|
|
|
775 |
|
|
|
439 |
|
|
2014
through 2018
|
|
|
4,211 |
|
|
|
2,067 |
|
|
Total
|
|
$ |
6,552 |
|
|
$ |
4,129 |
|
Included
in accumulated other comprehensive income (loss) on the Consolidated Balance
Sheets at December 31, 2008 and 2007 are the following amounts that have not
been recognized in net periodic pension costs (in millions):
|
|
|
At
December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Unrecognized
transition obligation
|
|
$ |
0.9 |
|
|
$ |
1.0 |
|
|
Net
of tax
|
|
|
0.5 |
|
|
|
0.6 |
|
|
|
|
|
|
|
|
|
|
|
|
Unrecognized
prior service cost credit
|
|
|
(1.0 |
) |
|
|
(1.2 |
) |
|
Net
of tax
|
|
|
(0.6 |
) |
|
|
(0.8 |
) |
|
|
|
|
|
|
|
|
|
|
|
Unrecognized
net actuarial loss
|
|
|
1.3 |
|
|
|
2.8 |
|
|
Net
of tax
|
|
|
0.8 |
|
|
|
1.7 |
|
We are
exposed to financial market risks, including changes in commodity prices,
interest rates and foreign exchange rates. We may use financial
instruments (e.g., futures, forwards, swaps, options and other financial
instruments with similar characteristics) to mitigate the risks of certain
identifiable and anticipated transactions. In general, the types of
risks we attempt to hedge are those related to (i) the variability of future
earnings, (ii) fair values of certain debt obligations and (iii) cash flows
resulting from changes in applicable interest rates, commodity prices or
exchange rates. See Note 14 for information regarding our consolidated debt
obligations.
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 hedging
criteria. When this occurs, we may enter into a new financial
instrument to reestablish the hedge to which the closed instrument
relates.
The following table presents gains
(losses) recorded in net income attributable to our interest rate risk and
commodity risk hedging transactions for the periods indicated. These
amounts do not present the corresponding gains (losses) attributable to the
underlying hedged items.
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Interest
Rate Risk Hedging Portfolio:
|
|
|
|
|
|
|
|
|
|
|
EPO:
|
|
|
|
|
|
|
|
|
|
|
Reclassification
of cash flow hedge amounts from AOCI, net
|
|
$ |
4,409 |
|
|
$ |
5,429 |
|
|
$ |
4,234 |
|
|
Other
gains (losses) from derivative transactions
|
|
|
5,340 |
|
|
|
(8,934 |
) |
|
|
(5,195 |
) |
|
Duncan
Energy Partners:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ineffective
portion of cash flow hedges
|
|
|
(5 |
) |
|
|
(155 |
) |
|
|
-- |
|
|
Reclassification
of cash flow hedge amounts from AOCI, net
|
|
|
(2,008 |
) |
|
|
350 |
|
|
|
-- |
|
|
Total
hedging gains (losses), net, in consolidated interest
expense
|
|
$ |
7,736 |
|
|
$ |
(3,310 |
) |
|
$ |
(961 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
Risk Hedging Portfolio:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EPO:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reclassification
of cash flow hedge amounts from
AOCI,
net - natural gas marketing activities
|
|
$ |
(30,175 |
) |
|
$ |
(3,299 |
) |
|
$ |
(1,327 |
) |
|
Reclassification
of cash flow hedge amounts from
AOCI,
net - NGL and petrochemical operations
|
|
|
(28,232 |
) |
|
|
(4,564 |
) |
|
|
13,891 |
|
|
Other
gains (losses) from derivative transactions
|
|
|
29,772 |
|
|
|
(20,712 |
) |
|
|
(2,307 |
) |
|
Total
hedging gains (losses), net, in consolidated operating costs and
expenses
|
|
$ |
(28,635 |
) |
|
$ |
(28,575 |
) |
|
$ |
10,257 |
|
The
following table provides additional information regarding derivative instruments
as presented in our Consolidated Balance Sheets at the dates
indicated:
|
|
|
At
December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Current
assets:
|
|
|
|
|
|
|
|
Derivative
assets:
|
|
|
|
|
|
|
|
Interest
rate risk hedging portfolio
|
|
$ |
7,780 |
|
|
$ |
-- |
|
|
Commodity
risk hedging portfolio
|
|
|
185,762 |
|
|
|
341 |
|
|
Foreign
currency risk hedging portfolio
|
|
|
9,284 |
|
|
|
1,308 |
|
|
Total
derivative assets – current
|
|
$ |
202,826 |
|
|
$ |
1,649 |
|
|
Other
assets:
|
|
|
|
|
|
|
|
|
|
Interest
rate risk hedging portfolio
|
|
$ |
38,939 |
|
|
$ |
14,744 |
|
|
Total
derivative assets – long-term
|
|
$ |
38,939 |
|
|
$ |
14,744 |
|
|
|
|
|
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
|
|
|
Derivative
liabilities:
|
|
|
|
|
|
|
|
|
|
Interest
rate risk hedging portfolio
|
|
$ |
5,910 |
|
|
$ |
22,209 |
|
|
Commodity
risk hedging portfolio
|
|
|
281,142 |
|
|
|
19,575 |
|
|
Foreign
currency risk hedging portfolio
|
|
|
109 |
|
|
|
27 |
|
|
Total
derivative liabilities – current
|
|
$ |
287,161 |
|
|
$ |
41,811 |
|
|
Other
liabilities:
|
|
|
|
|
|
|
|
|
|
Interest
rate risk hedging portfolio
|
|
$ |
3,889 |
|
|
$ |
3,080 |
|
|
Commodity
risk hedging portfolio
|
|
|
233 |
|
|
|
-- |
|
|
Total
derivative liabilities– long-term
|
|
$ |
4,122 |
|
|
$ |
3,080 |
|
The following table presents gains
(losses) recorded in other comprehensive income (loss) for cash flow hedges
associated with our interest rate risk, commodity risk and foreign currency risk
hedging portfolios. These amounts do not present the corresponding
gains (losses) attributable to the underlying hedged items.
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Interest
Rate Risk Hedging Portfolio:
|
|
|
|
|
|
|
|
|
|
|
EPO:
|
|
|
|
|
|
|
|
|
|
|
Gains
(losses) on cash flow hedges
|
|
$ |
(20,772 |
) |
|
$ |
17,996 |
|
|
$ |
11,196 |
|
|
Reclassification
of cash flow hedge amounts to net income, net
|
|
|
(4,409 |
) |
|
|
(5,429 |
) |
|
|
(4,234 |
) |
|
Duncan
Energy Partners:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Losses
on cash flow hedges
|
|
|
(7,989 |
) |
|
|
(3,271 |
) |
|
|
-- |
|
|
Reclassification
of cash flow hedge amounts to net income, net
|
|
|
2,008 |
|
|
|
(350 |
) |
|
|
-- |
|
|
Total
interest rate risk hedging gains (losses), net
|
|
|
(31,162 |
) |
|
|
8,946 |
|
|
|
6,962 |
|
|
Commodity
Risk Hedging Portfolio:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EPO:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas marketing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Losses
on cash flow hedges
|
|
|
(30,642 |
) |
|
|
(3,125 |
) |
|
|
(1,034 |
) |
|
Reclassification
of cash flow hedge amounts to net income, net
|
|
|
30,175 |
|
|
|
3,299 |
|
|
|
1,327 |
|
|
NGL
and petrochemical operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains
(losses) on cash flow hedges
|
|
|
(120,223 |
) |
|
|
(22,735 |
) |
|
|
9,976 |
|
|
Reclassification
of cash flow hedge amounts to net income, net
|
|
|
28,232 |
|
|
|
4,564 |
|
|
|
(13,891 |
) |
|
Total
commodity risk hedging gains (losses), net
|
|
|
(92,458 |
) |
|
|
(17,997 |
) |
|
|
(3,622 |
) |
|
Foreign
Currency Risk Hedging Portfolio:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains
on cash flow hedges
|
|
|
9,286 |
|
|
|
1,308 |
|
|
|
-- |
|
|
Total
foreign currency risk hedging gains (losses), net
|
|
|
9,286 |
|
|
|
1,308 |
|
|
|
-- |
|
|
Total
cash flow hedge amounts in other comprehensive income
|
|
$ |
(114,334 |
) |
|
$ |
(7,743 |
) |
|
$ |
3,340 |
|
The following information summarizes
the principal elements of our interest rate risk, commodity risk and foreign
currency risk hedging portfolios. For amounts recorded in net income and other
comprehensive
income and on our balance sheet related to our consolidated hedging activities,
please refer to the preceding tables.
Interest
Rate Risk Hedging Portfolio
Our interest rate exposure results from
variable and fixed rate borrowings under various debt agreements. The following
information summarizes significant components of our interest rate risk hedging
portfolio:
Fair
value hedges – EPO interest rate swaps
We manage
a portion of our interest rate exposure 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.
At December 31, 2008, we had four interest rate swap agreements outstanding
having an aggregate notional value of $400.0 million that were accounted
for as fair value hedges. The aggregate fair value of these interest
rate swaps at December 31, 2008, was $46.7 million (an asset), with an
offsetting increase in the fair value of the underlying debt. There
were eleven interest rate swaps outstanding at December 31, 2007 having an
aggregate fair value of $12.9 million (an asset).
The following table summarizes our
interest rate swaps outstanding at December 31, 2008.
|
|
Number
|
Period
Covered
|
Termination
|
Fixed
to
|
Notional
|
|
|
Hedged
Fixed Rate Debt
|
of
Swaps
|
by
Swap
|
Date
of Swap
|
Variable Rate
(1)
|
Value
|
|
|
Senior
Notes C, 6.375% fixed rate, due Feb. 2013
|
1
|
Jan.
2004 to Feb. 2013
|
Feb.
2013
|
6.375% to
5.015%
|
$100.0
million
|
|
|
Senior
Notes G, 5.60% fixed rate, due Oct. 2014
|
3
|
4th
Qtr. 2004 to Oct. 2014
|
Oct.
2014
|
5.60%
to 5.297%
|
$300.0
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.
Cash
flow hedges – EPO treasury locks
We may
enter into treasury rate lock transactions (“treasury locks”) to hedge U.S.
treasury rates related to its anticipated issuances of debt. Each of our
treasury lock transactions was designated as a cash flow hedge. Gains or
losses on the termination of such instruments are reclassified into net income
(as a component of interest expense) using the effective interest method over
the estimated term of the underlying fixed-rate debt. At December 31,
2008, we had no treasury lock financial instruments outstanding. At
December 31, 2007, the aggregate notional value of our treasury lock financial
instruments was $600.0 million, which had a total fair value (a liability) of
$19.6 million. We terminated a number of treasury lock
financial instruments during 2008 and 2007. These terminations
resulted in realized losses of $40.4 million in 2008 and gains of $48.8 million
in 2007.
We expect
to reclassify $1.6 million of cumulative net gains from our interest rate risk
cash flow hedges into net income (as a decrease to interest expense) during
2009.
Cash
flow hedges – Duncan Energy Partners’ interest rate swaps
At
December 31, 2008, Duncan Energy Partners had interest rate swap agreements
outstanding having an aggregate notional value of $175.0
million. These swaps were accounted for as cash flow
hedges. The purpose of these financial instruments is to reduce the
sensitivity of Duncan Energy Partners’ earnings to the variable interest rates
charged under its revolving credit facility. The aggregate fair value
of these interest rate swaps at December 31, 2008 and 2007 was a liability of
$9.8 million and $3.8 million,
respectively. Duncan
Energy Partners expects to reclassify $6.0 million of cumulative net losses from
its interest rate risk cash flow hedges into net income (as an increase to
interest expense) during 2009.
The following table summarizes Duncan
Energy Partners’ interest rate swaps outstanding at December 31,
2008.
|
|
Number
|
Period
Covered
|
Termination
|
Variable
to
|
Notional
|
|
|
Hedged
Variable Rate Debt
|
of
Swaps
|
by
Swap
|
Date
of Swap
|
Fixed Rate
(1)
|
Value
|
|
|
DEP
I Revolving Credit Facility, due Feb. 2011
|
3
|
Sep.
2007 to Sep. 2010
|
Sep.
2010
|
1.47% to
4.62%
|
$175.0
million
|
|
| (1) Amounts
receivable from or payable to the swap counterparties are settled every
three months (the “settlement
period”). |
As cash flow hedges, any increase or
decrease in fair value (to the extent effective) would be recorded in other
comprehensive income (loss) and amortized into earnings based on the settlement
period hedged. Any ineffectiveness is recorded directly into earnings
as an increase in interest expense.
Commodity
Risk Hedging Portfolio
Our
commodity risk hedging portfolio was impacted by a significant decline in
natural gas prices during the second half of 2008. As a result
of the global recession, commodity prices have continued to be volatile during
the first quarter of 2009. We may experience additional losses
related to our commodity risk hedging portfolio in 2009.
The
prices of natural gas, NGLs and certain 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 price risks associated with such products, we may enter into commodity
financial instruments.
The
primary purpose of our commodity risk management activities is to reduce our
exposure to price risks associated with (i) natural gas purchases, (ii) the
value of 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, NGLs or certain petrochemical products. From time
to time, we inject natural gas into storage and may utilize hedging instruments
to lock in the value of its inventory positions. The commodity
financial instruments we utilize are settled in cash.
We have segregated our commodity
financial instruments portfolio between those financial instruments utilized in
connection with our natural gas marketing activities and those used in
connection with its NGL and petrochemical operations.
A
significant number of the financial instruments in this portfolio hedge the
purchase of physical natural gas. If natural gas prices fall below
the price stipulated in such financial instruments, we recognize a liability for
the difference; however, if prices partially or fully recover, this liability
would be reduced or eliminated, as appropriate. Our restricted cash
balance at December 31, 2008 was $203.8 million in order to meet commodity
exchange deposit requirements and the negative change in the fair value of
our natural gas hedge positions.
Natural
gas marketing activities
At
December 31, 2008 and 2007, the aggregate fair value of those financial
instruments utilized in connection with our natural gas marketing activities was
an asset of $6.5 million and a liability of $0.3 million,
respectively. Almost all of the financial instruments within this
portion of the commodity financial instruments portfolio are accounted for using
mark-to-market accounting, with a small number accounted for as cash flow
hedges. We did not have any cash flow hedges related to our natural
gas marketing activities at December 31, 2008.
NGL
and petrochemical operations
At
December 31, 2008 and 2007, the aggregate fair value of those financial
instruments utilized in connection with our NGL and petrochemical operations
were liabilities of $102.1 million and $19.0 million,
respectively. Almost all of the financial instruments within this
portion of the commodity financial instruments portfolio are accounted for as
cash flow hedges, with a small number accounted for using mark-to-market
accounting. We expect to reclassify $114.0 million of
cumulative net losses from these cash flow hedges into net income (as an
increase in operating costs and expenses) during 2009.
We have employed a program to
economically hedge a portion of our earnings from natural gas processing in the
Rocky Mountain region. This program consists of (i) the forward
sale of a portion of our expected equity NGL production volumes at fixed prices
through 2009 and (ii) the purchase, using commodity financial instruments, of
the amount of natural gas expected to be consumed as plant thermal reduction
(“PTR”) in the production of such equity NGL volumes. The objective of this
strategy is to hedge a level of gross margins (i.e., NGL sales revenues less
actual costs for PTR and the gain or loss on the PTR hedge) associated with the
forward sales contracts by fixing the cost of natural gas used for PTR, through
the use of commodity financial instruments. At December 31, 2008,
this hedging program had hedged future expected gross margins (before plant
operating expenses) of $483.9 million on 22.5 million barrels of forecasted NGL
forward sales transactions extending through 2009.
Our NGL forward sales contracts are not
accounted for as financial instruments under SFAS 133 since they meet normal
purchase and sale exception criteria; therefore, changes in the aggregate
economic value of these sales contracts are not reflected in net income and
other comprehensive income until the volumes are delivered to
customers. On the other hand, the commodity financial instruments
used to purchase the related quantities of PTR (i.e., “PTR hedges”) are
accounted for as cash flow hedges; therefore, changes in the aggregate fair
value of the PTR hedges are presented in other comprehensive
income. Once the forecasted NGL forward sales transactions occur, any
realized gains and losses on the cash flow hedges would be reclassified into net
income in that period.
Prior to actual settlement, if the
market price of natural gas is less than the price stipulated in a commodity
financial instrument, we recognize an unrealized loss in other comprehensive
loss for the excess of the natural gas price stated in the hedge over the market
price. To the extent that we realize such financial losses upon
settlement of the instrument, the losses are added to the actual cost we pay for
PTR, which would then be based on the lower market price. Conversely,
if the market price of natural gas is greater than the price stipulated in such
hedges, we recognize an unrealized gain in other comprehensive income for the
excess of the market price over the natural gas price stated in the PTR
hedge. If realized, the gains on the financial instrument would
serve to reduce the actual cost paid for PTR, which would then be based on the
higher market price. The net effect of these hedging relationships is
that our total cost of natural gas used for PTR approximates the amount it
originally hedged under this program.
Foreign
Currency Hedging Portfolio
We are exposed to foreign currency
exchange rate risk primarily through a Canadian NGL marketing
subsidiary. As a result, we could be adversely affected by
fluctuations in the foreign currency exchange rate between the U.S. dollar and
the Canadian dollar. We attempt to hedge this risk using foreign
exchange purchase contracts to fix the exchange rate. Mark-to-market
accounting is utilized for these contracts, which typically have a duration of
one month. For the year ended December 31, 2008, we recorded minimal
gains from these financial instruments.
In
addition, we are exposed to foreign currency exchange rate risk through our
Japanese Yen Term Loan Agreement (“Yen Term Loan”) that EPO entered into in
November 2008. As a result, we could be adversely affected by
fluctuations in the foreign currency exchange rate between the U.S. dollar and
the Japanese yen. We hedged this risk by entering into a foreign
exchange purchase contract to fix the exchange rate. This purchase
contract was designated as a cash flow hedge. At December 31, 2008,
the fair value of this contract was $9.3 million. This contract will
be settled in March 2009 upon repayment of
the Yen
Term Loan. Total interest expense under this loan agreement was $4.0
million, of which $1.7 million is the expected foreign currency loss, which will
be recorded as interest expense.
Adoption
of SFAS 157 - Fair Value Measurements
On
January 1, 2008, we adopted the provisions of SFAS 157 that apply to
financial assets and liabilities. We adopted the provisions of SFAS 157 that
apply to nonfinancial assets and liabilities on January 1, 2009. SFAS
157 defines fair value as the price that would be received to sell an asset or
paid to transfer a liability in an orderly transaction between market
participants at a specified measurement date.
Our fair
value estimates are based on either (i) actual market data or (ii) assumptions
that other market participants would use in pricing an asset or
liability. These assumptions include estimates of risk.
Recognized valuation techniques employ inputs such as product prices, operating
costs, discount factors and business growth rates. These inputs
may be either readily observable, corroborated by market data or generally
unobservable. In developing our estimates of fair value, we endeavor
to utilize the best information available and apply market-based data to the
extent possible. Accordingly, we utilize valuation techniques (such
as the market approach) that maximize the use of observable inputs and minimize
the use of unobservable inputs.
SFAS 157
established a three-tier hierarchy that classifies fair value amounts recognized
or disclosed in the financial statements based on the observability of inputs
used to estimate such fair values. The hierarchy considers fair value
amounts based on observable inputs (Levels 1 and 2) to be more reliable and
predictable than those based primarily on unobservable inputs (Level 3). At each
balance sheet reporting date, we categorize our financial assets and liabilities
using this hierarchy. The characteristics of fair value amounts
classified within each level of the SFAS 157 hierarchy are described as
follows:
|
§
|
Level
1 fair values are based on quoted prices, which are available in active
markets for identical assets or liabilities as of the measurement
date. Active markets are defined as those in which transactions
for identical assets or liabilities occur in sufficient frequency so as to
provide pricing information on an ongoing basis (e.g., the NYSE or
NYMEX). Level 1 primarily consists of financial assets and
liabilities such as exchange-traded financial instruments, publicly-traded
equity securities and U.S. government treasury
securities.
|
|
§
|
Level
2 fair values are based on pricing inputs other than quoted prices in
active markets (as reflected in Level 1 fair values) and are either
directly or indirectly observable as of the measurement
date. Level 2 fair values include instruments that are valued
using financial models or other appropriate valuation
methodologies. Such financial models are primarily
industry-standard models that consider various assumptions, including
quoted forward prices for commodities, time value of money, volatility
factors for stocks and current market and contractual prices for the
underlying instruments, as well as other relevant economic
measures. Substantially all of these assumptions are (i)
observable in the marketplace throughout the full term of the instrument,
(ii) can be derived from observable data or (iii) are validated by inputs
other than quoted prices (e.g., interest rate and yield curves at commonly
quoted intervals). Level 2 includes non-exchange-traded
instruments such as over-the-counter forward contracts, options and
repurchase agreements.
|
|
§
|
Level
3 fair values are based on unobservable inputs. Unobservable
inputs are used to measure fair value to the extent that observable inputs
are not available, thereby allowing for situations in which there is
little, if any, market activity for the asset or liability at the
measurement date. Unobservable inputs reflect the reporting
entity’s own ideas about the assumptions that market participants would
use in pricing an asset or liability (including assumptions about
risk). Unobservable inputs are based on the best information
available in the circumstances, which might include the reporting entity’s
internally-developed data. The reporting entity must not ignore
information about market participant assumptions that is reasonably
available without undue cost and effort. Level 3 inputs are
typically used in connection with internally developed valuation
methodologies where management makes its best estimate of an instrument’s
fair value. Level 3
|
generally
includes specialized or unique financial instruments that are tailored to meet a
customer’s specific needs. At December 31, 2008 our Level 3 financial
assets consisted of ethane based contracts with a range of two to twelve months
in term. This classification is primarily due to our reliance on
broker quotes for this product due to the forward ethane markets being less than
highly active.
The
following table sets forth, by level within the fair value hierarchy, our
financial assets and liabilities measured on a recurring basis at December 31,
2008. These financial assets and liabilities are classified in their
entirety based on the lowest level of input that is significant to the fair
value measurement. Our assessment of the significance of a particular
input to the fair value measurement requires judgment, and may affect the
valuation of the fair value assets and liabilities and their placement within
the fair value hierarchy levels.
|
|
|
Level
1
|
|
|
Level
2
|
|
|
Level
3
|
|
|
Total
|
|
|
Financial
assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
financial instruments
|
|
$ |
4,030 |
|
|
$ |
149,180 |
|
|
$ |
32,552 |
|
|
$ |
185,762 |
|
|
Foreign
currency hedging financial instruments
|
|
|
-- |
|
|
|
9,284 |
|
|
|
-- |
|
|
|
9,284 |
|
|
Interest
rate financial instruments
|
|
|
-- |
|
|
|
46,719 |
|
|
|
-- |
|
|
|
46,719 |
|
|
Total
|
|
$ |
4,030 |
|
|
$ |
205,183 |
|
|
$ |
32,552 |
|
|
$ |
241,765 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
financial instruments
|
|
$ |
7,137 |
|
|
$ |
274,238 |
|
|
$ |
-- |
|
|
$ |
281,375 |
|
|
Foreign
currency hedging financial instruments
|
|
|
-- |
|
|
|
109 |
|
|
|
-- |
|
|
|
109 |
|
|
Interest
rate financial instruments
|
|
|
-- |
|
|
|
9,799 |
|
|
|
-- |
|
|
|
9,799 |
|
|
Total
|
|
$ |
7,137 |
|
|
$ |
284,146 |
|
|
$ |
-- |
|
|
$ |
291,283 |
|
Fair
values associated with our interest rate, commodity and foreign currency
financial instrument portfolios were developed using available market
information and appropriate valuation techniques in accordance with SFAS
157.
The
following table sets forth a reconciliation of changes in the fair value of our
Level 3 financial assets and liabilities during the year ended December 31,
2008:
|
Balance,
January 1, 2008
|
|
$ |
(4,660 |
) |
|
Total
gains (losses) included in:
|
|
|
|
|
|
Net
income (1)
|
|
|
(34,807 |
) |
|
Other
comprehensive loss
|
|
|
37,212 |
|
|
Purchases,
issuances, settlements
|
|
|
34,807 |
|
|
Balance,
December 31, 2008
|
|
$ |
32,552 |
|
|
|
|
|
|
|
|
(1) There
were no unrealized gains included in this amounts.
|
|
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:
|
|
|
At
December 31, 2008
|
|
|
At
December 31, 2007
|
|
|
|
|
Carrying
|
|
|
Fair
|
|
|
Carrying
|
|
|
Fair
|
|
|
Financial
Instruments
|
|
Value
|
|
|
Value
|
|
|
Value
|
|
|
Value
|
|
|
Financial
assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents, including restricted cash
|
|
$ |
239,162 |
|
|
$ |
239,162 |
|
|
$ |
92,866 |
|
|
$ |
92,866 |
|
|
Accounts
receivable
|
|
|
1,247,144 |
|
|
|
1,247,144 |
|
|
|
2,010,544 |
|
|
|
2,010,544 |
|
|
Commodity
financial instruments (1)
|
|
|
185,762 |
|
|
|
185,762 |
|
|
|
341 |
|
|
|
341 |
|
|
Foreign
currency hedging financial instruments (2)
|
|
|
9,284 |
|
|
|
9,284 |
|
|
|
1,308 |
|
|
|
1,308 |
|
|
Interest
rate hedging financial instruments (3)
|
|
|
46,719 |
|
|
|
46,719 |
|
|
|
14,744 |
|
|
|
14,744 |
|
|
Financial
liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
payable and accrued expenses
|
|
|
1,683,105 |
|
|
|
1,683,105 |
|
|
|
2,755,647 |
|
|
|
2,755,647 |
|
|
Fixed-rate
debt (principal amount) (4)
|
|
|
7,704,296 |
|
|
|
6,638,954 |
|
|
|
5,904,000 |
|
|
|
5,867,899 |
|
|
Variable-rate
debt
|
|
|
1,341,750 |
|
|
|
1,341,750 |
|
|
|
992,500 |
|
|
|
992,500 |
|
|
Commodity
financial instruments (1)
|
|
|
281,375 |
|
|
|
281,375 |
|
|
|
19,575 |
|
|
|
19,575 |
|
|
Foreign
currency hedging financial instruments (2)
|
|
|
109 |
|
|
|
109 |
|
|
|
27 |
|
|
|
27 |
|
|
Interest
rate hedging financial instruments (3)
|
|
|
9,799 |
|
|
|
9,799 |
|
|
|
25,289 |
|
|
|
25,289 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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)
Relates
to the hedging of our exposure to fluctuations in the Canadian dollar and
Japanese yen.
(3)
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.
(4)
Due
to the distress in the capital markets following the collapse of several
major financial entities and uncertainty in the credit markets during
2008, corporate debt securities were trading at significant
discounts.
|
|
SFAS
123(R) requires us to recognize compensation expense related to equity awards
based on the fair value of the award at grant date. The fair value of
restricted unit awards is based on the market price of the underlying common
units on the date of grant. The fair value of other equity awards is
estimated using the Black-Scholes option pricing model. Under SFAS
123(R), the fair value of an equity award is amortized to earnings on a
straight-line basis over the requisite service or vesting period for equity
awards. Compensation for liability-classified awards is recognized
over the requisite service or vesting period of an award based on the fair value
of the award remeasured at each reporting period. Liability
awards will be cash settled upon vesting.
Upon
adoption of SFAS 123(R), we recognized, as a benefit, the cumulative effect of a
change in accounting principle of $1.5 million based on the SFAS 123(R)
requirement to recognize compensation expense based upon the grant date fair
value of equity awards and the application of an estimated forfeiture rate to
unvested awards. See Note 5 for additional information regarding our
accounting for equity awards.
The
following table shows unaudited pro forma net income for the year ended December
31, 2006, assuming the accounting change noted above was applied retroactively
to January 1, 2006.
|
Pro
Forma income statement amounts:
|
|
|
|
|
Historical
net income
|
|
$ |
601,155 |
|
|
Adjustments
to derive pro forma net income:
|
|
|
|
|
|
Effect
of implementation of SFAS 123(R):
|
|
|
|
|
|
Remove
cumulative effect of change in accounting
|
|
|
|
|
|
principle
recorded in January 2006
|
|
|
(1,472 |
) |
|
Pro
forma net income
|
|
|
599,683 |
|
|
EPGP
interest
|
|
|
(96,969 |
) |
|
Pro
forma net income available to limited partners
|
|
$ |
502,714 |
|
|
|
|
|
|
|
|
Pro
forma per unit data (basic):
|
|
|
|
|
|
Historical
units outstanding
|
|
|
414,442 |
|
|
Per
unit data:
|
|
|
|
|
|
As
reported
|
|
$ |
1.22 |
|
|
Pro
forma
|
|
$ |
1.21 |
|
|
Pro
forma per unit data (diluted):
|
|
|
|
|
|
Historical
units outstanding
|
|
|
414,759 |
|
|
Per
unit data:
|
|
|
|
|
|
As
reported
|
|
$ |
1.22 |
|
|
Pro
forma
|
|
$ |
1.21 |
|
Our inventory amounts were as
follows at the dates indicated:
|
|
|
At
December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Working
inventory (1)
|
|
$ |
200,439 |
|
|
$ |
342,589 |
|
|
Forward sales
inventory (2)
|
|
|
162,376 |
|
|
|
11,693 |
|
|
Total
inventory
|
|
$ |
362,815 |
|
|
$ |
354,282 |
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Working
inventory is comprised of inventories of natural gas, NGLs and certain
petrochemical products that are either available-for-sale or used in the
provision for services.
(2)
Forward
sales inventory consists of identified NGL and natural gas volumes
dedicated to the fulfillment of forward sales
contracts.
|
|
Our
inventory values reflect payments for product purchases, freight charges
associated with such purchase volumes, terminal and storage fees, vessel
inspection costs, demurrage charges and other related costs. We value
our inventories at the lower of average cost or market.
Operating
costs and expenses, as presented on our Statements of Consolidated Operations,
include cost of sales amounts related to the sale of inventories. Our
costs of sales were $18.66 billion, $14.51 billion and $11.78 billion for the
years ended December 31, 2008, 2007 and 2006, respectively.
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. 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 commodity prices in the NGL, natural gas and petrochemical industry,
we recognize lower of cost or market (“LCM”) adjustments when the carrying value
of our inventories exceed their net realizable value. These non-cash
charges are a component of cost of sales in the period they are recognized and
generally affect our segment operating results in the following
manner:
|
§
|
Write-downs
of NGL inventories are recorded as a cost of our NGL marketing activities
within our NGL Pipelines & Services business
segment;
|
|
§
|
Write-downs
of natural gas inventories are recorded as a cost of our natural gas
pipeline operations within our Onshore Natural Gas Pipelines &
Services business segment; and
|
|
§
|
Write-downs
of petrochemical inventories 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, 2008, 2007 and 2006, we recognized LCM adjustments of
approximately $50.7 million, $13.3 million and $18.6 million,
respectively. 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.
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
|
|
|
2008
|
|
|
2007
|
|
|
Plants and pipelines
(1)
|
|
3-40
(5)
|
|
|
$ |
12,296,318 |
|
|
$ |
10,884,819 |
|
|
Underground
and other storage facilities (2)
|
|
5-35
(6)
|
|
|
|
900,664 |
|
|
|
720,795 |
|
|
Platforms
and facilities (3)
|
|
20-31
|
|
|
|
634,761 |
|
|
|
637,812 |
|
|
Transportation
equipment (4)
|
|
3-10 |
|
|
|
38,771 |
|
|
|
32,627 |
|
|
Land
|
|
|
|
|
|
|
54,627 |
|
|
|
48,172 |
|
|
Construction
in progress
|
|
|
|
|
|
|
1,604,691 |
|
|
|
1,173,988 |
|
|
Total
|
|
|
|
|
|
|
15,529,832 |
|
|
|
13,498,213 |
|
|
Less
accumulated depreciation
|
|
|
|
|
|
|
2,375,058 |
|
|
|
1,910,949 |
|
|
Property,
plant and equipment, net
|
|
|
|
|
|
$ |
13,154,774 |
|
|
$ |
11,587,264 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Plants
and pipelines include 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 include underground product storage caverns;
storage tanks; water wells; and related assets.
(3)
Platforms
and facilities include offshore platforms and related facilities and other
associated assets.
(4)
Transportation
equipment includes vehicles and similar assets used in our
operations.
(5)
In
general, the estimated useful lives of major components of this category
are as follows: processing plants, 20-35 years; pipelines, 18-40
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 as follows: 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).
|
|
The
following table summarizes our depreciation expense and capitalized interest
amounts for the periods indicated:
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Depreciation
expense (1)
|
|
$ |
466,054 |
|
|
$ |
414,901 |
|
|
$ |
350,832 |
|
|
Capitalized
interest (2)
|
|
|
71,584 |
|
|
|
75,476 |
|
|
|
55,660 |
|
|
(1) Depreciation
expense is a component of costs and expenses as presented in our
Statements of Consolidated Operations.
(2) Capitalized
interest increases the carrying value of the associated asset and reduces
interest expense during the period it is recorded.
|
|
We
reviewed assumptions underlying the estimated remaining useful lives of certain
of our assets during the first quarter of 2008. As a result of
our review, effective January 1, 2008, we revised the remaining useful lives of
these assets, most notably the assets that constitute our Texas Intrastate
System. This revision increased the remaining useful life of such
assets to incorporate recent data showing that proved natural gas reserves
supporting throughput and processing volumes for these assets have changed since
our original determination made in September 2004. These revisions
will prospectively reduce our depreciation expense on assets having carrying
values totaling $2.72 billion as of January 1, 2008. On average,
we extended the life of these assets by 3.1 years. As a result of
this change in estimate, depreciation expense included in operating income and
net income for the year ended December 31, 2008 decreased by approximately $20.0
million, which increased our basic and diluted earnings per unit by $0.04 from
what it would have been absent the change.
Asset
retirement obligations
We have
recorded AROs related to legal requirements to perform retirement activities as
specified in contractual arrangements and/or governmental regulations. In
general, our AROs 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 AROs may result
from the renovation or demolition of certain assets containing hazardous
substances such as asbestos.
The
following table presents information regarding our AROs since December 31,
2006.
|
ARO
liability balance, December 31, 2006
|
|
$ |
24,403 |
|
|
Liabilities
incurred
|
|
|
1,673 |
|
|
Liabilities
settled
|
|
|
(5,069 |
) |
|
Revisions
in estimated cash flows
|
|
|
15,645 |
|
|
Accretion
expense
|
|
|
3,962 |
|
|
ARO
liability balance, December 31, 2007
|
|
|
40,614 |
|
|
Liabilities
incurred
|
|
|
1,064 |
|
|
Liabilities
settled
|
|
|
(7,229 |
) |
|
Revisions
in estimated cash flows
|
|
|
1,163 |
|
|
Accretion
expense
|
|
|
2,114 |
|
|
ARO
liability balance, December 31, 2008
|
|
$ |
37,726 |
|
Property,
plant and equipment at December 31, 2008 and 2007 includes $9.9 million and
$10.6 million, respectively, of asset retirement costs capitalized as an
increase in the associated long-lived asset. We estimate that
accretion expense will approximate $2.1 million for 2009, $2.2 million for 2010,
$2.4 million for 2011, $2.6 million for 2012 and $2.9 million for
2013.
Certain
of our unconsolidated affiliates have AROs recorded at December 31, 2008 and
2007 relating to contractual agreements and regulatory
requirements. These amounts are immaterial to our financial
statements.
We own
interests in a number of related businesses that are accounted for using the
equity method of accounting. Our investments in and advances to
unconsolidated affiliates are grouped according to the business segment to which
they relate. See Note 16 for a general discussion of our business
segments. The following table shows our investments in and advances
to unconsolidated affiliates at the dates indicated.
|
|
|
Ownership
|
|
|
|
|
|
|
|
Percentage
at
|
|
|
|
|
|
|
|
December
31,
|
|
|
December
31,
|
|
|
December
31,
|
|
|
|
|
2008
|
|
|
2008
|
|
|
2007
|
|
|
NGL
Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
Venice
Energy Service Company, L.L.C. (“VESCO”)
|
|
13.1%
|
|
|
$ |
37,673 |
|
|
$ |
40,129 |
|
|
K/D/S
Promix, L.L.C. (“Promix”)
|
|
50.0%
|
|
|
|
46,380 |
|
|
|
51,537 |
|
|
Baton
Rouge Fractionators LLC (“BRF”)
|
|
32.2%
|
|
|
|
24,160 |
|
|
|
25,423 |
|
|
Skelly-Belvieu
Pipeline Company, L.L.C. (“Skelly-Belvieu”) (1)
|
|
49.0%
|
|
|
|
35,969 |
|
|
|
-- |
|
|
Onshore
Natural Gas Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jonah
Gas Gathering Company (“Jonah”)
|
|
19.4%
|
|
|
|
258,066 |
|
|
|
235,837 |
|
|
Evangeline
(2)
|
|
49.5%
|
|
|
|
4,528 |
|
|
|
3,490 |
|
|
White
River Hub, LLC (“White River Hub”) (3)
|
|
50.0%
|
|
|
|
21,387 |
|
|
|
-- |
|
|
Offshore
Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Poseidon
Oil Pipeline, L.L.C. (“Poseidon”)
|
|
36.0%
|
|
|
|
60,233 |
|
|
|
58,423 |
|
|
Cameron
Highway Oil Pipeline Company (“Cameron Highway”) (4)
|
|
50.0%
|
|
|
|
250,833 |
|
|
|
256,588 |
|
|
Deepwater
Gateway, L.L.C. (“Deepwater Gateway”)
|
|
50.0%
|
|
|
|
104,784 |
|
|
|
111,221 |
|
|
Neptune
|
|
25.7%
|
|
|
|
52,671 |
|
|
|
55,468 |
|
|
Nemo
(5)
|
|
33.9%
|
|
|
|
432 |
|
|
|
2,888 |
|
|
Texas
Offshore Port System
|
|
33.3%
|
|
|
|
35,890 |
|
|
|
-- |
|
|
Petrochemical
Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Baton
Rouge Propylene Concentrator, LLC (“BRPC”)
|
|
30.0%
|
|
|
|
12,633 |
|
|
|
13,282 |
|
|
La
Porte (6)
|
|
50.0%
|
|
|
|
3,887 |
|
|
|
4,053 |
|
|
Total
|
|
|
|
|
|
$ |
949,526 |
|
|
$ |
858,339 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
In
December 2008, we acquired a 49.0% ownership interest in
Skelly-Belvieu.
(2)
Refers
to our ownership interests in Evangeline Gas Pipeline Company, L.P. and
Evangeline Gas Corp., collectively.
(3)
In
February 2008, we acquired a 50.0% ownership interest in White River
Hub.
(4)
During
the year ended December 31, 2007, we contributed $216.5 million to Cameron
Highway to fund our portion of the repayment of Cameron Highway’s
debt.
(5)
The
December 31, 2007 amount includes a $7.0 million non-cash impairment
charge attributable to our investment in Nemo.
(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 a company exceeds
the underlying book value of the capital accounts we acquire. Such
excess cost amounts are included within the carrying values of our
investments in and advances to unconsolidated affiliates. At December
31, 2008 and 2007, our investments in Promix, La Porte, Neptune, Poseidon,
Cameron Highway and Jonah included excess cost amounts totaling $43.7 million
and $43.8 million, respectively, all of which were attributable to the fair
value of the underlying tangible assets of these entities exceeding their book
carrying values at the time of our acquisition of interests in these
entities. To the extent that we attribute all or a portion of an
excess cost amount to higher fair values, 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. Amortization of such excess cost amounts was $2.1
million, $2.6 million and $2.1 million for the years ended December 31,
2008, 2007 and 2006, respectively.
The
following table presents our equity in earnings of unconsolidated affiliates for
the periods indicated:
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
NGL
Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
VESCO
|
|
$ |
(1,519 |
) |
|
$ |
3,507 |
|
|
$ |
1,719 |
|
|
Promix
|
|
|
1,977 |
|
|
|
514 |
|
|
|
1,353 |
|
|
BRF
|
|
|
1,003 |
|
|
|
2,010 |
|
|
|
2,643 |
|
|
Skelly-Belvieu
|
|
|
(31 |
) |
|
|
-- |
|
|
|
-- |
|
|
Onshore
Natural Gas Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Evangeline
|
|
|
896 |
|
|
|
183 |
|
|
|
958 |
|
|
Coyote
Gas Treating, LLC (“Coyote”)
|
|
|
-- |
|
|
|
-- |
|
|
|
1,676 |
|
|
Jonah
|
|
|
21,408 |
|
|
|
9,357 |
|
|
|
238 |
|
|
White
River Hub
|
|
|
655 |
|
|
|
-- |
|
|
|
-- |
|
|
Offshore
Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Poseidon
|
|
|
6,883 |
|
|
|
10,020 |
|
|
|
11,310 |
|
|
Cameron
Highway
|
|
|
16,358 |
|
|
|
(11,200 |
) |
|
|
(11,000 |
) |
|
Deepwater
Gateway
|
|
|
17,062 |
|
|
|
20,606 |
|
|
|
18,392 |
|
|
Neptune (1)
|
|
|
(5,683 |
) |
|
|
(821 |
) |
|
|
(8,294 |
) |
|
Nemo
(2)
|
|
|
(973 |
) |
|
|
(5,977 |
) |
|
|
1,501 |
|
|
Texas
Offshore Port System
|
|
|
(38 |
) |
|
|
-- |
|
|
|
-- |
|
|
Petrochemical
Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BRPC
|
|
|
1,877 |
|
|
|
2,266 |
|
|
|
1,864 |
|
|
La
Porte
|
|
|
(771 |
) |
|
|
(807 |
) |
|
|
(795 |
) |
|
Total
|
|
$ |
59,104 |
|
|
$ |
29,658 |
|
|
$ |
21,565 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Equity
in earnings from Neptune for 2006 include a $7.4 million non-cash
impairment charge.
(2) Equity
in earnings from Nemo for 2007 include a $7.0 million non-cash impairment
charge.
|
|
NGL
Pipelines & Services
At December 31, 2008, 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 facility and related assets located
in south Louisiana.
Promix. We own a 50.0%
interest in Promix, which owns an NGL fractionation facility and related storage
and pipeline assets located in south Louisiana.
BRF. We own an
approximate 32.2% interest in BRF, which owns an NGL fractionation facility
located in south Louisiana.
Skelly-Belvieu. In
December 2008, we acquired a 49.0% interest in Skelly-Belvieu for $36.0
million. Skelly-Belvieu owns a 570-mile pipeline that transports
mixed NGLs to markets in southeast Texas.
The
combined balance sheet information for the last two years and results of
operations data for the last three years of this segment’s current
unconsolidated affiliates are summarized below.
|
|
|
At
December 31,
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
|
BALANCE
SHEET DATA:
|
|
|
|
|
|
|
|
|
Current
assets
|
|
$ |
64,080 |
|
|
$ |
112,352 |
|
|
|
Property,
plant and equipment, net
|
|
|
368,059 |
|
|
|
270,586 |
|
|
|
Other
assets
|
|
|
2,011 |
|
|
|
11,686 |
|
|
|
Total
assets
|
|
$ |
434,150 |
|
|
$ |
394,624 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
liabilities
|
|
$ |
50,180 |
|
|
$ |
75,314 |
|
|
|
Other
liabilities
|
|
|
24,271 |
|
|
|
9,095 |
|
|
|
Combined
equity
|
|
|
359,699 |
|
|
|
310,215 |
|
|
|
Total
liabilities and combined equity
|
|
$ |
434,150 |
|
|
$ |
394,624 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
2006
|
|
INCOME
STATEMENT DATA:
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
271,263 |
|
|
$ |
220,381 |
|
$ 190,320
|
|
Operating
income (loss)
|
|
|
20,518 |
|
|
|
41,147 |
|
(26,885)
|
|
Net
income (loss)
|
|
|
20,872 |
|
|
|
26,506 |
|
(25,543)
|
Onshore
Natural Gas Pipelines & Services
At December 31, 2008, 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 located in south Louisiana. A subsidiary of Acadian Gas, LLC
owns the Evangeline interests, which were contributed to Duncan Energy Partners
in February 2007 in connection with its initial public offering (see Note
17).
Coyote. We owned a 50.0% interest
in Coyote during 2005, which owns a natural gas treating facility located in the
San Juan Basin of southwestern Colorado. During 2006, we sold
our interest in Coyote and recorded a gain on the sale of $3.3
million.
Jonah. Our equity interest in
Jonah at December 31, 2008 is based on capital contributions we made to Jonah in
connection with its Phase V expansion project. We completed Phase I
of this expansion in July 2007 entitling us to approximately 19.4% in earnings
and ownership with the remaining 80.6% entitlement to TEPPCO. See
Note 17 for additional information regarding our Jonah
affiliate. Jonah owns the Jonah Gas Gathering System located in the
Greater Green River Basin of southwestern Wyoming.
White
River
Hub.
We own a 50.0% interest in White River Hub, which owns a natural gas hub
located in northwest Colorado. The hub was completed in December
2008.
The
combined balance sheet information for the last two years and results of
operations data for the last three years of this segment’s current
unconsolidated affiliates are summarized below.
|
|
|
At
December 31,
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
|
BALANCE
SHEET DATA:
|
|
|
|
|
|
|
|
|
Current
assets
|
|
$ |
97,470 |
|
|
$ |
83,962 |
|
|
|
Property,
plant and equipment, net
|
|
|
1,082,251 |
|
|
|
915,572 |
|
|
|
Other
assets
|
|
|
158,682 |
|
|
|
176,091 |
|
|
|
Total
assets
|
|
$ |
1,338,403 |
|
|
$ |
1,175,625 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
liabilities
|
|
$ |
62,147 |
|
|
$ |
43,951 |
|
|
|
Other
liabilities
|
|
|
21,890 |
|
|
|
25,002 |
|
|
|
Combined
equity
|
|
|
1,254,366 |
|
|
|
1,106,672 |
|
|
|
Total
liabilities and combined equity
|
|
$ |
1,338,403 |
|
|
$ |
1,175,625 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
2006
|
|
INCOME
STATEMENT DATA:
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
605,353 |
|
|
$ |
477,077 |
|
$ 372,240
|
|
Operating
income
|
|
|
118,907 |
|
|
|
98,549 |
|
48,387
|
|
Net
income
|
|
|
114,911 |
|
|
|
93,491 |
|
40,608
|
Offshore
Pipelines & Services
At December 31, 2008, our Offshore
Pipelines & Services segment included the following unconsolidated
affiliates accounted for using the equity method:
Poseidon. We
own a 36.0% 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 50.0%
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.
Cameron
Highway repaid its $365.0 million Series A notes and $50.0 million Series B
notes in 2007 using cash contributions from its partners. We funded
our 50.0% share of the capital contributions using borrowings under EPO’s
Multi-Year Revolving Credit Facility. Cameron Highway incurred a
$14.1 million make-whole premium in connection with the repayment of its Series
A notes.
Deepwater
Gateway. We own a 50.0%
interest in Deepwater Gateway, which owns the Marco Polo platform located in 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 Manta Ray Offshore Gathering System (“Manta Ray”) and
Nautilus Pipeline System (“Nautilus”), 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.
Texas Offshore
Port
System. In
August 2008, we, together with TEPPCO and Oiltanking Holding Americas, Inc.
(“Oiltanking”), announced the formation of the Texas Offshore Port System, a
joint venture to design, construct, operate and own a Texas offshore crude oil
port and a related onshore pipeline and storage system that would facilitate
delivery of waterborne crude oil to refining centers located along the
upper
Texas Gulf Coast. Demand for such projects is being driven by planned and
expected refinery expansions along the Gulf Coast, expected increases in
shipping traffic and operating limitations of regional ship channels. We own a one-third
interest in the Texas Offshore Port System. See Note 17 for
additional information regarding this joint venture.
The
combined balance sheet information for the last two years and results of
operations data for the last three years of this segment’s current
unconsolidated affiliates are summarized below.
|
|
|
At
December 31,
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
|
BALANCE
SHEET DATA:
|
|
|
|
|
|
|
|
|
Current
assets
|
|
$ |
106,392 |
|
|
$ |
46,795 |
|
|
|
Property,
plant and equipment, net
|
|
|
1,184,549 |
|
|
|
1,122,108 |
|
|
|
Other
assets
|
|
|
3,608 |
|
|
|
4,338 |
|
|
|
Total
assets
|
|
$ |
1,294,549 |
|
|
$ |
1,173,241 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
liabilities
|
|
$ |
58,379 |
|
|
$ |
19,720 |
|
|
|
Other
liabilities
|
|
|
116,654 |
|
|
|
96,791 |
|
|
|
Combined
equity
|
|
|
1,119,516 |
|
|
|
1,056,730 |
|
|
|
Total
liabilities and combined equity
|
|
$ |
1,294,549 |
|
|
$ |
1,173,241 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
2006
|
|
INCOME
STATEMENT DATA:
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
163,916 |
|
|
$ |
156,780 |
|
$ 153,996
|
|
Operating
income
|
|
|
68,969 |
|
|
|
85,550 |
|
71,977
|
|
Net
income
|
|
|
65,554 |
|
|
|
53,590 |
|
42,732
|
Neptune
owns Manta Ray and Nautilus. Manta Ray gathers natural gas
originating 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 the Nautilus
pipeline. Nautilus connects our Manta Ray pipeline to our Neptune
natural gas processing plant located in south Louisiana. Due to a
recent decrease in throughput volumes on the Manta Ray and Nautilus pipelines,
we evaluated our 25.7% investment in Neptune for impairment during the third
quarter of 2006. The decrease in throughput volumes is primarily due
to underperformance of certain fields, natural depletion and hurricane-related
delays in starting new production. These factors contributed to
significant delays in throughput volumes Neptune expects to
receive. As a result, Neptune has experienced operating losses in
recent periods.
Our
review of Neptune’s estimated cash flows during the third quarter of 2006
indicated that the carrying value of our investment exceeded its fair value,
which resulted in a non-cash impairment charge of $7.4 million. This
loss is recorded as a component of “Equity in earnings of unconsolidated
affiliates” in our Statement of Consolidated Operations for the year ended
December 31, 2006.
Nemo was
formed in 1999 to construct, own and operate the Nemo Gathering System, a
24-mile natural gas gathering system in the Gulf of Mexico offshore
Louisiana. The Nemo Gathering System, which began operations in 2001,
gathers natural gas from certain developments in the Green Canyon area
of the Gulf of Mexico to a pipeline interconnect with the Manta Ray Gathering
System. Due to a recent decrease in throughput volumes on the Nemo
Gathering System, we evaluated our 33.9% investment in Nemo for impairment
during the second quarter of 2007. The decrease in throughput volumes
is primarily due to underperformance of certain fields and natural
depletion.
Our
review of Nemo’s estimated future cash flows during the second quarter of 2007
indicated that the carrying value of our investment exceeded its fair value,
which resulted in a non-cash impairment charge of $7.0 million. This
loss is recorded as a component of “Equity in earnings of unconsolidated
affiliates” in our Statement of Consolidated Operations for the year ended
December 31, 2007. After
recording
this impairment charge, the carrying value of our investment in Nemo at December
31, 2007 was $2.9 million.
Our
investments in Neptune and Nemo were written down to fair value, which
management estimated using recognized business valuation
techniques. The fair value analysis is based upon management’s
expectation of future cash flows, which incorporates certain industry
information and assumptions made by management. For example, the
individual reviews of Neptune and Nemo included management estimates regarding
natural gas reserves of producers served by both Neptune and Nemo,
respectively. If the assumptions underlying our fair value analysis
change and expected cash flows are reduced, additional impairment charges may
result.
Petrochemical
Services
At December 31, 2008, our Petrochemical
Services segment included the following unconsolidated affiliates accounted for
using the equity method:
BRPC. We own a 30.0%
interest in BRPC, which owns a propylene fractionation facility located in south
Louisiana.
La
Porte. We own an
aggregate 50.0% 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 segment’s current
unconsolidated affiliates are summarized below.
|
|
|
At
December 31,
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
|
BALANCE
SHEET DATA:
|
|
|
|
|
|
|
|
|
Current
assets
|
|
$ |
3,634 |
|
|
$ |
3,187 |
|
|
|
Property,
plant and equipment, net
|
|
|
43,720 |
|
|
|
47,322 |
|
|
|
Total
assets
|
|
$ |
47,354 |
|
|
$ |
50,509 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
liabilities
|
|
$ |
1,737 |
|
|
$ |
970 |
|
|
|
Other
liabilities
|
|
|
2 |
|
|
|
2 |
|
|
|
Combined
equity
|
|
|
45,615 |
|
|
|
49,537 |
|
|
|
Total
liabilities and combined equity
|
|
$ |
47,354 |
|
|
$ |
50,509 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
2006
|
|
INCOME
STATEMENT DATA:
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
20,990 |
|
|
$ |
19,844 |
|
$ 19,014
|
|
Operating
income
|
|
|
4,666 |
|
|
|
5,961 |
|
4,626
|
|
Net
income
|
|
|
4,693 |
|
|
|
6,029 |
|
4,729
|
2008
Transactions
Our
expenditures for business combinations during the year ended December 31, 2008
were $202.2 million and primarily reflect the acquisitions described
below.
On a pro
forma consolidated basis, our revenues, costs and expenses, operating income,
net income and earnings per unit amounts would not have differed materially from
those we actually reported for 2008, 2007 and 2006 due to the immaterial nature
of our 2008 business combination transactions.
Great
Divide Gathering System Acquisition. In December 2008, one
of our affiliates, Enterprise Gas Processing, LLC, purchased a 100.0% membership
interest in Great Divide Gathering, LLC (“Great Divide”) for cash consideration
of $125.2 million. Great Divide was wholly owned by EnCana Oil & Gas
(“EnCana”).
The
assets of Great Divide consist of a 31-mile natural gas gathering system, the
Great Divide Gathering System, located in the Piceance Basin of
northwestern Colorado. The Great Divide Gathering System extends from
the southern portion of the Piceance Basin, including production from
EnCana’s Mamm Creek field, to a pipeline interconnection with our Piceance Basin
Gathering System. Volumes of natural gas originating on the Great
Divide Gathering System are transported through our Piceance Creek Gathering
System to our 1.4 Bcf/d Meeker natural gas treating and processing
complex. A significant portion of these volumes are produced by
EnCana, one of the largest natural gas producers in the region, and are
dedicated the Great Divide and Piceance Creek Gathering Systems for the life of
the associated lease holdings.
Tri-States
and Belle Rose Acquisitions. In October 2008, we
acquired additional 16.7% membership interests in both Tri-States NGL Pipeline,
L.L.C. (“Tri-States”) and Belle Rose NGL Pipeline, L.L.C. (“Belle Rose”) for
total cash consideration of $19.9 million. As a result of this
transaction, our ownership interest in Tri-States increased to
83.3%. We now own 100.0% of the membership interests in Belle
Rose.
Tri-States
owns a 194-mile NGL pipeline located along the Mississippi, Alabama and
Louisiana Gulf Coast. Belle Rose owns a 48-mile NGL pipeline
located in Louisiana. These systems, in conjunction with the Wilprise
pipeline, transport mixed NGLs to the BRF, Norco and Promix NGL fractionators
located in south Louisiana.
Acquisition
of Remaining Interest in Dixie. In August 2008, we
acquired the remaining 25.8% ownership interests in Dixie for cash consideration
of $57.1 million. As a result of this transaction, we own 100.0% of Dixie,
which owns a 1,371-mile pipeline system that delivers NGLs (primarily propane
and other chemical feedstock) to customers along the U.S. Gulf Coast and
southeastern United States.
Purchase
Price Allocations. We accounted for
business combinations completed during the year ended December 31, 2008 using
the purchase method of accounting and, accordingly, such costs have been
allocated to assets acquired and liabilities assumed based on estimated
preliminary fair values. Such preliminary values have been developed
using recognized business valuation techniques and are subject to change pending
a final valuation analysis.
|
|
Great
|
|
|
|
Belle
|
|
|
|
|
|
|
|
|
|
Divide
|
|
Tri-States
|
|
Rose
|
|
Dixie
|
|
Other
(1)
|
|
Total
|
|
|
Assets
acquired in business combination:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
assets
|
$ |
-- |
|
$ |
813 |
|
$ |
143 |
|
$ |
4,021 |
|
$ |
35 |
|
$ |
5,012 |
|
|
Property,
plant and equipment, net
|
|
70,643 |
|
|
18,417 |
|
|
1,129 |
|
|
33,727 |
|
|
(12,773 |
) |
|
111,143 |
|
|
Intangible
assets
|
|
9,760 |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
12,747 |
|
|
22,507 |
|
|
Other
assets
|
|
-- |
|
|
46 |
|
|
-- |
|
|
382 |
|
|
-- |
|
|
428 |
|
|
Total
assets acquired
|
|
80,403 |
|
|
19,276 |
|
|
1,272 |
|
|
38,130 |
|
|
9 |
|
|
139,090 |
|
|
Liabilities
assumed in business combination:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
liabilities
|
|
-- |
|
|
(581 |
) |
|
(68 |
) |
|
(2,581 |
) |
|
-- |
|
|
(3,230 |
) |
|
Long-term
debt
|
|
-- |
|
|
-- |
|
|
-- |
|
|
(2,582 |
) |
|
-- |
|
|
(2,582 |
) |
|
Other
long-term liabilities
|
|
(81 |
) |
|
-- |
|
|
(4 |
) |
|
(46,265 |
) |
|
-- |
|
|
(46,350 |
) |
|
Total
liabilities assumed
|
|
(81 |
) |
|
(581 |
) |
|
(72 |
) |
|
(51,428 |
) |
|
-- |
|
|
(52,162 |
) |
|
Total
assets acquired plus liabilities assumed
|
|
80,322 |
|
|
18,695 |
|
|
1,200 |
|
|
(13,298 |
) |
|
9 |
|
|
86,928 |
|
|
Total
cash used for business combinations
|
|
125,175 |
|
|
18,695 |
|
|
1,200 |
|
|
57,089 |
|
|
1 |
|
|
202,160 |
|
|
Goodwill
|
$ |
44,853 |
|
$ |
-- |
|
$ |
-- |
|
$ |
70,387 |
|
$ |
(8 |
) |
$ |
115,232 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Primarily
represents non-cash reclassification adjustments to December 2007
preliminary fair value estimates for assets acquired in the South Monco
natural gas pipeline business (“South Monco”)
acquisition.
|
|
As a
result of our 100% ownership interest in Dixie, we used push-down accounting to
record this business combination. In doing so, a temporary tax
difference was created between the assets and liabilities of Dixie for financial
reporting and tax purposes. Dixie recorded a deferred income tax liability
of $45.1 million attributable to the temporary tax
difference.
2007
Transactions
On a pro
forma consolidated basis, our revenues, costs and expenses, operating income,
net income and earnings per unit amounts would not have differed materially from
those we actually reported for 2007 and 2006 due to immaterial nature of our
2007 business combination transactions.
Our
expenditures for business combinations during the year ended December 31, 2007
were $35.8 million, which primarily reflect the $35.0 million we spent to
acquire South Monco in December 2007. This business includes
approximately 128 miles of natural gas pipelines located in southeast
Texas. The remaining business combination related amounts for 2007
consist of purchase price adjustments to prior period transactions.
We accounted for our 2007 business
combinations using the purchase method of accounting and, accordingly, such
costs have been allocated to assets acquired and liabilities assumed based on
estimated preliminary fair values. Such preliminary values have been
developed using recognized business valuation techniques and are subject to
change pending a final valuation analysis.
2006
Transactions
Our
expenditures for business combinations during the year ended December 31, 2006
were $276.5 million and primarily reflect the Encinal and Piceance Creek
acquisitions described below.
Encinal
Acquisition. In
July 2006, we acquired the Encinal and Canales natural gas gathering systems and
related gathering and processing contracts that comprised the South Texas
natural gas transportation and processing business of an affiliate of Lewis
Energy Group, L.P. (“Lewis”). The aggregate value of total
consideration we paid or issued to complete this business combination (referred
to as the “Encinal acquisition”) was $326.3 million, which consisted of $145.2
million in cash and 7,115,844 of our common units.
The Encinal and Canales gathering
systems are located in South Texas and are connected to over 1,450 natural gas
wells producing from the Olmos and Wilcox formations. The Encinal
system consists of 449 miles of pipeline, which is comprised of 277 miles of
pipeline we acquired from Lewis in this transaction and 172 miles of pipeline
that we own and had previously leased to Lewis. The Canales gathering
system is comprised of 32 miles of pipeline. Currently, natural gas
volumes gathered by the Encinal and Canales systems are transported by our
existing Texas Intrastate System and are processed by our South Texas natural
gas processing plants.
The Encinal and Canales gathering
systems will be supported by a life of reserves gathering and processing
dedication by Lewis related to its natural gas production from the Olmos
formation. In addition, we entered into a 10-year agreement with
Lewis for the transportation of natural gas treated at its proposed Big Reef
facility. This facility will treat natural gas from the southern
portion of the Edwards Trend in South Texas. We also entered into a
10-year agreement with Lewis for the gathering and processing of rich gas it
produces from below the Olmos formation.
The total
consideration we paid or granted to Lewis in connection with the Encinal
acquisition is as follows:
|
Cash
payment to Lewis
|
|
$ |
145,197 |
|
|
Fair
value of our 7,115,844 common units issued to Lewis
|
|
|
181,112 |
|
|
Total
consideration
|
|
$ |
326,309 |
|
In accordance with purchase accounting,
the value of our common units issued to Lewis was based on the average closing
price of such units immediately prior to and after the transaction was announced
on July 12, 2006. For purposes of this calculation, the average
closing price was $25.45 per unit.
Since the closing date of the Encinal
acquisition was July 1, 2006, our Statements of Consolidated Operations do not
include any earnings from these assets prior to this date. Given the
relative size of the Encinal acquisition to our other business combination
transactions during 2006, the following table presents selected pro forma
earnings information for the year ended December 31, 2006 as if the Encinal
acquisition had been completed on January 1, 2006, instead of July 1,
2006. This information was prepared based on financial data available
to us and reflects certain estimates and assumptions made by our
management. Our pro forma financial information is not necessarily
indicative of what our consolidated financial results would have been had the
Encinal acquisition actually occurred on January 1, 2006. The amounts
shown in the following table are in millions, except per unit
amounts.
|
|
|
For
the Year Ended
|
|
|
|
|
December
31, 2006
|
|
|
Pro
forma earnings data:
|
|
|
|
|
Revenues
|
|
$ |
14,066 |
|
|
Costs
and expenses
|
|
|
13,228 |
|
|
Operating
income
|
|
|
859 |
|
|
Net
income
|
|
|
598 |
|
|
Basic
earnings per unit (“EPU”):
|
|
|
|
|
|
Units
outstanding, as reported
|
|
|
414 |
|
|
Units
outstanding, pro forma
|
|
|
422 |
|
|
Basic
EPU, as reported
|
|
$ |
1.22 |
|
|
Basic
EPU, pro forma
|
|
$ |
1.19 |
|
|
Diluted
EPU:
|
|
|
|
|
|
Units
outstanding, as reported
|
|
|
415 |
|
|
Units
outstanding, pro forma
|
|
|
422 |
|
|
Diluted
EPU, as reported
|
|
$ |
1.22 |
|
|
Diluted
EPU, pro forma
|
|
$ |
1.19 |
|
Piceance
Creek Acquisition. In December 2006, we purchased a 100.0%
interest in Piceance Creek Pipeline, LLC (“Piceance Creek”), for $100.0
million. Piceance Creek was wholly owned by EnCana.
The
assets of Piceance Creek consist of a recently constructed 48-mile natural gas
gathering pipeline, the Piceance Creek Gathering System, located in the
Piceance Basin of northwestern Colorado. The Piceance Creek Gathering
System has a transportation capacity of 1.6 Bcf/d of natural gas and
extends from a connection with EnCana’s Great Divide Gathering System located
near Parachute, Colorado, northward through the heart of the Piceance Basin to
our 1.4 Bcf/d Meeker natural gas treating and processing complex.
Connectivity to EnCana’s Great Divide Gathering System (see above for
our purchase of this system in 2008) will provide the Piceance Creek Gathering
System with access to production from the southern portion of the Piceance
basin, including production from EnCana’s Mamm Creek field. The
Piceance Creek Gathering System was placed in service in January
2007 and began transporting initial volumes of approximately 300 million
cubic feet per day (“MMcf/d”) of natural gas. In conjunction with our
acquisition of Piceance Creek, EnCana signed a long-term, fixed fee gathering
agreement with us and dedicated significant production to the Piceance Creek
Gathering System for the life of the associated lease holdings.
Other
Transactions. In addition to the Encinal and Piceance Creek
acquisitions, our business combinations during 2006 included the purchase of (i)
an additional 8.2% ownership interest in Dixie for $12.9 million, (ii) all of
the capital stock of an affiliated NGL marketing company located in Canada from
related parties for $17.7 million (see Note 17) and (iii) a storage business in
Flagstaff, Arizona for $0.7 million.
Identifiable
Intangible Assets
The
following table summarizes our intangible assets at the dates
indicated:
|
|
At
December 31, 2008
|
|
At
December 31, 2007
|
|
|
Gross
|
|
Accum.
|
|
Carrying
|
|
Gross
|
|
Accum.
|
|
Carrying
|
|
|
Value
|
|
Amort.
|
|
Value
|
|
Value
|
|
Amort.
|
|
Value
|
|
NGL
Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
Shell
Processing Agreement
|
$ |
206,216 |
|
$ |
(89,299 |
) |
$ |
116,917 |
|
$ |
206,216 |
|
$ |
(78,252 |
) |
$ |
127,964 |
|
Encinal
gas processing customer relationship
|
|
127,119 |
|
|
(28,045 |
) |
|
99,074 |
|
|
127,119 |
|
|
(17,470 |
) |
|
109,649 |
|
STMA
and GulfTerra NGL Business
customer
relationships
|
|
49,784 |
|
|
(21,570 |
) |
|
28,214 |
|
|
49,784 |
|
|
(17,537 |
) |
|
32,247 |
|
Pioneer
gas processing contracts
|
|
37,752 |
|
|
(3,601 |
) |
|
34,151 |
|
|
37,752 |
|
|
(736 |
) |
|
37,016 |
|
Markham
NGL storage contracts
|
|
32,664 |
|
|
(18,509 |
) |
|
14,155 |
|
|
32,664 |
|
|
(14,154 |
) |
|
18,510 |
|
Toca-Western
contracts
|
|
31,229 |
|
|
(10,280 |
) |
|
20,949 |
|
|
31,229 |
|
|
(8,718 |
) |
|
22,511 |
|
Other
(1)
|
|
52,295 |
|
|
(14,745 |
) |
|
37,550 |
|
|
35,261 |
|
|
(10,087 |
) |
|
25,174 |
|
Segment
total
|
|
537,059 |
|
|
(186,049 |
) |
|
351,010 |
|
|
520,025 |
|
|
(146,954 |
) |
|
373,071 |
|
Onshore
Natural Gas Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
San
Juan Gathering System customer relationships
|
|
331,311 |
|
|
(92,471 |
) |
|
238,840 |
|
|
331,311 |
|
|
(73,087 |
) |
|
258,224 |
|
Petal
& Hattiesburg natural gas storage contracts
|
|
100,499 |
|
|
(36,524 |
) |
|
63,975 |
|
|
100,499 |
|
|
(27,931 |
) |
|
72,568 |
|
Other
(2)
|
|
41,501 |
|
|
(10,854 |
) |
|
30,647 |
|
|
31,741 |
|
|
(8,381 |
) |
|
23,360 |
|
Segment
total
|
|
473,311 |
|
|
(139,849 |
) |
|
333,462 |
|
|
463,551 |
|
|
(109,399 |
) |
|
354,152 |
|
Offshore
Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Offshore
pipeline & platform customer relationships
|
|
205,845 |
|
|
(90,686 |
) |
|
115,159 |
|
|
205,845 |
|
|
(73,905 |
) |
|
131,940 |
|
Other
|
|
1,167 |
|
|
(107 |
) |
|
1,060 |
|
|
1,167 |
|
|
(49 |
) |
|
1,118 |
|
Segment
total
|
|
207,012 |
|
|
(90,793 |
) |
|
116,219 |
|
|
207,012 |
|
|
(73,954 |
) |
|
133,058 |
|
Petrochemical
Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mont
Belvieu propylene fractionation contracts
|
|
53,000 |
|
|
(10,474 |
) |
|
42,526 |
|
|
53,000 |
|
|
(8,960 |
) |
|
44,040 |
|
Other
(3)
|
|
14,906 |
|
|
(2,707 |
) |
|
12,199 |
|
|
14,906 |
|
|
(2,227 |
) |
|
12,679 |
|
Segment
total
|
|
67,906 |
|
|
(13,181 |
) |
|
54,725 |
|
|
67,906 |
|
|
(11,187 |
) |
|
56,719 |
|
Total
all segments
|
$ |
1,285,288 |
|
$ |
(429,872 |
) |
$ |
855,416 |
|
$ |
1,258,494 |
|
$ |
(341,494 |
) |
$ |
917,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
In
2008, we acquired $6.0 million of certain permits related to our Mont
Belvieu complex and had $12.7 million of purchase price allocation
adjustments related
to San Felipe customer relationships from the December 2007 South Monco
acquisition.
(2)
In
2008, we acquired $9.8 million of customer relationships due to the Great
Divide business combination.
(3)
In
2007, we paid $11.2 million for certain air emission credits related to
our Morgan’s Point facility.
|
The
following table presents the amortization expense of our intangible assets by
segment for the periods indicated:
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
NGL
Pipelines & Services
|
|
$ |
39,095 |
|
|
$ |
36,419 |
|
|
$ |
31,159 |
|
|
Onshore
Natural Gas Pipelines & Services
|
|
|
30,450 |
|
|
|
31,997 |
|
|
|
33,447 |
|
|
Offshore
Pipelines & Services
|
|
|
16,839 |
|
|
|
19,318 |
|
|
|
22,156 |
|
|
Petrochemical
Services
|
|
|
1,994 |
|
|
|
1,993 |
|
|
|
1,993 |
|
|
Total
all segments
|
|
$ |
88,378 |
|
|
$ |
89,727 |
|
|
$ |
88,755 |
|
We
estimate that amortization expense associated with existing intangible assets
will approximate $82.7 million in 2009, $77.8 million in 2010, $71.9 million in
2011, $62.3 million in 2012 and $56.4 million in 2013.
In general, our intangible assets fall
within two categories – contract-based intangible assets and customer
relationships. Contract-based intangible assets represent commercial
rights we acquired in connection with business combinations or asset
purchases. Customer relationship intangible assets represent customer
bases that we acquired in connection with business combinations and asset
purchases. The values assigned to intangible assets are amortized to
earnings using either (i) a straight-line approach
or (ii)
other methods that closely resemble the pattern in which the economic benefits
of associated resource bases are estimated to be consumed or otherwise used, as
appropriate.
We acquired $141.3 million of
intangible assets primarily attributable to customer relationships we acquired
in connection with the Encinal acquisition. The $132.9 million of
intangible assets we acquired in connection with the Encinal acquisition (see
Note 12) represents the value we assigned to customer relationships,
particularly the long-term relationship we now have with Lewis through natural
gas processing and gathering arrangements. We recorded $127.1 million
in our NGL Pipelines & Services segment associated with processing
arrangements and $5.8 million in our Onshore Natural Gas Pipelines &
Services segment associated with gathering arrangements. These
intangible assets will be amortized to earnings over a 20-year life using
methods that closely resemble the pattern in which we estimate the depletion of
the underlying natural gas resources to occur.
We
acquired numerous customer relationship and contract-based intangible assets in
connection with the GulfTerra Merger. The customer relationship
intangible assets represent the exploration and production, natural gas
processing and NGL fractionation customer bases served by GulfTerra and the
South Texas midstream assets at the time the merger was
completed. The contract-based intangible assets represent the rights
we acquired in connection with discrete contracts to provide storage services
for natural gas and NGLs that GulfTerra had entered into prior to the
merger.
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
reserve estimates, the economic viability of production and exploration
activities and other industry factors. This group of intangible
assets primarily consists of the (i) Offshore Pipelines & Platforms customer
relationships; (ii) San Juan Gathering System customer relationships; (iii)
Texas Intrastate pipeline customer relationships; and (iv) STMA and GulfTerra
NGL Business customer relationships.
The contract-based intangible assets we
acquired in connection with the GulfTerra Merger are being amortized over the
estimated useful life (or term) of each agreement, which we estimate to range
from two to eighteen years. This group of intangible assets consists
of the (i) Petal and Hattiesburg natural gas storage contracts and (ii) Markham
NGL storage contracts.
The Shell
Processing Agreement grants us the right to process Shell’s (or its assignee’s)
current and future production within the state and federal waters of the Gulf of
Mexico. We acquired this intangible asset in connection with our 1999
purchase of certain of Shell’s midstream energy assets located along the
Gulf Coast. The value of the Shell Processing Agreement is being amortized
on a straight-line basis over the remainder of its initial 20-year contract term
through 2019.
Goodwill
Goodwill
represents the excess of the purchase price of an acquired business over the
amounts assigned to assets acquired and liabilities assumed in the
transaction. Goodwill is not amortized; however, it is subject to
annual impairment testing. The following table summarizes our
goodwill amounts by segment at the dates indicated:
|
|
|
At
December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
NGL
Pipelines & Services
|
|
|
|
|
|
|
|
GulfTerra
Merger
|
|
$ |
23,854 |
|
|
$ |
23,854 |
|
|
Acquisition
of Indian Springs natural gas processing business
|
|
|
13,162 |
|
|
|
13,162 |
|
|
Acquisition
of Encinal
|
|
|
95,272 |
|
|
|
95,280 |
|
|
Acquisition
of interest in Dixie
|
|
|
80,279 |
|
|
|
9,892 |
|
|
Acquisition
of Great Divide
|
|
|
44,853 |
|
|
|
-- |
|
|
Other
|
|
|
11,518 |
|
|
|
11,518 |
|
|
Onshore
Natural Gas Pipelines & Services
|
|
|
|
|
|
|
|
|
|
GulfTerra
Merger
|
|
|
279,956 |
|
|
|
279,956 |
|
|
Acquisition
of Indian Springs natural gas gathering business
|
|
|
2,165 |
|
|
|
2,165 |
|
|
Offshore
Pipelines & Services
|
|
|
|
|
|
|
|
|
|
GulfTerra
Merger
|
|
|
82,135 |
|
|
|
82,135 |
|
|
Petrochemical
Services
|
|
|
|
|
|
|
|
|
|
Acquisition
of Mont Belvieu propylene fractionation business
|
|
|
73,690 |
|
|
|
73,690 |
|
|
Total
|
|
$ |
706,884 |
|
|
$ |
591,652 |
|
In 2008,
our only significant changes to goodwill were the recording of $70.4 million in
connection with our acquisition of the remaining third party interest in Dixie
and $44.9 million in connection with the acquisition of Great
Divide. The remaining ownership interests in Dixie were acquired from
Amoco Pipeline Holding Company in August 2008. Management
attributes the goodwill to future earnings growth on the Dixie
Pipeline. Specifically, a 100.0% ownership interest in the Dixie
Pipeline will increase our flexibility to pursue future
opportunities. Great Divide was acquired from EnCana in December
2008. The Great Divide goodwill is attributable to management’s
expectations of future benefits derived from incremental natural gas processing
margins and other downstream activities. The Dixie and Great Divide
goodwill amounts are recorded as part of the NGL Pipelines & Services
business segment due to management’s belief that such future benefits will
accrue to businesses classified within this segment. For additional
information see Note 12.
Goodwill
recorded in connection with the GulfTerra Merger can be attributed to our belief
(at the time the merger was consummated) that the combined partnerships would
benefit from the strategic location of each partnership’s assets and the
industry relationships that each possessed. In addition, we expected
that various operating synergies could develop (such as reduced general and
administrative costs and interest savings) that would result in improved
financial results for the merged entity. Based on miles of pipelines,
GulfTerra was one of the largest natural gas gathering and transportation
companies in the United States, serving producers in the central and western
Gulf of Mexico and onshore in Texas and New Mexico. These regions
offer us significant growth potential through the acquisition and construction
of additional pipelines, platforms, processing and storage facilities and other
midstream energy infrastructure.
Management
attributes goodwill recorded in connection with the Encinal acquisition to
potential future benefits we may realize from our other south Texas processing
and NGL businesses as a result of acquiring the Encinal
business. Specifically, our acquisition of the long-term dedication
rights associated with the Encinal business is expected to add value to our
south Texas processing facilities and related NGL businesses due to increased
volumes. The Encinal goodwill is recorded as part of the NGL
Pipelines & Services business segment due to management’s belief that such
future benefits will accrue to businesses classified within this
segment.
The
remainder of our goodwill amounts is associated with prior acquisitions,
principally that of our purchase of a propylene fractionation business in
February 2002 and our acquisition of indirect ownership interests in the Indian
Springs natural gas gathering and processing business in January
2005.
Our
consolidated debt obligations consisted of the following at the dates
indicated:
|
|
|
At
December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
EPO
senior debt obligations:
|
|
|
|
|
|
|
|
Multi-Year
Revolving Credit Facility, variable rate, due November
2012
|
|
$ |
800,000 |
|
|
$ |
725,000 |
|
|
Pascagoula
MBFC Loan, 8.70% fixed-rate, due March 2010
|
|
|
54,000 |
|
|
|
54,000 |
|
|
Petal
GO Zone Bonds, variable rate, due August 2037
|
|
|
57,500 |
|
|
|
57,500 |
|
|
Yen
Term Loan, 4.93% fixed-rate, due March 2009 (1)
|
|
|
217,596 |
|
|
|
-- |
|
|
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 F, 4.625% fixed-rate, due October 2009 (1)
|
|
|
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
|
|
|
250,000 |
|
|
|
250,000 |
|
|
Senior
Notes J, 5.75% fixed-rate, due March 2035
|
|
|
250,000 |
|
|
|
250,000 |
|
|
Senior
Notes K, 4.950% fixed-rate, due June 2010
|
|
|
500,000 |
|
|
|
500,000 |
|
|
Senior
Notes L, 6.30% fixed-rate, due September 2017
|
|
|
800,000 |
|
|
|
800,000 |
|
|
Senior
Notes M, 5.65% fixed-rate, due April 2013
|
|
|
400,000 |
|
|
|
-- |
|
|
Senior
Notes N, 6.50% fixed-rate, due January 2019
|
|
|
700,000 |
|
|
|
-- |
|
|
Senior
Notes O, 9.75% fixed-rate, due January 2014
|
|
|
500,000 |
|
|
|
-- |
|
|
Duncan
Energy Partners’ debt obligations:
|
|
|
|
|
|
|
|
|
|
DEP
I Revolving Credit Facility, variable rate, due February
2011
|
|
|
202,000 |
|
|
|
200,000 |
|
|
DEP
II Term Loan Agreement, variable rate, due December 2011
|
|
|
282,250 |
|
|
|
-- |
|
|
Dixie
Revolving Credit Facility, variable rate, due June 2010
(2)
|
|
|
-- |
|
|
|
10,000 |
|
|
Total
principal amount of senior debt obligations
|
|
|
7,813,346 |
|
|
|
5,646,500 |
|
|
EPO
Junior Subordinated Notes A, fixed/variable rate, due August
2066
|
|
|
550,000 |
|
|
|
550,000 |
|
|
EPO
Junior Subordinated Notes B, fixed/variable rate, due January
2068
|
|
|
682,700 |
|
|
|
700,000 |
|
|
Total
principal amount of senior and junior debt obligations
|
|
|
9,046,046 |
|
|
|
6,896,500 |
|
|
Other,
non-principal amounts:
|
|
|
|
|
|
|
|
|
|
Change
in fair value of debt-related financial instruments (see Note
7)
|
|
|
51,935 |
|
|
|
14,839 |
|
|
Unamortized
discounts, net of premiums
|
|
|
(7,306 |
) |
|
|
(5,194 |
) |
|
Unamortized
deferred net gains related to terminated interest rate swaps (see Note
7)
|
|
|
17,735 |
|
|
|
-- |
|
|
Total
other, non-principal amounts
|
|
|
62,364 |
|
|
|
9,645 |
|
|
Total
long-term debt
|
|
$ |
9,108,410 |
|
|
$ |
6,906,145 |
|
|
|
|
|
|
|
|
|
|
|
|
Standby
letters of credit outstanding
|
|
$ |
1,000 |
|
|
$ |
1,100 |
|
|
|
|
|
|
|
|
|
|
|
|
(1)
In
accordance with SFAS 6, Classification of Short-Term Obligations Expected
to be Refinanced, long-term and current maturities of debt reflects the
classification of such obligations at December 31, 2008. With
respect to the Yen Term Loan and Senior Notes F due in October 2009,
we have the ability to use available credit capacity under EPO’s
Multi-Year Revolving Credit Facility to fund the repayment of this
debt.
(2)
The
Dixie Revolving Credit Facility was terminated in January
2009.
|
|
Letters
of credit
At
December 31, 2008, we had $1.0 million in standby letters outstanding under
Duncan Energy Partners’ DEP I Revolving Credit Facility. At
December 31, 2007, we had $1.1 million of standby letters of credit
outstanding under Duncan Energy Partners’ DEP I Revolving Credit
Facility.
Parent-Subsidiary
guarantor relationships
Enterprise
Partners Products L.P. acts as guarantor of the consolidated debt obligations of
EPO with the exception of the DEP I Revolving Credit Facility and the DEP II
Term Loan Agreement. If EPO were to default on any of its guaranteed
debt, Enterprise Products Partners L.P. would be responsible for full repayment
of that obligation.
EPO’s
debt obligations
Multi-Year
Revolving Credit Facility. In November 2007, EPO executed an
amended and restated Multi-Year Revolving Credit Facility totaling $1.75
billion, which replaced an existing $1.25 billion multi-year revolving credit
agreement. Amounts borrowed under the amended and restated credit
agreement mature in November 2012, although EPO is permitted, 30 to 60 days
before the maturity date in effect, to convert the principal balance of the
revolving loans then outstanding into a non-revolving, one-year term loan (the
“term-out option”). There is no sublimit on the amount of standby
letters of credit that can be outstanding under the amended facility. EPO’s
borrowings under this agreement are unsecured general obligations that are
non-recourse to EPGP. We have guaranteed repayment of amounts due
under this revolving credit agreement through an unsecured
guarantee.
As defined by the credit agreement,
variable interest rates charged under this facility bear interest at a
Eurodollar rate plus an applicable margin. In addition, EPO is
required to pay a quarterly facility fee on each lender’s commitment
irrespective of commitment usage.
The
applicable margins will be increased by 0.10% per annum for each day that the
total outstanding loans and letter of credit obligations under the facility
exceeds 50.0% of the total lender commitments. Also, upon the conversion of the
revolving loans to term loans pursuant to the term-out option described above,
the applicable margin will increase by 0.125% per annum and, if immediately
prior to such conversion, the total amount of outstanding loans and letter of
credit obligations under the facility exceeds 50.0% of the total lender
commitments, the applicable margin with respect to the term loans will increase
by an additional 0.10% per annum.
EPO may increase the amount that may be
borrowed under the facility, without the consent of the lenders, by an amount
not exceeding $500.0 million by adding to the facility one or more new
lenders and/or requesting that the commitments of existing lenders be increased,
although none of the existing lenders has agreed to or is obligated to increase
its existing commitment. EPO may request unlimited one-year extensions of the
maturity date by delivering a written request to the administrative agent, but
any such extension shall be effective only if consented to by the required
lenders in their sole discretion.
The
Multi-Year Revolving Credit Facility contains various covenants related to EPO’s
ability to incur certain indebtedness; grant certain liens; enter into certain
merger or consolidation transactions; and make certain investments. The loan
agreement also requires EPO to satisfy certain financial covenants at the
end of each fiscal quarter. The credit agreement also restricts EPO’s
ability to pay cash distributions to us if a default or an event of default (as
defined in the credit agreement) has occurred and is continuing at the time such
distribution is scheduled to be paid.
Pascagoula MBFC
Loan. In connection with the construction of our Pascagoula,
Mississippi natural gas processing plant in 2000, EPO entered into a ten-year
fixed-rate loan with the Mississippi Business Finance Corporation
(“MBFC”). This loan is subject to a make-whole redemption right and
is guaranteed by us through an unsecured and unsubordinated
guarantee. The Pascagoula MBFC Loan contains certain covenants
including the maintenance of appropriate levels of insurance on the Pascagoula
facility.
The indenture agreement for this loan
contains an acceleration clause whereby if EPO’s credit rating by Moody’s
declines below Baa3 in combination with our credit rating at Standard &
Poor’s declining below BBB-, the $54.0 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.
Petal GO
Zone Bonds. In August 2007, Petal
borrowed $57.5 million from the MBFC pursuant to a loan agreement and
promissory note between Petal Gas Storage, L.L.C. (“Petal”) and the MBFC to pay
a portion of the costs of certain natural gas storage facilities located in
Petal, Mississippi. The promissory note between Petal and MBFC is
guaranteed by EPO and supported by a letter of credit issued by
Petal. On the same date, the MBFC issued $57.5 million in Gulf
Opportunity Zone Tax-Exempt (“GO Zone”) bonds to various third
parties. A portion of the GO Zone bond proceeds were being held by a
third party trustee and reflected as a component of other assets on our balance
sheet. During 2008, virtually all proceeds from the GO Zone bonds
were released by the trustee to fund construction costs associated with the
expansion of our Petal, Mississippi storage facility. At December 31,
2007, $17.9 million of the GO Zone bond proceeds remained held by the third
party trustee. The promissory note and the GO Zone bonds have
identical terms including floating interest rates and maturities of 30
years. The bonds and the associated tax incentives are authorized under
the Mississippi Business Finance Act and the Gulf Opportunity Zone Act of
2005.
Petal
MBFC Loan. In August 2007,
Petal, a wholly owned subsidiary of EPO, entered into a loan agreement and a
promissory note with the MBFC under which Petal may borrow up to $29.5
million. On the same date, the MBFC issued taxable bonds to EPO in the
maximum amount of $29.5 million. As of December 31, 2008, there was $8.9
million outstanding under the loan and the bonds. EPO will make advances
on the bonds to the MBFC and the MBFC will in turn make identical advances to
Petal under the promissory note. The promissory note and the taxable bonds
have identical terms including fixed interest rates of 5.90% and maturities
of fifteen years. The bonds and the associated tax incentives are
authorized under the Mississippi Business Finance Act. Petal may prepay on
the promissory note without penalty, and thus cause the bonds to be redeemed,
any time after one year from their date of issue. The loan and bonds are
netted in preparing our Consolidated Balance Sheets, as well the related
interest expense and income amounts are netted in preparing our Statements of
Consolidated Operations.
Japanese
Yen Term Loan. In November 2008, EPO
executed the Yen Term Loan in the amount of approximately 20.7 billion yen
(approximately $217.6 million U.S. Dollar equivalent on the closing
date). EPO’s obligations under the Yen Term Loan are not secured by
any collateral; however, the obligations are guaranteed by Enterprise Products
Partners L.P. pursuant to a guaranty agreement. The Yen Term Loan
will mature on March 30, 2009.
Under the
Yen Term Loan, interest accrues on the loan at the Tokyo Interbank Offered Rate
(“TIBOR”) plus 2.0%. EPO entered into foreign exchange currency swaps
that effectively convert the TIBOR loan into a U.S. Dollar loan with a fixed
interest rate (including the cost of the swaps) through maturity of
approximately 4.93%. As a result, EPO received US$217.6 million net
from this transaction. In addition, EPO executed a forward purchase
exchange (yen principal and interest due) for March 30, 2009 at an exchange rate
of 94.515 to eliminate foreign exchange risk, resulting in a payment of US$221.6
million on March 30, 2009. For additional information see Note
7.
364-Day
Revolving Credit Facility. In November 2008,
EPO executed a 364-Day Revolving Credit Agreement (“364-Day Revolving Credit
Facility”) in the amount of $375.0 million. EPO’s obligations under
the 364-Day Revolving Credit Facility are not secured by any collateral;
however, the obligations are guaranteed by Enterprise Products Partners L.P.
pursuant to a guaranty agreement. The 364-Day Revolving Credit
Facility will mature on November 16, 2009. As of December 31, 2008,
there were no borrowings outstanding under this credit facility.
The
364-Day Revolving Credit Facility offers the following loans, each having
different interest requirements: (i) LIBOR loans bear interest at a rate
per annum equal to LIBOR plus the applicable LIBOR
margin and (ii) Base Rate loans bear interest each day at a
rate per annum equal to the higher of (a) the rate of
interest announced by the administrative agent as its prime rate,
(b) 0.5% per annum above the Federal Funds Rate in effect on such
date , and (c) 1.0% per annum above LIBOR in effect on such date plus,
in each case, the applicable Base Rate margin.
The
commitments may be increased by an amount not to exceed $1.0 billion by adding
one or more new lenders to the facility or increasing the commitments of
existing lenders, although none of the existing lenders has agreed to or is
obligated to increase its existing commitment. With certain exceptions and after
certain time periods, if EPO issues debt with a maturity of more than three
years, the lenders’ commitments under the 364-Day Revolving Credit Facility will
be reduced to the extent of any debt proceeds, and any outstanding loans in
excess of such reduced commitments must be repaid.
Senior
Notes B through
L.
These fixed-rate notes are unsecured obligations of EPO and rank equally with
its existing and future unsecured and unsubordinated indebtedness.
They are senior to any future subordinated indebtedness. EPO’s
borrowings under these notes are non-recourse to EPGP. We have
guaranteed repayment of amounts due under these notes through an unsecured and
unsubordinated guarantee. Our guarantee of such notes is non-recourse
to EPGP. The Senior Notes are subject to make-whole redemption rights
and were issued under indentures containing certain covenants, which generally
restrict EPO’s ability, with certain exceptions, to incur debt secured by liens
and engage in sale and leaseback transactions.
EPO used
net proceeds from its issuance of Senior Notes L in 2007 to temporarily reduce
indebtedness outstanding under its Multi-Year Revolving Credit Facility and for
general partnership purposes. In October 2007, EPO used borrowing
capacity under its Multi-Year Revolving Credit Facility to repay its $500.0
million Senior Notes E.
Senior
Notes M and N. In April 2008, EPO sold
$400.0 million in principal amount of 5-year senior unsecured notes (“Senior
Notes M”) and $700.0 million in principal amount of 10-year senior unsecured
notes (“Senior Notes N”) under its universal registration
statement. Senior Notes M were issued at 99.906% of their principal
amount, have a fixed interest rate of 5.65% and mature in April
2013. Senior Notes N were issued at 99.866% of their principal
amount, have a fixed interest rate of 6.50% and mature in January
2019.
Senior
Notes M pay interest semi-annually in arrears on April 1 and October 1 of each
year. Senior Notes N pay interest semi-annually in arrears on January
31 and July 31 of each year. Net proceeds from the issuance of Senior
Notes M and N were used to temporarily reduce indebtedness outstanding under the
EPO Multi-Year Revolving Credit Facility.
Senior
Notes M and N rank equal with EPO’s existing and future unsecured and
unsubordinated indebtedness. They are senior to any existing and
future subordinated indebtedness of EPO. Senior Notes M and N are
subject to make-whole redemption rights and were issued under indentures
containing certain covenants, which generally restrict EPO’s ability, with
certain exceptions, to incur debt secured by liens and engage in sale and
leaseback transactions.
Senior
Notes O. In December
2008, EPO sold $500.0 million in principal amount of 5-year senior unsecured
notes (“Senior Notes O”) under its universal registration
statement. Senior Notes O were issued at 100.0% of their principal
amount, have a fixed interest rate of 9.75% and mature in January
2014.
Senior
Notes O pay interest semi-annually in arrears on January 31 and July 31 of each
year, commencing January 31, 2009. Net proceeds from the issuance of
Senior Notes O were used to temporarily reduce indebtedness outstanding under
the EPO Multi-Year Revolving Credit Facility.
Senior
Notes O rank equal with EPO’s existing and future unsecured and unsubordinated
indebtedness. They are senior to any existing and future subordinated
indebtedness of EPO. Senior Notes O are subject to make-whole
redemption rights and were issued under indentures containing certain covenants,
which generally restrict EPO’s ability, with certain exceptions, to incur debt
secured by liens and engage in sale and leaseback transactions.
Junior
Notes A. In the third quarter of 2006, EPO sold $550.0 million
in principal amount of fixed/floating, unsecured, long-term subordinated notes
due 2066 (“Junior Notes A”). EPO used the proceeds from this
subordinated debt to temporarily reduce borrowings outstanding under its
Multi-Year
Revolving
Credit Facility and for general partnership purposes. EPO’s payment
obligations under Junior Notes A are subordinated to all of its current and
future senior indebtedness (as defined in the related indenture
agreement). We guaranteed EPO’s repayment of amounts due under Junior
Notes A through an unsecured and subordinated guarantee.
The indenture agreement governing
Junior Notes A allows EPO to defer interest payments on one or more occasions
for up to ten consecutive years, subject to certain conditions. The
indenture agreement also provides that, unless (i) all deferred interest on
Junior Notes A has been paid in full as of the most recent interest payment
date, (ii) no event of default under the indenture agreement has occurred and is
continuing and (iii) we are not in default of our obligations under related
guarantee agreements, neither we nor EPO cannot declare or make any
distributions to any of our respective equity securities or make any payments on
indebtedness or other obligations that rank pari passu with or are
subordinated to the Junior Notes A.
The
Junior Notes A bear interest at a fixed annual rate of 8.375% from July 2006 to
August 2016, payable semi-annually in arrears in February and August of each
year, which commenced in February 2007. After August 2016, the Junior
Notes A will bear variable rate interest at an annual rate equal to the 3-month
LIBOR rate for the related interest period plus 3.708%, payable quarterly in
arrears in February, May, August and November of each year commencing in
November 2016. Interest payments may be deferred on a cumulative
basis for up to ten consecutive years, subject to the certain
provisions. The Junior Notes A mature in August 2066 and are not
redeemable by EPO prior to August 2016 without payment of a make-whole
premium.
In connection with the issuance of
Junior Notes A, EPO entered into a Replacement Capital Covenant in favor of the
covered debt holders (as defined in the underlying documents) pursuant to which
EPO agreed for the benefit of such debt holders that it would not redeem or
repurchase such junior notes unless such redemption or repurchase is made using
proceeds from the issuance of certain securities.
Junior
Notes B. EPO
sold $700.0 million in principal amount of fixed/floating, unsecured, long-term
subordinated notes due January 2068 (“Junior Notes B”) during the second quarter
of 2007. EPO used the proceeds from this subordinated debt to
temporarily reduce borrowings outstanding under its Multi-Year Revolving Credit
Facility and for general partnership purposes. EPO’s payment
obligations under Junior Notes B are subordinated to all of its current and
future senior indebtedness (as defined in the Indenture
Agreement). We have guaranteed repayment of amounts due under Junior
Notes B through an unsecured and subordinated guarantee.
The indenture agreement governing
Junior Notes B allows EPO to defer interest payments on one or more occasions
for up to ten consecutive years subject to certain conditions. During
any period in which interest payments are deferred and subject to certain
exceptions, neither we nor EPO can declare or make any distributions to any
of our respective equity securities or make any payments on indebtedness or
other obligations that rank pari passu with or are subordinate
to Junior Notes B. Junior Notes B rank pari passu with Junior Notes
A.
The
Junior Notes B will bear interest at a fixed annual rate of 7.034%
through January 15, 2018, payable semi-annually in arrears in January and
July of each year, which commenced in January 2008. After January
2018, the Junior Notes B will bear variable rate interest at the greater of (1)
the sum of the 3-month LIBOR for the related interest period plus a spread of
268 basis points or (2) 7.034% per annum, payable quarterly in arrears in
January, April, July and October of each year commencing in April
2018. Interest payments may be deferred on a cumulative basis for up
to ten consecutive years, subject to certain provisions. The Junior
Notes B mature in January 2068 and are not redeemable by EPO prior to January
2018 without payment of a make-whole premium.
In
connection with the issuance of Junior Notes B, we and EPO entered into a
Replacement Capital Covenant in favor of the covered debt holders (as named
therein) pursuant to which we and EPO agreed for the benefit of such debt
holders that neither we nor EPO would redeem or repurchase such junior
notes on
or before January 15, 2038, unless such redemption or repurchase is made from
the proceeds of issuance of certain securities.
During
the fourth quarter of 2008, we retired $17.3 million of our Junior Notes B
for $10.2 million. The $7.1 million gain on extinguishment of debt is
included in “Other, net” on our Statement of Consolidated
Operations.
Duncan
Energy Partners’ debt obligations
We
consolidate the debt of Duncan Energy Partners with that of our own; however, we
do not have the obligation to make interest payments or debt payments with
respect to the debt of Duncan Energy Partners.
DEP
I Revolving
Credit
Facility. In February
2007, Duncan Energy Partners entered into a $300.0 million revolving credit
facility, all of which may be used for letters of credit, with a $30.0 million
sublimit for Swingline loans. Letters of credit outstanding under
this facility reduce the amount available for borrowings. At the
closing of its initial public offering, Duncan Energy Partners made its initial
borrowing of $200.0 million under the facility to fund a $198.9 million cash
distribution to EPO and the remainder to pay debt issuance costs. At
December 31, 2008, the principal balance outstanding under this facility was
$202.0 million.
This
credit facility matures in February 2011 and will be used by Duncan Energy
Partners in the future to fund working capital and other capital requirements
and for general partnership purposes. Duncan Energy Partners may make
up to two requests for one-year extensions of the maturity date (subject to
certain restrictions). The revolving credit facility is available to
pay distributions upon the initial contribution of assets to Duncan Energy
Partners, fund working capital, make acquisitions and provide payment for
general purposes. Duncan Energy Partners can increase the revolving
credit facility, without consent of the lenders, by an amount not to exceed
$150.0 million by adding to the facility one or more new lenders and/or
increasing the commitments of existing lenders. No existing lender is
required to increase its commitment, unless it agrees to do so in its sole
discretion.
This revolving credit facility offers
the following unsecured loans, each having different interest requirements: (i)
a Eurodollar rate, plus the applicable Eurodollar margin (as defined in the
credit agreement), (ii) Base Rate loans bear interest at a rate per annum equal
to the higher of (a) the rate of interest publicly announced by the
administrative agent, Wachovia Bank, National Association, as its Base Rate and
(b) 0.5% per annum above the Federal Funds Rate in effect on such date and (iii)
Swingline loans bear interest at a rate per annum equal to LIBOR plus an
applicable LIBOR margin.
The Duncan Energy Partners’ credit
facility contains certain financial and other customary
covenants. Also, if an event of default exists under the credit
agreement, the lenders will be able to accelerate the maturity date of amounts
borrowed under the credit agreement and exercise other rights and
remedies.
DEP II
Term Loan Agreement. In April 2008,
Duncan Energy Partners entered into a standby term loan agreement consisting of
commitments for up to a $300.0 million senior unsecured term
loan. Subsequently, commitments under this agreement decreased to
$282.3 million due to bankruptcy of one of the lenders. Duncan Energy Partners
borrowed the full amount of $282.3 million on December 8, 2008 in connection
with the acquisition of equity interests in the DEP II Midstream
Businesses. See “Relationship with Duncan Energy Partners” in Note 17
for additional information regarding the DEP II Midstream
Businesses.
Loans under the term loan agreement are
due and payable on December 8, 2011. Duncan Energy Partners may also prepay
loans under the term loan agreement at any time, subject to prior notice in
accordance with the credit agreement. Loans may also be payable earlier in
connection with an event of default.
Loans under the term loan agreement
bear interest of the type specified in the applicable borrowing request, and
consist of either Alternate Base Rate (“ABR”) loans or Eurodollar loans.
The term loan agreement contains customary affirmative and negative
covenants.
Dixie
Revolving Credit Facility
Dixie’s
debt obligation consisted of a senior, unsecured revolving credit facility
having a borrowing capacity of $28.0 million. As of December 31,
2008, there were no debt obligations outstanding under the Dixie
Revolver. This credit facility was terminated in January
2009. EPO consolidated the debt of Dixie; however, EPO did not have
the obligation to make interest or debt payments with respect to Dixie’s
debt.
Variable
interest rates charged under this facility generally bore interest, at Dixie’s
election at the time of each borrowing, at either (i) a Eurodollar rate plus an
applicable margin or (ii) the greater of (a) the prime rate or (b) the Federal
Funds Effective Rate plus 0.5%.
Canadian
Debt Obligation
In May
2007, Canadian Enterprise Gas Products, Ltd. (“Canadian Enterprise”), a wholly
owned subsidiary of EPO, entered into a $30.0 million Canadian revolving credit
facility with The Bank of Nova Scotia. The credit facility, which
includes the issuance of letters of credit, matures in October
2011. Letters of credit outstanding under this facility reduce the
amount available for borrowings.
Borrowings
may be made in Canadian or U.S. dollars. Canadian denominated
borrowings may be comprised of Canadian Prime Rate (“CPR”) loans or Bankers’
Acceptances and U.S. denominated borrowings may be comprised of ABR or
Eurodollar loans, each having different interest rate
requirements. CPR loans bear interest at a rate determined by
reference to the Canadian Prime Rate. ABR loans bear interest at a
rate determined by reference to an alternative base rate as defined in the
credit agreement. Eurodollar loans bear interest at a rate determined
by the LIBOR plus an applicable rate as defined in the credit
agreement. Bankers’ Acceptances carry interest at the rate for
Canadian bankers’ acceptances plus an applicable rate as defined in the credit
agreement.
The
credit facility contains customary covenants and events of
default. The restrictive covenants limit Canadian Enterprise from
materially changing the nature of its business or operations, dissolving, or
completing mergers. A continuing event of default would accelerate
the maturity of amounts borrowed under the credit facility. The
obligations under the credit facility are guaranteed by EPO. As of
December 31, 2008, there were no debt obligations outstanding under this credit
facility.
Covenants
We are in
compliance with the covenants of our consolidated debt agreements at December
31, 2008 and 2007.
Information
regarding variable interest rates paid
The
following table shows the range of interest rates paid and weighted-average
interest rate paid on our consolidated variable-rate debt obligations during the
year ended December 31, 2008.
|
|
Range
of
|
|
Weighted-Average
|
|
|
|
Interest
Rates
|
|
Interest
Rate
|
|
|
|
Paid
|
|
Paid
|
|
|
EPO’s
Multi-Year Revolving Credit Facility
|
0.97%
to 6.00%
|
|
3.54%
|
|
|
DEP
I Revolving Credit Facility
|
1.30%
to 6.20%
|
|
4.25%
|
|
|
DEP
II Term Loan Agreement
|
2.93%
to 2.93%
|
|
2.93%
|
|
|
Dixie
Revolving Credit Facility
|
0.81%
to 5.50%
|
|
3.20%
|
|
|
Petal
GO Zone Bonds
|
0.78%
to 7.90%
|
|
2.24%
|
|
Consolidated
debt maturity table
The
following table presents the scheduled maturities of principal amounts of our
debt obligations for the next five years and in total thereafter.
|
2009
|
|
$ |
-- |
|
|
2010
|
|
|
554,000 |
|
|
2011
|
|
|
934,250 |
|
|
2012
|
|
|
1,517,596 |
|
|
2013
|
|
|
750,000 |
|
|
Thereafter
|
|
|
5,290,200 |
|
|
Total
scheduled principal payments
|
|
$ |
9,046,046 |
|
Debt
Obligations of Unconsolidated Affiliates
We have
two unconsolidated affiliates with long-term debt obligations. The
following table shows (i) our ownership interest in each entity at December 31,
2008, (ii) total debt of each unconsolidated affiliate at December 31, 2008 (on
a 100.0% basis to the affiliate) and (iii) the corresponding scheduled
maturities of such debt.
|
|
|
Our
|
|
|
|
|
|
Scheduled
Maturities of Debt
|
|
|
|
|
Ownership
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
After
|
|
|
|
|
Interest
|
|
|
Total
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
2013
|
|
|
Poseidon
|
|
36.0%
|
|
|
$ |
109,000 |
|
|
$ |
-- |
|
|
$ |
-- |
|
|
$ |
109,000 |
|
|
$ |
-- |
|
|
$ |
-- |
|
|
$ |
-- |
|
|
Evangeline
|
|
49.5%
|
|
|
|
15,650 |
|
|
|
5,000 |
|
|
|
3,150 |
|
|
|
7,500 |
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
Total
|
|
|
|
|
|
$ |
124,650 |
|
|
$ |
5,000 |
|
|
$ |
3,150 |
|
|
$ |
116,500 |
|
|
$ |
-- |
|
|
$ |
-- |
|
|
$ |
-- |
|
The
credit agreements of our unconsolidated affiliates contain various affirmative
and negative covenants, including financial covenants. These
businesses were in compliance with such covenants at December 31, 2008 and
2007. The credit agreements of our unconsolidated affiliates restrict
their ability to pay cash dividends if a default or an event of default (as
defined in each credit agreement) has occurred and is continuing at the time
such dividend is scheduled to be paid. Cameron Highway repaid its debt
obligations during the second quarter of 2007 using pro rata capital
contributions from EPO and its joint venture partner in Cameron
Highway.
The
following information summarizes significant terms of the debt obligations of
our unconsolidated affiliates at December 31, 2008:
Poseidon. Poseidon
has $109.0 million outstanding under its $150.0 million revolving credit
facility that matures in May 2011. Interest rates charged under this
revolving credit facility are variable and depend on the ratio of Poseidon’s
total debt to its earnings before interest, taxes, depreciation and
amortization. This credit agreement is secured by substantially all
of Poseidon’s assets. The variable interest rates charged on this
debt at December 31, 2008 and 2007 were 4.31% and 6.62%,
respectively.
Evangeline. At
December 31, 2008, short and long-term debt for Evangeline consisted of (i) $8.2
million in principal amount of 9.90% fixed-rate Series B senior secured notes
due December 2010 and (ii) a $7.5 million subordinated note
payable. The Series B senior secured notes are collateralized by
Evangeline’s property, plant and equipment, proceeds from a gas sales contract,
and by a debt service reserve requirement. Scheduled principal
repayments on the Series B notes are $5.0 million in 2009 with a final repayment
in 2010 of approximately $3.2 million. The trust indenture governing the
Series B notes contains covenants such as requirements to maintain certain
financial ratios.
Evangeline
incurred the subordinated note payable as a result of its acquisition of a
contract-based intangible asset in the 1990s. This note is subject to a
subordination agreement which prevents the repayment of principal and accrued
interest on the note until such time as the Series B noteholders are either
fully cash secured through debt service accounts or have been completely
repaid. Variable rate interest accrues on the subordinated note at a
Eurodollar rate plus 0.5%. The variable interest rates charged
on this
note at December 31, 2008 and 2007 were 3.20% and 5.88%,
respectively. Accrued interest payable related to the subordinated
note was $9.8 million and $9.1 million at December 31, 2008 and 2007,
respectively.
Our
common units represent limited partner interests, which give the holders thereof
the right to participate in distributions and to exercise the other rights or
privileges available to them under our Fifth Amended and
Restated Agreement of Limited Partnership (together with all amendments thereto,
the “Partnership Agreement”). We are managed by our general partner,
EPGP.
In
accordance with the Partnership Agreement, capital accounts are maintained for
our general partner and limited partners. The capital account
provisions of our Partnership Agreement incorporate principles established for
U.S. Federal income tax purposes and are not comparable to the equity accounts
reflected under GAAP in our consolidated financial statements.
Our
Partnership Agreement sets forth the calculation to be used in determining the
amount and priority of cash distributions that our limited partners and general
partner will receive. The Partnership Agreement also contains provisions for the
allocation of net earnings and losses to our limited partners and general
partner. For purposes of maintaining partner capital accounts, the
Partnership Agreement specifies that items of income and loss shall be allocated
among the partners in accordance with their respective percentage
interests. Normal income and loss allocations according to percentage
interests are done only after giving effect to priority earnings allocations in
an amount equal to incentive cash distributions allocated to our general
partner.
In August
2005, we revised our Partnership Agreement to allow EPGP, at its discretion, to
elect not to make its proportionate capital contributions to us in connection
with our issuance of limited partner interests, in which case its 2.0% general
partner interest would be proportionately reduced. At the time of
such offerings, EPGP has historically contributed cash to us to maintain its
2.0% general partner interest. EPGP made such cash contributions to us
during the years ended December 31, 2008 and 2007. If EPGP exercises
this option in the future, the amount of earnings we allocate to it and the cash
distributions it receives from us will be reduced accordingly. If
this occurs, EPGP can, under certain conditions, restore its full 2.0% general
partner interest by making additional cash contributions to us.
Equity
offerings and registration statements
In general, the Partnership Agreement
authorizes us to issue an unlimited number of additional limited partner
interests and other equity securities for such consideration and on such terms
and conditions as may be established by EPGP in its sole discretion (subject,
under certain circumstances, to the approval of our unitholders).
In August
2007, we filed a universal shelf registration statement with the SEC that allows
us to issue an unlimited amount of debt and equity securities. In
January 2009, we sold 10,590,000 common units (including an over-allotment of
990,000 common units) to the public at an offering price of $22.20 per unit
under this universal shelf registration. See Note 25 for additional
information.
During
2003, we instituted a distribution reinvestment plan (“DRIP”). In
April 2007, we filed a registration statement with the SEC authorizing the
issuance of up to 25,000,000 common units in connection with the
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. A
total of 21,471,047 common units have been issued under this registration
statement through December 31, 2008.
We also
have a registration statement on file related to our employee unit purchase plan
(“EUPP”), 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 10.0% discount through payroll deductions. A total of
651,297 common units have been issued to employees under this plan through
December 31, 2008.
The
following table reflects the number of common units issued and the net proceeds
received from underwritten and other common unit offerings completed during the
years ended December 31, 2008, 2007 and 2006:
|
|
|
Net
Proceeds from Sale of Common Units
|
|
|
|
|
Number
of
|
|
|
Contributed
|
|
|
Contributed
by
|
|
|
Total
|
|
|
|
|
Common
Units
|
|
|
by
Limited
|
|
|
General
|
|
|
Net
|
|
|
|
|
Issued
|
|
|
Partners
|
|
|
Partner
|
|
|
Proceeds
|
|
|
Fiscal
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Underwritten
offerings
|
|
|
31,050,000 |
|
|
$ |
735,819 |
|
|
$ |
15,003 |
|
|
$ |
750,822 |
|
|
DRIP
and EUPP
|
|
|
3,774,649 |
|
|
|
95,006 |
|
|
|
1,940 |
|
|
|
96,946 |
|
|
Total
2006
|
|
|
34,824,649 |
|
|
$ |
830,825 |
|
|
$ |
16,943 |
|
|
$ |
847,768 |
|
|
Fiscal
2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DRIP
and EUPP
|
|
|
2,056,615 |
|
|
$ |
60,445 |
|
|
$ |
1,232 |
|
|
$ |
61,677 |
|
|
Total
2007
|
|
|
2,056,615 |
|
|
$ |
60,445 |
|
|
$ |
1,232 |
|
|
$ |
61,677 |
|
|
Fiscal
2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DRIP
and EUPP
|
|
|
5,523,946 |
|
|
$ |
139,248 |
|
|
$ |
2,842 |
|
|
$ |
142,090 |
|
|
Total
2008
|
|
|
5,523,946 |
|
|
$ |
139,248 |
|
|
$ |
2,842 |
|
|
$ |
142,090 |
|
Net proceeds received from our
underwritten and other offerings completed during 2006 were used to temporarily
reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility
and for general partnership purposes.
Net
proceeds received from our DRIP and EUPP were used to temporarily reduce
borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility and for
general partnership purposes.
Summary
of Changes in Outstanding Units
The
following table summarizes changes in our outstanding units since December
31, 2005:
|
|
|
|
|
|
Restricted
|
|
|
|
|
|
|
|
Common
|
|
|
Common
|
|
|
Treasury
|
|
|
|
|
Units
|
|
|
Units
|
|
|
Units
|
|
|
Balance,
December 31, 2005
|
|
|
389,109,564 |
|
|
|
751,604 |
|
|
|
-- |
|
|
Common
units issued in connection with underwritten offerings
|
|
|
31,050,000 |
|
|
|
-- |
|
|
|
-- |
|
|
Common
units issued in connection with DRIP and EUPP
|
|
|
3,774,649 |
|
|
|
-- |
|
|
|
-- |
|
|
Common
units issued in connection with equity awards
|
|
|
211,000 |
|
|
|
466,400 |
|
|
|
-- |
|
|
Forfeiture
of restricted units
|
|
|
-- |
|
|
|
(70,631 |
) |
|
|
-- |
|
|
Conversion
of restricted units to common units
|
|
|
42,136 |
|
|
|
(42,136 |
) |
|
|
-- |
|
|
Common
units issued in connection with Encinal acquisition
|
|
|
7,115,844 |
|
|
|
-- |
|
|
|
-- |
|
|
Balance,
December 31, 2006
|
|
|
431,303,193 |
|
|
|
1,105,237 |
|
|
|
-- |
|
|
Common
units issued in connection with DRIP and EUPP
|
|
|
2,056,615 |
|
|
|
-- |
|
|
|
-- |
|
|
Common
units issued in connection with equity awards
|
|
|
244,071 |
|
|
|
738,040 |
|
|
|
-- |
|
|
Forfeiture
or settlement of restricted units
|
|
|
-- |
|
|
|
(149,853 |
) |
|
|
-- |
|
|
Conversion
of restricted units to common units
|
|
|
4,884 |
|
|
|
(4,884 |
) |
|
|
-- |
|
|
Balance,
December 31, 2007
|
|
|
433,608,763 |
|
|
|
1,688,540 |
|
|
|
-- |
|
|
Common
units issued in connection with DRIP and EUPP
|
|
|
5,523,946 |
|
|
|
-- |
|
|
|
-- |
|
|
Common
units issued in connection with equity awards
|
|
|
21,905 |
|
|
|
-- |
|
|
|
-- |
|
|
Restricted
units issued
|
|
|
-- |
|
|
|
766,200 |
|
|
|
-- |
|
|
Forfeiture
or settlement of restricted units
|
|
|
-- |
|
|
|
(88,777 |
) |
|
|
-- |
|
|
Conversion
of restricted units to common units
|
|
|
285,363 |
|
|
|
(285,363 |
) |
|
|
-- |
|
|
Acquisition
of treasury units
|
|
|
(85,246 |
) |
|
|
-- |
|
|
|
85,246 |
|
|
Cancellation
of treasury units
|
|
|
-- |
|
|
|
-- |
|
|
|
(85,246 |
) |
|
Balance,
December 31, 2008
|
|
|
439,354,731 |
|
|
|
2,080,600 |
|
|
|
-- |
|
Treasury
Units. In 2000, we and a consolidated trust (the “1999 Trust”)
were authorized by EPGP to repurchase up to 2,000,000 publicly-held common units
under an announced buy-back program. The repurchases would be made
during periods of temporary market weakness at price levels that would be
accretive to our remaining unitholders. After deducting for
repurchases under the program in prior periods, we and the 1999 Trust could
repurchase up to 618,400 common units at December 31, 2008.
During
the year ended December 31, 2008, 285,363 restricted unit awards vested and were
converted to common units. Of this amount, 85,246 were sold back to
us by employees to cover related withholding tax requirements. The total cost of
these treasury units was approximately $1.9 million, of which a minimal amount
was allocated to our general partner. Immediately upon acquisition,
we cancelled such treasury units.
Summary
of Changes in Limited Partners’ Equity
The
following table details the changes in limited partners’ equity since December
31, 2005:
|
|
|
|
|
|
Restricted
|
|
|
|
|
|
|
|
Common
|
|
|
Common
|
|
|
|
|
|
|
|
Units
|
|
|
Units
|
|
|
Total
|
|
|
Balance,
December 31, 2005
|
|
$ |
5,542,700 |
|
|
$ |
18,638 |
|
|
$ |
5,561,338 |
|
|
Net
income
|
|
|
502,969 |
|
|
|
1,187 |
|
|
|
504,156 |
|
|
Operating
leases paid by EPCO
|
|
|
2,062 |
|
|
|
5 |
|
|
|
2,067 |
|
|
Cash
distributions to partners
|
|
|
(738,004 |
) |
|
|
(1,628 |
) |
|
|
(739,632 |
) |
|
Unit
option reimbursements to EPCO
|
|
|
(1,818 |
) |
|
|
-- |
|
|
|
(1,818 |
) |
|
Net
proceeds from issuance of common units
|
|
|
830,825 |
|
|
|
-- |
|
|
|
830,825 |
|
|
Common
units issued in connection with
Encinal
acquisition
|
|
|
181,112 |
|
|
|
-- |
|
|
|
181,112 |
|
|
Proceeds
from exercise of unit options
|
|
|
5,601 |
|
|
|
|
|
|
|
5,601 |
|
|
Amortization
of equity awards
|
|
|
2,209 |
|
|
|
6,073 |
|
|
|
8,282 |
|
|
Change
in accounting method for equity
awards
(see Note 5)
|
|
|
(896 |
) |
|
|
(14,919 |
) |
|
|
(15,815 |
) |
|
Acquisition-related
disbursement of cash
|
|
|
(6,183 |
) |
|
|
(16 |
) |
|
|
(6,199 |
) |
|
Balance,
December 31, 2006
|
|
|
6,320,577 |
|
|
|
9,340 |
|
|
|
6,329,917 |
|
|
Net
income
|
|
|
416,323 |
|
|
|
1,405 |
|
|
|
417,728 |
|
|
Operating
leases paid by EPCO
|
|
|
2,056 |
|
|
|
7 |
|
|
|
2,063 |
|
|
Cash
distributions to partners
|
|
|
(831,155 |
) |
|
|
(2,638 |
) |
|
|
(833,793 |
) |
|
Unit
option reimbursements to EPCO
|
|
|
(2,999 |
) |
|
|
-- |
|
|
|
(2,999 |
) |
|
Net
proceeds from issuance of common units
|
|
|
60,445 |
|
|
|
-- |
|
|
|
60,445 |
|
|
Proceeds
from exercise of unit options
|
|
|
7,549 |
|
|
|
-- |
|
|
|
7,549 |
|
|
Repurchase
of restricted units and options
|
|
|
(512 |
) |
|
|
(1,056 |
) |
|
|
(1,568 |
) |
|
Amortization
of equity awards
|
|
|
4,663 |
|
|
|
8,890 |
|
|
|
13,553 |
|
|
Balance,
December 31, 2007
|
|
|
5,976,947 |
|
|
|
15,948 |
|
|
|
5,992,895 |
|
|
Net
income
|
|
|
807,894 |
|
|
|
3,653 |
|
|
|
811,547 |
|
|
Operating
leases paid by EPCO
|
|
|
1,988 |
|
|
|
9 |
|
|
|
1,997 |
|
|
Cash
distributions to partners
|
|
|
(888,802 |
) |
|
|
(3,891 |
) |
|
|
(892,693 |
) |
|
Unit
option reimbursements to EPCO
|
|
|
(550 |
) |
|
|
-- |
|
|
|
(550 |
) |
|
Non-cash
distributions
|
|
|
(7,140 |
) |
|
|
-- |
|
|
|
(7,140 |
) |
|
Acquisition
of treasury units, limited partner share
|
|
|
-- |
|
|
|
(1,873 |
) |
|
|
(1,873 |
) |
|
Net
proceeds from issuance of common units
|
|
|
139,248 |
|
|
|
-- |
|
|
|
139,248 |
|
|
Proceeds
from exercise of unit options
|
|
|
679 |
|
|
|
-- |
|
|
|
679 |
|
|
Amortization
of equity awards
|
|
|
6,623 |
|
|
|
12,373 |
|
|
|
18,996 |
|
|
Balance,
December 31, 2008
|
|
$ |
6,036,887 |
|
|
$ |
26,219 |
|
|
$ |
6,063,106 |
|
In October 2006, we acquired all of the
capital stock of an affiliated NGL marketing company located in Canada from EPCO
and Dan L. Duncan for $17.7 million in cash. The amount we paid for
this business exceeded the carrying values of the assets acquired and
liabilities assumed from this related party (which is under common control with
us) by $6.3 million, of which $6.2 million was allocated to limited partners and
$0.1 million to our general partner. The excess of the acquisition
price over the net book value of this business at the time of acquisition is
treated as a deemed distribution to our owners and presented as an
“Acquisition-related disbursement of cash” in our Statement of Partners’ Equity
for the year ended
December
31, 2006. The total purchase price is a component of “Cash used for
business combinations” as presented in our Statement of Consolidated Cash Flows
for the year ended December 31, 2006.
Distributions
to Partners
The
percentage interest of EPGP in our quarterly cash distributions is increased
after certain specified target levels of quarterly distribution rates are
met. At current distribution rates, we are in the highest tier of
such incentive targets. EPGP’s quarterly incentive distribution
thresholds are as follows:
|
§
|
2.0%
of quarterly cash distributions up to $0.253 per
unit;
|
|
§
|
15.0%
of quarterly cash distributions from $0.253 per unit up to $0.3085 per
unit; and
|
|
§
|
25.0%
of quarterly cash distributions that exceed $0.3085 per
unit.
|
We paid
incentive distributions of $125.9 million, $107.4 million and $86.7 million to
EPGP during the years ended December 31, 2008, 2007 and 2006,
respectively.
The
following table presents our declared quarterly cash distribution rates per unit
since the first quarter of 2007 and the related record and distribution payment
dates. The quarterly cash distribution rates per unit correspond to
the fiscal quarters indicated. Actual cash distributions are paid
within 45 days after the end of such fiscal quarter.
|
|
Distribution
|
Record
|
Payment
|
|
|
per
Unit
|
Date
|
Date
|
|
2007
|
|
|
|
|
1st
Quarter
|
$0.4750
|
Apr.
30, 2007
|
May
10, 2007
|
|
2nd
Quarter
|
$0.4825
|
Jul.
31, 2007
|
Aug.
9, 2007
|
|
3rd
Quarter
|
$0.4900
|
Oct.
31, 2007
|
Nov.
8, 2007
|
|
4th
Quarter
|
$0.5000
|
Jan.
31, 2008
|
Feb.
7, 2008
|
|
2008
|
|
|
|
|
1st
Quarter
|
$0.5075
|
Apr.
30, 2008
|
May
7, 2008
|
|
2nd
Quarter
|
$0.5150
|
Jul.
31, 2008
|
Aug.
7, 2008
|
|
3rd
Quarter
|
$0.5225
|
Oct.
31, 2008
|
Nov.
12, 2008
|
|
4th
Quarter
|
$0.5300
|
Jan.
30, 2009
|
Feb.
9, 2009
|
Accumulated
Other Comprehensive Income (Loss)
Accumulated other comprehensive income
(loss) primarily includes the effective portion of the gain or loss on financial
instruments designated and qualified as a cash flow hedge, foreign currency
adjustments and Dixie’s minimum pension liability
adjustments. Amounts accumulated in other comprehensive income (loss)
from cash flow hedges are reclassified into earnings in the same period(s) in
which the hedged forecasted transactions (such as a forecasted forward sale of
NGLs) affect earnings. If it becomes probable that the forecasted
transaction will not occur, the net gain or loss in accumulated other
comprehensive income (loss) must be immediately reclassified.
The
following table presents the components of accumulated other comprehensive
income (loss) at the dates indicated:
|
|
|
At
December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Commodity
financial instruments – cash flow hedges (1)
|
|
$ |
(114,077 |
) |
|
$ |
(21,619 |
) |
|
Interest
rate financial instruments – cash flow hedges (1)
|
|
|
3,818 |
|
|
|
34,980 |
|
|
Foreign
currency cash flow hedges (1)
|
|
|
10,594 |
|
|
|
1,308 |
|
|
Foreign
currency translation adjustment (2)
|
|
|
(1,301 |
) |
|
|
1,200 |
|
|
Pension
and postretirement benefit plans (3)
|
|
|
(751 |
) |
|
|
588 |
|
|
Total
accumulated other comprehensive income (loss)
|
|
$ |
(101,717 |
) |
|
$ |
16,457 |
|
|
|
|
|
|
|
|
|
|
|
|
(1)
See
Note 7 for additional information regarding these components of
accumulated other comprehensive income (loss).
(2)
Relates
to transactions of our Canadian NGL marketing
subsidiary.
(3)
See
Note 6 for additional information regarding pension and postretirement
benefit plans.
|
|
We have
four reportable business segments: NGL Pipelines & Services, Onshore Natural
Gas Pipelines & Services, Offshore Pipelines & Services and
Petrochemical Services. Our business segments are generally organized
and managed according to the type of services rendered (or technologies
employed) and products produced and/or sold.
We
evaluate segment performance based on the non-GAAP financial measure of gross
operating margin. Gross operating margin (either in total or by
individual segment) is an important performance measure of the core
profitability of our operations. This measure forms the basis of our
internal financial reporting and is used by our senior management in deciding
how to allocate capital resources among business segments. We believe
that investors benefit from having access to the same financial measures that
our management uses in evaluating segment results. The GAAP financial
measure most directly comparable to total segment gross operating margin is
operating income. Our non-GAAP financial measure of total segment
gross operating margin should not be considered an alternative to GAAP operating
income.
We define
total segment gross operating margin as consolidated operating income before:
(i) depreciation, amortization and accretion expense; (ii) operating lease
expenses for which we do not have the payment obligation; (iii) gains and losses
from asset sales and related transactions; and (iv) general and administrative
costs. Gross operating margin is exclusive of other income and
expense transactions, provision for income taxes, minority interest,
extraordinary charges and the cumulative effect of change in accounting
principle. Gross operating margin by segment is calculated by
subtracting segment operating costs and expenses (net of the adjustments noted
above) from segment revenues, with both segment totals before the elimination of
intersegment and intrasegment transactions.
Segment
revenues include intersegment and intrasegment transactions, which are generally
based on transactions made at market-related rates. Our consolidated
revenues reflect the elimination of intercompany (both intersegment and
intrasegment) transactions.
We
include equity in earnings of unconsolidated affiliates in our measurement of
segment gross operating margin and operating income. Our equity investments with
industry partners are a vital component of our business
strategy. They are a means by which we conduct our operations to
align our interests with those of our customers and/or
suppliers. This method of operation 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, crude oil and certain petrochemicals. In general,
hydrocarbons enter our asset system in a number of ways, such as an offshore
natural gas or crude oil pipeline, an offshore platform, a natural gas
processing plant, an onshore natural gas gathering pipeline, an NGL
fractionator, an NGL storage facility, or an NGL transportation or distribution
pipeline.
Many of
our equity investees are included 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 mixed NGLs extracted by our gas
plants. The fractionated NGLs we receive from Promix can then be sold
in our NGL marketing activities. Given the integral nature of our
equity method investees to our operations, we believe the presentation of
earnings from such investees as a component of gross operating margin and
operating income is meaningful and appropriate.
Historically,
substantially all of our consolidated revenues were earned in the United States
and derived from a wide customer base. The majority of our
plant-based operations are located in Texas, Louisiana, Mississippi, New Mexico,
Colorado and Wyoming. Our natural gas, NGL and crude oil pipelines
are located in a number of regions of the United States including (i) the Gulf
of Mexico offshore Texas and Louisiana; (ii) the south and southeastern United
States (primarily in Texas, Louisiana, Mississippi and Alabama); and (iii)
certain regions of the central and western United States, including the Rocky
Mountains. Our marketing activities are headquartered in Houston,
Texas and serve customers in a number of regions of the United States including
the Gulf Coast, West Coast and Mid-Continent areas.
Consolidated property, plant and
equipment and investments in and advances to unconsolidated affiliates are
assigned to each segment on the basis of each asset’s or investment’s principal
operations. The principal reconciling difference between consolidated
property, plant and equipment and the total value of segment assets is
construction in progress. Segment assets represent the net book
carrying value of facilities and other assets that contribute to gross operating
margin of that particular segment. Since assets under construction
generally do not contribute to segment gross operating margin, such assets are
excluded from segment asset totals until they are placed in
service. Consolidated intangible assets and goodwill are assigned to
each segment based on the classification of the assets to which they
relate.
We consolidate the financial statements
of Duncan Energy Partners with those of our own. As a result, our
consolidated gross operating margin amounts include 100.0% of the gross
operating margin amounts of Duncan Energy Partners.
The
following table shows our measurement of total segment gross operating margin
for the periods indicated:
|
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Revenues
(1)
|
|
$ |
21,905,656 |
|
|
$ |
16,950,125 |
|
|
$ |
13,990,969 |
|
|
Less:
|
Operating
costs and expenses (1)
|
|
|
(20,460,964 |
) |
|
|
(16,009,051 |
) |
|
|
(13,089,091 |
) |
|
Add:
|
Equity
in earnings of unconsolidated affiliates (1)
|
|
|
59,104 |
|
|
|
29,658 |
|
|
|
21,565 |
|
|
|
Depreciation,
amortization and accretion in operating costs and expenses
(2)
|
|
|
555,370 |
|
|
|
513,840 |
|
|
|
440,256 |
|
|
|
Operating
lease expenses paid by EPCO (2)
|
|
|
2,038 |
|
|
|
2,105 |
|
|
|
2,109 |
|
|
|
Loss
(gain) from asset sales and related transactions in operating
costs
and expenses (2)
|
|
|
(3,735 |
) |
|
|
5,391 |
|
|
|
(3,359 |
) |
|
Total
segment gross operating margin
|
|
$ |
2,057,469 |
|
|
$ |
1,492,068 |
|
|
$ |
1,362,449 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
These
amounts are taken from our Statements of Consolidated
Operations.
(2)
These
non-cash expenses are taken from the operating activities section of our
Statements of Consolidated Cash Flows.
|
|
A
reconciliation of our total segment gross operating margin to operating income
and income before provision for income taxes, minority interest and the
cumulative effect of change in accounting principle follows:
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Total
segment gross operating margin
|
|
$ |
2,057,469 |
|
|
$ |
1,492,068 |
|
|
$ |
1,362,449 |
|
|
Adjustments
to reconcile total segment gross operating margin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
to
operating income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
amortization and accretion in operating costs and expenses
|
|
|
(555,370 |
) |
|
|
(513,840 |
) |
|
|
(440,256 |
) |
|
Operating
lease expense paid by EPCO
|
|
|
(2,038 |
) |
|
|
(2,105 |
) |
|
|
(2,109 |
) |
|
Gain
(loss) from asset sales and related transactions in operating
costs
and expenses
|
|
|
3,735 |
|
|
|
(5,391 |
) |
|
|
3,359 |
|
|
General
and administrative costs
|
|
|
(90,550 |
) |
|
|
(87,695 |
) |
|
|
(63,391 |
) |
|
Operating
income
|
|
|
1,413,246 |
|
|
|
883,037 |
|
|
|
860,052 |
|
|
Other
expense, net
|
|
|
(391,448 |
) |
|
|
(303,463 |
) |
|
|
(229,967 |
) |
|
Income
before provision for income taxes, minority interest
|
|
|
|
|
|
|
|
|
|
|
|
|
|
and
cumulative effect of change in accounting principle
|
|
$ |
1,021,798 |
|
|
$ |
579,574 |
|
|
$ |
630,085 |
|
Information
by segment, together with reconciliations to our consolidated totals, is
presented in the following table:
|
|
Reportable
Segments
|
|
|
|
|
|
|
|
|
|
Onshore
|
|
|
|
|
|
|
|
|
|
|
|
NGL
|
|
Natural
Gas
|
|
Offshore
|
|
|
|
Adjustments
|
|
|
|
|
|
Pipelines
|
|
Pipelines
|
|
Pipelines
|
|
Petrochemical
|
|
and
|
|
Consolidated
|
|
|
|
&
Services
|
|
&
Services
|
|
&
Services
|
|
Services
|
|
Eliminations
|
|
Totals
|
|
|
Revenues
from third parties:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
ended December 31, 2008
|
$ |
14,664,707 |
|
$ |
3,161,014 |
|
$ |
260,288 |
|
$ |
2,683,197 |
|
$ |
-- |
|
$ |
20,769,206 |
|
|
Year
ended December 31, 2007
|
|
12,101,715 |
|
|
1,788,219 |
|
|
222,642 |
|
|
2,184,833 |
|
|
-- |
|
|
16,297,409 |
|
|
Year
ended December 31, 2006
|
|
10,079,534 |
|
|
1,407,872 |
|
|
144,065 |
|
|
1,956,268 |
|
|
-- |
|
|
13,587,739 |
|
|
Revenues
from related parties:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
ended December 31, 2008
|
|
717,244 |
|
|
411,084 |
|
|
8,122 |
|
|
-- |
|
|
-- |
|
|
1,136,450 |
|
|
Year
ended December 31, 2007
|
|
369,654 |
|
|
281,876 |
|
|
1,169 |
|
|
17 |
|
|
-- |
|
|
652,716 |
|
|
Year
ended December 31, 2006
|
|
110,409 |
|
|
291,023 |
|
|
1,798 |
|
|
-- |
|
|
-- |
|
|
403,230 |
|
|
Intersegment
and intrasegment revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
ended December 31, 2008
|
|
7,947,889 |
|
|
833,931 |
|
|
1,418 |
|
|
639,142 |
|
|
(9,422,380 |
) |
|
-- |
|
|
Year
ended December 31, 2007
|
|
5,346,571 |
|
|
191,741 |
|
|
1,959 |
|
|
514,852 |
|
|
(6,055,123 |
) |
|
-- |
|
|
Year
ended December 31, 2006
|
|
4,131,776 |
|
|
113,132 |
|
|
1,679 |
|
|
383,754 |
|
|
(4,630,341 |
) |
|
-- |
|
|
Total
revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
ended December 31, 2008
|
|
23,329,840 |
|
|
4,406,029 |
|
|
269,828 |
|
|
3,322,339 |
|
|
(9,422,380 |
) |
|
21,905,656 |
|
|
Year
ended December 31, 2007
|
|
17,817,940 |
|
|
2,261,836 |
|
|
225,770 |
|
|
2,699,702 |
|
|
(6,055,123 |
) |
|
16,950,125 |
|
|
Year
ended December 31, 2006
|
|
14,321,719 |
|
|
1,812,027 |
|
|
147,542 |
|
|
2,340,022 |
|
|
(4,630,341 |
) |
|
13,990,969 |
|
|
Equity
in earnings of
unconsolidated
affiliates:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
ended December 31, 2008
|
|
1,430 |
|
|
22,959 |
|
|
33,609 |
|
|
1,106 |
|
|
-- |
|
|
59,104 |
|
|
Year
ended December 31, 2007
|
|
6,031 |
|
|
9,540 |
|
|
12,628 |
|
|
1,459 |
|
|
-- |
|
|
29,658 |
|
|
Year
ended December 31, 2006
|
|
5,715 |
|
|
2,872 |
|
|
11,909 |
|
|
1,069 |
|
|
-- |
|
|
21,565 |
|
|
Gross
operating margin by individual business segment and in
total:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
ended December 31, 2008
|
|
1,290,458 |
|
|
411,344 |
|
|
188,083 |
|
|
167,584 |
|
|
-- |
|
|
2,057,469 |
|
|
Year
ended December 31, 2007
|
|
812,521 |
|
|
335,683 |
|
|
171,551 |
|
|
172,313 |
|
|
-- |
|
|
1,492,068 |
|
|
Year
ended December 31, 2006
|
|
752,548 |
|
|
333,399 |
|
|
103,407 |
|
|
173,095 |
|
|
-- |
|
|
1,362,449 |
|
|
Segment
assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At
December 31, 2008
|
|
5,424,134 |
|
|
4,033,312 |
|
|
1,394,480 |
|
|
698,157 |
|
|
1,604,691 |
|
|
13,154,774 |
|
|
At
December 31, 2007
|
|
4,570,555 |
|
|
3,702,297 |
|
|
1,452,568 |
|
|
687,856 |
|
|
1,173,988 |
|
|
11,587,264 |
|
|
Investments
in and advances to
unconsolidated
affiliates (see Note 11):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At
December 31, 2008
|
|
144,182 |
|
|
283,981 |
|
|
504,843 |
|
|
16,520 |
|
|
-- |
|
|
949,526 |
|
|
At
December 31, 2007
|
|
117,089 |
|
|
239,327 |
|
|
484,588 |
|
|
17,335 |
|
|
-- |
|
|
858,339 |
|
|
Intangible
assets, net (see Note 13):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At
December 31, 2008
|
|
351,010 |
|
|
333,462 |
|
|
116,219 |
|
|
54,725 |
|
|
-- |
|
|
855,416 |
|
|
At
December 31, 2007
|
|
373,071 |
|
|
354,152 |
|
|
133,058 |
|
|
56,719 |
|
|
-- |
|
|
917,000 |
|
|
Goodwill
(see Note 13):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At
December 31, 2008
|
|
268,938 |
|
|
282,121 |
|
|
82,135 |
|
|
73,690 |
|
|
-- |
|
|
706,884 |
|
|
At
December 31, 2007
|
|
153,706 |
|
|
282,121 |
|
|
82,135 |
|
|
73,690 |
|
|
-- |
|
|
591,652 |
|
Our
revenues are derived from a wide customer base. During 2008 our
largest customer was LyondellBasell Industries (“LBI”) and its affiliates, which
accounted for 9.6% of our consolidated revenues. See Note 21 for
additional information regarding our credit exposure to LBI’s bankruptcy filing
in January 2009. In 2007 and 2006, our largest customer was The Dow
Chemical Company and its affiliates, which accounted for 6.9% and 6.1%,
respectively, of our consolidated revenues.
On
January 6, 2009, LBI announced that its U.S. operations had voluntarily filed to
reorganize under Chapter 11 of the U.S. Bankruptcy Code. At the time
of the bankruptcy filing, we had approximately $17.3 million of credit exposure
to LBI, which was reduced to approximately $10.0 million through remedies
provided under certain pipeline tariffs. In addition, we are seeking
to have LBI accept certain contracts and have filed claims pursuant to current
Bankruptcy Court Orders that we expect will allow us to recover the majority of
the remaining credit exposure.
For 2008,
LBI accounted for 10.2%, or $1.6 billion, of revenues attributable to our NGL
Pipelines & Services business segment and 19.2%, or $516.2 million, of
revenues attributable to our Petrochemical Services business
segment.
The
following table provides additional information regarding our consolidated
revenues (net of adjustments and eliminations) and expenses for the periods
noted:
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
NGL
Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
Sales
of NGLs
|
|
$ |
14,680,607 |
|
|
$ |
11,757,895 |
|
|
$ |
9,442,403 |
|
|
Sales
of other petroleum and related products
|
|
|
2,387 |
|
|
|
3,027 |
|
|
|
2,353 |
|
|
Midstream
services
|
|
|
698,957 |
|
|
|
710,447 |
|
|
|
745,187 |
|
|
Total
|
|
|
15,381,951 |
|
|
|
12,471,369 |
|
|
|
10,189,943 |
|
|
Onshore
Natural Gas Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
of natural gas
|
|
|
3,091,296 |
|
|
|
1,481,569 |
|
|
|
1,103,169 |
|
|
Midstream
services
|
|
|
480,802 |
|
|
|
588,526 |
|
|
|
595,726 |
|
|
Total
|
|
|
3,572,098 |
|
|
|
2,070,095 |
|
|
|
1,698,895 |
|
|
Offshore
Pipelines & Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
of natural gas
|
|
|
100 |
|
|
|
101 |
|
|
|
307 |
|
|
Sales
of other petroleum and related products
|
|
|
11,144 |
|
|
|
12,086 |
|
|
|
4,562 |
|
|
Midstream
services
|
|
|
257,166 |
|
|
|
211,624 |
|
|
|
140,994 |
|
|
Total
|
|
|
268,410 |
|
|
|
223,811 |
|
|
|
145,863 |
|
|
Petrochemical
Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
of other petroleum and related products
|
|
|
2,593,856 |
|
|
|
2,115,429 |
|
|
|
1,873,722 |
|
|
Midstream
services
|
|
|
89,341 |
|
|
|
69,421 |
|
|
|
82,546 |
|
|
Total
|
|
|
2,683,197 |
|
|
|
2,184,850 |
|
|
|
1,956,268 |
|
|
Total
consolidated revenues
|
|
$ |
21,905,656 |
|
|
$ |
16,950,125 |
|
|
$ |
13,990,969 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated
cost and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost
of sales
|
|
$ |
18,662,263 |
|
|
$ |
14,509,220 |
|
|
$ |
11,778,928 |
|
|
Depreciation,
amortization and accretion
|
|
|
555,370 |
|
|
|
513,840 |
|
|
|
440,256 |
|
|
Loss
(gain) on sale of assets and related transactions
|
|
|
(3,735 |
) |
|
|
5,391 |
|
|
|
(3,359 |
) |
|
Other
operating costs and expenses
|
|
|
1,247,066 |
|
|
|
980,600 |
|
|
|
873,266 |
|
|
General
and administrative costs
|
|
|
90,550 |
|
|
|
87,695 |
|
|
|
63,391 |
|
|
Total
consolidated costs and expenses
|
|
$ |
20,551,514 |
|
|
$ |
16,096,746 |
|
|
$ |
13,152,482 |
|
The
following table summarizes our related party transactions for the periods
indicated.
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Revenues
from consolidated operations
|
|
|
|
|
|
|
|
|
|
|
EPCO
and affiliates
|
|
$ |
121,201 |
|
|
$ |
67,635 |
|
|
$ |
98,671 |
|
|
Energy
Transfer Equity and subsidiaries
|
|
|
618,370 |
|
|
|
294,441 |
|
|
|
-- |
|
|
Unconsolidated
affiliates
|
|
|
396,879 |
|
|
|
290,640 |
|
|
|
304,559 |
|
|
Total
|
|
$ |
1,136,450 |
|
|
$ |
652,716 |
|
|
$ |
403,230 |
|
|
Cost
of sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EPCO
and affiliates
|
|
$ |
59,173 |
|
|
$ |
33,827 |
|
|
$ |
86,050 |
|
|
Energy
Transfer Equity and subsidiaries
|
|
|
173,875 |
|
|
|
26,889 |
|
|
|
-- |
|
|
Unconsolidated
affiliates
|
|
|
90,836 |
|
|
|
41,474 |
|
|
|
42,166 |
|
|
Total
|
|
$ |
323,884 |
|
|
$ |
102,190 |
|
|
$ |
128,216 |
|
|
Operating
costs and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EPCO
and affiliates
|
|
$ |
314,612 |
|
|
$ |
260,716 |
|
|
$ |
225,487 |
|
|
Energy
Transfer Equity and subsidiaries
|
|
|
18,284 |
|
|
|
8,267 |
|
|
|
-- |
|
|
Unconsolidated
affiliates
|
|
|
(10,388 |
) |
|
|
(8,709 |
) |
|
|
(10,560 |
) |
|
Total
|
|
$ |
322,508 |
|
|
$ |
260,274 |
|
|
$ |
214,927 |
|
|
General
and administrative expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EPCO
and affiliates
|
|
$ |
59,058 |
|
|
$ |
56,518 |
|
|
$ |
41,265 |
|
|
Unconsolidated
affiliates
|
|
|
(51 |
) |
|
|
-- |
|
|
|
-- |
|
|
Total
|
|
$ |
59,007 |
|
|
$ |
56,518 |
|
|
$ |
41,265 |
|
|
Other
income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EPCO
and affiliates
|
|
$ |
(274 |
) |
|
$ |
(170 |
) |
|
$ |
680 |
|
|
Unconsolidated
affiliates
|
|
|
-- |
|
|
|
-- |
|
|
|
262 |
|
|
Total
|
|
$ |
(274 |
) |
|
$ |
(170 |
) |
|
$ |
942 |
|
We believe that the terms and
provisions of our related party agreements are fair to us; however, such
agreements and transactions may not be as favorable to us as we could have
obtained from unaffiliated third parties.
Relationship
with EPCO and affiliates
We have an extensive and ongoing
relationship with EPCO and its affiliates, which include the following
significant entities that are not a part of our consolidated group of
companies:
|
§
|
EPCO
and its private company
subsidiaries;
|
|
§
|
EPGP,
our sole general partner;
|
|
§
|
Enterprise
GP Holdings, which owns and controls our general
partner;
|
|
§
|
TEPPCO,
which is owned and controlled by Enterprise GP Holdings;
and
|
|
§
|
the
Employee Partnerships (see Note 5).
|
We also
have an ongoing relationship with Duncan Energy Partners, the financial
statements of which are consolidated with those of our own. Our
transactions with Duncan Energy Partners are eliminated in
consolidation. A description of our relationship with Duncan Energy
Partners is presented within this Note 17.
EPCO is a
private company controlled by Dan L. Duncan, who is also a Director and Chairman
of EPGP, our general partner. At December 31, 2008, EPCO and its
affiliates beneficially owned 152,506,527 (or 34.5%) of our outstanding common
units, which includes 13,670,925 of our common units owned by Enterprise GP
Holdings. In addition, at December 31, 2008, EPCO and its affiliates
beneficially
owned
77.8% of the limited partner interests of Enterprise GP Holdings and 100.0% of
its general partner, EPE Holdings. Enterprise GP Holdings owns all of
the membership interests of EPGP. The principal business activity of
EPGP is to act as our managing partner. The executive officers and
certain of the directors of EPGP and EPE Holdings are employees of
EPCO.
As our
general partner, EPGP received cash distributions of $144.1 million, $124.4
million and $101.8 million from us during the years ended December 31, 2008,
2007 and 2006, respectively. These amounts include incentive
distributions of $125.9 million, $107.4 million and $86.7 million for the years
ended December 31, 2008, 2007 and 2006, respectively.
We and
EPGP are both separate legal entities apart from each other and apart from EPCO,
Enterprise GP Holdings and their respective other affiliates, with assets and
liabilities that are separate from those of EPCO, Enterprise GP Holdings and
their respective other affiliates. EPCO and its private company
subsidiaries depend on the cash distributions they receive from us, Enterprise
GP Holdings and other investments to fund their other operations and to meet
their debt obligations. EPCO and its private company affiliates
received $405.2 million, $355.5 million and $306.5 million in cash distributions
from us and Enterprise GP Holdings during the years ended December 31, 2008,
2007 and 2006, respectively.
The ownership interests in us that are
owned or controlled by Enterprise GP Holdings are pledged as security under its
credit facility. In addition, substantially all of the ownership
interests in us that are owned or controlled by EPCO and its affiliates, other
than those interests owned by Enterprise GP Holdings, Dan Duncan LLC and certain
trusts affiliated with Dan L. Duncan, are pledged as security under the credit
facility of a private company affiliate of EPCO. This credit facility
contains customary and other events of default relating to EPCO and certain
affiliates, including Enterprise GP Holdings, TEPPCO and us.
We have entered into an agreement with
an affiliate of EPCO to provide trucking services to us for the transportation
of NGLs and other products. For the years ended December 31, 2008,
2007 and 2006, we paid this trucking affiliate $21.7 million, $17.5 million and
$20.7 million, respectively, for such services.
We lease office space in various
buildings from affiliates of EPCO. The rental rates in these lease
agreements approximate market rates. For the years ended December 31,
2008, 2007 and 2006, we paid EPCO $5.3 million, $5.6 million and $3.0 million,
respectively, for office space leases.
Historically, we entered into
transactions with a Canadian affiliate of EPCO for the purchase and sale of NGL
products in the normal course of business. These transactions were at
market-related prices. We acquired this affiliate in October 2006 and
began consolidating its financial statements with those of our own from the date
of acquisition. For the nine months ended September 30, 2006, our
revenues from this former unconsolidated affiliate were $55.8 million and our
purchases were $43.4 million.
EPCO
ASA
We have
no employees. All of our operating functions and general and administrative
support services are provided by employees of EPCO pursuant to the
ASA. We, Duncan Energy Partners, Enterprise GP Holdings, TEPPCO and
our respective general partners are parties to the ASA. The
significant terms of the ASA are as follows:
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EPCO
will provide selling, general and administrative services, and management
and operating services, as may be necessary to manage and operate our
businesses, properties and assets (all in accordance with prudent industry
practices). EPCO will employ or otherwise retain the services
of such personnel as may be necessary to provide such
services.
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We
are required to reimburse EPCO for its services in an amount equal to the
sum of all costs and expenses incurred by EPCO which are directly or
indirectly related to our business or activities (including expenses
reasonably allocated to us by EPCO). In addition, we have
agreed to pay all
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sales, use,
excise, value added or similar taxes, if any, that may be applicable from time
to time in respect of the services provided to us by EPCO.
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EPCO
will allow us to participate as a named insured in its overall insurance
program, with the associated premiums and other costs being allocated to
us.
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Under the ASA, EPCO subleases to us
(for $1 per year) certain equipment which it holds pursuant to operating leases
and has assigned to us its purchase option under such leases (the “retained
leases”). EPCO remains liable for the actual cash lease payments
associated with these agreements. We record the full value of these
payments made by EPCO on our behalf as a non-cash related party operating lease
expense, with the offset to partners’ equity accounted for as a general
contribution to our partnership. We exercised our election under the
retained leases to purchase a cogeneration unit in December 2008 for $2.3
million. Should we decide to exercise the purchase option associated
with the remaining agreement, we would pay the original lessor $3.1 million in
June 2016.
Our operating costs and expenses for
the years ended December 31, 2008, 2007 and 2006 include reimbursement payments
to EPCO for the costs it incurs to operate our facilities, including
compensation of employees. We reimburse EPCO for actual direct and
indirect expenses it incurs related to the operation of our
assets. These reimbursements were $329.7 million, $273.0 million and
$285.4 million during the years ended December 31, 2008, 2007 and 2006,
respectively.
Likewise, our general and
administrative costs for the years ended December 31, 2008, 2007 and 2006
include amounts we reimburse to EPCO for administrative services, including
compensation of employees. In general, our reimbursement to EPCO for
administrative services is either (i) on an actual basis for direct expenses it
may incur on our behalf (e.g., the purchase of office supplies) or (ii) based on
an allocation of such charges between the various parties to ASA based on the
estimated use of such services by each party (e.g., the allocation of general
legal or accounting salaries based on estimates of time spent on each entity’s
business and affairs). These reimbursements were $59.1 million, $56.5
million and $41.3 million during the years ended December 31, 2008, 2007 and
2006, respectively.
Since the
vast majority of such expenses are charged to us on an actual basis (i.e. no
mark-up or subsidy is charged or received by EPCO), we believe that such
expenses are representative of what the amounts would have been on a
stand alone basis. With respect to allocated costs, we believe that
the proportional direct allocation method employed by EPCO is reasonable and
reflective of the estimated level of costs we would have incurred on a
standalone basis.
The ASA also addresses potential
conflicts that may arise among Enterprise Products Partners (including EPGP),
Enterprise GP Holdings (including EPE Holdings), Duncan Energy Partners
(including DEP GP), and the EPCO Group with respect to business opportunities
with third parties. The EPCO Group includes EPCO and its other
affiliates, but excludes Enterprise Products Partners, Enterprise GP Holdings,
Duncan Energy Partners and their respective general partners. With
respect to potential conflicts with respect to third party business
opportunities, the ASA provides, among other things, that:
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If
a business opportunity to acquire “equity securities” (as defined
below) is
presented to the EPCO Group, Enterprise Products Partners (including
EPGP), Enterprise GP Holdings (including EPE Holdings), Duncan Energy
Partners (including DEP GP), then Enterprise GP Holdings will have the
first right to pursue such opportunity. The term “equity
securities” is defined to
include:
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general
partner interests (or securities which have characteristics similar to
general partner interests) or interests in “persons” that own or control
such general partner or similar interests (collectively, “GP Interests”)
and securities convertible, exercisable, exchangeable or otherwise
representing ownership or control of such GP Interests;
and
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IDRs
and limited partner interests (or securities which have characteristics
similar to IDRs or limited partner interests) in publicly traded
partnerships or interests in “persons” that own or control such limited
partner or similar interests (collectively, “non-GP Interests”); provided
that
such non-GP Interests are associated with GP Interests and are owned by
the owners of GP Interests or their respective
affiliates.
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Enterprise
GP Holdings will be presumed to want to acquire the equity securities until such
time as EPE Holdings advises the EPCO Group, EPGP and DEP GP that it has
abandoned the pursuit of such business opportunity. In the event that
the purchase price of the equity securities is reasonably likely to equal or
exceed $100.0 million, the decision to decline the acquisition will be made
by the chief executive officer of EPE Holdings after consultation with and
subject to the approval of the ACG Committee of EPE Holdings. If the
purchase price is reasonably likely to be less than $100.0 million, the chief
executive officer of EPE Holdings may make the determination to decline the
acquisition without consulting the ACG Committee of EPE
Holdings.
In the
event that Enterprise GP Holdings abandons the acquisition and so notifies the
EPCO Group, EPGP and DEP GP, Enterprise Products Partners will have the second
right to pursue such acquisition. Enterprise Products Partners will
be presumed to want to acquire the equity securities until such time as EPGP
advises the EPCO Group and DEP GP that Enterprise Products Partners has
abandoned the pursuit of such acquisition. In determining whether or
not to pursue the acquisition, Enterprise Products Partners will follow the same
procedures applicable to Enterprise GP Holdings, as described above but
utilizing EPGP’s chief executive officer and ACG Committee.
In its
sole discretion, Enterprise Products Partners may affirmatively direct such
acquisition opportunity to Duncan Energy Partners. In the event this
occurs, Duncan Energy Partners may pursue such acquisition.
In the
event Enterprise Products Partners abandons the acquisition opportunity for the
equity securities and so notifies the EPCO Group and DEP GP, the EPCO Group may
pursue the acquisition or offer the opportunity to TEPPCO (including TEPPCO GP)
and their controlled affiliates, in either case, without any further obligation
to any other party or offer such opportunity to other
affiliates.
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If
any business opportunity not covered by the preceding bullet point (i.e.
not involving equity securities) is presented to the EPCO Group,
Enterprise Products Partners (including EPGP), Enterprise GP Holdings
(including EPE Holdings), or Duncan Energy Partners (including DEP GP),
Enterprise Products Partners will have the first right to pursue such
opportunity either for itself or, if desired by Enterprise Products
Partners in its sole discretion, for the benefit of Duncan Energy
Partners. It will be presumed that Enterprise Products Partners will
pursue the business opportunity until such time as its general partner
advises the EPCO Group, EPE Holdings and DEP GP that it has abandoned the
pursuit of such business
opportunity.
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In the
event the purchase price or cost associated with the business opportunity is
reasonably likely to equal or exceed $100.0 million, any decision to
decline the business opportunity will be made by the chief executive officer of
EPGP after consultation with and subject to the approval of the ACG Committee of
EPGP. If the purchase price or cost is reasonably likely to be less
than $100.0 million, the chief executive officer of EPGP may make the
determination to decline the business opportunity without consulting EPGP’s ACG
Committee.
In its
sole discretion, Enterprise Products Partners may affirmatively direct such
acquisition opportunity to Duncan Energy Partners. In the event this
occurs, Duncan Energy Partners may pursue such acquisition.
In the
event that Enterprise Products Partners abandons the business opportunity for
itself and Duncan Energy Partners and so notifies the EPCO Group, EPE Holdings
and DEP GP, Enterprise GP Holdings will have the second right to pursue such
business opportunity. It will be presumed that Enterprise GP Holdings
will pursue such acquisition until such time as its general partner declines
such opportunity (in accordance with the procedures described above for
Enterprise
Products
Partners) and advises the EPCO Group that it has abandoned the pursuit of such
business opportunity. Should this occur, the EPCO Group may either
pursue the business opportunity or offer the business opportunity to TEPPCO
(including TEPPCO GP) and their controlled affiliates without any further
obligation to any other party or offer such opportunity to other
affiliates.
None of
Enterprise Products Partners, Enterprise GP Holdings, Duncan Energy Partners or
their respective general partners or the EPCO Group have any obligation to
present business opportunities to TEPPCO (including TEPPCO GP) or their
controlled affiliates. Likewise, TEPPCO (including TEPPCO GP) and their
controlled affiliates have no obligation to present business opportunities to
Enterprise Products Partners, Enterprise GP Holdings, Duncan Energy Partners or
their respective general partners or the EPCO Group.
The ASA
was amended on January 30, 2009 to provide for the cash reimbursement by us and
Enterprise GP Holdings to EPCO of distributions of cash or securities, if
any, made by EPCO Unit to its Class B limited partners. The ASA
amendment also extended the term under which EPCO provides services to the
partnership entities from December 2010 to December 2013 and made other updating
and conforming changes.
Employee
Partnerships. EPCO formed the
Employee Partnerships to serve as an incentive arrangement for key employees of
EPCO by providing them a “profits interest” in such
partnerships. Certain EPCO employees who work on behalf of us and
EPCO were issued Class B limited partner interests and admitted as Class B
limited partners without any capital contribution. The profits
interest awards (i.e., the Class B limited partner interests) in the
Employee Partnerships entitles each holder to participate in the appreciation in
value of our common units, Enterprise GP Holdings’ units, or both. See Note
5 for additional information regarding the Employee Partnerships.
Relationship
with TEPPCO
TEPPCO
became a related party to us in February 2005 when its general partner was
acquired by private company affiliates of EPCO. Our relationship was
further reinforced by the acquisition of TEPPCO’s general partner by Enterprise
GP Holdings in May 2007. Enterprise GP Holdings also owns our general
partner.
We
received $121.2 million, $67.6 million and $42.9 million from TEPPCO during the
years ended December 31, 2008, 2007 and 2006, respectively, from the sale of
hydrocarbon products. We paid TEPPCO $42.0 million, $19.4 million and
$24.0 million for NGL pipeline transportation and storage services during the
years ended December 31, 2008, 2007 and 2006, respectively.
Purchase
of Pioneer I
plant
from TEPPCO. In
March 2006, we paid TEPPCO $38.2 million for its Pioneer I natural gas
processing plant located in Opal, Wyoming and certain natural gas processing
rights related to natural gas production from the Jonah and Pinedale fields
located in the Greater Green River Basin in Wyoming. After an
in-depth consideration of all relevant factors, this transaction was approved by
the ACG Committee of our general partner and the Audit and Conflicts Committee
of the general partner of TEPPCO. TEPPCO has no continued involvement
in the contracts or in the operations of the Pioneer facility.
Jonah
Joint Venture with TEPPCO. In August 2006, we became a
joint venture partner with TEPPCO in Jonah, which owns the Jonah Gas Gathering
System located in the Greater Green River Basin of southwestern
Wyoming. The Jonah Gathering System gathers and transports natural
gas produced from the Jonah and Pinedale fields to regional natural gas
processing plants and major interstate pipelines that deliver natural gas to
end-user markets.
Prior to
entering into the Jonah joint venture, we managed the construction of the Phase
V expansion and funded the initial construction costs under a letter of intent
we entered into in February 2006. In connection with the joint
venture arrangement, we and TEPPCO shared equally in the costs of the Phase V
expansion, which is increased the capacity of the Jonah Gathering System from
1.5 Bcf/d to 2.4
Bcf/d and
significantly reduced system operating pressures, which we anticipate will lead
to increased production rates and ultimate reserve recoveries. The
first portion of the expansion, which has increased the system gathering
capacity to 2.0 Bcf/d, was completed in July 2007 and the final phase of this
expansion was completed in June 2008. We managed the Phase V
construction project. Currently, the gathering capacity of this
system is 2.4 Bcf/d.
Since
August 1, 2006, we and TEPPCO have equally shared in the construction costs of
the Phase V expansion. TEPPCO has reimbursed us $306.5 million, which
represents 50.0% of total Phase V costs incurred through December 31,
2008. We had a receivable of $1.0 million from TEPPCO at December 31,
2008 for Phase V expansion costs.
During
the first quarter of 2008, Jonah initiated a separate project to increase
gathering capacity on that portion of its system that serves the Pinedale
production field. This new project is expected to increase overall
capacity of the Jonah Gas Gathering System by an additional 0.2
Bcf/d. The total anticipated cost of this new project is $125.0
million, of which we will be responsible for our share of the construction
costs.
TEPPCO
was entitled to all distributions from the joint venture until specified
milestones were achieved, at which point, we became entitled to receive 50.0% of
the incremental cash flow from portions of the system placed in service as part
of the expansion. Since the first phase of this expansion was reached
in July 2007, we and TEPPCO have shared earnings based on a formula that takes
into account our respective capital contributions, including expenditures by
TEPPCO prior to the expansion.
At
December 31, 2008, we owned an approximate 19.4% interest in Jonah and TEPPCO
owns 80.6%. We operate the Jonah system. We account for
our investment in the Jonah joint venture using the equity method.
The Jonah
joint venture is governed by a management committee comprised of two
representatives approved by us and two appointed by TEPPCO, each with equal
voting power. After an in-depth consideration of all relevant
factors, this transaction was approved by the ACG Committee of our general
partner and the Audit and Conflicts Committee of the general partner of
TEPPCO.
We have
agreed to indemnify TEPPCO from any and all losses, claims, demands, suits,
liabilities, costs and expenses arising out of or related to breaches of our
representations, warranties, or covenants related to the Jonah joint
venture. A claim for indemnification cannot be filed until the losses
suffered by TEPPCO exceed $1.0 million. The maximum potential amount
of future payments under the indemnity agreement is limited to $100.0
million. All indemnity payments are net of insurance recoveries that
TEPPCO may receive from third-party insurance carriers. We carry
insurance coverage that may offset any payments required under the
indemnification.
Purchase
of Houston-area pipelines from TEPPCO. In October 2006, we
purchased certain idle pipeline assets in the Houston, Texas area from TEPPCO
for $11.7 million in cash. The acquired pipelines became part of our
Texas Intrastate System. The purchase of this asset was in accordance
with the Board-approved management authorization policy.
Purchase
and lease of pipelines for DEP South Texas NGL Pipeline System from
TEPPCO. In
January 2007, we purchased a 10-mile segment of pipeline from TEPPCO located in
the Houston area for $8.0 million. This pipeline segment is part of
the DEP South Texas NGL Pipeline System that commenced operations in January
2007. In addition, we entered into a lease with TEPPCO for an 11-mile
interconnecting pipeline located in the Houston area that is part of the DEP
South Texas NGL Pipeline System. Although the primary term of
the lease expired in September 2007, it was renewed on a month-to-month basis
until construction of a parallel pipeline was completed in early
2008. These transactions were in accordance with the Board-approved
management authorization policy.
Texas Offshore
Port
System Joint
Venture. In
August 2008, we, together with TEPPCO and Oiltanking, announced the
formation of the Texas Offshore Port System, a joint venture to design,
construct,
operate and own a Texas offshore crude oil port and a related onshore pipeline
and storage system that would facilitate delivery of waterborne crude oil to
refining centers located along the upper Texas Gulf Coast. The joint
venture’s primary project, referred to as “TOPS,” includes (i) an offshore port
(which will be located approximately 36 miles from Freeport, Texas), (ii)
an onshore storage facility with approximately 3.9 million barrels of crude
oil storage capacity, and (iii) an 85-mile crude oil pipeline system having a
transportation capacity of up to 1.8 million barrels per day, that will extend
from the offshore port to a storage facility near Texas City,
Texas. The joint venture’s complementary project, referred to as the
Port Arthur Crude Oil Express (or “PACE”) will transport crude oil from Texas
City, including crude oil from TOPS, and will consist of a 75-mile pipeline and
1.2 million barrels of crude oil storage capacity in the Port Arthur, Texas
area. The timing of the construction and related capital costs of the
TOPS and PACE projects will be affected by the expansion plans of Motiva and the
acquisition of requisite permits.
We, TEPPCO and Oiltanking each own, through our respective subsidiaries, a
one-third interest in the joint venture. The aggregate cost of the TOPS
and PACE projects is expected to be approximately $1.8 billion (excluding
capitalized interest), with the majority of such capital expenditures currently
expected to occur in 2010 and 2011. We and TEPPCO have each guaranteed up
to approximately $700.0 million, which includes a contingency amount for
potential cost overruns, of the capital contribution obligations of our
respective subsidiary partners in the joint venture. As of December 31,
2008, our investment in the Texas Offshore Port System was $35.9
million.
Relationship
with Energy Transfer Equity
Enterprise
GP Holdings acquired equity method investments in Energy Transfer Equity and its
general partner in May 2007. As a result, Energy Transfer Equity and
its consolidated subsidiaries became related parties to our consolidated
businesses.
For the
year ended December 31, 2008 and the eight months ended December 31, 2007, we
recorded $618.4 million and $294.4 million, respectively, of revenues from
Energy Transfer Partners, L.P. (“ETP”), primarily from NGL marketing
activities. We incurred $192.2 million and $35.2 million in costs of
sales and operating costs and expenses for the year ended December 31, 2008 and
the eight months ended December 31, 2007, respectively. We have a
long-term revenue generating contract with Titan Energy Partners, L.P.
(“Titan”), a consolidated subsidiary of ETP. Titan purchases
substantially all of its propane requirements from us. The contract
continues until March 31, 2010 and contains renewal and extension
options. We and Energy Transfer Company (“ETC OLP”) transport natural
gas on each other’s systems and share operating expenses on certain
pipelines. ETC OLP also sells natural gas to us.
Relationship
with Duncan Energy Partners
Duncan
Energy Partners was formed in September 2006 and did not acquire any assets
prior to February 5, 2007, which was the date it completed its initial public
offering of 14,950,000 common units and acquired controlling interests in
certain midstream energy businesses of EPO. The business purpose of
Duncan Energy Partners is to acquire, own and operate a diversified portfolio of
midstream energy assets and to support the growth objectives of EPO and other
affiliates under common control. Duncan Energy Partners is
engaged in the business of transporting and storing NGLs and petrochemical
products and gathering, transporting, storing and marketing of natural
gas.
At December 31, 2008, Duncan Energy
Partners is owned 99.3% by its limited partners and 0.7% by its general partner,
DEP GP, which is a wholly owned subsidiary of EPO. DEP GP is
responsible for managing the business and operations of Duncan Energy
Partners. DEP OLP, a wholly owned subsidiary of Duncan Energy
Partners, conducts substantially all of Duncan Energy Partners’
business.
At December 31, 2008, EPO owned
approximately 74.1% of Duncan Energy Partners’ limited partner interests and
100.0% of its general partner.
DEP
I Midstream Businesses
On February 5, 2007, EPO contributed a
66.0% controlling equity interest in each of the DEP I Midstream Businesses
(defined below) to Duncan Energy Partners in a dropdown of assets (the “DEP I
dropdown”). EPO retained the remaining 34.0% equity interest in each
of the DEP I Midstream Businesses. The DEP I Midstream Businesses
consist of (i) Mont Belvieu Caverns, LLC (“Mont Belvieu Caverns”); (ii) Acadian
Gas, LLC (“Acadian Gas”); (iii) Enterprise Lou-Tex Propylene Pipeline L.P.
(“Lou-Tex Propylene”), including its general partner; (iv) Sabine Propylene
Pipeline L.P. (“Sabine Propylene’), including its general partner; and (v) South
Texas NGL Pipelines, LLC (“South Texas NGL”).
As consideration for controlling equity
interests in the DEP I Midstream Businesses and reimbursement for capital
expenditures related to these businesses, Duncan Energy Partners distributed to
EPO (i) $260.6 million of the $290.5 million of net proceeds from its initial
public offering to EPO, (ii) $198.9 million in borrowings under its
DEP I Revolving Credit Facility and (iii) a net 5,351,571 common units of Duncan
Energy Partners. See Note 14 for information regarding the debt
obligations of Duncan Energy Partners.
DEP
II Midstream Businesses
On December 8, 2008, Duncan Energy
Partners entered into the DEP II Purchase Agreement with EPO and Enterprise GTM,
a wholly owned subsidiary of EPO. Pursuant to the DEP II Purchase
Agreement, DEP OLP acquired 100.0% of the membership interests in Enterprise III
from Enterprise GTM, thereby acquiring a 66.0% general partner interest in
Enterprise GC, a 51.0% general partner interest in Enterprise Intrastate and a
51.0% membership interest in Enterprise Texas. Collectively, we
refer to Enterprise GC, Enterprise Intrastate and Enterprise Texas as the
“DEP II Midstream Businesses.” EPO was the sponsor of this second
dropdown transaction (the “DEP II dropdown”). Enterprise GTM retained
the remaining limited partner and member interests in the DEP II Midstream
Businesses.
As consideration for controlling equity
interests in the DEP II Midstream Businesses, EPO received $280.5 million in
cash and 37,333,887 Class B limited partner units having a market value of
$449.5 million from Duncan Energy Partners. The Class B limited
partner units automatically converted to common units of Duncan Energy Partners
on February 1, 2009. The total value of the consideration provided to
EPO and Enterprise GTM was $730.0 million. The cash portion of the
consideration provided by Duncan Energy Partners in this dropdown transaction
was derived from borrowings under the DEP II Term Loan Agreement. See
Note 14 for information regarding the debt obligations of Duncan Energy
Partners.
Generally, the DEP II dropdown
transaction documents provide that to the extent that the DEP II Midstream
Businesses generate cash sufficient to pay distributions to their partners or
members, such cash will be distributed to Enterprise III (a wholly owned by
Duncan Energy Partners) and Enterprise GTM (our wholly owned subsidiary) in an
amount sufficient to generate an aggregate annualized return on their respective
investments of 11.85%. Distributions in excess of this amount will be
distributed 98.0% to Enterprise GTM and 2.0% to Enterprise
III. The initial annual fixed return amount of 11.85% will be
increased by 2.0% each calendar year beginning January 1, 2010. For example, the
fixed return in 2010, assuming no other adjustments, would be 102.0% of 11.85%,
or 12.087%.
Duncan
Energy Partners paid a pro rated cash distribution of $0.1115 per unit on the
Class B units with respect to the fourth quarter of 2008.
The borrowings of Duncan Energy
Partners are presented as part of our consolidated debt; however, we do not have
any obligation for the payment of interest or repayment of borrowings incurred
by Duncan Energy Partners.
We may contribute other equity
interests in our subsidiaries to Duncan Energy Partners and use the proceeds we
receive from Duncan Energy Partners to fund our capital spending
program.
Omnibus
Agreement
On
December 8, 2008, we entered into an amended and restated Omnibus Agreement with
Duncan Energy Partners. The key provisions of this agreement are
summarized as follows:
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indemnification
for certain environmental liabilities, tax liabilities and right-of-way
defects with respect to the DEP I and DEP II Midstream Businesses we
contributed to Duncan Energy Partners in connection with the
respective dropdown transactions;
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funding
by EPO of 100.0% of post-February 5, 2007 capital expenditures incurred by
South Texas NGL and Mont Belvieu Caverns with respect to certain expansion
projects under construction at the time of Duncan Energy Partners’ initial
public offering;
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funding
by EPO of 100.0% of post-December 8, 2008 capital expenditures (estimated
at $1.4 million) to complete the Sherman Extension natural gas
pipeline;
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a
right of first refusal to EPO in our current and future subsidiaries and a
right of first refusal on the material assets of such subsidiaries, other
than sales of inventory and other assets in the ordinary course of
business; and
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a
preemptive right with respect to equity securities issued by certain of
our subsidiaries, other than as consideration in an acquisition or in
connection with a loan or debt
financing.
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We and Duncan Energy Partners have also
agreed to negotiate in good faith any necessary amendments to the partnership or
company agreements of the DEP II Midstream Businesses when either party believes
that business circumstances have changed.
Our general partner’s ACG Committee
must approve amendments to the Omnibus Agreement when such amendments would
adversely affect our unitholders.
EPO has
indemnified Duncan Energy Partners against certain environmental liabilities,
tax liabilities and right-of-way defects associated with the assets EPO
contributed to Duncan Energy Partners in connection with the DEP I
and DEP II dropdown transactions. These liabilities include both
known and unknown environmental and related liabilities. These
indemnifications terminate on February 5, 2010. There is an aggregate
cap of $15.0 million on the amount of indemnity coverage, and Duncan Energy
Partners is not entitled to indemnification until the aggregate amount of claims
it incurs exceeds $250 thousand. Environmental liabilities resulting
from a change of law after February 5, 2007 are excluded from the
indemnity. In addition, EPO has indemnified Duncan Energy Partners
for liabilities related to:
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certain
defects in the easement rights or fee ownership interests in and to the
lands on which any assets contributed to Duncan Energy Partners in
connection with its initial public offering are located and failure to
obtain certain consents and permits necessary to conduct its business that
arise through February 5, 2010; and
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certain
income tax liabilities attributable to the operation of the assets
contributed to Duncan Energy Partners in connection with its initial
public offering prior to February 5,
2007.
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The Omnibus Agreement may not be
amended without the prior approval of the ACG Committee if the proposed
amendment will, in the reasonable discretion of DEP GP, adversely affect holders
of its common units.
Neither we, nor EPO and any of its
affiliates are restricted under the Omnibus Agreement from competing with Duncan
Energy Partners. Except as otherwise expressly agreed in the ASA, EPO
and any of its affiliates may acquire, construct or dispose of additional
midstream energy or other assets in the future without any obligation to offer
Duncan Energy Partners the opportunity to purchase or construct
those
assets. These agreements are in addition to other agreements relating
to business opportunities and potential conflicts of interest set forth in the
ASA with EPO, EPCO and other affiliates of EPCO.
Under the Omnibus Agreement, EPO agreed
to make additional contributions to Duncan Energy Partners as reimbursement for
Duncan Energy Partners’ 66.0% share of any excess construction costs above the
(i) $28.6 million of estimated capital expenditures to complete Phase II
expansions of the DEP South Texas NGL Pipeline System and (ii) $14.1 million of
estimated construction costs for additional brine production capacity and
above-ground storage reservoir projects at Mont Belvieu, Texas. Both
projects were underway at the time of Duncan Energy Partners’ initial public
offering. EPO made cash contributions to Duncan Energy Partners of
$32.5 million and $9.9 million in connection with the Omnibus Agreement during
the years ended December 31, 2008 and 2007, respectively. The
majority of these contributions related to funding the Phase II expansion costs
of the DEP South Texas NGL Pipeline System. EPO will not receive an
increased allocation of earnings or cash flows as a result of these
contributions to South Texas NGL and Mont Belvieu Caverns.
Mont
Belvieu Caverns’ LLC Agreement
The Mont
Belvieu Caverns’ LLC Agreement (the “Caverns LLC Agreement”) states that if
Duncan Energy Partners elects to not participate in certain projects of Mont
Belvieu Caverns, then EPO is responsible for funding 100.0% of such
projects. To the extent such non-participated projects generate
identifiable incremental cash flows for Mont Belvieu Caverns in the future, the
earnings and cash flows of Mont Belvieu Caverns will be adjusted to allocate
such incremental amounts to EPO by special allocation or
otherwise. Under the terms of the Caverns LLC Agreement, Duncan
Energy Partners may elect to acquire a 66.0% share of these projects from EPO
within 90 days of such projects being placed in service.
EPO made
cash contributions of $99.5 million and $38.1 million under the Caverns LLC
Agreement during the years ended December 31, 2008 and 2007, respectively, to
fund 100.0% of certain storage-related projects for the benefit of EPO’s NGL
marketing activities. At present, Mont Belvieu Caverns is not
expected to generate any identifiable incremental cash flows in connection with
these projects; thus, the sharing ratio for Mont Belvieu Caverns is not expected
to change from the current sharing ratio of 66.0% for Duncan Energy Partners and
34.0% for EPO. EPO expects to make additional contributions of
approximately $27.5 million to fund such projects in 2009. The
constructed assets will be the property of Mont Belvieu Caverns.
In
November 2008, the Caverns LLC Agreement was amended to provide that EPO would
prospectively receive a special allocation of 100.0% of the depreciation related
to projects that it has fully funded. For the two-month period
in 2008 covered by the amendment, EPO was allocated depreciation expense of $1.0
million related to such projects.
The
Caverns LLC Agreement also requires the allocation to EPO of operational
measurement gains and losses. Operational measurement gains and
losses are created when product is moved between storage wells and are
attributable to pipeline and well connection measurement variances.
Company and
Limited
Partnership Agreements
–
DEP
II Midstream Businesses
On
December 8, 2007, the DEP II Midstream Businesses amended and restated their
governing documents in connection with the DEP II dropdown
transaction. Collectively, these amended and restated agreements
provide for the following:
|
§
|
the
acquisition by Enterprise III (a wholly owned subsidiary of Duncan Energy
Partners) from Enterprise GTM (our wholly owned subsidiary) of a 66.0%
general partner interest in Enterprise GC, a 51.0% general partner
interest in Enterprise Intrastate and a 51.0% member interest in
Enterprise Texas;
|
|
§
|
the
payment of distributions in accordance with an overall “waterfall”
approach that stipulates that to the extent that the DEP II Midstream
Businesses collectively generate cash sufficient to pay
|
distributions
to their partners or members, such cash will be distributed first to Enterprise
III (based on an initial defined investment of $730.0 million, the “Enterprise
III Distribution Base”) and then to Enterprise GTM (based on an initial defined
investment of $452.1 million, the “Enterprise GTM Distribution Base”) in amounts
sufficient to generate an aggregate annualized fixed return on their respective
investments of 11.85%. Distributions in excess of these amounts will
be distributed 98.0% to Enterprise GTM and 2.0% to Enterprise
III. The initial annual fixed return amount of 11.85% will be
increased by 2.0% each calendar year beginning January 1, 2010. For example, the
fixed return in 2010, assuming no other adjustments, would be 102.0% of 11.85%,
or 12.087%;
|
§
|
the
funding of operating cash flow deficits in accordance with each owner’s
respective partner or member interest;
and
|
|
§
|
the
election by either owner to fund cash calls associated with expansion
capital projects. Since December 8, 2008, Enterprise III has
elected to not participate in such cash calls and, as a result, Enterprise
GTM has funded 100.0% of the expansion project costs of the DEP II
Midstream Businesses. If Enterprise III later elects to
participate in an expansion projects, then Enterprise III will be required
to make a capital contribution for its share of the project
costs.
|
Any
capital contributions to fund expansion projects made by either Enterprise III
or Enterprise GTM will increase such partner’s Distribution Base (and hence
future priority return amounts) under the Company Agreement of Enterprise Texas.
As noted, Enterprise III has declined participation in expansion project
spending since December 8, 2008. As a result, Enterprise GTM has funded 100.0%
of such growth capital spending and its Distribution Base has increased from
$452.1 million at December 8, 2008 to $473.4 million at December 31,
2008. The Enterprise III Distribution Base was unchanged at $730.0
million at December 31, 2008.
Relationships
with Unconsolidated Affiliates
Many of
our unconsolidated affiliates perform supporting or complementary roles to our
other business operations. See Note 16 of the Notes to
Consolidated Financial Statements for a discussion of this alignment of
commercial interests. Since we and our affiliates hold ownership
interests in these entities and directly or indirectly benefit from our related
party transactions with such entities, they are presented here.
The
following information summarizes significant related party transactions with our
current unconsolidated affiliates:
|
§
|
We
sell natural gas to Evangeline, which, in turn, uses the natural gas to
satisfy supply commitments it has with a major Louisiana
utility. Revenues from Evangeline were $362.9 million, $268.0
million and $277.7 million for the years ended December 31, 2008, 2007 and
2006. In addition, Duncan Energy Partners furnished $1.0 million in
letters of credit on behalf of Evangeline at December 31,
2008.
|
|
§
|
We
pay Promix for the transportation, storage and fractionation of
NGLs. In addition, we sell natural gas to Promix for its plant
fuel requirements. Revenues from Promix were $24.5 million,
$17.3 million and $21.8 million for the years ended December 31, 2008,
2007 and 2006. Expenses with Promix were $38.7 million, $30.4
million and $34.9 million for the years ended December 31, 2008, 2007 and
2006.
|
|
§
|
We
pay Jonah for natural gas purchases from its gathering
system. Expenses with Jonah were $38.3 million and $4.9 million
for the years ended December 31, 2008 and 2007. We were not
entitled to our 19.4% interest in Jonah until July
2007.
|
|
§
|
We
perform management services for certain of our unconsolidated
affiliates. We charged such affiliates $9.9 million, $9.3
million and $8.9 million for the years ended December 31, 2008, 2007 and
2006.
|
Our
provision for income taxes relates primarily to federal and state income taxes
of Seminole and Dixie, our two largest corporations subject to such income
taxes. In addition, with the amendment of the Texas Franchise
Tax in 2006, we have become a taxable entity in the state of
Texas. Our federal and state income tax provision is summarized
below:
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$ |
4,922 |
|
|
$ |
4,700 |
|
|
$ |
7,694 |
|
|
State
|
|
|
19,350 |
|
|
|
3,871 |
|
|
|
1,148 |
|
|
Foreign
|
|
|
414 |
|
|
|
128 |
|
|
|
-- |
|
|
Total
current
|
|
|
24,686 |
|
|
|
8,699 |
|
|
|
8,842 |
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
760 |
|
|
|
2,784 |
|
|
|
6,109 |
|
|
State
|
|
|
928 |
|
|
|
3,774 |
|
|
|
6,372 |
|
|
Foreign
|
|
|
27 |
|
|
|
-- |
|
|
|
-- |
|
|
Total
deferred
|
|
|
1,715 |
|
|
|
6,558 |
|
|
|
12,481 |
|
|
Total
provision for income taxes
|
|
$ |
26,401 |
|
|
$ |
15,257 |
|
|
$ |
21,323 |
|
A reconciliation of the provision for
income taxes with amounts determined by applying the statutory U.S. federal
income tax rate to income before income taxes is as follows:
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Pre
Tax Net Book Income (“NBI”)
|
|
$ |
1,021,798 |
|
|
$ |
579,574 |
|
|
$ |
630,085 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revised
Texas franchise tax
|
|
|
19,344 |
|
|
|
7,146 |
|
|
|
8,119 |
|
|
State
income taxes (net of federal benefit)
|
|
|
505 |
|
|
|
325 |
|
|
|
(396 |
) |
|
Federal
income taxes computed by applying the federal
|
|
|
|
|
|
|
|
|
|
|
|
|
|
statutory
rate to NBI of corporate entities
|
|
|
6,305 |
|
|
|
5,318 |
|
|
|
13,347 |
|
|
Taxes
charged to cumulative effect of change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
in
accounting principle
|
|
|
-- |
|
|
|
-- |
|
|
|
(3 |
) |
|
Valuation
allowance
|
|
|
(1,412 |
) |
|
|
2,347 |
|
|
|
123 |
|
|
Other
permanent differences
|
|
|
1,659 |
|
|
|
121 |
|
|
|
133 |
|
|
Provision
for income taxes
|
|
$ |
26,401 |
|
|
$ |
15,257 |
|
|
$ |
21,323 |
|
|
Effective
income tax rate
|
|
|
2.6% |
|
|
|
2.6% |
|
|
|
3.4% |
|
Significant
components of deferred tax assets and deferred tax liabilities as of December
31, 2008 and 2007 are as follows:
|
|
|
At
December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Deferred
tax assets:
|
|
|
|
|
|
|
|
Net
operating loss carryovers
|
|
$ |
26,311 |
|
|
$ |
23,270 |
|
|
Property,
plant and equipment
|
|
|
753 |
|
|
|
-- |
|
|
Credit
carryover
|
|
|
26 |
|
|
|
26 |
|
|
Charitable
contribution carryover
|
|
|
20 |
|
|
|
16 |
|
|
Employee
benefit plans
|
|
|
2,631 |
|
|
|
3,214 |
|
|
Deferred
revenue
|
|
|
964 |
|
|
|
642 |
|
|
Reserve
for legal fees and damages
|
|
|
289 |
|
|
|
478 |
|
|
Equity
investment in partnerships
|
|
|
596 |
|
|
|
409 |
|
|
AROs
|
|
|
76 |
|
|
|
80 |
|
|
Accruals
|
|
|
898 |
|
|
|
1,068 |
|
|
Total
deferred tax assets
|
|
|
32,564 |
|
|
|
29,203 |
|
|
Valuation allowance
|
|
|
(3,932 |
) |
|
|
(5,345 |
) |
|
Net
deferred tax assets
|
|
|
28,632 |
|
|
|
23,858 |
|
|
Deferred
tax liabilities:
|
|
|
|
|
|
|
|
|
|
Property,
plant and equipment
|
|
|
92,899 |
|
|
|
40,520 |
|
|
Other
|
|
|
43 |
|
|
|
99 |
|
|
Total
deferred tax liabilities
|
|
|
92,942 |
|
|
|
40,619 |
|
|
Total
net deferred tax liabilities
|
|
$ |
(64,310 |
) |
|
$ |
(16,761 |
) |
|
|
|
|
|
|
|
|
|
|
|
Current
portion of total net deferred tax assets
|
|
$ |
1,397 |
|
|
$ |
1,081 |
|
|
Long-term
portion of total net deferred tax liabilities
|
|
$ |
(65,707 |
) |
|
$ |
(17,842 |
) |
We had net operating loss carryovers of
$26.3 million and $23.3 million at December 31, 2008 and 2007,
respectively. These losses expire in various years between 2009 and
2028 and are subject to limitations on their utilization. We record a
valuation allowance to reduce our deferred tax assets to the amount of future
tax benefit that is more likely than not to be realized. The
valuation allowance was $3.9 million and $5.3 million at December 31, 2008 and
2007, respectively, and serves to reduce the recognized tax benefit associated
with carryovers of our corporate entities to an amount that will, more
likely than not, be realized. The $1.4 million decrease in
valuation allowance for 2008 is comprised primarily of a $1.6
million decrease for Canadian Enterprise Gas Products, Ltd.
We have
deferred tax liabilities on property plant and equipment of $92.9 million and
$40.5 million at December 31, 2008 and 2007, respectively. The
increase in 2008 is comprised primarily of $45.1 million related to the
difference in book and tax basis of property, plant and equipment resulting from
the acquisition of the remaining equity interest of Dixie
Pipeline. See Note 12 for additional information.
On May
18, 2006, the State of Texas enacted House Bill 3 which revised the pre-existing
state franchise tax. In general, legal entities that conduct business
in Texas are subject to the Revised Texas Franchise Tax, including previously
non-taxable entities such as limited liability companies, limited partnerships
and limited liability partnerships. The tax is assessed on Texas
sourced taxable margin which is defined as the lesser of (i) 70.0% of total
revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation
and benefits.
Although
the bill states that the Revised Texas Franchise Tax is not an income tax, it
has the characteristics of an income tax since it is determined by applying a
tax rate to a base that considers both revenues and expenses. Due to
the enactment of the Revised Texas Franchise Tax, we recorded a net deferred tax
liability of $0.9 million and $3.8 million during the years ended December 31,
2008 and 2007, respectively. The offsetting net charge of $0.9
million and $3.8 million is shown on our Statements of Consolidated Operations
for the years ended December 31, 2008 and 2007, respectively, as a component of
“Provision for income taxes.”
Basic
earnings per unit is computed by dividing net income or loss allocated to
limited partner interests by the weighted-average number of distribution-bearing
units outstanding during a period. Diluted earnings per unit is
computed by dividing net income or loss allocated to limited partner interests
by the sum of (i) the weighted-average number of distribution-bearing units
outstanding during a period (as used in determining basic earnings per unit);
(ii) the weighted-average number of performance-based phantom units outstanding
during a period; and (iii) the number of incremental common units resulting from
the assumed exercise of dilutive unit options outstanding during a period (the
“incremental option units”).
In a
period of net losses, restricted units, phantom units and incremental option
units are excluded from the calculation of diluted earnings per unit due to
their antidilutive effect. The dilutive incremental option units are
calculated using the treasury stock method, which assumes that proceeds from the
exercise of all in-the-money options at the end of each period are used to
repurchase common units at an average market value during the
period. The amount of common units remaining after the proceeds are
exhausted represents the potentially dilutive effect of the
securities.
The amount of net income or loss
allocated to limited partner interests is net of our general partner’s share of
such earnings. The following table presents the allocation of net
income to EPGP for the periods indicated:
|
|
|
For
The Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$ |
954,021 |
|
|
$ |
533,674 |
|
|
$ |
601,155 |
|
|
Less
incentive earnings allocations to EPGP
|
|
|
(125,912 |
) |
|
|
(107,421 |
) |
|
|
(86,710 |
) |
|
Net
income available after incentive earnings allocation
|
|
|
828,109 |
|
|
|
426,253 |
|
|
|
514,445 |
|
|
Multiplied
by EPGP ownership interest
|
|
|
2.0% |
|
|
|
2.0% |
|
|
|
2.0% |
|
|
Standard
earnings allocation to EPGP
|
|
$ |
16,562 |
|
|
$ |
8,525 |
|
|
$ |
10,289 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incentive
earnings allocation to EPGP
|
|
$ |
125,912 |
|
|
$ |
107,421 |
|
|
$ |
86,710 |
|
|
Standard
earnings allocation to EPGP
|
|
|
16,562 |
|
|
|
8,525 |
|
|
|
10,289 |
|
|
Net
income available to EPGP
|
|
$ |
142,474 |
|
|
$ |
115,946 |
|
|
$ |
96,999 |
|
The
following table presents our calculation of basic and diluted earnings per unit
for the periods indicated:
|
|
|
For
The Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Income
before change in accounting principle
and
EPGP interest
|
|
$ |
954,021 |
|
|
$ |
533,674 |
|
|
$ |
599,683 |
|
|
Cumulative
effect of change in accounting principle
|
|
|
-- |
|
|
|
-- |
|
|
|
1,472 |
|
|
Net
income
|
|
|
954,021 |
|
|
|
533,674 |
|
|
|
601,155 |
|
|
Net
income available to EPGP
|
|
|
(142,474 |
) |
|
|
(115,946 |
) |
|
|
(96,999 |
) |
|
Net
income available to limited partners
|
|
$ |
811,547 |
|
|
$ |
417,728 |
|
|
$ |
504,156 |
|
|
BASIC
EARNINGS PER UNIT
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before change in accounting principle
and
EPGP earnings allocation
|
|
$ |
954,021 |
|
|
$ |
533,674 |
|
|
$ |
599,683 |
|
|
Cumulative
effect of change in accounting principle
|
|
|
-- |
|
|
|
-- |
|
|
|
1,472 |
|
|
Net
income available to EPGP
|
|
|
(142,474 |
) |
|
|
(115,946 |
) |
|
|
(96,999 |
) |
|
Net
income available to limited partners
|
|
$ |
811,547 |
|
|
$ |
417,728 |
|
|
$ |
504,156 |
|
|
Denominator
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
units
|
|
|
435,397 |
|
|
|
432,513 |
|
|
|
413,472 |
|
|
Time-vested
restricted units
|
|
|
1,980 |
|
|
|
1,446 |
|
|
|
970 |
|
|
Total
|
|
|
437,377 |
|
|
|
433,959 |
|
|
|
414,442 |
|
|
Basic
earnings per unit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
per unit before change in accounting principle
and
EPGP earnings allocation
|
|
$ |
2.18 |
|
|
$ |
1.23 |
|
|
$ |
1.45 |
|
|
Cumulative
effect of change in accounting principle
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
Net
income available to EPGP
|
|
|
(0.33 |
) |
|
|
(0.27 |
) |
|
|
(0.23 |
) |
|
Net
income available to limited partners
|
|
$ |
1.85 |
|
|
$ |
0.96 |
|
|
$ |
1.22 |
|
|
DILUTED
EARNINGS PER UNIT
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before change in accounting principle
and
EPGP earnings allocation
|
|
$ |
954,021 |
|
|
$ |
533,674 |
|
|
$ |
599,683 |
|
|
Cumulative
effect of change in accounting principle
|
|
|
-- |
|
|
|
-- |
|
|
|
1,472 |
|
|
Net
income available to EPGP
|
|
|
(142,474 |
) |
|
|
(115,946 |
) |
|
|
(96,999 |
) |
|
Net
income available to limited partners
|
|
$ |
811,547 |
|
|
$ |
417,728 |
|
|
$ |
504,156 |
|
|
Denominator
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
units
|
|
|
435,397 |
|
|
|
432,513 |
|
|
|
413,472 |
|
|
Time-vested
restricted units
|
|
|
1,980 |
|
|
|
1,446 |
|
|
|
970 |
|
|
Performance-based
restricted units
|
|
|
5 |
|
|
|
9 |
|
|
|
20 |
|
|
Incremental
option units
|
|
|
200 |
|
|
|
459 |
|
|
|
297 |
|
|
Total
|
|
|
437,582 |
|
|
|
434,427 |
|
|
|
414,759 |
|
|
Diluted
earnings per unit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
per unit before change in accounting principle
and
EPGP earnings allocation
|
|
$ |
2.18 |
|
|
$ |
1.23 |
|
|
$ |
1.45 |
|
|
Cumulative
effect of change in accounting principle
|
|
|
-- |
|
|
|
-- |
|
|
|
-- |
|
|
Net
income available to EPGP
|
|
|
(0.33 |
) |
|
|
(0.27 |
) |
|
|
(0.23 |
) |
|
Net
income available to limited partners
|
|
$ |
1.85 |
|
|
$ |
0.96 |
|
|
$ |
1.22 |
|
Litigation
On
occasion, we or our unconsolidated affiliates are named as a defendant in
litigation relating to our normal business activities, including regulatory and
environmental matters. Although we are insured against various
business risks to the extent we believe it is prudent, there is no assurance
that the nature and amount of such insurance will be adequate, in every case, to
indemnify us against liabilities arising from future legal proceedings as a
result of our ordinary business activities. We are unaware of any
significant
litigation,
pending or threatened, that could have a significant adverse effect on our
financial position, results of operations or cash flows.
On
September 18, 2006, Peter Brinckerhoff, a purported unitholder of TEPPCO, filed
a complaint in the Court of Chancery of New Castle County in the State of
Delaware, in his individual capacity, as a putative class action on behalf of
other unitholders of TEPPCO and derivatively on behalf of TEPPCO, concerning,
among other things, certain transactions involving TEPPCO and us or our
affiliates. Mr. Brinkerhoff filed an amended complaint on July 12, 2007.
The amended complaint names as defendants (i) TEPPCO, its current and certain
former directors, and certain of its affiliates; (ii) us and certain of our
affiliates; (iii) EPCO.; and (iv) Dan L. Duncan.
The
amended complaint alleges, among other things, that the defendants caused TEPPCO
to enter into certain transactions that were unfair to TEPPCO or otherwise
unfairly favored Enterprise Products Partners or its affiliates over
TEPPCO. These transactions are alleged to include: (i) the joint
venture to further expand the Jonah system entered into by TEPPCO and Enterprise
Products Partners in August 2006; (ii) the sale by TEPPCO of its Pioneer
natural gas processing plant to Enterprise Products Partners in March 2006;
and (iii) certain amendments to TEPPCO’s partnership agreement, including a
reduction in the maximum tier of TEPPCO’s IDRs in exchange for TEPPCO common
units. The amended complaint seeks (i) rescission of the
amendments to TEPPCO’s partnership agreement; (ii) damages for profits and
special benefits allegedly obtained by defendants as a result of the alleged
wrongdoings in the amended complaint; and (iii) awarding plaintiff costs of
the action, including fees and expenses of his attorneys and experts.
We believe this lawsuit is without merit and intend to vigorously defend
against it. See Note 17 for additional information regarding our
relationship with TEPPCO.
On
February 14, 2007, EPO received a letter from the Environment and Natural
Resources Division (“ENRD”) of the U.S. Department of Justice (“DOJ”) related to
an ammonia release in Kingman County, Kansas on October 27, 2004 from a
pressurized anhydrous ammonia pipeline owned by a third party, Magellan Ammonia
Pipeline, L.P. (“Magellan”) and a previous release of ammonia on September 27,
2004 from the same pipeline. EPO was the operator of this pipeline until
July 1, 2008. The ENRD has indicated that it may pursue civil damages against
EPO and Magellan as a result of these incidents. Based on this
correspondence from the ENRD, the statutory maximum amount of civil fines that
could be assessed against EPO and Magellan is up to $17.4 million in the
aggregate. EPO is cooperating with the DOJ and is hopeful that an
expeditious resolution of this civil matter acceptable to all parties will be
reached in the near future. Magellan has agreed to indemnify EPO for the
civil matter. At this time, we do not believe that a final resolution
of the civil claims by the ENRD will have a material impact on our consolidated
financial position, results of operations or cash flows.
On October 25, 2006, a rupture in
the Magellan Ammonia Pipeline resulted in the release of ammonia near Clay
Center, Kansas. The pipeline has been repaired and environmental
remediation tasks related to this incident have been completed. At
this time, we do not believe that this incident will have a material impact on
our consolidated financial position, results of operations or cash
flows.
Several
lawsuits have been filed by municipalities and other water suppliers against a
number of manufacturers of reformulated gasoline containing methyl tertiary
butyl ether (“MTBE”). In general, such suits have not named
manufacturers of MTBE as defendants, and there have been no such lawsuits filed
against our subsidiary that owns an octane-additive production
facility. It is possible, however, that former MTBE manufacturers
such as our subsidiary could ultimately be added as defendants in such lawsuits
or in new lawsuits.
The Attorney General of Colorado on
behalf of the Colorado Department of Public Health and Environment filed suit
against us and others on April 15, 2008 in connection with the construction of a
pipeline near Parachute, Colorado. The State sought a temporary
restraining order and an injunction to halt construction activities since it
alleged that the defendants failed to install measures to minimize damage to the
environment and to follow requirements for the pipeline’s stormwater permit and
appropriate stormwater plan. The State’s complaint also seeks penalties
for the above alleged failures. Defendants and the State agreed to
certain stipulations that, among other things, require us to install specified
environmental
protection measures in the disturbed pipeline right-of-way to comply with
regulations. We have complied with the stipulations and the State has
dismissed the portions of the complaint seeking the temporary restraining order
and injunction. The State has not yet assessed penalties and we are
unable to predict the amount of penalties that may be assessed. At this
time, we do not believe that this incident will have a material impact on our
consolidated financial position, results of operations or cash
flows.
In January 2009, the State of New
Mexico filed suit in District Court in Santa Fe County, New Mexico, under the
New Mexico Air Quality Control Act. The lawsuit arose out of a February
27, 2008 Notice Of Violation issued to Marathon as operator of the Indian Basin
natural gas processing facility located in Eddy County, New
Mexico. We own a 40.0% undivided interest in the assets comprising
the Indian Basin facility. The State alleges violations of its air
laws, and Marathon believes there has been no adverse impact to public health or
the environment, having implemented voluntary emission reduction measures over
the years. The State seeks penalties above $100,000. Marathon
continues to work with the State to determine if resolution of the case is
possible.
Contractual
Obligations
The following table summarizes our
various contractual obligations at December 31, 2008. A description
of each type of contractual obligation follows:
|
|
|
Payment
or Settlement due by Period
|
|
Contractual
Obligations
|
|
Total
|
|
2009
|
|
2010
|
|
2011
|
|
2012
|
|
2013
|
|
Thereafter
|
|
Scheduled
maturities of long-term debt
|
|
$ |
9,046,046 |
|
$ |
-- |
|
$ |
554,000 |
|
$ |
934,250 |
|
$ |
1,517,596 |
|
$ |
750,000 |
|
$ |
5,290,200 |
|
Estimated
cash payments for interest
|
|
$ |
9,351,928 |
|
$ |
544,658 |
|
$ |
522,633 |
|
$ |
471,253 |
|
$ |
451,450 |
|
$ |
369,673 |
|
$ |
6,992,261 |
|
Operating
lease obligations
|
|
$ |
331,419 |
|
$ |
32,299 |
|
$ |
27,541 |
|
$ |
27,831 |
|
$ |
27,066 |
|
$ |
24,481 |
|
$ |
192,201 |
|
Purchase
obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product
purchase commitments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
payment obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
$ |
5,225,141 |
|
$ |
323,309 |
|
$ |
515,102 |
|
$ |
635,000 |
|
$ |
660,626 |
|
$ |
487,984 |
|
$ |
2,603,120 |
|
NGLs
|
|
$ |
1,923,792 |
|
$ |
969,870 |
|
$ |
136,422 |
|
$ |
136,250 |
|
$ |
136,250 |
|
$ |
136,250 |
|
$ |
408,750 |
|
Petrochemicals
|
|
$ |
1,746,138 |
|
$ |
685,643 |
|
$ |
376,636 |
|
$ |
247,757 |
|
$ |
181,650 |
|
$ |
86,768 |
|
$ |
167,684 |
|
Other
|
|
$ |
37,455 |
|
$ |
19,202 |
|
$ |
3,459 |
|
$ |
3,322 |
|
$ |
3,051 |
|
$ |
2,919 |
|
$ |
5,502 |
|
Underlying
major volume commitments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (in BBtus)
|
|
|
981,955 |
|
|
56,650 |
|
|
93,150 |
|
|
115,925 |
|
|
120,780 |
|
|
93,950 |
|
|
501,500 |
|
NGLs
(in MBbls)
|
|
|
56,622 |
|
|
23,576 |
|
|
4,726 |
|
|
4,720 |
|
|
4,720 |
|
|
4,720 |
|
|
14,160 |
|
Petrochemicals
(in MBbls)
|
|
|
67,696 |
|
|
24,949 |
|
|
13,420 |
|
|
10,428 |
|
|
7,906 |
|
|
3,759 |
|
|
7,234 |
|
Service
payment commitments
|
|
$ |
529,402 |
|
$ |
52,614 |
|
$ |
50,902 |
|
$ |
49,501 |
|
$ |
47,025 |
|
$ |
46,142 |
|
$ |
283,218 |
|
Capital
expenditure commitments
|
|
$ |
521,262 |
|
$ |
521,262 |
|
$ |
-- |
|
$ |
-- |
|
$ |
-- |
|
$ |
-- |
|
$ |
-- |
Scheduled
Maturities of Long-Term Debt. We have long-term and
short-term payment obligations under debt agreements such as the indentures
governing EPO’s senior notes and the credit agreement governing EPO’s Multi-Year
Revolving Credit Facility. Amounts shown in the preceding table
represent our scheduled future maturities of debt principal for the periods
indicated. See Note 14 for additional information regarding our
consolidated debt obligations.
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 operating leases with terms in excess of one
year.
Our
significant lease agreements involve (i) the lease of underground caverns for
the storage of natural gas and NGLs, (ii) leased office space with an affiliate
of EPCO, (iii) a railcar unloading terminal in Mont Belvieu, Texas and (iv)
land held pursuant to right-of-way agreements. In general, our
material lease agreements have original terms that range from 2 to 28 years and
include renewal options that could extend the agreements for up to an additional
20 years.
Lease expense is charged to operating
costs and expenses on a straight line basis over the period of expected economic
benefit. Contingent rental payments are expensed as
incurred. We are generally required to perform routine maintenance on
the underlying leased assets. In addition, certain leases give us
the
option to make leasehold improvements. Maintenance and repairs of
leased assets resulting from our operations are charged to expense as
incurred. We did not make any significant leasehold improvements
during the years ended December 31, 2008, 2007 or 2006; however, we did incur
$9.3 million of repair costs associated with our lease of an underground natural
gas storage facility in 2006.
The
operating lease commitments shown in the preceding table exclude the non-cash,
related party expense associated with retained leases contributed to us by EPCO
at our formation. EPCO remains liable for the actual cash lease
payments associated with these agreements, which it accounts for as operating
leases. At December 31, 2008, the retained leases were for approximately
100 railcars. EPCO’s minimum future rental payments under these
leases are $0.7 million for each of the years 2009 through 2015 and $0.3 million
for 2016. We record the full value of these payments made by EPCO on
our behalf as a non-cash related party operating lease expense, with the offset
to partners’ equity accounted for as a general contribution to our
partnership.
The
retained lease agreements contain lessee purchase options, which are at prices
that approximate fair value of the underlying leased assets. EPCO has
assigned these purchase options to us. We have exercised
our election under the retained leases to purchase a cogeneration unit in
December 2008 for $2.3 million. Should we decide to exercise the
purchase option associated with the remaining agreement, we would pay the
original lessor $3.1 million in June 2016.
Lease and
rental expense included in costs and expenses was $36.0 million, $38.5 million
and $39.3 million during the years ended December 31, 2008, 2007 and 2006,
respectively.
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:
|
§
|
We
have long and short-term product purchase obligations for NGLs, certain
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, 2008 applied to all future volume
commitments. Actual future payment obligations may vary
depending on market prices at the time of delivery. At December
31, 2008, we do not have any significant product purchase commitments with
fixed or minimum pricing provisions with remaining terms in excess of one
year.
|
|
§
|
We
have long and short-term commitments to pay third-party providers for
services such as equipment maintenance agreements. Our
contractual payment obligations vary by contract. The preceding
table shows our future payment obligations under these service
contracts.
|
|
§
|
We
have short-term payment obligations relating to our capital projects and
those of our unconsolidated affiliates. These commitments
represent unconditional payment obligations to vendors for services
rendered or products purchased. The preceding table presents
our share of such commitments for the periods
indicated.
|
Commitments
under equity compensation plans of EPCO
In accordance with our agreements with
EPCO, we reimburse EPCO for our share of its compensation expense associated
with certain employees who perform management, administrative and operating
functions for us (see Note 17). This includes costs associated with
unit option awards granted to these employees to purchase our common
units. At December 31, 2008, there were 2,168,500 and 795,000 unit
options outstanding under the EPCO 1998 Plan and EPD 2008 LTIP, respectively,
for which we were responsible for reimbursing EPCO for the costs of such
awards.
The weighted-average strike price of
unit option awards outstanding at December 31, 2008 was $26.32 and $30.93
per common unit under the EPCO 1998 Plan and EPD 2008 LTIP,
respectively. At December 31, 2008, 548,500 of these unit options
were exercisable under the EPCO 1998 Plan. An additional 365,000,
480,000 and 775,000 of these unit options will be exercisable in 2009, 2010 and
2012, respectively under the EPCO 1998 Plan. The 795,000 unit options
outstanding under the EPD 2008 LTIP will become exercisable in
2013. As these options are exercised, we will reimburse EPCO in the
form of a special cash distribution for the difference between the strike price
paid by the employee and the actual purchase price paid for the units awarded to
the employee. See Note 5 for additional information regarding our
accounting for equity awards.
Performance
Guaranty
In
December 2004, a subsidiary of ours entered into the Independence Hub Agreement
(the “Agreement”) with six oil and natural gas producers. The
Agreement, as amended, obligated our subsidiary to construct the
Independence Hub offshore platform and to process 1.0 Bcf/d of natural gas
and condensate for the producers. We guaranteed to the producers the
construction-related performance of our subsidiary up to an amount of $340.8
million. The performance guaranty expired during the second quarter
of 2007.
Other
Claims
As part of our normal business
activities with joint venture partners and certain customers and suppliers, we
occasionally have claims made against us as a result of disputes related to
contractual agreements or similar arrangements. As of December 31,
2008, claims against us totaled approximately $15.4 million. These
matters are in various stages of assessment and the ultimate outcome of such
disputes cannot be reasonably estimated. However, in our opinion, the
likelihood of a material adverse outcome related to disputes against us is
remote. Accordingly, accruals for loss contingencies related to these
matters, if any, that might result from the resolution of such disputes have not
been reflected in our consolidated financial statements.
Other
Commitments
We
transport and store natural gas, NGLs and petrochemicals for third parties under
various processing, storage, transportation and similar
agreements. These volumes are (i) accrued as product payables on our
Consolidated Balance Sheets, (ii) in transit for delivery to our customers or
(iii) held at our storage facilities for redelivery to our
customers. We are insured against any physical loss of such volumes
due to catastrophic events. Under the terms of our natural gas, NGL
and petrochemical storage agreements, we are generally required to
redeliver volumes to the owner on demand. At December 31, 2008, NGL
and petrochemical products aggregating 29.6 million barrels were due to be
redelivered to their owners along with 18.5 BBtus of natural gas. See
Note 2 for more information regarding accrued product payables.
Nature
of Operations in Midstream Energy Industry
Our operations are within the midstream
energy industry, which includes gathering, transporting, processing,
fractionating and storing natural gas, NGLs, certain petrochemicals and crude
oil. As such, our financial condition, results of operations and cash
flows may be affected by changes in the commodity prices of these hydrocarbon
products, including changes in the relative price levels among these
products. In general, the prices of natural gas, NGLs, crude oil and
other hydrocarbon products are subject to fluctuations in response to changes in
supply, market uncertainty and a variety of additional factors that are beyond
our control.
Our profitability could be impacted by
a decline in the volume of hydrocarbon products transported, gathered or
processed at our facilities. A material decrease in natural gas or
crude oil
production
or crude oil refining for reasons such as depressed commodity prices or a
decrease in exploration and development activities, could result in a decline in
the volume of natural gas, NGLs and crude oil handled by our
facilities.
A reduction in demand for NGL products
by the petrochemical, refining or heating industries, whether because of (i)
general economic conditions, (ii) reduced demand by consumers for the end
products made using NGLs, (iii) increased competition from petroleum-based
products due to pricing differences, (iv) adverse weather conditions, (v)
government regulations affecting energy commodity prices, production levels of
hydrocarbons or the content of motor gasoline or (vi) other reasons,
could adversely affect our financial position, results of
operations and cash flows.
Credit
Risk due to Industry Concentrations
A
substantial portion of our revenues are derived from companies in the domestic
natural gas, NGL and petrochemical industries. This concentration
could affect our overall exposure to credit risk since these customers may be
affected by similar economic or other conditions. We generally do not
require collateral for our accounts receivable; however, we do attempt to
negotiate offset, prepayment, or automatic debit agreements with customers that
are deemed to be credit risks in order to minimize our potential exposure to any
defaults.
Our
revenues are derived from a wide customer base. During 2008 our
largest customer was LBI and its affiliates, which accounted for 9.6% of our
consolidated revenues. In 2007 and 2006, our largest customer was The
Dow Chemical Company and its affiliates, which accounted for 6.9% and 6.1%,
respectively, of our consolidated revenues.
On January 6, 2009, LBI announced that
its U.S. operations had voluntarily filed to reorganize under Chapter 11 of the
U.S. Bankruptcy Code. At the time of the bankruptcy filing, we had
approximately $17.3 million of credit exposure to LBI, which was reduced to
approximately $10.0 million through remedies provided under certain pipeline
tariffs. In addition, we are seeking to have LBI accept certain
contracts and have filed claims pursuant to current Bankruptcy Court Orders that
we expect will allow us to recover the majority of the remaining credit
exposure.
For 2008,
LBI accounted for 10.2%, or $1.6 billion, of revenues attributable to our NGL
Pipelines & Services business segment and 19.2%, or $516.2 million, of
revenues attributable to our Petrochemical Services business
segment.
Counterparty
Risk with Respect to Financial Instruments
In those
situations where we are exposed to credit risk in our financial instrument
transactions, we analyze the counterparty’s financial condition prior to
entering into an agreement, establish credit and/or margin limits and monitor
the appropriateness of these limits on an ongoing basis. Generally,
we do not require collateral nor do we anticipate nonperformance by our
counterparties.
Weather-Related
Risks
We
participate as a named insured in EPCO’s insurance program, which provides us
with property damage, business interruption and other coverages, the scope and
amounts of which are customary and sufficient for the nature and extent of our
operations. While we believe EPCO maintains adequate insurance
coverage on our behalf, insurance will not cover every type of damage or
interruption that might occur. If we were to incur a significant
liability for which we were not fully insured, it could have a material impact
on our consolidated financial position, results of operations and cash
flows. In addition, the proceeds of any such insurance may not be
paid in a timely manner and may be insufficient to reimburse us for our repair
costs or lost income. Any event that interrupts the revenues generated by
our consolidated operations, or which causes us to make significant expenditures
not covered by insurance,
could
reduce our ability to pay distributions to our partners and, accordingly,
adversely affect the market price of our common units.
For
windstorm events such as hurricanes and tropical storms, EPCO’s deductible for
onshore physical damage is $10.0 million per storm. For
offshore assets, the windstorm deductible is $10.0 million per storm plus a
one-time $15.0 million aggregate deductible per policy period. For
non-windstorm events, EPCO’s deductible for onshore and offshore physical damage
is $5.0 million per occurrence. In meeting the deductible amounts,
property damage costs are aggregated for EPCO and its affiliates, including
us. Accordingly, our exposure with respect to the deductibles may be
equal to or less than the stated amounts depending on whether other EPCO or
affiliate assets are also affected by an event.
To
qualify for business interruption coverage in connection with a windstorm event,
covered assets must be out-of-service in excess of 60 days for onshore assets
and 75 days for offshore assets. To qualify for business
interruption coverage in connection with a non-windstorm event, covered onshore
and offshore assets must be out-of-service in excess of 60 days.
The following is a discussion of the
general status of our insurance claims related to recent significant storm
events. 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.
Hurricane
Ivan insurance claims. During the year
ended December 31, 2008, we did not receive any reimbursements from insurance
carriers related to property damage claims associated with this
storm. During the year ended December 31, 2007, we received cash
reimbursements from insurance carriers totaling $1.3 million, related to
property damage claims. If the final recovery of funds is different
than the amount previously expended, we will recognize an income impact at that
time.
We have submitted business interruption
insurance claims for our estimated losses caused by Hurricane Ivan, which struck
the eastern U.S. Gulf Coast region in September 2004. During the year
ended December 31, 2008, we did not receive any proceeds from these claims.
During the year ended December 31, 2007, we received $0.4 million of
nonrefundable cash proceeds from such claims. We are continuing our
efforts to collect residual balances from this storm. To the extent
we receive nonrefundable cash proceeds from business interruption insurance
claims, they are recorded as a gain in our Statements of Consolidated Operations
in the period of receipt.
Hurricanes
Katrina and Rita insurance claims. Hurricanes
Katrina and Rita, both significant storms, affected certain of our Gulf Coast
assets in August and September of 2005, respectively. With respect to
these storms, we have $30.5 million of estimated property damage claims
outstanding at December 31, 2008, that we believe are probable of collection
during the period 2009. We continue to pursue collection of our
property damage claims related to these named storms. As of December
31, 2008, we had received all proceeds from our business interruption claims
related to these storm events.
Hurricanes
Gustav and Ike
insurance claims. In
the third quarter of 2008, our onshore and offshore facilities located along the
Gulf Coast of Texas and Louisiana were adversely impacted by Hurricanes Gustav
and Ike. The disruptions in natural gas, NGL and crude oil
production caused by these storms resulted in decreased volumes for some of our
pipeline systems, natural gas processing plants, NGL fractionators and offshore
platforms, which, in turn, caused a decrease in gross operating margin from
these operations. As a result of our allocated share of EPCO’s
insurance deductibles for windstorm coverage, we expensed a combined $47.9
million of repair costs for property damage in connection with these two
storms. We expect to file property damage insurance claims to the
extent repair costs exceed deductible amounts. Due to the recent
nature of these storms, we are still evaluating the total cost of repairs and
the potential for business interruption claims on certain assets.
Proceeds
from Business Interruption and Property Damage Claims
The
following table summarizes proceeds we received during the periods indicated
from business interruption and property damage insurance claims with respect to
certain named storms:
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Business
interruption proceeds:
|
|
|
|
|
|
|
|
|
|
|
Hurricane
Ivan
|
|
$ |
-- |
|
|
$ |
377 |
|
|
$ |
17,382 |
|
|
Hurricane
Katrina
|
|
|
501 |
|
|
|
19,005 |
|
|
|
24,500 |
|
|
Hurricane
Rita
|
|
|
662 |
|
|
|
14,955 |
|
|
|
22,000 |
|
|
Other
|
|
|
-- |
|
|
|
996 |
|
|
|
-- |
|
|
Total
proceeds
|
|
|
1,163 |
|
|
|
35,333 |
|
|
|
63,882 |
|
|
Property
damage proceeds:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hurricane
Ivan
|
|
|
-- |
|
|
|
1,273 |
|
|
|
24,104 |
|
|
Hurricane
Katrina
|
|
|
9,404 |
|
|
|
79,651 |
|
|
|
7,500 |
|
|
Hurricane
Rita
|
|
|
2,678 |
|
|
|
24,105 |
|
|
|
3,000 |
|
|
Other
|
|
|
-- |
|
|
|
184 |
|
|
|
-- |
|
|
Total
proceeds
|
|
|
12,082 |
|
|
|
105,213 |
|
|
|
34,604 |
|
|
Total
|
|
$ |
13,245 |
|
|
$ |
140,546 |
|
|
$ |
98,486 |
|
At
December 31, 2008, we have $39.0 million of estimated property damage claims
outstanding related to these storms that we believe are probable of collection
through 2009. In February 2009, we collected $20.8 million of the
amounts outstanding. To the extent we estimate the dollar value of
such damages, please be aware that a change in our estimates may occur as
additional information becomes available.
During
2008, we collected $0.2 million of business interruption proceeds that were not
related to storm events.
We
determine net cash flows provided by operating activities using the indirect
method, which adjusts net income for items that did not affect
cash. Under GAAP, we use the accrual basis of accounting to determine
net income. This basis of accounting requires that we record revenue
when earned and expenses when incurred. Earned revenues may include
credit sales that have not been collected in cash and expenses incurred that may
not have been paid in cash. The extent to which changes in
operating accounts influence net cash flows provided by operating activities
generally depends on the following:
|
§
|
The
timing of cash receipts from revenue transactions and cash payments for
expense transactions near the end of each reporting
period. For example, if significant cash receipts are
posted on the last day of the current reporting period, but subsequent
payments on expense invoices are made on the first day of the next
reporting period, net cash flows provided by operating activities will
reflect an increase in the current reporting period that will be reduced
as payments are made in the next period. We employ prudent cash
management practices and monitor our daily cash requirements to meet our
ongoing liquidity needs.
|
|
§
|
If
commodity or other prices increase between reporting periods, changes in
accounts receivable and accounts payable and accrued expenses may appear
larger than in previous periods; however, overall levels of receivables
and payables may still reflect normal ranges. From a
receivables standpoint, we monitor the amount of credit extended to
customers.
|
|
§
|
Additions
to inventory for forward sales transactions or other reasons or increased
expenditures for prepaid items would be reflected as a use of cash and
reduce overall cash provided by operating activities in a given reporting
period. As these assets are charged to expense in subsequent
periods, the expense amount is reflected as a positive change in operating
accounts; however, there is no impact on operating cash
flows.
|
In
addition to the adjustments noted above, non-cash charges in the income
statement are added back to net income and non-cash credits are deducted to
compute net cash flows provided by operating
activities. Examples of non-cash charges include depreciation
and amortization.
The
following table provides information regarding (i) the net effect of changes in
our operating assets and liabilities; (ii) cash payments for interest and (iii)
cash payments for federal and state income taxes for the periods
indicated.
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Decrease
(increase) in:
|
|
|
|
|
|
|
|
|
|
|
Accounts
and notes receivable – trade
|
|
$ |
744,277 |
|
|
$ |
(640,092 |
) |
|
$ |
164,240 |
|
|
Accounts
receivable – related party
|
|
|
16,494 |
|
|
|
(63,254 |
) |
|
|
(8,612 |
) |
|
Inventories
|
|
|
(15,425 |
) |
|
|
(14,051 |
) |
|
|
(66,288 |
) |
|
Prepaid
and other current assets
|
|
|
(26,156 |
) |
|
|
41,266 |
|
|
|
14,261 |
|
|
Other
assets
|
|
|
(2,910 |
) |
|
|
5,630 |
|
|
|
(22,581 |
) |
|
Increase
(decrease) in:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
payable – trade
|
|
|
(18,372 |
) |
|
|
36,870 |
|
|
|
(1,509 |
) |
|
Accounts
payable – related party
|
|
|
15,126 |
|
|
|
17,111 |
|
|
|
(10,769 |
) |
|
Accrued
product payables
|
|
|
(1,080,034 |
) |
|
|
862,941 |
|
|
|
(8,344 |
) |
|
Accrued
expenses
|
|
|
1,920 |
|
|
|
120,054 |
|
|
|
(62,963 |
) |
|
Accrued
interest
|
|
|
20,902 |
|
|
|
40,107 |
|
|
|
19,671 |
|
|
Other
current liabilities
|
|
|
(17,913 |
) |
|
|
37,248 |
|
|
|
74,206 |
|
|
Other
liabilities
|
|
|
4,661 |
|
|
|
(2,524 |
) |
|
|
(7,894 |
) |
|
Net
effect of changes in operating accounts
|
|
$ |
(357,430 |
) |
|
$ |
441,306 |
|
|
$ |
83,418 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
payments for interest, net of $71,584, $75,476 and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$55,660
capitalized in 2008, 2007 and 2006, respectively
|
|
$ |
441,550 |
|
|
$ |
325,339 |
|
|
$ |
213,365 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
payments for federal and state income taxes
|
|
$ |
4,830 |
|
|
$ |
5,760 |
|
|
$ |
10,497 |
|
The following table provides
supplemental cash flow information regarding business combinations we completed
during the periods indicated. See Note 12, for additional information
regarding our business combination transactions.
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Assets
acquired
|
|
$ |
254,322 |
|
|
$ |
37,037 |
|
|
$ |
477,015 |
|
|
Less
liabilities assumed
|
|
|
(52,162 |
) |
|
|
(1,244 |
) |
|
|
(19,403 |
) |
|
Net
assets acquired
|
|
|
202,160 |
|
|
|
35,793 |
|
|
|
457,612 |
|
|
Less
equity issued
|
|
|
-- |
|
|
|
-- |
|
|
|
(181,112 |
) |
|
Cash
used for business combinations, net of cash received
|
|
$ |
202,160 |
|
|
$ |
35,793 |
|
|
$ |
276,500 |
|
We incurred liabilities for
construction in progress that had not been paid at December 31, 2008, 2007 and
2006 of $90.6 million, $95.5 million and $195.1 million,
respectively. Such amounts are not included under the caption
“Capital expenditures” on the Statements of Consolidated Cash
Flows.
Third parties may be obligated to
reimburse us for all or a portion of expenditures on certain of our capital
projects. The majority of such arrangements are associated with projects
related to pipeline construction and production well tie-ins. We
received $25.8 million, $57.5 million and $60.5 million as contributions in aid
of our construction costs during the years ended December 31, 2008, 2007 and
2006, respectively.
The
following table presents selected quarterly financial data for the years ended
December 31, 2008 and 2007:
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
For
the Year Ended December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
5,684,535 |
|
|
$ |
6,339,615 |
|
|
$ |
6,297,902 |
|
|
$ |
3,583,604 |
|
|
Operating
income
|
|
|
366,732 |
|
|
|
374,270 |
|
|
|
319,116 |
|
|
|
353,128 |
|
|
Income
before change in accounting principle
|
|
|
259,609 |
|
|
|
263,270 |
|
|
|
203,081 |
|
|
|
228,061 |
|
|
Net
income
|
|
|
259,609 |
|
|
|
263,270 |
|
|
|
203,081 |
|
|
|
228,061 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
per unit before change in accounting principle:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
0.51 |
|
|
$ |
0.52 |
|
|
$ |
0.38 |
|
|
$ |
0.44 |
|
|
Diluted
|
|
$ |
0.51 |
|
|
$ |
0.52 |
|
|
$ |
0.38 |
|
|
$ |
0.44 |
|
|
Net
income per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
0.51 |
|
|
$ |
0.52 |
|
|
$ |
0.38 |
|
|
$ |
0.44 |
|
|
Diluted
|
|
$ |
0.51 |
|
|
$ |
0.52 |
|
|
$ |
0.38 |
|
|
$ |
0.44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Year Ended December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
3,322,854 |
|
|
$ |
4,212,806 |
|
|
$ |
4,111,996 |
|
|
$ |
5,302,469 |
|
|
Operating
income
|
|
|
187,924 |
|
|
|
214,562 |
|
|
|
210,830 |
|
|
|
269,721 |
|
|
Income
before change in accounting principle
|
|
|
112,045 |
|
|
|
142,154 |
|
|
|
117,606 |
|
|
|
161,869 |
|
|
Net
income
|
|
|
112,045 |
|
|
|
142,154 |
|
|
|
117,606 |
|
|
|
161,869 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
per unit before change in accounting principle:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
0.20 |
|
|
$ |
0.26 |
|
|
$ |
0.20 |
|
|
$ |
0.30 |
|
|
Diluted
|
|
$ |
0.20 |
|
|
$ |
0.26 |
|
|
$ |
0.20 |
|
|
$ |
0.30 |
|
|
Net
income per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
0.20 |
|
|
$ |
0.26 |
|
|
$ |
0.20 |
|
|
$ |
0.30 |
|
|
Diluted
|
|
$ |
0.20 |
|
|
$ |
0.26 |
|
|
$ |
0.20 |
|
|
$ |
0.30 |
|
EPO
conducts substantially all of our business. Currently, we have no
independent operations and no material assets outside those of
EPO. EPO consolidates the financial statements of Duncan Energy
Partners with those of its own.
Enterprise
Products Partners L.P. guarantees the debt obligations of EPO, with the
exception of the Dixie revolving credit facility (terminated January 2009) and
the Duncan Energy Partners’ debt obligations. If EPO were to
default on any of its guaranteed debt, Enterprise Products Partners L.P. would
be responsible for full repayment of that obligation. See Note 14 for
additional information regarding our consolidated debt obligations.
The
reconciling items between our consolidated financial statements and those of EPO
are insignificant. The following table presents condensed
consolidated balance sheet data for EPO at the dates indicated:
|
|
|
At
December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
ASSETS
|
|
|
|
|
|
|
|
Current
assets
|
|
$ |
2,175,555 |
|
|
$ |
2,545,297 |
|
|
Property,
plant and equipment, net
|
|
|
13,154,774 |
|
|
|
11,587,264 |
|
|
Investments
in and advances to unconsolidated affiliates, net
|
|
|
949,526 |
|
|
|
858,339 |
|
|
Intangible
assets, net
|
|
|
855,416 |
|
|
|
917,000 |
|
|
Goodwill
|
|
|
706,884 |
|
|
|
591,652 |
|
|
Other
assets
|
|
|
126,619 |
|
|
|
115,458 |
|
|
Total
|
|
$ |
17,968,774 |
|
|
$ |
16,615,010 |
|
|
LIABILITIES
AND PARTNERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
Current
liabilities
|
|
$ |
2,222,650 |
|
|
$ |
3,044,002 |
|
|
Long-term
debt
|
|
|
9,108,410 |
|
|
|
6,906,145 |
|
|
Other
long-term liabilities
|
|
|
147,339 |
|
|
|
95,112 |
|
|
Minority
interest
|
|
|
404,214 |
|
|
|
439,854 |
|
|
Partners’
equity
|
|
|
6,086,161 |
|
|
|
6,129,897 |
|
|
Total
|
|
$ |
17,968,774 |
|
|
$ |
16,615,010 |
|
|
|
|
|
|
|
|
|
|
|
|
Total
EPO debt obligations guaranteed
Enterprise
Products Partners L.P.
|
|
$ |
8,561,796 |
|
|
$ |
6,686,500 |
|
The following table presents condensed
consolidated statements of operations data for EPO for the periods
indicated:
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Revenues
|
|
$ |
21,905,656 |
|
|
$ |
16,950,125 |
|
|
$ |
13,990,969 |
|
|
Costs
and expenses
|
|
|
20,549,026 |
|
|
|
16,094,248 |
|
|
|
13,148,530 |
|
|
Equity
in earnings of unconsolidated affiliates
|
|
|
59,104 |
|
|
|
29,658 |
|
|
|
21,565 |
|
|
Operating
income
|
|
|
1,415,734 |
|
|
|
885,535 |
|
|
|
864,004 |
|
|
Other
expense
|
|
|
(391,457 |
) |
|
|
(305,236 |
) |
|
|
(231,876 |
) |
|
Income
before provision for income taxes, minority
interest
and change in accounting principle
|
|
|
1,024,277 |
|
|
|
580,299 |
|
|
|
632,128 |
|
|
Provision
for income taxes
|
|
|
(26,376 |
) |
|
|
(15,317 |
) |
|
|
(21,198 |
) |
|
Income
before minority interest and change in
accounting
principle
|
|
|
997,901 |
|
|
|
564,982 |
|
|
|
610,930 |
|
|
Minority
interest
|
|
|
(41,638 |
) |
|
|
(30,737 |
) |
|
|
(9,190 |
) |
|
Income
before change in accounting principle
|
|
|
956,263 |
|
|
|
534,245 |
|
|
|
601,740 |
|
|
Cumulative
effect of change in accounting principle
|
|
|
-- |
|
|
|
-- |
|
|
|
1,472 |
|
|
Net
income
|
|
$ |
956,263 |
|
|
$ |
534,245 |
|
|
$ |
603,212 |
|
In
January 2009, we sold 10,590,000 common units (including an over-allotment of
990,000 common units) to the public at an offering price of $22.20 per
unit. We used the net offering proceeds of $225.6 million to
temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving
Credit Facility, which may be reborrowed to fund capital expenditures and other
growth projects, and for general partnership purposes.