Pre-Effective Amendment to Registration Statement (General Form) — Form S-1 Filing Table of Contents
Document/ExhibitDescriptionPagesSize 1: S-1/A Amendment No.3 to Form S-1 - Registration No. HTML 2.38M 333-138371
2: EX-1.1 Form of Underwriting Agreement HTML 224K
3: EX-3.6 Amended Limited Liability Company Agreement HTML 134K
4: EX-5.1 Opinion of Andrews Kurth LLP HTML 9K
5: EX-8.1 Opinion of Andrews Kurth LLP HTML 10K
6: EX-10.1 Form of Contribution, Conveyance and Assumption HTML 53K
Agreement
9: EX-10.13 Form of Amended Limited Liability Company HTML 172K
Agreement
10: EX-10.15 Form of Amended Limited Liability Company HTML 155K
Agreement
11: EX-10.18 Form of Fourth Amended Administrative Services HTML 105K
Agreement
12: EX-10.19 Form of Omnibus Agreement HTML 66K
7: EX-10.8 Form of Contribution, Conveyance and Assumption HTML 70K
Agreement
8: EX-10.9 Form of Contribution, Conveyance and Assumption HTML 59K
Agreement
13: EX-21.1 List of Subsidiaries HTML 15K
14: EX-23.1 Consent of Deloitte & Touche LLP HTML 9K
(Name, Address, Including Zip
Code, and Telephone Number, Including Area Code, of Agent for
Service)
Copies to:
Robert V. Jewell
David C. Buck
Andrews Kurth LLP
600 Travis, Suite 4200 Houston, Texas77002
(713) 220-4200
Joshua Davidson
Sean T. Wheeler
Baker Botts L.L.P.
One Shell Plaza, 910 Louisiana Houston, Texas77002
(713) 229-1234
Approximate date of commencement of proposed sale to the
public: As soon as practicable after this
Registration Statement becomes effective.
If any of the securities being registered on this form are to be
offered on a delayed or continuous basis pursuant to
Rule 415 under the Securities Act of 1933, check the
following box. o
If this Form is filed to register additional securities for an
offering pursuant to Rule 462(b) under the Securities Act,
check the following box and list the Securities Act registration
statement number of the earlier effective registration statement
for the same offering. o
If this Form is a post-effective amendment filed pursuant to
Rule 462(c) under the Securities Act, check the following
box and list the Securities Act registration statement number of
the earlier effective registration statement for the same
offering. o
If this Form is a post-effective amendment filed pursuant to
Rule 462(d) under the Securities Act, check the following
box and list the Securities Act registration statement number of
the earlier effective registration statement for the same
offering. o
The Registrant hereby amends this Registration Statement on
such date or dates as may be necessary to delay its effective
date until the Registrant shall file a further amendment which
specifically states that this Registration Statement shall
thereafter become effective in accordance with Section 8(a)
of the Securities Act of 1933 or until the Registration
Statement shall become effective on such date as the Securities
and Exchange Commission, acting pursuant to said
Section 8(a), may determine.
The information in
this preliminary prospectus is not complete and may be changed.
These securities may not be sold until the registration
statement filed with the Securities and Exchange
Commission is effective. This preliminary prospectus is not an
offer to sell these securities and it is not soliciting an offer
to buy these securities in any state where the offer or sale is
not permitted.
Duncan Energy Partners L.P. is a limited partnership recently
formed by Enterprise Products Partners L.P. This is the initial
public offering of our common units. We currently estimate that
the initial public offering price will be between $19.00 and
$21.00 per common unit. Before this offering, there has
been no public market for our common units. Our common units
have been approved for listing, subject to official notice of
issuance, on the New York Stock Exchange under the symbol
“DEP.”
Investing in our common units
involves risks. Please read “Risk Factors” beginning
on page 21.
These risks include the following:
•
We may not have sufficient cash from operations to enable us to
pay distributions on our common units.
•
Changes in demand for and production of hydrocarbon products may
materially adversely affect our results of operations, cash
flows and financial condition.
•
We depend on Enterprise Products Partners L.P. and certain other
key customers for a significant portion of our revenues. The
loss of any of these key customers could result in a decline in
our revenues and cash from operations available to pay
distributions to our unitholders.
•
Our general partner and its affiliates, including Enterprise
Products Partners L.P., will have conflicts of interest and
limited fiduciary duties, which may permit them to favor their
own interests to your detriment.
•
Affiliates of our general partner, including Enterprise Products
Partners L.P., Enterprise GP Holdings L.P. and TEPPCO Partners
L.P., may compete with us and be entitled to pursue certain
business opportunities before us. This arrangement may limit our
ability to grow.
•
Our general partner has a limited call right that may require
you to sell your common units at an undesirable time or price.
•
Unitholders have limited voting rights and are not entitled to
elect our general partner or its directors.
•
You will experience immediate and substantial dilution of
$5.64 per unit in the net tangible book value of your
common units.
•
You may be required to pay taxes on income from us even if you
do not receive any cash distributions from us.
Per Common Unit
Total
Initial public offering price
$
$
Underwriting discount(1)
$
$
Proceeds to us (before expenses)
$
$
(1)
Excludes a fee payable to Lehman Brothers of $1,000,000 in
consideration of advice rendered by Lehman Brothers regarding
the structure of this offering and our partnership.
We have granted the underwriters a
30-day
option to purchase up to an additional 1,950,000 common units on
the same terms and conditions as set forth above if the
underwriters sell more than 13,000,000 common units in this
offering.
Neither the Securities and Exchange Commission nor any state
securities commission has approved or disapproved of these
securities or passed upon the accuracy or adequacy of this
prospectus. Any representation to the contrary is a criminal
offense.
Lehman Brothers, on behalf of the underwriters, expects to
deliver the common units on or
about ,
2007.
You should rely only on the information contained in this
prospectus. We have not, and the underwriters have not,
authorized any other person to provide you with different
information. If anyone provides you with
different or inconsistent information, you should not rely on
it. We are not, and the underwriters are not, making an offer to
sell these securities in any jurisdiction where an offer or sale
is not permitted. You should assume that the information
appearing in this prospectus is accurate only as of the date on
the front cover of this prospectus. Our business, financial
condition and results of operations may have changed since that
date.
Until ,
2007 (25 days after the date of this prospectus), all
dealers that buy, sell or trade our common units, whether or not
participating in this offering, may be required to deliver a
prospectus. This is in addition to the dealers’ obligation
to deliver a prospectus when acting as underwriters and with
respect to their unsold allotments or subscriptions.
This summary highlights information contained elsewhere in
this prospectus. You should read the entire prospectus
carefully, including the historical and pro forma financial
statements and the notes to those financial statements. You
should read “Risk Factors” for important information
about risks that you should consider before buying our common
units. The information presented in this prospectus assumes an
initial public offering price per unit of $20.00 and that the
underwriters’ option to purchase additional common units is
not exercised, unless otherwise noted.
All references in this prospectus to “we,”“us,”“Duncan Energy Partners,” the
“Partnership” and “our” refer to Duncan
Energy Partners L.P. and its subsidiaries. All references in
this prospectus to “we,”“us,”“our” or the “Company,” when used in a
historical context, are intended to mean and include the
combined business and operations of Duncan Energy Partners
Predecessor. Duncan Energy Partners Predecessor reflects
ownership of 100% of the assets being contributed, but we will
own only a 66% interest in these assets after their contribution
in connection with this offering. For all references in this
prospectus to the terms “our general partner,”“DEP Holdings,”“Enterprise Products
Partners,”“Enterprise Products OLP,”“Enterprise Products GP,”“Enterprise GP
Holdings,”“EPE Holdings,”“EPCO,”“Mont Belvieu Caverns,”“Acadian Gas,”“Sabine Propylene,”“Lou-Tex Propylene,”“South Texas NGL,”“TEPPCO Partners,”“TEPPCO GP” and “Evangeline,” please read
Appendix B — Glossary of Terms. Please also read
Appendix B — Glossary of Terms for a glossary of
industry terms used in this prospectus.
We are a Delaware limited partnership formed by Enterprise
Products Partners in September 2006 to own, operate and acquire
a diversified portfolio of midstream energy assets. We are
engaged in the business of gathering, transporting, marketing
and storing natural gas and transporting and storing natural gas
liquids, or NGLs, and petrochemicals. Our assets were previously
owned by Enterprise Products Partners and are part of its
integrated midstream energy asset network, or “value
chain,” which includes natural gas gathering, processing,
transportation and storage; NGL fractionation (or separation),
transportation, storage and import and export terminaling; crude
oil transportation; and offshore production platform services.
After this offering, we will own 66% of the equity interests in
the subsidiaries that hold our operating assets, and affiliates
of Enterprise Products Partners will continue to own the
remaining 34%. We believe our relationship with Enterprise
Products Partners will enable us to maintain stable cash flows
and optimize our scale, strategic location and pipeline
connections.
Our operations are organized into the following four business
segments:
•
NGL & Petrochemical Storage
Services. Our NGL & Petrochemical
Storage Services segment consists of 33 salt dome caverns
located in Mont Belvieu, Texas, with an underground storage
capacity of approximately 100 MMBbls, and certain related
assets. These assets receive, store and deliver NGLs and
petrochemical products for industrial customers located along
the upper Texas Gulf Coast, which has the largest concentration
of petrochemical plants and refineries in the United States.
•
Natural Gas Pipelines & Services. Our
Natural Gas Pipelines & Services segment consists of
the Acadian Gas system, which is an onshore natural gas pipeline
system that gathers, transports, stores and markets natural gas
in Louisiana. The Acadian Gas system links natural gas supplies
from onshore and offshore Gulf of Mexico developments (including
offshore pipelines, continental shelf and deepwater production)
with local gas distribution companies, electric generation
plants and industrial customers, including those in the Baton
Rouge-New Orleans-Mississippi River corridor. In the aggregate,
the Acadian Gas system includes over 1,000 miles of
high-pressure transmission lines and lateral and gathering lines
with an aggregate throughput capacity of approximately one Bcf/d
and a leased storage facility with approximately three Bcf of
storage capacity.
•
Petrochemical Pipeline Services. Our
Petrochemical Pipeline Services segment consists of two
petrochemical pipeline systems with an aggregate of
284 miles of pipeline. The Lou-Tex Propylene pipeline
system consists of a
263-mile
pipeline used to transport chemical-grade propylene between
Sorrento, Louisiana and Mont Belvieu, Texas. The
Sabine Propylene pipeline system consists of a
21-mile
pipeline used to transport polymer-grade propylene from Port
Arthur, Texas to a pipeline interconnect in Cameron Parish,
Louisiana on a
transport-or-pay
basis.
•
NGL Pipeline Services. Our NGL Pipeline
Services segment consists of a
290-mile
pipeline system used to transport NGLs from two Enterprise
Products Partners’ facilities located in South Texas to
Mont Belvieu, Texas and related interconnections. We acquired a
223-mile
segment of the system in August 2006, and we are in the process
of acquiring and constructing other segments of the pipeline.
The system became operational and began transporting NGLs in
January 2007 after undergoing modifications, extensions and
interconnections. Additional expansions are scheduled to be
completed during the remainder of 2007.
Our
Relationship With Enterprise Products Partners
Enterprise Products Partners is a North American midstream
energy company that provides a wide range of services to
producers and consumers of natural gas, NGLs and crude oil.
Enterprise Products Partners’ value chain is an integrated
midstream energy asset network that 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. For the year ended
December 31, 2005, Enterprise Products Partners had
revenues of $12.3 billion, operating income of
$663 million and net income of $420 million. For the
nine months ended September 30, 2006, Enterprise Products
Partners had revenues of $10.6 billion, operating income of
$653.7 million and net income of $468.4 million. After
giving effect to this offering, we will continue to have a
number of commercial relationships, including transportation and
storage agreements, with Enterprise Products Partners and its
affiliates. In addition, in the event we propose to sell any
equity interests in our operating subsidiaries or material
assets of those entities, other than sales of inventory and
other assets in the ordinary course of business, Enterprise
Products OLP will have a right of first refusal to purchase
those interests or assets.
We believe our relationship with EPCO and Enterprise Products
Partners will provide us access to an experienced management
team and commercial relationships throughout the energy
industry. However, this relationship is also a source of
potential conflicts. For example, Enterprise Products Partners,
EPCO and their affiliates are not restricted from competing with
us and may generally acquire, construct or dispose of midstream
or other assets in the future without any obligation to offer us
the opportunity to purchase or construct those assets or
participate in these activities. Please read “Conflicts of
Interest, Business Opportunity Agreements and Fiduciary
Duties” and “Certain Relationships and Related Party
Transactions” for more information on these commercial and
other relationships.
Formation
Transactions
At the closing of this offering, the following transactions will
occur:
•
Enterprise Products OLP will contribute to us 66% of the equity
interests in Mont Belvieu Caverns, Acadian Gas, Sabine
Propylene, Lou-Tex Propylene and South Texas NGL;
•
We will issue to Enterprise Products OLP 7,301,571 common units
representing an approximate 35.2% limited partner interest in us
(or an approximate 25.8% limited partner interest if the
underwriters exercise in full their option to purchase
additional common units), and we will issue a 2% general partner
interest to our general partner, DEP Holdings, LLC;
•
We will borrow approximately $200 million under our new
credit agreement, which will be used to fund a portion of our
payment to Enterprise Products Partners in connection with the
transactions described above;
•
We will sell 13,000,000 common units to the public in this
offering representing an approximate 62.8% limited partner
interest in us (or an approximate 72.2% limited partner interest
if the underwriters exercise in full their option to purchase
additional common units), and will use the net proceeds from
this offering as described under “Use of Proceeds;”
We will become party to an existing administrative services
agreement among EPCO and certain of its affiliates;
•
We will enter into various new transportation, storage and
operating agreements with Enterprise Products OLP and its
affiliates; and
•
We will enter into an omnibus agreement with Enterprise Products
OLP, pursuant to which Enterprise Products OLP will agree to
(i) indemnify us for certain environmental liabilities, tax
liabilities and title and
right-of-way
defects occurring or existing before the closing and
(ii) reimburse us for our 66% share of excess construction
costs, if any, above our current estimated cost to complete
planned expansions on the South Texas NGL pipeline and Mont
Belvieu Caverns brine-related facilities. In addition, we will
grant Enterprise Products OLP a right of first refusal on
the equity interests in certain of our operating subsidiaries
and on the material assets of these entities, other than sales
of inventory and other assets in the ordinary course of
business, and 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.
Management
and Ownership
As is common with publicly traded limited partnerships and in
order to maximize operational flexibility, we will conduct our
operations through subsidiaries.
Our general partner will manage our operations and activities.
Some of the executive officers and non-independent directors of
our general partner also serve as executive officers or
directors of Enterprise Products GP, EPE Holdings and TEPPCO GP.
Please read “Management.” Our general partner will not
receive any management fee or other compensation in connection
with its management of our business but will be entitled to be
reimbursed for all direct and indirect expenses incurred on our
behalf. Neither our general partner nor the board of directors
of our general partner will be elected by our unitholders.
Unlike shareholders in a corporation, our unitholders will not
elect or remove the board of directors of our general partner.
Our principal executive offices are located at 1100 Louisiana
Street, 10th Floor, Houston, Texas77002, and our telephone
number is
(713) 381-6500.
Our website is located at http://www.deplp.com. Information on
our website or any other website is not incorporated by
reference into this prospectus and does not constitute a part of
this prospectus.
The following diagram depicts our organizational structure after
giving effect to this offering and the related transactions
assuming no exercise of the underwriters’ option to
purchase additional common units.
Common units subject to the underwriters’ option to
purchaseadditional common units
If the underwriters exercise their option to purchase additional
units in full, we will issue 1,950,000 additional common units
to the public and redeem 1,950,000 common units from Enterprise
Products OLP, who may be deemed to be a selling unitholder in
this offering. Please read “Selling Unitholder.”
Common units outstanding after this offering
20,301,571 common units.
Use of proceeds
We will use the net proceeds from this offering of approximately
$243.4 million (based on an assumed offering price of
$20.00 per unit), after deducting the underwriting discount and
a $1.0 million structuring fee, but before estimated
expenses associated with the offering and related formation
transactions, to:
• distribute approximately $212.3 million to
Enterprise Products OLP as a portion of the cash consideration
and reimbursement for capital expenditures relating to the
assets contributed to us;
• provide approximately $28.2 million to fund our
share of estimated capital expenditures to complete planned
expansions to the South Texas NGL pipeline system and brine
production and above-ground storage projects at Mont Belvieu
subsequent to the closing of this offering; and
• pay approximately $2.9 million of other
estimated net expenses associated with this offering and related
formation transactions described on page 2.
In addition, we will borrow approximately $200 million
under our new $300 million credit agreement, and we will
distribute $198.9 million of these borrowings to Enterprise
Products OLP in partial consideration for the assets contributed
to us upon the closing of this offering.
If the underwriters exercise their option to purchase additional
common units, we will use all of the net proceeds from the sale
of those common units to redeem an equal number of common units
from Enterprise Products OLP. For the resulting beneficial
ownership, read “Security Ownership of Certain Beneficial
Owners and Management.”
Cash distributions
We will make initial quarterly distributions of $0.40 per
common unit to the extent we have sufficient cash from
operations after establishment of cash reserves and payment of
fees and expenses, including reimbursement of expenses to our
general partner. Our ability to pay cash distributions at this
initial distribution rate is subject to various restrictions and
other factors described in more detail under the caption
“Cash Distribution Policy and Restrictions on
Distributions.” We must distribute all of our cash on hand
at the end of each quarter, less reserves established by our
general partner.
We refer to this cash as “available cash,” and we
define its meaning in our partnership agreement as summarized in
“How We Make Cash Distributions — Distributions
of Available Cash — Definition of Available
Cash.” The amount of available cash may be greater than or
less than the aggregate amount associated with payment of the
expected initial quarterly distribution on all common units. In
general, we will pay 98% of any cash distributions we make each
quarter to our unitholders and the remaining 2% to our general
partner.
Unlike many publicly traded limited partnerships, our general
partner is not entitled to any incentive distributions and we do
not have any subordinated units.
We believe that, based on the assumptions and considerations
described in “Cash Distribution Policy and Restrictions on
Distributions — Assumptions and Considerations,”
we will have sufficient available cash to pay the full initial
quarterly distribution on all our common units and our general
partner interest for each quarter during the four quarters
ending December 31, 2007. We estimate that our pro forma
available cash for the year ended December 31, 2005 would
have been sufficient to pay only 30% of the initial quarterly
distributions on our common units and our general partner
interest during that period. We estimate that our pro forma
available cash for the four quarters ended September 30,2006 would not have been sufficient to pay any distributions on
our common units and our general partner interest.
We will pay investors in this offering a prorated distribution
for the first quarter during which we are a publicly traded
partnership. This distribution will be paid for the period
beginning on the first day our common units are publicly traded
and ending on the last day of that fiscal quarter. Therefore, we
will pay investors in this offering a distribution for the
period from the closing date of this offering to and including
March 31, 2007. We expect to pay this cash distribution on
or about May 15, 2007.
Limited call right
If at any time our general partner and its affiliates own 80% or
more of our outstanding common units, our general partner has
the right, but not the obligation, to purchase all of the
remaining common units at a price not less than the then-current
market price of the common units.
Issuance of additional units
We can issue an unlimited number of units without the consent of
our unitholders. Please read “Common Units Eligible For
Future Sale” and “Description of Material Provisions
of Our Partnership Agreement — Issuance of Additional
Securities.”
Limited voting rights
Our general partner will manage all of our operations. Unlike
the holders of common stock of a corporation, you will have only
limited voting rights on matters affecting our business and you
will have no right to elect our general partner or its officers
or directors. Our general partner may not be removed except by a
vote of the holders of at least
662/3%
of the outstanding common units, including common units owned by
our general partner and its affiliates. Upon completion of this
offering, affiliates of our
general partner will own approximately 36.0% of our outstanding
common units (or approximately 26.4% of our outstanding common
units if the underwriters’ option to purchase additional
common units is exercised in full). Please read
“Description of Material Provisions of Our Partnership
Agreement — Withdrawal or Removal of Our General
Partner.”
Estimated ratio of taxable income to distributions
We estimate that if you own the common units you purchase in
this offering through the record date for distributions for the
period ending December 31, 2009, you will be allocated, on
a cumulative basis, an amount of federal taxable income for that
period that will be less than 20% of the cash distributed with
respect to that period. For example, if you receive an annual
distribution of $1.60 per common unit, we estimate that
your average allocated federal taxable income per year will be
no more than $0.32 per common unit. Please read
“Material Tax Consequences” in this prospectus for the
basis of this estimate.
Material tax consequences
For a discussion of other material federal income tax
consequences that may be relevant to prospective unitholders who
are individual citizens or residents of the United States,
please read “Material Tax Consequences.”
Exchange listing
Our common units have been approved for listing, subject to
official notice of issuance, on the New York Stock Exchange
under the symbol “DEP.”
The following diagram summarizes the current organizational
structure of EPCO, affiliates of Dan L. Duncan and our
affiliates at December 31, 2006.
General. Conflicts of interest exist and may
arise in the future as a result of the relationships among us,
Enterprise Products Partners, Enterprise GP Holdings, TEPPCO
Partners and our and their respective general partners and
affiliates. Our general partner is controlled indirectly by
Enterprise Products Partners. Mr. Dan L. Duncan has the
ability to elect, remove and replace the directors and officers
of our general partner and the general partners of Enterprise
Products Partners, Enterprise GP Holdings and TEPPCO Partners.
The assets of Enterprise Products Partners, Enterprise GP
Holdings, TEPPCO Partners and us overlap in certain areas, which
may result in various conflicts of interest in the future.
The directors and officers of our general partner have fiduciary
duties to manage our business in a manner beneficial to us and
our partners. Some of the executive officers and non-independent
directors of our general partner also serve as executive
officers or directors of Enterprise Products GP, EPE Holdings
and TEPPCO GP. As a result, they have fiduciary duties to manage
the business of each of those entities in a manner beneficial to
such entities and their respective partners. Consequently, these
directors and officers may
encounter situations in which their fiduciary obligations to
Enterprise Products Partners, Enterprise GP Holdings or TEPPCO
Partners, on the one hand, and us, on the other hand, are in
conflict. For a more detailed description of the conflicts of
interest involving our general partner, please read
“Conflicts of Interest, Business Opportunity Agreements and
Fiduciary Duties.”
It is not possible to predict the nature or extent of these
potential future conflicts of interest at this time, nor is it
possible to determine how we will address and resolve any such
future conflicts of interest. However, the resolution of these
conflicts may not always be in our best interest or that of our
unitholders.
Business Opportunity Agreements under our Administrative
Services Agreement. At or prior to the closing of
this offering, we and our general partner will become party to
an existing administrative services agreement with EPCO,
Enterprise Products Partners and its general partner, Enterprise
GP Holdings and its general partner, TEPPCO Partners and its
general partner, and certain affiliated entities. The
administrative services agreement will address potential
conflicts that may arise among us and our general partner,
Enterprise Products Partners and its general partner, Enterprise
GP Holdings and its general partner, TEPPCO Partners and its
general partner, and the EPCO Group, which includes EPCO and its
affiliates but does not include the aforementioned entities and
their controlled affiliates.
The administrative services agreement will provide, among other
things, that:
•
if a business opportunity to acquire certain equity securities
(which we define to include general partner interests in
publicly traded partnerships and similar interests and any
associated incentive distribution rights, limited partner
interests or similar interests owned by the owner of such
general partner interest or its affiliates), is presented to the
EPCO Group, us, and our general partner, Enterprise Products
Partners and its general partner, or Enterprise GP Holdings and
its general partner, Enterprise GP Holdings will have the first
right to pursue the acquisition. In the event that Enterprise GP
Holdings abandons the acquisition, Enterprise Products Partners
will have the second right to pursue such acquisition either for
itself or, if desired by Enterprise Products Partners in its
sole discretion, for our benefit. In the event that Enterprise
Products Partners affirmatively directs the acquisition to us,
we may pursue such acquisition. In the event that Enterprise
Products Partners abandons the acquisition for itself and for
us, the EPCO Group may pursue the acquisition without any
further obligation to any other party or offer such opportunity
to other affiliates; and
•
if any business opportunity not covered by the preceding bullet
point is presented to the EPCO Group, us and our general
partner, Enterprise Products Partners and its general partner,
or Enterprise GP Holdings and its general partner, 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 our benefit. In
the event that Enterprise Products Partners affirmatively
directs the business opportunity to us, we may pursue such
business opportunity. In the event Enterprise Products Partners
abandons the business opportunity for itself and for us,
Enterprise GP Holdings will have the second right to pursue such
business opportunity. In the event Enterprise GP Holdings
abandons the business opportunity, the EPCO Group may pursue the
business opportunity without any further obligation to any other
party or offer such opportunity to other affiliates.
None of the EPCO Group, we and our general partner, Enterprise
Products Partners and its general partner, or Enterprise GP
Holdings and its general partner will have any obligation to
present business opportunities to TEPPCO Partners, its general
partner or their controlled affiliates, nor will TEPPCO
Partners, its general partner or their controlled affiliates
have any obligation to present business opportunities to the
EPCO Group, us and our general partner, Enterprise Products
Partners and its general partner, or Enterprise GP Holdings and
its general partner. For a more detailed description of these
provisions, please read “Certain Relationships and Related
Party Transactions — Administrative Services
Agreement.”
Shared Personnel. DEP Holdings, as our general
partner, will manage our operations and activities. Under the
administrative services agreement, EPCO will provide all
employees and administrative, operational and other services for
us. All of our general partner’s executive officers will,
and certain other EPCO employees assigned to our operations may,
also perform services for EPCO, Enterprise Products Partners,
Enterprise GP Holdings, TEPPCO Partners and their affiliates.
The services performed by these shared personnel will generally
be limited to non-commercial functions, including but not
limited to human resources, information technology, financial
and accounting services and legal services. We have adopted
policies and procedures intended to protect and prevent
inappropriate disclosure by shared personnel of commercial and
other non-public information relating to us, EPCO, Enterprise
Products Partners, Enterprise GP Holdings and TEPPCO Partners.
Because our general partner’s executive officers allocate
time among EPCO, us, Enterprise Products Partners, Enterprise GP
Holdings and TEPPCO Partners, these officers face conflicts
regarding the allocation of their time, which may adversely
affect our business, results of operations and financial
condition.
Compensation Arrangements. Dan L. Duncan, as
the control person of EPCO, our general partner and the general
partners of Enterprise Products Partners, Enterprise GP Holdings
and TEPPCO Partners, is responsible for establishing the
compensation arrangements for all EPCO employees, including
employees who provide services to us, Enterprise Products
Partners, Enterprise GP Holdings and TEPPCO Partners.
Fiduciary Duties. Our partnership agreement
limits the liability and reduces the fiduciary duties of our
general partner and its affiliates to our unitholders. Our
partnership agreement also restricts the remedies available to
unitholders for actions that might otherwise constitute a breach
of our general partner’s and its affiliates’ fiduciary
duty owed to unitholders. By purchasing our common units, you
are treated as having consented to various actions contemplated
in the partnership agreement and conflicts of interest that
might otherwise constitute a breach of fiduciary or other duties
under applicable state law. Please read “Conflicts of
Interest, Business Opportunity Agreements and Fiduciary
Duties — Fiduciary Duties” for a description of
the fiduciary duties imposed on our general partner by Delaware
law, the material modifications of these duties contained in our
partnership agreement and certain legal rights and remedies
available to unitholders.
For a description of our other relationships with our
affiliates, please read “Certain Relationships and Related
Party Transactions.”
An investment in our common units involves risks associated with
our business, our partnership structure and the tax
characteristics of our common units. The following list of risk
factors is not exhaustive. For more information about these and
other risks, please read “Risk Factors” beginning on
page 21. These risks include, among others:
Risks
Inherent in Our Business
•
We may not have sufficient cash from operations to enable us to
pay our expected initial quarterly distribution on our common
units.
•
A decrease in demand for natural gas, NGLs, NGL products or
petrochemical products by the petrochemical, refining or heating
industries could materially adversely affect our results of
operations, cash flows and financial position.
•
Because of the natural decline in gas production from existing
wells, our success depends on our ability to obtain access to
new sources of natural gas, which is dependent on factors beyond
our control. Any decrease in supplies of natural gas could
adversely affect our business and operating results.
•
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.
•
We may not be able to make acquisitions or to make acquisitions
on economically acceptable terms, which may limit our ability to
grow.
•
Federal, state or local regulatory measures could materially
adversely affect our business, results of operations, cash flows
and financial condition.
•
Environmental costs and liabilities and changing environmental
regulation could materially affect our results of operations,
cash flows and financial condition.
•
We depend on Enterprise Products Partners and certain other key
customers for a significant portion of our revenues. The loss of
any of these key customers could result in a decline in our
revenues and cash available to pay distributions to you.
•
Successful development of LNG import terminals outside our areas
of operations could reduce the demand for our services.
•
We do not own all of the land on which our pipelines and
facilities are located, which could disrupt our operations.
Risks
Inherent in an Investment in Us
•
Affiliates of our general partner, including Enterprise Products
Partners, Enterprise GP Holdings and TEPPCO Partners, may
compete with us, and business opportunities may be directed by
contract to Enterprise Products Partners and Enterprise GP
Holdings before us under the administrative services agreement.
•
Our general partner and its affiliates own a controlling
interest in us and have conflicts of interest and limited
fiduciary duties, which may permit them to favor their own
interests to your detriment.
•
Our general partner has a limited call right that may require
you to sell your common units at an undesirable time or price.
•
Our partnership agreement limits our general partner’s
fiduciary duties to unitholders and restricts the remedies
available to unitholders for actions taken by our general
partner that might otherwise constitute breaches of fiduciary
duty.
An affiliate of Enterprise Products Partners will have the power
to appoint and remove our directors and management.
•
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.
•
You will experience immediate and substantial dilution of
$5.64 per common unit.
•
We may issue additional units without your approval, which would
dilute your ownership interests.
•
Cost reimbursements to EPCO and its affiliates will reduce cash
available for distribution to you.
Tax
Risks
•
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, or the IRS, were to treat us as
a corporation or if we were to become subject to entity-level
taxation for state tax purposes, then our cash distributions to
you would be substantially reduced.
•
If the IRS contests the federal income tax positions we take,
the market for our common units may be adversely impacted, and
the costs of any contest will reduce our cash distributions to
you.
•
You may be required to pay taxes on your share of our income
even if you do not receive any cash distributions from us.
Duncan Energy Partners L.P. was formed on
September 29, 2006; therefore, it does not have any
historical financial statements prior to its formation. The
following tables set forth, for the periods and at the dates
indicated, the summary historical combined financial and
operating data of Duncan Energy Partners Predecessor, which was
derived from the books and records of Enterprise Products
Partners.
The summary historical combined financial data for the nine
months ended September 30, 2006 and for the years ended
December 31, 2005, 2004 and 2003 and combined balance sheet
data at September 30, 2006 and at December 31, 2005
and 2004 is derived from and should be read in conjunction with
the audited combined financial statements of Duncan Energy
Partners Predecessor included elsewhere in this prospectus
beginning on
page F-13.
The summary historical combined financial data for the nine
months ended September 30, 2005 and combined balance sheet
data at September 30, 2005 is derived from the unaudited
condensed combined financial statements of Duncan Energy
Partners Predecessor. The operating data for all periods are
unaudited. The summary unaudited pro forma combined financial
data of Duncan Energy Partners was derived from and should be
read in conjunction with our unaudited pro forma condensed
combined financial statements included in this prospectus
beginning on
page F-2.
The following information should also be read together with the
“Management’s Discussion and Analysis of Financial
Condition and Results of Operations.”
Enterprise Products Partners, through its subsidiaries, has
owned controlling interests and operated the underlying assets
of Mont Belvieu Caverns, Acadian Gas, Lou-Tex Propylene and
Sabine Propylene for several years. Enterprise Products Partners
will retain a 34% ownership interest in each of these four
entities (as well as South Texas NGL). Enterprise Products
Partners will own our general partner, DEP Holdings, which owns
a 2% general partner interest in us, and therefore indirectly
has the ability to control us. In addition, Enterprise Products
Partners will own approximately 36.0% of our common units after
completion of this offering, or approximately 26.4% of our
outstanding common units if the underwriters exercise their
option to purchase additional common units in full. For
financial reporting purposes, the ownership interests of
Enterprise Products Partners are deemed to represent the parent
(or sponsor) interest in our pro forma results of our operations
and financial position.
The summary unaudited pro forma combined financial data for the
nine months ended September 30, 2006 and for the year ended
December 31, 2005 assume the pro forma transactions noted
herein occurred at the beginning of each period presented or on
September 30, 2006 for the balance sheet data. These
transactions include:
•
The August 2006 purchase of a pipeline by Enterprise Products
Partners for approximately $97.7 million in cash, the
subsequent contribution of this pipeline to South Texas NGL, and
estimated additional costs of $37.7 million required to
modify this pipeline and to acquire and construct additional
pipelines in order to place this system into operation in
January 2007. The pro forma financial data does not reflect
estimated additional capital expenditures of $28.6 million
that will be made by South Texas NGL in 2007 to complete planned
expansions to this system. We will retain cash in an amount
equal to our 66% share (approximately $18.9 million)
of these estimated capital expenditures from the net proceeds of
this offering in order to fund our share of the planned
expansion costs. The pro forma combined results of operations
data does not reflect any results attributable to the historical
activities of this pipeline.
•
The expenditure of $21.3 million in connection with the
construction of additional brine production capacity and
above-ground storage reservoirs at Mont Belvieu. The pro forma
financial data does not reflect estimated additional capital
expenditures of $14.1 million that will be made by Mont
Belvieu Caverns subsequent to December 31, 2006 to complete
these projects. We will retain cash in an amount equal to our
66% share (approximately $9.3 million) of these
additional capital expenditures from the net proceeds of this
offering in order to fund our share of the planned expansion
costs.
•
The contribution of a 66% interest in certain entities, which
are wholly-owned subsidiaries of Enterprise Products Partners,
and the retention by Enterprise Products Partners of a 34%
interest in these entities.
The revision of related party storage contracts between us and
Enterprise Products Partners to (1) increase certain
storage fees paid by Enterprise Products Partners and
(2) reflect the allocation to Enterprise Products Partners
of all storage measurement gains and losses relating to products
under these agreements, and the execution of a limited liability
company agreement for Mont Belvieu Caverns providing for the
special allocation and other agreements relating to other
measurement gains and losses to Enterprise Products Partners.
•
The assignment to us of certain third-party agreements that
effectively reduce tariff rates received by us for the transport
of propylene volumes.
Our unaudited pro forma, as adjusted financial data also gives
effect to the following:
•
our borrowing of $200 million under a new revolving credit
facility;
•
our issuance and sale of 13,000,000 common units to the public
in this offering;
•
our payment of estimated underwriting discounts and commissions,
a structuring fee and other offering expenses; and
•
our use of net proceeds from the borrowing and this offering as
consideration for the contributed ownership interests in Mont
Belvieu Caverns, Acadian Gas, Lou-Tex Propylene, Sabine
Propylene and South Texas NGL from Enterprise Products Partners.
The following table presents the summary historical combined
financial and operating data of Duncan Energy Partners
Predecessor and our summary unaudited pro forma combined
financial information for the annual periods indicated (dollars
in thousands, except per unit amounts):
The following table presents the summary historical combined
financial and operating data of Duncan Energy Partners
Predecessor and our summary unaudited pro forma combined
financial information for the interim periods indicated (dollars
in thousands, except per unit amounts):
Income before provision for income
taxes and parent interest
31,557
40,284
33,209
23,279
Provision for income taxes
(21
)
(21
)
(21
)
Income before parent interest
31,557
40,263
33,188
23,258
Parent’s share of net income
(15,733
)
Income from continuing operations
31,557
40,263
$
33,188
$
7,525
Cumulative effect of change in
accounting principle
9
Net income
$
31,557
$
40,272
Earnings per unit —
public, basic and diluted
$
0.58
Combined Balance Sheet Data (at
period end):(1)
Total assets
$
617,402
$
747,155
$
799,675
$
828,963
Total debt
200,000
Parent’s interest in the
Partnership
305,233
Owners’ net investment
520,727
662,131
716,465
Partners’ equity —
public
240,520
Other Combined Financial
Data:(1)
Net cash flows provided by
operating activities
$
37,226
$
62,301
Cash flows used in investing
activities
16,669
58,226
Cash flows used in financing
activities(2)
20,557
4,075
Gross operating margin
49,611
58,198
$
52,998
$
52,998
EBITDA
45,810
55,761
48,677
32,944
Operating
Data:(1)
Natural Gas Pipelines &
Services, net:
Natural gas throughput volumes
(Bbtus/d)
657
773
773
773
Petrochemical Pipeline Services,
net:
Petrochemical transportation
volumes (MBbls/d)
34
36
36
36
The non-GAAP financial measures of gross operating margin and
earnings before interest, income taxes, depreciation and
amortization, which we refer to as “EBITDA,” are
presented in the summary historical financial data for Duncan
Energy Partners Predecessor and in our pro forma financial data.
For a description of these non-GAAP financial measures and
reconciliations of these non-GAAP financial measures to their
most directly comparable GAAP financial measures, please read
“— Non-GAAP Financial Measures.”
The following information is provided to highlight significant
trends and other information regarding Duncan Energy Partners
Predecessor’s historical operating results, financial
position and other financial data. Each section below represents
a footnote to the tables above:
(1) We view the combined financial data of Duncan Energy
Partners Predecessor from the financial statements of Mont
Belvieu Caverns, Acadian Gas, Lou-Tex Propylene and Sabine
Propylene, which were derived from the accounts and records of
Enterprise Products Partners. Enterprise Products Partners did
not own certain of the businesses for all periods presented in
this section. As a result, the summary selected data reflects
the following information:
•
Enterprise Products Partners owned Mont Belvieu Caverns and
Lou-Tex Propylene for all periods presented. Our pro forma
balance sheet data reflects assumed capital expenditures of
$21.3 million by Mont Belvieu Caverns in connection with
the construction of additional brine production capacity and
above-ground storage reservoirs. Our pro forma financial data
does not reflect estimated additional capital expenditures of
$14.1 million that will be made by Mont Belvieu Caverns
subsequent to December 31, 2006 to complete these projects.
We will retain cash in an amount equal to our 66% share
(approximately $9.3 million) of these additional capital
expenditures from the net proceeds of this offering in order to
fund our share of the planned expansion costs.
•
Enterprise Products Partners acquired Acadian Gas in April 2001;
therefore, the selected data includes Acadian Gas from the date
of its acquisition. No financial data was available from the
seller for periods prior to April 2001.
•
Enterprise Products Partners constructed the pipeline owned by
Sabine Propylene and placed it in service in November 2001;
therefore, the selected data includes Sabine Propylene from
November 2001 to present.
•
In August 2006, Enterprise Products Partners purchased a
223-mile
pipeline extending from Corpus Christi, Texas to Pasadena, Texas
from ExxonMobil Pipeline Company. The total purchase price for
this asset was approximately $97.7 million in cash. This
pipeline system will be owned by South Texas NGL (along with
others being constructed and to be acquired) and will be used to
transport NGLs from two Enterprise Products Partners’
facilities located in South Texas to Mont Belvieu, Texas. The
total estimated cost to acquire and construct the additional
pipelines is $66.3 million. Our pro forma balance sheet
data reflects assumed capital expenditures of
$37.7 million, including approximately $8 million
spent to acquire a
10-mile
pipeline from an affiliate of TEPPCO Partners, to make this
pipeline system operational in January 2007. We expect that it
will cost an additional $28.6 million to complete planned
expansions of the South Texas NGL pipeline after the closing of
this offering, of which our 66% share will be approximately
$18.9 million. This expenditure is not reflected in the pro
forma financial data because we expect to use cash on hand from
the proceeds of this offering to fund this cost.
Duncan Energy Partners Predecessor’s historical financial
information does not reflect any transactions related to the NGL
pipeline asset acquired in August 2006 or subsequent capital
expenditures for the construction and acquisition of related
pipelines. Furthermore, the pro forma adjustments are limited to
those required to present an estimate of owners’ net
investment immediately prior to this offering. The pro forma
results of operations data does not reflect any results
attributable to the historical activities of these NGL pipelines.
ExxonMobil has informed us that no discrete and separable
financial information existed for the pipeline we acquired in
August 2006, which was comprised of two separately operated
pipelines prior to our purchase. The seller had previously
utilized these pipelines for a different product and the
pipeline was out of service when we acquired it. The
10-mile
pipeline acquired from an affiliate of TEPPCO Partners was used
as a feeder line for NGL products and operated by different
management. We understand no financial statement information is
available for this minor component asset. There is no meaningful
financial data available regarding the prior use of these
pipelines by the sellers that would be meaningful to our
investors. In addition, such data, if available, would not
assist investors in understanding either the evolution of the
business (which is a new NGL transportation network) nor the
track record of management (which will be different).
(2) Duncan Energy Partners Predecessor operated within the
Enterprise Products Partners cash management program for all
periods presented. Cash flows used in financing activities
represent transfers of excess cash from Duncan Energy Partners
Predecessor to Enterprise Products Partners equal to cash
provided by operations less cash used in investing activities.
Conversely, cash flows provided by financing activities
represent contributions from Enterprise Products Partners.
For additional information regarding our combined results of
operations and liquidity and capital resources, please read
“Management’s Discussion and Analysis of Financial
Condition and Results of Operations.”
Non-GAAP Financial
Measures
We include in this prospectus the non-GAAP financial measures of
gross operating margin and EBITDA, and provide reconciliations
of these non-GAAP measures to their most directly comparable
measure or measures calculated and presented in accordance with
GAAP.
Gross operating margin. We evaluate segment
performance based on the non-GAAP financial measure of gross
operating margin. Gross operating margin (total and by 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 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 (or combined) segment gross operating margin as
operating income before: (1) depreciation, amortization and
accretion expense; (2) gains and losses on the sale of
assets; and (3) general and administrative expenses. Gross
operating margin is exclusive of other income and expense
transactions, provision for income taxes, minority interest,
extraordinary charges and the cumulative effect of changes in
accounting principles. Gross operating margin by segment is
calculated by subtracting segment operating costs and expenses
(net of the adjustments noted above) from segment revenues, with
both segment totals before the elimination of any intersegment
and intrasegment transactions. Our combined revenues reflect the
elimination of all material intercompany transactions.
We include equity earnings from Evangeline, a subsidiary of
Acadian Gas, in our measurement of the Natural Gas
Pipelines & Services segment gross operating margin and
operating income. Our equity investments in midstream energy
operations such as those conducted by Evangeline are a vital
component of our long-term business strategy and important to
the operations of Acadian Gas. This method of operation enables
us to achieve favorable economies of scale relative to our level
of investment and also lowers our exposure to business risks
compared the profile we would have on a stand-alone basis. Our
equity investments are within the same industry as our combined
operations; therefore, we believe treatment of earnings from our
equity method investee as a component of gross operating margin
and operating income is appropriate.
EBITDA. We define EBITDA as net income or loss
plus interest expense, provision for income taxes and
depreciation, accretion and amortization expense. EBITDA is
commonly used as a supplemental financial measure by management
and by external users of our financial statements, such as
investors, commercial banks, research analysts and rating
agencies, to assess: (1) the financial performance of our
assets without regard to financing methods, capital structures
or historical cost basis; (2) the ability of our assets to
generate cash sufficient to pay interest cost and support our
indebtedness; (3) our operating performance and return on
capital as compared to those of other companies in the midstream
energy industry, without regard to financing and capital
structure; and (4) the viability of projects and the
overall rates of return on alternative investment opportunities.
Because EBITDA excludes some, but not all, items that affect net
income or loss and because these measures may vary among other
companies, the EBITDA data presented in this prospectus may not
be comparable to similarly titled measures of other companies.
The GAAP measure most directly comparable to EBITDA is net cash
provided by operating activities.
The following tables present (1) a reconciliation of the
non-GAAP financial measure of gross operating margin to the GAAP
financial measure of operating income and (2) a
reconciliation of the non-GAAP financial measure of EBITDA to
the GAAP financial measure of net income (income from continuing
operations with regards to our pro forma information) on a
historical and pro forma basis, as applicable, for each of the
periods presented (dollars in thousands). With regards to EBITDA
measures determined using the historical financial information
of Duncan Energy Partners Predecessor, EBITDA is also reconciled
to the GAAP financial measure of net cash provided by operating
activities.
Reconciliation of GAAP
“operating income” to non-GAAP “gross operating
margin”
Operating income
$
52,453
$
58,176
$
40,201
$
33,927
$
33,927
Adjustments to reconcile
operating income to gross operating margin:
Depreciation, amortization and
accretion in operating costs and expenses
17,882
18,374
19,453
19,453
19,453
Loss (gain) on sale of assets in
operating costs and expenses
(7
)
5
5
5
General and administrative costs
6,138
5,442
4,483
6,983
6,983
Total gross operating margin
$
76,473
$
81,985
$
64,142
$
60,368
$
60,368
Reconciliation of non-GAAP
“EBITDA” to GAAP “net income” (or GAAP
“income from continuing operations” with respect to
pro forma data) and GAAP “net cash provided by operating
activities”
Net income (income from continuing
operations with respect to pro forma data)
$
52,454
$
58,124
$
39,087
$
33,395
$
5,846
Additions to income to derive
EBITDA:
Interest expense
532
532
13,807
Depreciation, accretion and
amortization
17,882
18,374
19,453
19,453
19,453
EBITDA
$
70,336
$
76,498
$
59,072
$
53,380
$
39,106
Adjustments to EBITDA to derive
net cash provided by operating activities (add or subtract as
indicated by sign of number):
Cumulative effect of change in
accounting principle
582
Interest expense
(532
)
Equity in income of unconsolidated
affiliates
(131
)
(231
)
(331
)
Loss (gain) on sale of assets
(7
)
5
Changes in fair market value of
financial instruments
Reconciliation of GAAP
“operating income” to non-GAAP “gross operating
margin”
Operating income
$
31,557
$
40,278
$
33,203
$
33,203
Adjustments to reconcile
operating income to gross operating margin:
Depreciation, amortization and
accretion in operating costs and expenses
14,253
15,468
15,468
15,468
Loss (gain) on sale of assets in
operating costs and expenses
2
(17
)
(17
)
(17
)
General and administrative costs
3,799
2,469
4,344
4,344
Total gross operating margin
$
49,611
$
58,198
$
52,998
$
52,998
Reconciliation of non-GAAP
“EBITDA” to GAAP “net income” (or GAAP
“income from continuing operations” with respect to
pro forma data) and GAAP “net cash provided by operating
activities”
Net income (income from continuing
operations with respect to pro forma data)
$
31,557
$
40,272
$
33,188
$
7,525
Additions to income to derive
EBITDA:
Interest expense
9,930
Provision for income taxes
21
21
21
Depreciation, accretion and
amortization
14,253
15,468
15,468
15,468
EBITDA
$
45,810
$
55,761
$
48,677
$
32,944
Adjustments to EBITDA to derive
net cash provided by operating activities (add or subtract as
indicated by sign of number):
Provision for income taxes
(21
)
Cumulative effect of change in
accounting principle
(9
)
Equity in income of unconsolidated
affiliates
(280
)
(624
)
Deferred income tax expense
21
Loss (gain) on sale of assets
2
(17
)
Changes in fair market value of
financial instruments
Limited partner interests are inherently different from the
capital stock of a corporation, although many of the business
risks to which we are subject are similar to those that would be
faced by a corporation engaged in a similar business. You should
carefully consider the following risk factors together with all
of the other information included in this prospectus in
evaluating an investment in our common units.
If any of the following risks were actually to occur, our
business, financial condition, or results of operations could be
materially adversely affected. In that case, we might not be
able to pay distributions on our common units, the trading price
of our common units could decline, and you could lose all or
part of your investment.
We may
not have sufficient available cash to enable us to pay our
expected initial quarterly distribution on our common units
after establishment of cash reserves and payment of fees and
expenses, including reimbursement of expenses to our general
partner.
We may not have sufficient available cash each quarter to pay
our expected initial quarterly distribution. The amount of cash
we can distribute on our common units principally depends upon
the amount of cash we generate from our operations, which will
fluctuate from quarter to quarter based on, among other things:
•
the prices we obtain for our transportation and storage
services;
•
the volumes of natural gas, NGLs and propylene our customers
transport or store;
•
the prices of, level of production of, and demand for, natural
gas, propylene and NGLs in the markets we serve;
•
the level of competition from other midstream energy companies,
as well as from alternative fuels;
•
the level of our operating costs, including reimbursement of
expenses to our general partner; and
•
prevailing economic and market conditions.
In addition, the actual amount of cash we will have available
for distribution will depend on other factors such as:
•
the level of our capital expenditures;
•
the restrictions on distributions contained in our credit
agreement and our debt service requirements;
•
the cost of acquisitions, if any;
•
fluctuations in our working capital needs;
•
our ability to borrow to make distributions to our
unitholders; and
•
the amount, if any, of cash reserves established by our general
partner.
Please read “Cash Distribution Policy and Restrictions on
Distributions” for a discussion of how we determine our
available cash.
On a
pro forma historical basis, we would not have had sufficient
cash available for distributions to pay the expected initial
quarterly distribution on all common units for the year ended
December 31, 2005 and the four quarters ended
September 30, 2006.
The amount of available cash we will need to pay our expected
initial quarterly distribution for four quarters on the common
units and the 2% general partner interest to be outstanding
immediately after this offering is approximately
$33.1 million. Pro forma combined available cash to make
distributions generated during fiscal 2005 and the four quarters
ended September 30, 2006 would have been approximately
$9.9 million and a deficit of $14.1 million,
respectively. These amounts would have been sufficient to allow
us
to pay only 30% of the initial quarterly distributions on the
common units and the 2% general partner interest during 2005.
These amounts would not have been sufficient to allow us to pay
any distributions on our common units and the general partner
interest during the four quarters ended September 30, 2006.
For a calculation of our ability to make distributions to
unitholders based on our pro forma results in 2005 and for the
twelve months ended September 30, 2006, as well as
estimated cash available to pay distributions for the four
quarters ending December 31, 2007, please read “Cash
Distribution Policy and Restrictions on Distributions.”
The
assumptions underlying our estimate of cash available for
distribution we include in our “Cash Distribution Policy
and Restrictions on Distributions” are inherently uncertain
and are subject to significant business, economic, financial,
regulatory and competitive risks and uncertainties that could
cause actual results to differ materially from those
expected.
Our estimate of cash available for distribution set forth in
“Cash Distribution Policy and Restrictions on
Distributions” is based on assumptions that are inherently
uncertain and are subject to significant business, economic,
financial, regulatory and competitive risks and uncertainties
that could cause actual results to differ materially from those
estimated. Furthermore, our estimate of cash available for
distribution for the four quarters ending December 31, 2007
is equal to the amount of available cash we need to pay the
expected initial quarterly distribution on all common units for
such quarters. If we do not achieve the estimated results, we
may not be able to pay the full expected initial quarterly
distribution or any amount on our common units, in which event
the market price of our common units may decline materially.
The
amount of cash we have available for distribution to unitholders
depends primarily on our cash flow and not solely on
profitability, which may prevent us from making cash
distributions during periods when we record net
income.
The amount of cash we have available for distribution depends
primarily on our cash flow, including cash flow from financial
reserves and working capital or other borrowings, and not solely
on profitability, which will be affected by non-cash items. As a
result, we may make cash distributions during periods when we
record losses and may not make cash distributions during periods
when we record net income.
Changes
in demand for and production of hydrocarbon products may
materially adversely affect our results of operations, cash
flows and financial condition.
We operate predominantly in the midstream energy sector which
includes transporting and storing natural gas, NGLs and
propylene. As such, our results of operations, cash flows and
financial condition may be materially adversely affected by
changes in the prices of these hydrocarbon products and by
changes in the relative price levels among these hydrocarbon
products. Changes in prices and changes in the relative price
levels may impact demand for hydrocarbon products, which in turn
may impact production and volumes transported by us and related
transportation and storage handling fees. We may also incur
price risk to the extent counterparties do not perform in
connection with our marketing of natural gas, NGLs and propylene.
In the past, the prices of natural gas have been extremely
volatile, and we expect this volatility to continue. The NYMEX
daily settlement price for natural gas for the prompt month
contract in 2004 ranged from a high of $8.75 per MMBtu to a low
of $4.57 per MMBtu. In 2005, the same index ranged from a
high of $15.38 per MMBtu to a low of $5.79 per MMBtu.
In 2006, the same index ranged from a high of $10.63 per MMBtu
to a low of $4.20 per MMBtu.
Generally, the prices of natural gas, NGLs and other hydrocarbon
products are subject to fluctuations in response to changes in
supply, demand, market uncertainty and a variety of additional
factors that are impossible to control. These factors include:
•
the level of domestic production and consumer product demand;
•
the availability of imported natural gas;
•
actions taken by foreign natural gas producing nations;
the availability of transportation systems with adequate
capacity;
•
the availability of competitive fuels;
•
fluctuating and seasonal demand for natural gas and NGLs;
•
the impact of conservation efforts;
•
the extent of governmental regulation and taxation of
production; and
•
the overall economic environment.
A
decrease in demand for natural gas, NGLs, NGL products or
petrochemical products by the petrochemical, refining or heating
industries could materially adversely affect our results of
operations, cash flows and financial position.
A decrease in demand for natural gas, NGLs, NGL products or
petrochemical products by the petrochemical, refining or heating
industries, whether because of a general downturn in economic
conditions, reduced demand by consumers for the end products
made with products we transport, increased competition from
petroleum-based products due to pricing differences, adverse
weather conditions, increased government regulations affecting
prices and production levels of natural gas or other reasons,
could materially adversely affect our results of operations,
cash flows and financial position. 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.
•
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.
Any
decrease in supplies of natural gas could adversely affect our
business and operating results. Because of the natural decline
in gas production from existing wells, our success depends on
our ability to obtain access to new sources of natural gas,
which is dependent on factors beyond our control.
Over the past two years that have been reported, gas production
from state waters of the Gulf Coast region, which supplies much
of our throughput, has declined an average of approximately
2.9% from 133 Bcf for 2003 to 129 Bcf for 2004,
according to the Energy Information Administration, or EIA. We
cannot give any assurance regarding the gas production
industry’s ability to find new sources of domestic supply.
Production from existing wells and gas supply basins connected
to our pipelines will naturally decline over time, which means
that our cash flows associated with the gathering or
transportation of gas from these wells and basins will also
decline over time. The amount of natural gas reserves underlying
these wells may also be less than we anticipate, and the rate at
which production from these reserves declines may be greater
than we anticipate. Accordingly, to maintain or increase
throughput levels on our pipelines, we must continually obtain
access to new supplies of natural gas. The primary factors
affecting our ability to obtain new sources of natural gas to
our pipelines include:
•
the level of successful drilling activity near our pipelines;
•
our ability to compete for these supplies;
•
our ability to connect our pipelines to the suppliers;
•
the successful completion of new LNG facilities near our
pipelines; and
The level of drilling activity is dependent on economic and
business factors beyond our control. The primary factor that
impacts drilling decisions is the price of oil and natural gas.
These commodity prices reached record levels during 2006, but
current prices have declined in recent months. A sustained
decline in natural gas prices could result in a decrease in
exploration and development activities in the fields served by
our pipelines, which would lead to reduced throughput levels on
our pipelines. Other factors that impact production decisions
include producers’ capital budget limitations, the ability
of producers to obtain necessary drilling and other governmental
permits, the availability and cost of drilling rigs and other
drilling equipment, and regulatory changes. Because of these
factors, even if new natural gas reserves were discovered in
areas served by our pipelines, producers may choose not to
develop those reserves or may connect them to different
pipelines.
Imported 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. Eleven LNG
projects have been approved by the FERC to be constructed in the
Gulf Coast region and an additional four LNG projects have been
proposed for the region. We cannot predict which, if any, of
these projects will be constructed. If a significant number of
these new projects fail to be developed with their announced
capacity, or there are significant delays in such development,
or if they are built in locations where they are not connected
to our systems or they do not influence sources of supply on our
systems, we may not realize expected increases in future natural
gas supply available for transportation through our systems.
If we are not able to obtain new supplies of natural gas to
replace the natural decline in volumes from existing supply
basins, or if the expected increase in natural gas supply
through imported LNG is not realized, throughput on our
pipelines would decline which could have a material adverse
effect on our financial condition, results of operations and
ability to make distributions to you.
In
accordance with industry practice, we do not obtain independent
evaluations of natural gas reserves dedicated to our pipeline
systems, including our South Texas NGL pipeline. Accordingly,
volumes of natural gas gathered on our pipeline systems in the
future could be less than we anticipate, which could adversely
affect our cash flow and our ability to make cash distributions
to unitholders.
In accordance with industry practice, we do not obtain
independent evaluations of natural gas reserves connected to our
pipeline systems due to the unwillingness of producers to
provide reserve information as well as the cost of such
evaluations. Accordingly, we do not have estimates of total
reserves dedicated to our systems (or to processing facilities
such as those serving Enterprise Products Partners in South
Texas) or the anticipated lives of such reserves. If the total
reserves or estimated lives of the reserves connected to our
pipeline systems, particularly in South Texas, is less than we
anticipate and we are unable to secure additional sources of
natural gas, then the volumes of natural gas gathered on our
South Texas NGL and other pipeline systems in the future could
be less than we anticipate. A decline in the volumes of natural
gas gathered on our pipeline systems could have an adverse
effect on our business, results of operations, financial
condition and our ability to make cash distributions to you.
We
will depend in large part on Enterprise Products Partners and
the continued success of its business as we operate our assets
as part of their value chain, and adverse changes in its related
businesses may reduce our revenue, earnings or cash available
for distribution.
We will enter into a number of material contracts with
Enterprise Products Partners and its subsidiaries relating to
transportation, storage and leases, and our cash flows and
financial condition will depend in large part on the continued
success of Enterprise Products Partners as we operate our assets
as part of its value chain. For example, our South Texas NGL
system revenues will depend solely on the volumes processed at
the South Texas facilities owned by Enterprise Products
Partners. Enterprise Products Partners has no obligation to
produce any volumes at these facilities. If anticipated volumes
are not processed by Enterprise Products Partners at these
facilities, our estimated revenues on this system will be
reduced.
Any adverse changes in the business of Enterprise Products
Partners, due to market conditions, sales of assets or
otherwise, or the failure of Enterprise Products Partners to
renew any of its material agreements with
us, could reduce our revenue, earnings or cash available for
distribution. Please read “Certain Relationships and
Related Party Transactions” for a summary of certain of
these agreements.
The
credit and risk profile of our general partner and its owners
could adversely affect our credit ratings and risk profile,
which could increase our borrowing costs or hinder our ability
to raise capital.
The credit and business risk profiles of a 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 controls the business activities of the partnership,
including its cash distribution policy and acquisition strategy
and business risk profile. Another factor that may be considered
is the financial condition of our 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.
If we were to seek a credit rating in the future, our credit
rating may be adversely affected by the leverage of the owners
of our general partner, as credit rating agencies such as
Standard & Poor’s Ratings Services and
Moody’s Investors Service may consider these entities’
leverage because of their ownership interest in and control of
us, the strong operational links between them and their
affiliates and us, and our reliance on Enterprise Products
Partners for a substantial percentage of our revenue. Any such
adverse effect on our credit rating would increase our cost of
borrowing or hinder our ability to raise money in the capital
markets, which would impair our ability to grow our business and
make distributions to unitholders.
Affiliates of Enterprise Products Partners, the indirect owner
of our general partner, have significant indebtedness
outstanding and are dependent principally on the cash
distributions from their general partner and limited partner
interests in Enterprise Products Partners, Enterprise GP
Holdings and TEPPCO Partners to service such indebtedness. Any
distributions by Enterprise Products Partners, Enterprise GP
Holdings and TEPPCO Partners to such entities will be made only
after satisfying their then current obligations to their
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, and
other entities controlled by Dan L. Duncan, our credit ratings
and business risk profile could be adversely affected if the
ratings and risk profiles of Dan L. Duncan or the entities that
control our general partner were viewed as substantially lower
or more risky than ours.
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.
Pipelines may suffer inadvertent damage from construction, and
farm and utility equipment. Virtually all of our operations are
exposed to potential natural disasters, including hurricanes,
tornadoes, storms and floods. The location of our assets and our
customers’ assets in the Gulf Coast region makes them
particularly vulnerable to hurricane risk.
If one or more facilities that we own or that deliver 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. 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.
EPCO maintains insurance coverage on behalf of us, 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, changes in the
insurance markets subsequent to the terrorist attacks on
September 11, 2001 and the hurricanes in 2005 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
and results of operations. In addition, the proceeds of any such
insurance may not be paid in a timely manner and may be
insufficient if such an event were to occur.
Our
debt levels may limit our flexibility to obtain additional
financing and pursue other business opportunities.
At the closing of this offering, we expect to have approximately
$200 million of indebtedness outstanding under our credit
agreement and the ability to borrow up to an additional
$100 million, subject to certain conditions and
limitations, under the credit agreement. Our significant level
of indebtedness could have important consequences to us,
including:
•
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;
•
covenants contained in our existing and future credit and debt
arrangements will require us to meet financial tests that may
affect our flexibility in planning for and reacting to changes
in our business, including possible acquisition opportunities;
•
we will need a substantial portion of our cash flow to make
principal and interest payments on our indebtedness, reducing
the funds that would otherwise be available for operation,
future business opportunities and distributions to
unitholders; and
•
our debt level will make us more vulnerable than our competitors
with less debt to competitive pressures or a downturn in our
business or the economy generally.
Our ability to service our indebtedness will depend upon, among
other things, our future financial and operating performance,
which will be affected by prevailing economic conditions and
financial, business, regulatory and other factors, some of which
are beyond our control. If our operating results are not
sufficient to service our current or future indebtedness, we
will be forced to take actions such as reducing distributions,
reducing or delaying business activities, acquisition,
investments or capital expenditures, selling assets,
restructuring or refinancing our indebtedness, or seeking
additional equity capital or bankruptcy protection. We may not
be able to effect any of these remedies on satisfactory terms or
at all.
Our
new revolving credit facility will contain operating and
financial restrictions, including covenants and restrictions
that may be affected by events beyond our control, that may
limit our business and financing activities.
The operating and financial restrictions and covenants in our
credit agreement and any future financing agreements could
restrict our ability to finance future operations or capital
needs or to expand or pursue our business activities. For
example, our new credit agreement will restrict or limit our
ability to:
•
make distributions if any default or event of default occurs;
•
incur additional indebtedness or guarantee other indebtedness;
make any material change to the nature of our business,
including consolidations, liquidations and dissolutions; or
•
enter into a merger, consolidation, sale and leaseback
transaction or sale of assets.
Our ability to comply with the covenants and restrictions
contained in our credit agreement may be affected by events
beyond our control, including prevailing economic, financial and
industry conditions. If market or other economic conditions
deteriorate, our ability to comply with these covenants may be
impaired. If we violate any of the restrictions, covenants,
ratios or tests in our credit agreement, a significant portion
of our indebtedness may become immediately due and payable, and
our lenders’ commitment to make further loans to us may
terminate. We might not have, or be able to obtain, sufficient
funds to make these accelerated payments.
Restrictions
in our revolving credit facility could limit our ability to make
distributions upon the occurrence of certain
events.
Our payment of principal and interest on our debt will reduce
cash available for distributions on our common units. Our new
credit agreement will limit our ability to make distributions
upon the occurrence of the following events, among others:
•
failure to pay any principal, interest, fees, expenses or other
amounts when due;
•
failure of any representation or warranty to be true and correct
in any material respect;
•
failure to perform or otherwise comply with the covenants in the
credit agreement;
•
failure to pay any other material debt;
•
a bankruptcy or insolvency event involving us, our general
partner or any of our subsidiaries;
•
the entry of, and failure to pay, one or more adverse judgments
in excess of a specified amount against which enforcement
proceedings are brought or that are not stayed pending appeal;
•
a change in control of us;
•
a judgment default or a default under any material agreement if
such default could have a material adverse effect on us; and
•
the occurrence of certain events with respect to employee
benefit plans subject to ERISA.
Any subsequent refinancing of our current debt or any new debt
could have similar or more restrictive provisions. For more
information regarding our credit agreement, please read
“Management’s Discussion and Analysis of Financial
Condition and Results of Operations — Liquidity and
Capital Resources — New Revolving Credit
Facility.”
Increases
in interest rates could materially adversely affect our
business, results of operations, cash flows and financial
condition.
We have significant exposure to increases in interest rates.
After giving effect to this offering and the borrowing of
approximately $200 million under our new credit agreement,
pro forma as of September 30, 2006, we would have
approximately $200 million of consolidated debt, of which
we expect all will be at variable interest rates. As a result,
our results of operations, cash flows and financial condition
could be materially adversely affected by significant increases
in interest rates.
An increase in interest rates may also cause a corresponding
decline in demand for equity investments, in general, and in
particular for yield-based equity investments such as our common
units. Any such reduction in demand for our common units
resulting from other more attractive investment opportunities
may cause the trading price of our common units to decline.
Our
hedging activities may have a material adverse effect on our
earnings, profitability, cash flows, including its ability to
make distributions, and financial condition.
We utilize derivative financial instruments related to the
future price of natural gas and the future price of NGLs with
the intent of reducing volatility in our cash flows due to
fluctuations in commodity prices. While our hedging activities
are designed to reduce commodity price risk, we remain exposed
to fluctuations in commodity prices to some extent. The extent
of our commodity price exposure is related largely to the
effectiveness and scope of our hedging activities. For example,
the derivative instruments we utilize are based on posted market
prices, which may differ significantly from the actual natural
gas prices or NGLs prices that we realize in our operations.
Furthermore, our hedges relate to only a portion of the volume
of our expected sales and, as a result, we will continue to have
direct commodity price exposure to the unhedged portion. Our
actual future sales may be significantly higher or lower than
estimated at the time we entered into derivative transactions
for such period. If the actual amount is higher than estimated,
we will have greater commodity price exposure than intended. If
the actual amount is lower than the amount that is subject to
our derivative financial instruments, we might be forced to
satisfy all or a portion of our derivative transactions without
the benefit of the cash flow from the sale or purchase of the
underlying physical commodity, resulting in a substantial
diminution of liquidity.
As a result of these factors, our hedging activities may not be
as effective as intended in reducing the volatility of our cash
flows, which could adversely affect our ability to make
distributions to unitholders. In addition, our hedging
activities are subject to the risks that a counterparty may not
perform its obligation under the applicable derivative
instrument, the terms of the derivative instruments are
imperfect, and our hedging procedures may not be properly
followed. We cannot assure you that the steps we take to monitor
our derivative financial instruments will detect and prevent
violations of our risk management policies and procedures,
particularly if deception or other intentional misconduct is
involved.
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 connections between our South Texas NGL pipeline and
the Mont Belvieu facility is a pipeline we have leased from
TEPPCO Partners. The initial term of this lease will expire on
September 15, 2007, and if we are unable to construct our
planned replacement pipeline or extend the lease, the operations
of our South Texas NGL pipeline will be interrupted. We cannot
assure you that any construction will not be delayed due to
government permits, weather conditions or other factors beyond
our control.
In addition, 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:
•
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;
•
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;
•
we may construct facilities to capture anticipated future growth
in production in a region in which such growth does not
materialize;
•
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 make construct
facilities in an area where the reserves are materially lower
than we anticipate;
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
•
we may be unable to obtain
rights-of-way
to construct additional pipelines or the cost to do so may be
uneconomical.
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.
We may
not be able to make acquisitions or to make acquisitions on
economically acceptable terms, which may limit our ability to
grow.
We will be limited in our ability to make acquisitions by our
business opportunity agreements with Enterprise Products
Partners and Enterprise GP Holdings. These agreements will
entitle them to take business opportunities for the benefit of
themselves before allowing us to take them. In addition, our
ability to grow depends, in part, on our ability to make
acquisitions that result in an increase in the cash generated
from operations per unit. If we are unable to make these
accretive acquisitions either because we are (1) unable to
identify attractive acquisition candidates or negotiate
acceptable purchase contracts with them, (2) unable to
obtain financing for these acquisitions on economically
acceptable terms, or (3) outbid by competitors, then our
future growth and ability to maintain and increase over time
distributions will be limited.
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:
•
mistaken assumptions about volumes, revenues and costs,
including synergies;
•
an inability to integrate successfully the businesses we acquire;
•
a decrease in our liquidity as a result of our using a
significant portion of our available cash or borrowing capacity
to finance the acquisition;
•
a significant increase in our interest expense or financial
leverage if we incur additional debt to finance the acquisition;
•
the assumption of unknown liabilities for which we are not
indemnified or for which our indemnity is inadequate;
•
an inability to hire, train or retain qualified personnel to
manage and operate our growing business and assets;
•
limitations on rights to indemnity from the seller;
•
mistaken assumptions about the overall costs of equity or debt;
•
the diversion of management’s and employees’ attention
from other business concerns;
•
unforeseen difficulties operating in new product areas or new
geographic areas; and
•
customer or key employee losses at the acquired businesses.
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.
Federal,
state or local regulatory measures could materially affect our
business, results of operations, cash flows and financial
condition.
The Surface Transportation Board, or STB, regulates
transportation on interstate propylene pipelines. The current
version of the Interstate Commerce Act, or ICA, and its
implementing regulations give the STB authority to regulate the
rates we charge for service on the propylene pipelines and
generally requires that our rates and practices be just and
reasonable and nondiscriminatory. The rates we charge for
movements on our propylene pipelines may be subject to challenge
and any successful challenge to those rates could adversely
affect our revenues. Our interstate propylene pipelines formerly
were regulated by the FERC, and we cannot guarantee that the
FERC will not reassert jurisdiction over those facilities in the
future.
The intrastate natural gas pipeline transportation services we
provide are subject to various Louisiana state laws and
regulations that apply to the rates we charge and the terms and
conditions of the services we offer. Although state regulation
typically is less onerous than FERC regulation, the rates we
charge and the provision of our services may be subject to
challenge. In addition, the transportation and storage services
furnished by our intrastate natural gas facilities on behalf of
interstate natural gas pipelines or certain local distribution
companies are regulated by the FERC pursuant to Section 311
of the Natural Gas Policy Act of 1978, or NGPA. Pursuant to the
NGPA, we are required to offer those services on an open and
nondiscriminatory basis at a fair and equitable rate. Such
FERC-regulated NGPA Section 311 rates also may be subject
to challenge and successful challenges may adversely affect our
revenues.
Although our natural gas gathering systems are generally exempt
from FERC regulation under the Natural Gas Act of 1938, FERC
regulation still significantly affects our natural gas gathering
business. In recent years, the FERC has pursued pro-competition
policies in its regulation of interstate natural gas pipelines.
If the FERC does not continue this approach, it could have an
adverse effect on the rates we are able to charge in the future.
In addition, the distinction between FERC-regulated transmission
service and federally unregulated gathering services is the
subject of regular litigation, so, in such a circumstance, the
classification and regulation of some of our gathering
facilities may be subject to change based on future
determinations by the FERC and the courts. Additional rules and
legislation pertaining to these matters are considered and
adopted from time to time. We cannot predict what effect, if
any, such regulatory changes and legislation might have on our
operations, but we could be required to incur additional capital
expenditures.
For a general overview of federal, state and local regulation
applicable to our assets, please read “Business —
Regulation of Operations.”
Our
partnership status may be a disadvantage to us in calculating
our cost of service for rate-making purposes.
In May 2005, the FERC issued a policy statement permitting the
inclusion of an income tax allowance in the cost of
service-based rates of a pipeline organized as a tax
pass-through partnership entity to reflect actual or potential
income tax liability on public utility income, if the pipeline
proves that the ultimate owner of its interests has an actual or
potential income tax liability on such income. The policy
statement also provides that whether a pipeline’s owners
have such actual or potential income tax liability will be
reviewed by the FERC on a
case-by-case
basis. In August 2005, the FERC also dismissed requests for
rehearing of its new policy statement. On December 16,2005, the FERC issued its first significant case-specific review
of the income tax allowance issue in another company’s rate
case. The FERC reaffirmed its new income tax allowance policy
and directed the subject pipeline to provide certain evidence
necessary for the pipeline to determine its income tax
allowance. The new tax allowance policy and the December 16
order have been appealed to the United States Court of Appeals
for the District of Columbia Circuit. As a result, the ultimate
outcome of these proceedings is not certain and could result in
changes to the FERC’s treatment of income tax allowances in
cost of service. Depending upon how the policy statement on
income tax allowances is applied in practice to pipelines
organized as pass-through entities, and whether it is ultimately
upheld or modified on judicial review, these decisions might
adversely affect us.
Environmental
costs and liabilities and changing environmental regulation
could materially affect our results of operations, cash flows
and financial condition.
Our operations are subject to extensive federal, state and local
regulatory requirements relating to environmental affairs,
health and safety, waste management and chemical and petroleum
products. These include, for example, (1) the federal Clean
Air Act and comparable state laws and regulations that impose
obligations related to air emissions, (2) the federal
Resource Conservation and Recovery Act, or RCRA, and comparable
state laws that impose requirements for the discharge of waste
from our facilities and (3) the Comprehensive Environmental
Response Compensation and Liability Act of 1980, or CERCLA, also
known as “Superfund,” and comparable state laws that
regulate the clean up of hazardous substances that may have been
released at properties currently or previously owned or operated
by us or locations to which we have sent waste for disposal.
Governmental authorities have the power to enforce compliance
with applicable regulations and permits and to subject violators
to administrative, civil and criminal penalties, including
substantial fines, the imposition of remedial requirements, and
the issuance of orders enjoining future operations. 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.
Our
pipeline integrity program may impose significant costs and
liabilities on us.
Pursuant to the Pipeline Safety Improvement Act of 2002, the
United States Department of Transportation, or DOT, has adopted
regulations requiring pipeline operators to develop integrity
management programs for transportation pipelines located where a
leak or rupture could do the most harm in “high consequence
areas.” The regulations require operators to:
•
perform ongoing assessments of pipeline integrity;
•
identify and characterize applicable threats to pipeline
segments that could impact a high consequence area;
•
improve data collection, integration and analysis;
•
repair and remediate the pipeline, as necessary; and
•
implement preventive and mitigating actions.
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.
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 you.
The workplaces associated with our pipelines 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 condition,
results of operations and ability to make distributions to you.
We
depend on Enterprise Products Partners and certain other key
customers for a significant portion of our revenues. The loss of
any of these key customers could result in a decline in our
revenues and cash available to make distributions to
you.
We rely on a limited number of customers for a significant
portion of revenues. For the year ended December 31, 2005
and the nine months ended September 30, 2006, Enterprise
Products Partners and its affiliates accounted for approximately
9% and 12% of our total combined revenues, respectively. We
expect Enterprise Products Partners and its affiliates will
account for an increased percentage of our total revenues after
this offering. In addition, several of our assets will also rely
on only one or two customers for the asset’s cash flow. For
example, the only shipper on our South Texas NGL pipeline is
Enterprise Products Partners; the only customers on our Lou-Tex
Propylene pipeline are ExxonMobil and Shell; the only customer
on our Sabine Propylene pipeline is Shell; and the only shipper
on the pipeline held by Evangeline is Entergy. In order for new
customers to use these pipelines, we or the new shippers would
be required to construct interim pipeline connections.
Our contracts with affiliates include storage leases between
Mont Belvieu Caverns and certain subsidiaries of Enterprise
Products Partners and TEPPCO Partners that will reflect
amendments to prior agreements effective concurrently with the
closing of this offering. The effect of these amendments will be
to decrease the total fees payable to us. Although we believe
the current agreements will generally reflect current market
rates, these agreements will be entered into with affiliates and
not through arms’ length negotiations. Please read
“Certain Relationships and Related Party
Transactions — Related Party Transactions with
Enterprise Products Partners” for a description of our
affiliate contracts.
We may be unable to negotiate extensions or replacements of
these contracts and those with other key customers on favorable
terms. The loss of all or even a portion of the contracted
volumes of these customers, as a result of competition,
creditworthiness or otherwise, could have a material adverse
effect on our financial condition, results of operations and
ability to make distributions to you, unless we are able to
contract for comparable volumes from other customers at
favorable rates.
We are
exposed to the credit risks of our key customers, and any
material nonpayment or nonperformance by our key customers could
reduce our ability to make distributions to our
unitholders.
We are subject to risks of loss resulting from nonpayment or
nonperformance by our customers. Any material nonpayment or
nonperformance by our key customers could reduce our ability to
make distributions to our unitholders. Furthermore, some of our
customers may be highly leveraged and subject to their own
operating and regulatory risks. We generally do not require
collateral for our accounts receivable. If we fail to adequately
assess the creditworthiness of existing or future customers,
unanticipated deterioration in their creditworthiness and any
resulting increase in nonpayment or nonperformance by them could
have a material adverse effect on our business, results of
operations, financial condition and ability to make cash
distributions to you.
We
depend on the leadership and involvement of Dan L. Duncan and
other key personnel for the success of our and our
subsidiaries’ businesses.
We depend on the leadership, involvement and services of Dan L.
Duncan, the founder of EPCO and the Chairman of our general
partner. Mr. Duncan has been integral to the success of
Enterprise Products Partners and the success of EPCO, and will
be integral to our success, due in part to his ability to
identify and develop business opportunities, make strategic
decisions and attract and retain key personnel. The loss of his
leadership and involvement or the services of any members of our
senior management team could have a material adverse effect on
our business, results of operations, cash flows and financial
condition.
Successful
development of LNG import terminals outside our areas of
operations could reduce the demand for our
services.
Development of new, or expansion of existing, LNG facilities
outside our areas of operations could reduce the need for
customers to transport natural gas from supply basins connected
to our pipelines. This could reduce the amount of gas
transported by our pipelines for delivery off-system to other
intrastate or interstate pipelines serving these customers. If
we are not able to replace these volumes with volumes to other
markets or other regions, throughput on our pipelines would
decline which could have a material adverse effect on our
financial condition, results of operations and ability to make
distributions to you.
We do
not own all of the land on which our pipelines and facilities
are located, which could disrupt our operations.
We do not own all of the land on which our pipelines and
facilities are located, and we are therefore subject to the risk
of increased costs to maintain necessary land use. We obtain the
rights to construct and operate certain of our pipelines and
related facilities on land owned by third parties and
governmental agencies for a specific period of time. Our loss of
these rights, through our inability to renew
right-of-way
contracts or otherwise, or increased costs to renew such rights,
could have a material adverse effect on our business, results of
operations, financial condition and ability to make
distributions to you.
Mergers
among our customers or competitors could result in lower volumes
being shipped on our pipelines, thereby reducing the amount of
cash we generate.
Mergers among our existing customers or competitors could
provide strong economic incentives for the combined entities to
utilize systems other than ours and we could experience
difficulty in replacing lost volumes and revenues. Because most
of our operating costs are fixed, a reduction in volumes would
result in not only a reduction of revenues, but also a decline
in net income and cash flow of a similar magnitude, which would
reduce our ability to meet our financial obligations and make
distributions to you.
Because
of our lack of asset and geographic diversification, adverse
developments in our pipeline operations would reduce our ability
to make distributions to our unitholders.
We rely on the revenues generated from our pipelines and related
assets. Furthermore, our assets are concentrated in Texas and
Louisiana. Due to our lack of diversification in asset type and
location, an adverse development in our business or our
operating areas would have a significantly greater impact on our
financial condition and results of operations than if we
maintained more diverse assets and operating areas.
Terrorist
attacks aimed at our facilities or our customers’
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.
Enterprise
Products Partners, EPCO and their affiliates may compete with
us, and business opportunities may be directed by contract to
those affiliates prior to us under the administrative services
agreement.
Our partnership agreement will not prohibit Enterprise Products
Partners, EPCO and their affiliates, other than our general
partner, from owning and operating natural gas and NGL pipeline
and storage assets or engaging in businesses that otherwise
compete directly or indirectly with us. In addition, Enterprise
Products Partners and EPCO may acquire, construct or dispose of
additional midstream or other natural gas assets in the future,
without any obligation to offer us the opportunity to purchase
or construct any of these assets.
Under the administrative services agreement that we will enter
into at or prior to the closing of this offering, if any
business opportunity, other than a business opportunity to
acquire general partner interests and other related equity
securities in a publicly traded partnership, is presented to
EPCO and its affiliates, us and our general partner, Enterprise
Products Partners and its general partner, or Enterprise GP
Holdings and its general partner, then Enterprise Products
Partners will have the first right to pursue such opportunity
for itself or, in its sole discretion, to affirmatively direct
the opportunity to us. If Enterprise Products Partners abandons
the business opportunity for itself or for us, then Enterprise
GP Holdings will have the second right to pursue such
opportunity. If any business opportunity to acquire general
partner interests and other related equity securities in a
publicly traded partnership is presented, then Enterprise GP
Holdings will have the right to pursue such opportunity before
Enterprise Products Partners is given the opportunity to pursue
it for itself or to direct it to us. Accordingly, we will be
limited by contract in our ability to take certain business
opportunities for our partnership. Please read “Conflicts
of Interest, Business Opportunity Agreements and Fiduciary
Duties.”
Our
general partner and its affiliates own a controlling interest in
us and have conflicts of interest and limited fiduciary duties,
which may permit them to favor their own interests to your
detriment.
Following the offering, Enterprise Products OLP will own
indirectly a 2% general partner interest and directly
approximately 36.0% of our outstanding common units (or
approximately 26.4% of our outstanding common units if the
underwriters’ option to purchase additional common units is
exercised in full) and will own and control our general partner,
which controls us. Although our general partner has a fiduciary
duty to manage us in a manner beneficial to us and our
unitholders, the directors and officers of our general partner
have a fiduciary duty to manage it and our general partner in a
manner beneficial to Enterprise Products Partners and its
affiliates. Furthermore, certain directors and officers of our
general partner may be directors or officers of affiliates of
our general partner. Conflicts of interest may arise between
Enterprise Products Partners and its affiliates, including our
general partner, on the one hand, and us and our unitholders, on
the other hand. As a result of these conflicts, our general
partner may favor its own interests and the interests of its
affiliates over the interests of our unitholders. Please read
“— Our partnership agreement limits our general
partner’s fiduciary duties to unitholders and restricts the
remedies available to unitholders for actions taken by our
general partner that might otherwise constitute breaches of
fiduciary duty.” These potential conflicts include, among
others, the following situations:
•
Enterprise Products Partners, EPCO and their affiliates may
engage in substantial competition with us on the terms set forth
in an amended and restated administrative services agreement.
Please read “— Enterprise Products Partners, EPCO
and their affiliates may engage in competition with us, and
business opportunities may be directed by contract to those
affiliates prior to us under an amended and restated
administrative services agreement.”
•
Neither our partnership agreement nor any other agreement
requires EPCO, Enterprise Products Partners, Enterprise GP
Holdings and TEPPCO Partners or their affiliates (other than our
general partner) to pursue a business strategy that favors us.
Directors and officers of EPCO and the general partners of
Enterprise Products Partners, Enterprise GP Holdings and TEPPCO
Partners and their affiliates have a fiduciary duty to make
decisions in the best interest of their shareholders or
unitholders, which may be contrary to our interests.
•
Our general partner is allowed to take into account the
interests of parties other than us, such as EPCO, Enterprise
Products Partners, Enterprise GP Holdings and TEPPCO Partners
and their affiliates, in resolving conflicts of interest, which
has the effect of limiting its fiduciary duty to our unitholders.
•
Some of the officers of EPCO who provide services to us also may
devote significant time to the business of Enterprise Products
Partners, Enterprise GP Holdings and TEPPCO Partners, and will
be compensated by EPCO for such services.
•
Our partnership agreement limits the liability and reduces the
fiduciary duties of our general partner, while also restricting
the remedies available to our unitholders for actions that,
without these limitations, might constitute breaches of
fiduciary duty. By purchasing common units, unitholders will
be deemed to have consented to some actions and conflicts of
interest that might otherwise constitute a breach of fiduciary
or other duties under applicable law.
•
Our general partner determines the amount and timing of asset
purchases and sales, operating expenditures, capital
expenditures, borrowings, repayments of indebtedness, issuances
of additional partnership securities and cash reserves, each of
which can affect the amount of cash that is available for
distribution to our unitholders.
•
Our general partner determines which costs, including allocated
overhead, incurred by it and its affiliates are reimbursable by
us.
•
Enterprise Products Partners or TEPPCO Partners may propose to
contribute additional assets to us and, in making such proposal,
the directors of those entities have a fiduciary duty to their
unitholders and not to our unitholders.
•
Our partnership agreement does not restrict our general partner
from causing us to pay it or its affiliates for any services
rendered on terms that are fair and reasonable to us or entering
into additional contractual arrangements with any of these
entities on our behalf.
•
Our general partner intends to limit its liability regarding our
contractual obligations.
•
Our general partner may exercise its rights to call and purchase
all of our common units if at any time it and its affiliates own
80% or more of the outstanding common units.
•
Our general partner controls the enforcement of obligations owed
to us by it and its affiliates, including the administrative
services agreement.
•
Our general partner decides whether to retain separate counsel,
accountants or others to perform services for us.
Please read “Certain Relationships and Related Party
Transactions” and “Conflicts of Interest, Business
Opportunity Agreements and Fiduciary Duties.”
We may
be limited in our ability to consummate transactions, including
acquisitions with affiliates of our general
partner.
We will have inherent conflicts of interest with affiliates of
our general partner, including Enterprise Products Partners and
TEPPCO Partners. These conflicts may cause the audit and
conflicts committees of these entities not to approve, or
unitholders of these entities to dispute, any transactions that
may be proposed or consummated between or among us and these
affiliates. This may inhibit or prevent us from consummating
transactions, including acquisitions, with them.
We do
not have any officers or employees and rely solely on officers
of our general partner and employees of EPCO and its
affiliates.
Certain of the executive officers and directors of our general
partner are also officers and/or directors of EPCO, the general
partner of Enterprise GP Holdings, the general partner of
Enterprise Products Partners, the general partner of TEPPCO or
other affiliates of EPCO. These relationships may create
conflicts of interest regarding corporate opportunities and
other matters. The resolution of any such conflicts may not
always be in our or our unitholders’ best interests. In
addition, these overlapping executive officers and directors
allocate their time among EPCO, Enterprise GP Holdings,
Enterprise Products Partners, TEPPCO Partners, us and other
affiliates of EPCO. These officers and directors face potential
conflicts regarding the allocation of their time, which may
adversely affect our business, results of operations and
financial condition.
An
affiliate of Enterprise Products Partners will have the power to
appoint and remove our directors and management.
Because Enterprise Products OLP owns 100% of DEP Holdings, it
will have the ability to elect all the members of the board of
directors of our general partner. Our general partner will have
control over all
decisions related to our operations. Furthermore, the goals and
objectives of Enterprise Products OLP relating to us may not be
consistent with those of a majority of the public unitholders.
Our
general partner has a limited call right that may require you to
sell your common units at an undesirable time or
price.
If at any time our general partner and its affiliates own 80% or
more of the outstanding common units, our general partner will
have the right, which it may assign to any of its affiliates or
to us, but not the obligation, to acquire all, but not less than
all, of the common units held by unaffiliated persons at a price
equal to the greater of:
•
the average of the daily closing prices of the common units over
the 20 trading days preceding the date three days before notice
of exercise of the call right is first mailed and
•
the highest price paid by our general partner or any of its
affiliates for common units during the
90-day
period preceding the date such notice is first mailed.
As a result, you may be required to sell your common units at a
price that is less than the initial offering price in this
offering or, because of the manner in which the purchase price
is determined, at a price less than the then current market
price of the common units. In addition, this call right may be
exercised at an otherwise undesirable time or price and you may
not receive any return on your investment. You may also incur a
tax liability upon a sale of your common units. Our general
partner is not obligated to obtain a fairness opinion regarding
the value of the common units to be repurchased by it upon
exercise of the call right. There is no restriction in our
partnership agreement that prevents our general partner from
issuing additional common units or other equity securities and
exercising its call right. If our general partner exercised its
call right, the effect would be to take us private and, if the
common units were subsequently deregistered, we might no longer
be subject to the reporting requirements of the Securities
Exchange Act of 1934, as amended, or the Exchange Act. Following
this offering, affiliates of our general partner will own
approximately 36.0% of the outstanding common units
(approximately 26.4% of the outstanding common units if the
underwriters exercise their option to purchase additional common
units in full).
For additional information about the call right, please read
“Description of Material Provisions of Our Partnership
Agreement — Limited Call Right.”
Our
partnership agreement limits our general partner’s
fiduciary duties to unitholders and restricts the remedies
available to unitholders for actions taken by our general
partner that might otherwise constitute breaches of fiduciary
duty.
Our partnership agreement contains provisions that reduce the
standards to which our general partner would otherwise be held
by state fiduciary duty law. For example, our partnership
agreement:
•
permits our general partner to make a number of decisions in its
individual capacity, as opposed to in its capacity as our
general partner. This entitles our general partner to consider
only the interests and factors that it desires, and it has no
duty or obligation to give any consideration to any interest of,
or factors affecting, us, our affiliates or any limited partner.
Examples include the exercise of its limited call right, its
rights to vote or transfer the common units it owns, its
registration rights and the determination of whether to consent
to any merger or consolidation of the partnership or amendment
to the partnership agreement;
•
provides in the absence of bad faith by the audit and conflicts
committee or our general partner, the resolution, action or
terms made, taken or provided in connection with a potential
conflict of interest transaction will be conclusive and binding
on all persons (including all partners) and will not constitute
a breach of the partnership agreement or any standard of care or
duty imposed by law;
•
provides the general partner shall not be liable to the
partnership or any partner for its good faith reliance on the
provisions of the partnership agreement to the extent it has
duties, including fiduciary duties, and liabilities at law or in
equity;
generally provides that affiliate transactions and resolutions
of conflicts of interest not approved by the audit and conflicts
committee of the board of directors of our general partner must
be on terms no less favorable to us than those generally
provided to or available from unrelated third parties or be
“fair and reasonable” to us;
•
provides that it shall be presumed that the resolution of any
conflicts of interest by our general partner or the audit and
conflicts committee was not made in bad faith, and in any
proceeding brought by or on behalf of any limited partner or us,
the person bringing or prosecuting such proceeding will have the
burden of overcoming such presumption; and
•
provides that our general partner and its officers and directors
will not be liable for monetary damages to us or our limited
partners for any acts or omissions unless there has been a final
and non-appealable judgment entered by a court of competent
jurisdiction determining that the general partner or those other
persons acted in bad faith or engaged in fraud or willful
misconduct or, in the case of a criminal matter, acted with
knowledge that the conduct was criminal.
By purchasing a common unit, a unitholder will become bound by
the provisions of our partnership agreement, including the
provisions described above. Please read “Description of Our
Common Units — Transfer of Units.”
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.
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
will have no right to elect our general partner or its board of
directors on an annual or other continuing basis. The board of
directors of our general partner, including the independent
directors, is chosen entirely by its owners and not by the
unitholders. Furthermore, even if our unitholders were
dissatisfied with the performance of our general partner, they
will, practically speaking, have no ability to remove our
general partner. As a result of these limitations, the price at
which the common units will trade could be diminished because of
the absence or reduction of a control premium in the trading
price.
The vote of the holders of at least
662/3%
of all outstanding common units is required to remove our
general partner. Following the closing of this offering,
Enterprise Products Partners and its affiliates will own
approximately 36.0% of our outstanding common units (or
approximately 26.4% of our outstanding common units if the
underwriters exercise their option to purchase additional common
units in full).
You
will experience immediate and substantial dilution of
$5.64 per unit.
The assumed initial public offering price of $20.00 per
unit exceeds the pro forma net tangible book value of
$14.36 per common unit. Based on this assumed initial
public offering price, you will incur immediate and substantial
dilution of $5.64 per unit. This dilution results primarily
because the assets sold and contributed by our general partner
and its affiliates are recorded at their historical cost, and
not their fair value, in accordance with GAAP. Please read
“Dilution.”
We may
issue additional units without your approval, which would dilute
your ownership interests.
At any time, we may issue an unlimited number of limited partner
interests of any type without the approval of our unitholders.
Our partnership agreement does not give our unitholders the
right to approve our issuance of equity securities ranking
junior to the common units at any time. In addition, our
partnership agreement does not prohibit the issuance by our
subsidiaries of equity securities, which may effectively rank
senior to the common units.
The issuance by us of additional common units or other equity
securities will have the following effects:
•
the ownership interest of unitholders immediately prior to the
issuance will decrease;
•
the amount of cash distributions on each common unit may
decrease;
the relative voting strength of each previously outstanding
common unit may be diminished;
•
the ratio of taxable income to distributions may
increase; and
•
the market price of the common units may decline.
Our
partnership agreement restricts the voting rights of unitholders
owning 20% or more of our common units.
Our partnership agreement restricts unitholders’ voting
rights by providing that any common units held by a person that
owns 20% or more of any class of units then outstanding, other
than our general partner, its affiliates, their transferees and
persons who acquired such units with the prior approval of the
board of directors of our general partner, cannot vote on any
matter. Our partnership agreement also contains provisions
limiting the ability of common unitholders to call meetings or
to acquire information about our operations, as well as other
provisions limiting common unitholders’ ability to
influence the manner or direction of management.
We
have a holding company structure in which our subsidiaries
conduct our operations and own our operating assets, which may
affect our ability to make distributions to you.
We are a partnership holding company and our operating
subsidiaries conduct all of our operations and own all of our
operating assets. We have no significant assets other than the
ownership interests in our subsidiaries and joint ventures. As a
result, our ability to make distributions to our unitholders
depends on the performance of our subsidiaries and joint
ventures and their ability to distribute funds to us. 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.
Affiliates of Enterprise Products Partners currently own a
minority equity interest in all of our subsidiaries and will
have a right of first refusal to acquire these subsidiaries or
their material assets if we desire to sell them, other than
inventory and other assets sold in the ordinary course of
business. These rights may adversely affect our ability to
dispose of these assets. In addition, our ownership interest in
Mont Belvieu Caverns may be diluted, and the cash flow from
our NGL & Petrochemical Storage Services segment may be
reduced, if we do not contribute our proportionate share of any
future costs to fund expansion projects at Mont Belvieu Caverns.
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 common units and other
limited partner interests may decrease in direct correlation
with decreases in the amount we distribute per common unit.
Accordingly, if we experience a liquidity problem in the future,
we may not be able to issue more equity to recapitalize.
Cost
reimbursements to EPCO and its affiliates will reduce cash
available for distribution to you.
Prior to making any distribution on the common units, we will
reimburse EPCO and its affiliates 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. Please
read “Cash Distribution Policy and Restrictions on
Distributions,”“Certain Relationships and Related
Party Transactions” and “Conflicts of Interest,
Business Opportunity Agreements and Fiduciary Duties —
Conflicts of Interest and Business Opportunity Agreements.”
The
payment of these amounts, including allocated overhead, to EPCO
and its affiliates could adversely affect our ability to make
distributions to you.
Unitholders
may not have limited liability if a court finds that unitholder
action constitutes control of our business.
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.
Please read “Description of Material Provisions of Our
Partnership Agreement — Limited Liability” for a
discussion of the implications of the limitations of liability
on a unitholder.
Unitholders
may have liability to repay distributions.
Under certain circumstances, 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 you
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 may transfer its general partner interest to
a third party in a merger or in a sale of all or substantially
all of its assets without the consent of the unitholders.
Furthermore, there is no restriction in our partnership
agreement on the ability of DEP Holdings or Enterprise Products
OLP to transfer their equity interests in our general partner or
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.
There
is no existing market for our common units, and a trading market
that will provide you with adequate liquidity may not
develop.
Prior to this offering, there has been no public market for the
common units. After this offering, there will be 13,000,000
publicly traded common units, assuming no exercise of the
underwriters’ option to purchase additional common units.
We do not know the extent to which investor interest will lead
to the development of a trading market or how liquid that market
might be. You may not be able to resell your common units at or
above the initial public offering price. Additionally, the lack
of liquidity may result in wide bid-ask spreads, contribute to
significant fluctuations in the market price of the common units
and limit the number of investors who are able to buy the common
units.
The initial public offering price for the common units will be
determined by negotiations between us and the representatives of
the underwriters and may not be indicative of the market price
of the common units that will prevail in the trading market. The
market price of our common units may decline below the initial
public offering price.
You should read “Material Tax Consequences” for a more
complete discussion of the expected material federal income tax
consequences of owning and disposing of common units.
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 IRS 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 distributions to you would be
substantially reduced.
The anticipated after-tax benefit of an investment in the 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 IRS on this or any other
matter affecting us.
If we were treated as a corporation for federal income tax
purposes, we would pay federal income tax on our income at the
corporate tax rate, which is currently a maximum of 35%.
Distributions to you would generally be taxed again as corporate
distributions, and no income, gains, losses, deductions or
credits would flow through to you. Because a tax would be
imposed upon us as a corporation, our cash available for
distribution to you would be substantially reduced. Thus,
treatment of us as a corporation would result in a material
reduction in the anticipated cash flow and after-tax return to
you, likely causing a substantial reduction in the value of the
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, our operating
subsidiaries will be subject to a newly revised Texas franchise
tax (the “Texas Margin Tax”) on the portion of their
revenue that is generated in Texas beginning for tax reports due
on or after January 1, 2008. Specifically, the Texas Margin
Tax will be 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 a tax upon us
or the operating subsidiaries as an entity, the cash available
for distribution to you would be reduced.
If the
IRS contests the federal income tax positions we take, the
market for our common units may be adversely impacted, and the
costs of any contest will reduce our cash distributions to
you.
We have not requested any ruling from the IRS with respect to
our treatment as a partnership for federal income tax purposes
or any other matter affecting us. The IRS may adopt positions
that differ from our counsel’s conclusions expressed in
this prospectus. It may be necessary to resort to administrative
or court proceedings to sustain some or all of our
counsel’s conclusions or the positions we take. A court may
not agree with some or all of our counsel’s conclusions or
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 they trade. In addition, because the costs of any
contest with the IRS will be borne indirectly by our unitholders
and our general partner, any such contest will result in a
reduction in cash available for distribution.
You
may be required to pay taxes on your share of our income even if
you do not receive any cash distributions from us.
You will be required to pay federal income taxes and, in some
cases, state and local income taxes on your share of our taxable
income, whether or not you receive cash distributions from us.
You may not receive cash distributions from us equal to your
share of our taxable income or even equal to the actual tax
liability that results from your share of our taxable income.
Tax
gain or loss on the disposition of our common units could be
different than expected.
If you sell your common units, you will recognize gain or loss
equal to the difference between the amount realized and your tax
basis in those common units. Prior distributions to you in
excess of the total net taxable income you were allocated for a
common unit, which decreased your tax basis in that common unit,
will, in effect, become taxable income to you if the common unit
is sold at a price greater than your tax basis in that common
unit, even if the price you receive is less than your original
cost. A substantial portion of the amount realized, whether or
not representing gain, may be ordinary income to you.
Tax-exempt
entities and foreign persons face unique tax issues from owning
common units that may result in adverse tax consequences to
them.
Investment in common units by tax-exempt entities, such as
individual retirement accounts (“IRAs”), other
retirement plans, and
non-U.S. persons
raises issues unique to them. For example, virtually all of our
income allocated to organizations that are exempt from federal
income tax, including IRAs 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 tax returns and
pay tax on their share of our taxable income. If you are a
tax-exempt entity or a
non-U.S. person
you should consult your tax advisor before investing in our
common units.
We
will treat each purchaser of common units as having the same tax
benefits without regard to the common units purchased. The IRS
may challenge this treatment, which could result in a decrease
in the value of the common units.
Because we cannot match transferors and transferees of common
units, we will adopt depreciation and amortization positions
that may not conform with all aspects of existing Treasury
regulations. A successful IRS challenge to those positions could
decrease the amount of tax benefits available to you. It also
could affect the timing of these tax benefits or the amount of
gain from your sale of common units and could have a negative
impact on the value of our common units or result in audit
adjustments to your tax returns. Please read “Material Tax
Consequences — Uniformity of Units” for a further
discussion of the effect of the depreciation and amortization
positions we will adopt.
The
sale or exchange of 50% or more of our capital and profits
interests will result in the termination of our partnership for
federal income tax purposes.
We will be considered to have terminated for federal income tax
purposes if there is a sale or exchange of 50% or more of the
total interests in our capital and profits within a twelve month
period. Our termination would, among other things, result in the
closing of our taxable year for all unitholders and could result
in a deferral of depreciation deductions allowable in computing
our taxable income. Please read “Material Tax
Consequences — Disposition of Common Units —
Constructive Termination” for a discussion of the
consequences of our termination for federal income tax purposes.
You
may be subject to state and local taxes and return filing
requirements as a result of investing in our common
units.
In addition to federal income taxes, you will likely be subject
to other taxes, such as 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. You may 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, you may be subject to penalties for failure to comply
with those requirements. We will initially own property or
conduct business in Louisiana and Texas. We may own property or
conduct business in other states or foreign countries in the
future. It is your responsibility to file all federal, state and
local tax returns. Our counsel has not rendered an opinion on
the state and local tax consequences of an investment in our
common units.
We expect to receive net proceeds from this offering of
approximately $243.4 million (based on an assumed offering
price of $20.00 per unit), after deducting underwriting
discounts and commissions and a $1.0 million structuring
fee, but before estimated net expenses associated with the
offering and related formation transactions.
We intend to use the net proceeds from this offering to:
•
distribute approximately $212.3 million to Enterprise
Products OLP as a portion of the cash consideration and
reimbursement for capital expenditures relating to the assets
contributed to us;
•
provide approximately $28.2 million to fund our
66% share of estimated capital expenditures to complete
planned expansions to the South Texas NGL pipeline system and
brine production and above-ground storage projects at Mont
Belvieu subsequent to the closing of this offering; and
•
pay approximately $2.9 million of other estimated net
expenses associated with this offering and related formation
transactions described on page 2.
The portion of net proceeds that we retain to fund planned
expansions (and the amount that we plan to distribute to
Enterprise Products OLP) assumes that, prior to the closing date
of this offering, South Texas NGL and Mont Belvieu Caverns will
have recorded $59 million of a total estimated additional
cost of $101.7 million to complete our acquisition and
construction of the South Texas NGL pipeline system and our
completion of brine production and above-ground storage projects
at Mont Belvieu. The amounts actually distributed or retained at
the closing of this offering will be increased or decreased by
an amount equal to 66% of the difference between:
(1) $101.7 million (the estimated total additional
costs); and
(2)
the actual construction and acquisition costs paid with respect
to (i) the South Texas NGL pipeline (excluding the original
pipeline purchase costs of approximately $97.7 million) and
(ii) the Mont Belvieu brine production and above-ground
storage projects, prior to the contribution of interests in
South Texas NGL and Mont Belvieu Caverns to us at the closing of
this offering.
Of the $59 million in total estimated costs noted above, as
of December 31, 2006, we had recorded $19.6 million of
the estimated additional costs for construction and acquisition
of the South Texas NGL pipeline system and $21.3 million of
the estimated additional costs related to the Mont Belvieu brine
production and above-ground storage projects.
If the offering price is more or less than the assumed
$20.00 per unit price, the amount that we will actually
distribute to Enterprise Products OLP will also be increased or
decreased by all of the difference in such net proceeds from
this offering.
Concurrently with the closing of this offering, we will also
borrow approximately $200 million under our new
$300 million credit agreement. We will distribute
$198.9 million of these borrowings to Enterprise Products
OLP in partial consideration for the assets contributed to us
upon the closing of this offering. For a description of our
credit agreement, please read “Management’s Discussion
and Analysis of Financial Condition and Results of
Operations — Liquidity and Capital
Resources — New Revolving Credit Facility.”
If the underwriters exercise their option to purchase additional
common units, we will use all of the net proceeds from the sale
of those common units to redeem an equal number of common units
from Enterprise Products OLP, which may be deemed a selling
unitholder in this offering. Please read “Selling
Unitholder” and “Security Ownership of Certain
Beneficial Owners and Management.”
the cash and capitalization of our predecessor, Duncan Energy
Partners Predecessor, as of September 30, 2006 on a
combined historical basis;
•
our pro forma cash and capitalization as of September 30,2006, after, giving effect to:
•
the August 2006 purchase of a pipeline by Enterprise Products
Partners for approximately $97.7 million in cash, the
subsequent contribution of this pipeline to South Texas NGL and
the payment of estimated additional costs of $37.7 million
required to modify this pipeline and to acquire and construct
additional pipelines in order to place this pipeline system into
operation in January 2007;
•
the payment of estimated additional costs of $21.3 million
required to expand our Mont Belvieu brine production capacity
and above-ground storage reservoirs;
•
the contribution of a 66% interest in certain entities which are
wholly-owned subsidiaries of Enterprise Products Partners, and
the retention by Enterprise Products Partners of a 34% interest
in these entities;
•
the revision of related party storage contracts between us and
Enterprise Products Partners to (1) increase certain
storage fees paid by Enterprise Products Partners and
(2) reflect the allocation to Enterprise Products Partners
of all storage measurement gains and losses relating to products
under these agreements, and the execution of a limited liability
company agreement for Mont Belvieu Caverns providing for the
special allocation and other agreements relating to other
measurement gains and losses to Enterprise Products
Partners; and
•
the assignment to us of certain third-party agreements that
effectively reduce tariff rates received by us for the transport
of propylene volumes; and
•
our unaudited pro forma, as adjusted cash and capitalization as
of September 30, 2006, after giving effect to the
transactions described above, this offering, the borrowing of
approximately $200 million under a new $300 million
credit agreement by us in connection with our acquisition of
ownership interests in our subsidiaries from Enterprise Products
Partners, and the application of the net proceeds from this
offering and the borrowings as described under “Use of
Proceeds.”
This table is derived from, and should be read together with,
the historical combined financial statements of Duncan Energy
Partners Predecessor and our unaudited pro forma condensed
combined financial information included elsewhere in this
prospectus. You should also read this table in conjunction with
“Summary — Duncan Energy Partners
L.P. — Formation Transactions,”“Use of
Proceeds,” and “Management’s Discussion and
Analysis of Financial Condition and Results of Operations”
included elsewhere in this prospectus.
Represents cash retained for our 66% share of estimated 2007
capital expenditures to complete planned expansions of our South
Texas NGL pipeline and Mont Belvieu brine-related facilities.
Dilution is the amount by which the offering price paid by
purchasers of our common units sold in this offering will exceed
the pro forma net tangible book value per common unit after the
offering. Assuming an initial public offering price of
$20.00 per common unit, on a pro forma basis as of
September 30, 2006, after giving effect to the offering of
13,000,000 common units, our net tangible book value was
$297.5 million, or $14.36 per common unit. This amount
includes equity from new investors of $240.5 million and
the parent’s interest in common units and the general
partner interest of $61.6 million less the
Partnership’s 66% share of intangible assets. Purchasers of
our common units in this offering will experience substantial
and immediate dilution in net tangible book value per common
unit for financial accounting purposes, as illustrated in the
following table.
Assumed initial public offering
price per common unit
$
20.00
Pro forma net tangible book value
per common unit before the offering(1)
$
60.68
Decrease in net tangible book
value per common unit attributable to purchasers in the offering
46.32
Less: Pro forma net tangible book
value per common unit after the offering(2)
14.36
Immediate dilution in net tangible
book value per common unit to purchasers in the offering
$
5.64
(1)
Determined by dividing the net tangible book value of the
contributed net assets of $468.2 million, net of subsidiary
ownership interests retained by parent of $243.6 million,
by the number of common units (7,301,571 common units and the 2%
general partner interest, which has a dilutive effect equivalent
to 414,318 common units) to be issued to our general partner and
its affiliates for their contribution of assets and liabilities
to us. Our general partner’s dilutive effect equivalent was
determined by multiplying the total number of common units
deemed to be outstanding (i.e., the total number of common units
outstanding of 20,301,571 divided by 98%) by our general
partner’s 2% general partner interest.
(2)
Determined by dividing our pro forma net tangible book value of
$297.5 million, which reflects the application of the
assumed net proceeds of this offering, by the total number of
common units (20,301,571 common units and the 2% general partner
interest, which has a dilutive effect equivalent to 414,318
common units) to be outstanding after the offering. The
following table shows our calculation of pro forma net
tangible book value (dollars in thousands):
Pro forma net book value,
including Parent interest
$
302,155
Less: 66% share of intangible
assets attributable to parent’s interest in common units
and the general partner interest and new investors
(4,636
)
Pro forma net tangible book value,
including Parent interest
$
297,519
The following table sets forth the number of common units that
we will issue and the total consideration contributed to us by
our general partner and its affiliates and by the purchasers of
common units in this offering (dollars in thousands):
Common Units
Total
Acquired
Consideration
Number
Percent
Amount
Percent
Parent’s interest in common
units and general partner interest (1)(2)
7,715,889
37.2
%
$
61,635
20.4
%
New investors
13,000,000
62.8
%
240,520
79.6
%
Total
20,715,889
100.0
%
$
302,155
100.0
%
(1)
Upon the consummation of this offering, Enterprise Products OLP
and our general partner will own an aggregate of 7,301,571
common units and a 2% general partner interest having a dilutive
effect equivalent to 414,318 common units.
The assets contributed by Enterprise Products OLP were recorded
at historical cost in accordance with GAAP. Book value of the
consideration provided by our general partner and Enterprise
Products OLP, as of September 30, 2006, after giving effect
to the application of the net proceeds of the offering and the
retention of a 34% equity interest in the contributed
subsidiaries is as follows (dollars in thousands):
Pro forma owners’ net
investment
$
716,465
Less: Payment to Parent from the
net proceeds of the offering and borrowings under the credit
agreement
(411,232
)
Less: Parent retention of 34% of
the equity interests in contributed subsidiaries of the
Partnership
(243,598
)
Total consideration for
Parent’s interest in common units and general partner
interest
$
61,635
For financial reporting purposes, the parent’s retained
interest in the subsidiaries of $243.6 million and the
carryover basis in the common units and the general partner
interest as part of this offering is presented outside the
Partnership equity from the new public investors.
You should read the following discussion of our cash
distribution policy in conjunction with the specific assumptions
included in this section. For detailed information regarding the
factors and assumptions upon which our cash distribution policy
is based, please read “— Assumptions and
Considerations” below. In addition, you should read
“Forward-Looking Statements” and “Risk
Factors” for information regarding statements that do not
relate strictly to historical or current facts and certain risks
inherent in our business.
For additional information regarding our historical and pro
forma financial information, you should refer to the audited
historical combined financial statements of Duncan Energy
Partners Predecessor for the years ended December 31, 2003,
2004 and 2005 and the nine months ended September 30, 2006,
our unaudited historical financial statements for the nine
months ended September 30, 2005, and our unaudited pro
forma condensed combined financial information at
September 30, 2006 and for the year ended December 31,2005 and nine months ended September 30, 2006 included
elsewhere in this prospectus.
Our partnership agreement requires us to distribute all of our
available cash on a quarterly basis. Available cash is defined
to mean generally, for each fiscal quarter, all cash and cash
equivalents on the date of determination of available cash for
such quarter, less the reserves that our general partner
determines are necessary or appropriate to provide for the
conduct of our business, to comply with applicable law, any of
our debt instruments or other agreements or to provide for
future distributions to our unitholders for any one or more of
the upcoming four quarters. We intend to fund a portion of our
capital expenditures with additional borrowings under our new
revolving credit facility or the issuance of additional units.
We may also borrow to make distributions to unitholders, for
example, in circumstances where we believe that the distribution
level is sustainable over the long term, but short-term factors
have caused available cash from operations to be insufficient to
pay the distribution at the current level. Our partnership
agreement will not restrict our ability to borrow to pay
distributions. It is the current policy of the board of
directors of our general partner, however, that we should
maintain or increase our level of quarterly cash distributions
only when, in its judgment, we can sustain such distribution
levels over a long-term period. Our cash distribution policy
reflects a basic judgment that our unitholders will be better
served by us distributing our available cash, after expenses and
reserves, rather than retaining it. Also, because we are not
subject to an entity-level federal income tax, we have more cash
to distribute to you than would be the case if we were subject
to federal income tax.
Restrictions
and Limitations on Cash Distributions and Our Ability to Change
Our Cash Distribution Policy
There is no guarantee that unitholders will receive quarterly
distributions from us. Our distribution policy is subject to
certain restrictions and may be changed at any time, including:
•
Our cash distribution policy will be subject to restrictions on
distributions under our new credit facility. Specifically, our
revolving credit facility contains certain material financial
tests, such as a Consolidated Debt to Consolidated EBITDA ratio,
or leverage ratio, not to exceed 4.75 to 1.00 and a Consolidated
EBITDA to Consolidated Interest Expense ratio, or interest
coverage ratio, of not less than 2.75 to 1.00, and other
covenants that we must satisfy. Should we be unable to satisfy
these restrictions under our revolving credit facility, or if we
otherwise default under our revolving credit facility, we would
be prohibited from making a distribution to you notwithstanding
our stated cash distribution policy. These financial tests and
covenants are described in the prospectus under the caption
“Management’s Discussion and Analysis of Financial
Condition and Results of Operations — Liquidity and
Capital Resources — New Revolving Credit
Facility.”
•
Our general partner will have the authority to establish cash
reserves for the prudent conduct of our business and for future
cash distributions to our unitholders, and the establishment of
those reserves
could result in a reduction in cash distributions to you from
levels we currently anticipate pursuant to our stated cash
distribution policy. Any determination to establish reserves
made by our general partner in the absence of bad faith will be
binding on the unitholders. Over a period of time, if we do not
set aside sufficient cash reserves or make sufficient cash
expenditures to maintain our asset base, we will be unable to
pay distributions at the current level from cash generated from
operations and would therefore expect to reduce our
distributions. We will not be able to increase our current level
of distributions without making accretive acquisitions or
capital expenditures that grow our asset base. A significant
decrease in throughput volumes or in the demand for or
production of hydrocarbon products from current levels would
adversely affect our ability to pay distributions. If our asset
base decreases and we do not reduce our distributions, a portion
of the distributions you receive may be considered a return of
part of your investment in us as opposed to a return on your
investment.
•
While our partnership agreement requires us to distribute all of
our available cash, our partnership agreement, including our
cash distribution policy contained therein, may be amended with
the consent of the general partner and a vote of the holders of
a majority of our common units. Following completion of this
offering, our public unitholders will own 64.0% of our common
units and Enterprise Products Partners (our parent and sponsor)
will own the remainder.
•
Even if our cash distribution policy is not amended, modified or
revoked, the amount of distributions we pay under our cash
distribution policy and the decision to make any distribution is
determined by our general partner, taking into consideration the
terms of our partnership agreement. Enterprise Products OLP owns
our general partner.
•
Under
Section 17-607
of the Delaware Revised Uniform Limited Partnership Act, we may
not make a distribution to our partners if the distribution
would cause our liabilities to exceed the fair value of our
assets.
We may lack sufficient cash to pay distributions to our
unitholders due to a number of factors, including:
•
A reduction in throughput volumes on our pipelines would
decrease our cash receipts from pipeline transportation
revenues, which would reduce cash available to pay distributions.
•
An increase in operating expenses, general and administrative
costs and state and federal income taxes would increase our cash
outlays for such items, which would reduce cash available to pay
distributions.
•
Principal repayments (to the extent not refinanced) and interest
payments on any current or future debt would generally be made
from cash generated by operating activities, which would reduce
cash available to pay distributions.
•
Capital expenditures reduce cash available to pay distributions
to the extent such amounts are funded from cash generated by
operating activities.
•
To the extent not funded by borrowings under our revolving
credit facility, working capital needs for such items as
inventory or prepaid items reduce cash available to pay
distributions.
Please read “Risk Factors” for additional discussion
of these factors.
Our
Ability to Grow Depends on Our Ability to Access External Growth
Capital
Our partnership agreement requires us to distribute all of our
available cash to our unitholders. As a result, we expect to
rely primarily upon external financing sources, including
commercial bank borrowings and the issuance of debt and equity
securities, to fund acquisition capital expenditures. To the
extent we are unable to finance growth externally, our cash
distribution policy will significantly impair our ability to
grow. To the extent we issue additional units in connection with
any acquisitions or other capital expenditures, the payment of
distributions on those additional units may increase the risk
that we will be unable to maintain or increase our per unit
distribution level, which in turn may impact the available cash
that we have to distribute on each unit. There are no
limitations in our partnership agreement or our revolving credit
facility on our ability to issue additional units, including
units ranking senior to the common units. The incurrence of
additional
commercial borrowings or other debt to finance any future growth
would result in increased interest expense, which in turn may
impact the amount of available cash that we have to distribute
to our unitholders.
Upon completion of this offering, the board of directors of our
general partner will adopt a cash distribution policy pursuant
to which we will declare an initial distribution of
$0.40 per unit per quarter (pro rated for the first quarter
during which we are a publicly traded partnership), or
$1.60 per unit per year, to be paid no later than
45 days after the end of each fiscal quarter. This equates
to an aggregate cash distribution of approximately
$8.3 million per quarter, or $33.1 million per year,
based on the units outstanding immediately after completion of
this offering. If the underwriters’ option to purchase
additional units is exercised, an equivalent number of common
units will be redeemed from Enterprise Products OLP.
Accordingly, the exercise of the underwriters’ option to
purchase additional units will not affect the total amount of
units outstanding or the amount of cash needed to pay the
initial distribution rate on all units. Our ability to make cash
distributions at the initial distribution rate pursuant to this
policy will be subject to the factors described above under the
caption “— General — Restrictions
and Limitations on Cash Distributions and Our Ability to Change
Our Cash Distribution Policy.”
As of the date of this offering, our general partner will be
entitled to 2% of all distributions that we make prior to our
liquidation. The general partner’s initial 2% interest in
these distributions may be reduced if we issue additional units
in the future and our general partner does not contribute a
proportionate amount of capital to us to maintain its initial 2%
general partner interest. Our general partner is not obligated
to contribute a proportionate amount of capital to us to
maintain its current general partner interest.
The following table sets forth the estimated aggregate
distribution amounts payable on our common units and general
partner interest during the year following the closing of this
proposed offering at our initial distribution rate of
$0.40 per common unit per quarter (or $1.60 per common
unit on an annualized basis).
Initial Quarterly Distribution
Units
One Quarter
Four Quarters
(Dollars in thousands)
Common units held by parent
(Enterprise Products OLP)
$
2,141
$
8,562
Common units held by public
unitholders (non-parent)
5,980
23,920
General partner interest
166
663
Total
$
8,287
$
33,145
These distributions will not be cumulative. Consequently, if
distributions on our common units are not paid with respect to
any fiscal quarter at the expected initial quarterly
distribution, our unitholders will not be entitled to receive
such payments in the future. We will pay distributions on or
about the 15th of each February, May, August and November
to holders of record on or about the 1st of each such
month. If the distribution date does not fall on a business day,
we will make the distribution on the business day immediately
preceding the indicated distribution date. On or before
May 15, 2007 to the extent we have available cash in
accordance with the terms of our partnership agreement, we will
pay a distribution to our unitholders equal to the initial
quarterly distribution prorated for the portion of the quarter
ending March 31, 2007 that we are public.
We do not have a legal obligation to pay distributions at our
initial distribution rate or at any other rate except as
provided in our partnership agreement. Our distribution policy
is consistent with the terms of our partnership agreement, which
requires that we distribute all of our available cash quarterly.
Under our partnership agreement, available cash is defined to
mean generally, for each fiscal quarter, all cash and cash
equivalents on the date of determination of available cash for
such quarter, less the reserves that our general partner
determines are necessary or appropriate to provide for the
conduct of our business, to comply with applicable law, any of
our debt instruments or other agreements or to provide for
future distributions to our unitholders for any one or more of
the upcoming four quarters.
In the sections that follow, we present in detail the basis for
our belief that we will be able to fully fund our initial
quarterly distribution of $0.40 per common unit per quarter
for the four quarters ending December 31, 2007. In those
sections we present two tables, including:
•
Our “Unaudited Pro Forma Combined Available Cash,” in
which we present the amount of pro forma available cash that we
would have had available for distribution to our limited
partners and parent with respect to the year ended
December 31, 2005 and four quarters ended
September 30, 2006 based on our pro forma financial
statements included in this prospectus. Our calculation of pro
forma available cash in this table should only be viewed as a
general indication of the amount of available cash that we might
have generated had we been in existence in an earlier period.
•
Our “Estimated Cash Available to Pay Distributions,”
in which we present our estimate of available cash to pay
distributions for the four quarters ending December 31,2007, which supports our belief that we will be able to fully
fund our initial annual distribution of $1.60 per common
unit during such period.
If we had completed the transactions contemplated in this
prospectus on January 1, 2005, our pro forma available cash
to pay distributions for the year ended December 31, 2005
would have been $9.9 million. This amount would have been
insufficient by approximately $23.2 million to pay the
initial annual distribution of $33.1 million on all our
common units and general partner interest. Likewise, our pro
forma available cash to pay distributions for the four quarters
ended September 30, 2006 would have been a deficit of
$14.1 million. This amount would have been insufficient by
approximately $47.2 million to pay the initial annual
distribution amount of $33.1 million on all our common
units and general partner interest.
The pro forma financial information does not reflect certain
changes in operating assumptions and expected results that
affect our projections for the four quarters ending
December 31, 2007, including principally:
•
The commencement of operations within our NGL Pipeline Services
segment. The South Texas NGL pipeline became operational in
January 2007 and is expected to generate an additional
$16.4 million of Estimated Consolidated Adjusted EBITDA
during the four quarters ending December 31, 2007. For a
definition of Estimated Consolidated Adjusted EBITDA, please
read “—Estimated Cash Available to Pay
Distributions;” and
•
The funding of growth capital expenditures with sources other
than cash from operations. Because we had no external financing
of capital projects in the year ended December 31, 2005 and
the four quarters ended September 30, 2006, pro forma
available cash was reduced by $19.5 million and
$61.1 million for capital expenditures in those respective
periods. We expect that, in the future, growth capital
expenditures will be funded with sources other than cash from
operations, such as proceeds from this offering, borrowings
under our new revolving credit facility, debt or equity
financings, or contributions from Enterprise Products OLP.
Therefore, we believe that we will have sufficient cash
available to pay quarterly distributions of $0.40 per unit
on all our common units and our general partner interest during
the four quarters ending December 31, 2007. See
“— Assumptions and Considerations” for the
specific assumptions underlying this belief.
The tables used in this section, “Unaudited Pro Forma
Combined Available Cash” and “Estimated Cash Available
to Pay Distributions,” have been prepared by, and are the
responsibility of our management. Our independent registered
public accounting firm has neither examined, compiled or
otherwise applied procedures to such information presented
herein and, accordingly do not express an opinion or any other
form of assurance on such information or its achievability, and
assume no responsibility for, and disclaim any association with
the prospective financial information. Such independent
registered public accounting firm’s reports included
elsewhere in this prospectus relate to the appropriately
described historical financial information. Such reports do not
extend to the tables and related information and should not be
read to do so. In addition, such tables and information were not
prepared with a view toward compliance with published guidelines
of the Securities and Exchange Commission or the guidelines
established by the American Institute of Certified Public
Accountants for preparation and presentation of prospective
financial information, and were not prepared in accordance with
accounting principles generally accepted in the United States of
America nor
The pro forma financial statements, upon which our pro forma
combined available cash for distributions is based, do not
purport to present our results of operations had the
transactions contemplated in this prospectus actually been
completed as of the dates indicated. Furthermore, cash available
for distribution is a cash accounting concept, while our pro
forma financial statements have been prepared on an accrual
basis. We derived the amounts of pro forma combined available
cash for distribution in the manner described in the table
below. As a result, the amount of pro forma combined available
cash for distribution should be viewed as only a general
indication of the amount of cash available for distribution that
we might have generated had we been formed in earlier periods.
The following table illustrates, on a pro forma basis, for the
year ended December 31, 2005 and for the four quarters
ended September 30, 2006, the amount of cash that would
have been available for distribution to the holders of our
common units (including Enterprise Products Partners) and our
general partner assuming that this offering had been consummated
at the beginning of each such period. The pro forma adjustments
in the following table give effect to (i) the contribution
of 66% of the ownership interests in Mont Belvieu Caverns,
Acadian Gas, Sabine Propylene and Lou-Tex Propylene,
(ii) the revision of related party storage contracts with
Enterprise Products Partners, including terms relating to the
allocation of measurement gains and losses, (iii) the
execution of a limited liability company agreement with Mont
Belvieu Caverns providing for special allocations to Enterprise
Products Partners, and (iv) the assignment of certain
third-party propylene transportation agreements, as if they had
occurred at the beginning of the periods presented.
Parent contribution (distribution)
for operating losses(d)
2,122
(49
)
Capital expenditures(i)
(19,472
)
(61,083
)
Pro Forma Combined Available
Cash
$
9,930
$
(14,056
)
Expected Cash
Distributions:
Expected distribution per unit
$
1.60
$
1.60
Distributions to our general
partner
$
663
$
663
Distributions on common units held
by public unitholders (non-parent)
23,920
23,920
Distributions on common units held
by parent
8,562
8,562
Total cash distributions
$
33,145
$
33,145
(Shortfall)
$
(23,215
)
$
(47,201
)
Debt Covenant Ratios
Leverage ratio(j)
5.56
5.07
Interest coverage ratio(j)
2.66
2.91
Notes to “Unaudited Pro Forma Combined Available Cash”
table:
(a)
Reflects historical combined cash provided by operating
activities of Duncan Energy Partners Predecessor for the year
ended December 31, 2005 or derived from such predecessor
information for the four quarters ended September 30, 2006.
(b)
Primarily reflects the historical combined changes in operating
accounts of Duncan Energy Partners Predecessor. Such changes are
generally the result of timing of cash receipts from sales and
cash payments for purchases and other expenses near the end of
each period. We will be able to use borrowings under our new
$300 million revolving credit facility to satisfy
discretionary cash needs for working capital requirements and,
thereby potentially decrease the use of cash flows from
operations to satisfy such
needs. We expect to have $100 million of additional
borrowing capacity under our revolving credit facility
immediately after giving effect to this offering and the
transactions contemplated at the closing. Consequently, we do
not reflect any adjustments to pro forma combined available cash
as a result of working capital components.
(c)
Reflects an increase in related party storage fees charged to
Enterprise Products Partners attributable to its use of the
storage facilities owned by Mont Belvieu Caverns.
(d)
Reflects the allocation to Enterprise Products Partners of
measurement gains and losses relating to products under storage
agreements between Enterprise Products Partners and Mont Belvieu
Caverns and the execution of a limited liability company
agreement with Mont Belvieu Caverns providing for special
allocations to Enterprise Products Partners and other agreements
relating to other measurement gains and losses.
(e)
Reflects a reduction in transportation rates we charge for usage
of the Lou-Tex Propylene and Sabine Propylene pipelines.
(f)
Reflects $2.5 million of our incremental general and
administrative expenses that we expect to incur as a result of
becoming a publicly traded entity. These costs include fees
associated with annual and quarterly reports to unitholders, tax
return and
Schedule K-1
preparation and distribution, investor relations, registrar and
transfer agent fees, incremental insurance costs, accounting and
legal services. These costs also include estimated related party
amounts payable to EPCO in connection with the administrative
services agreement. For additional information regarding the
administrative services agreement, please read “Certain
Relationships and Related Party Transactions —
Administrative Services Agreement.”
(g)
Reflects $13 million of cash interest cost resulting from
an assumed $200 million borrowed at an estimated variable
interest rate of 6.5% per annum under our $300 million
revolving credit facility. If the variable interest rate used to
calculate this interest expense were
1/8%
higher, our annual cash interest cost would increase to
$13.3 million.
(h)
Reflects Enterprise Products Partners contributions to (and
distributions from) subsidiaries. These amounts are net of the
parent’s share of capital expenditures of each subsidiary.
Enterprise Products Partners will own a 34% interest in each of
our subsidiaries and will be allocated a portion of the cash
flows of each subsidiary in accordance with its ownership
percentage. However, the parent’s 34% earnings allocation
with respect to Mont Belvieu Caverns is after a special
allocation by Mont Belvieu Caverns to the parent in an amount
equal to the subsidiary’s net measurement gain or loss each
period. Enterprise Products Partners will receive a cash
distribution from Mont Belvieu Caverns with respect to a net
measurement gain each quarter. Conversely, Enterprise Products
Partners will make a cash contribution to Mont Belvieu Caverns
with respect to a net measurement loss each quarter.
(i)
Reflects actual capital expenditures, net of contributions in
aid of construction costs, for growth and sustaining capital
projects for the periods indicated. The majority of these
capital expenditures were for the construction of additional
brine production capacity at the storage facility owned by Mont
Belvieu Caverns.
(j)
With the exception of meeting the interest coverage ratio for
the pro forma four quarters ending September 30, 2006, we
would not have been in compliance with the expected financial
covenants of our new revolving credit facility. These financial
tests and covenants are described under “Management’s
Discussion and Analysis of Financial Condition and Results of
Operations — Liquidity and Capital
Resources — New Revolving Credit Facility.” The
reason for this compliance shortfall is the lack of pro forma
EBITDA from our South Texas NGL pipeline, which became
operational in January 2007. Prior to the consummation of this
offering, we will enter into a ten-year transportation contract
with Enterprise Products Partners that will include all of the
volumes of NGLs transported on this pipeline system. Please read
“Business — NGL Pipeline Services
Segment — Customer and Related Party Contract”
and “Certain Relationships and Related Party
Transactions — Related Party Transactions with
Enterprise Products Partners.”
In order for us to pay an initial distribution rate of
$0.40 per unit for each quarter in the four quarters ending
December 31, 2007, we must generate at least
$77.1 million in Estimated Consolidated Adjusted EBITDA
during that period. Estimated Consolidated Adjusted EBITDA
should not be viewed as management’s projection of the
actual Consolidated Adjusted EBITDA that we would generate
during the four quarters ending December 31, 2007.
Estimated Consolidated Adjusted EBITDA of $77.1 million is
$23.7 million higher than Pro Forma Consolidated Adjusted
EBITDA for the year ended December 31, 2005 and
$16.3 million higher than Pro Forma Consolidated Adjusted
EBITDA for the four quarters ended September 30, 2006.
Our definition of EBITDA included under
“Summary — Summary Historical and Pro Forma
Financial and Operating Data — Non-GAAP Financial
Measures” differs from “Estimated Consolidated
Adjusted EBITDA.” We define EBITDA as net income or loss
plus interest expense, income taxes, depreciation and
amortization expense. We defined Estimated Consolidated Adjusted
EBITDA as EBITDA before parent interest in earnings. Our
measures of EBITDA and Estimated Consolidated Adjusted EBITDA
should not be considered alternatives to net income, income from
continuing operations, cash flows from operating activities, or
any other measure of financial performance calculated in
accordance with accounting principles generally accepted in the
United States as those items are used to measure operating
performance, liquidity or ability to service debt obligations.
We believe that we will be able to generate sufficient Estimated
Consolidated Adjusted EBITDA to pay our estimated initial
quarterly distribution during each of the four quarters ending
December 31, 2007. In “Assumptions and
Considerations,” we discuss the major assumptions
underlying this belief. We can give you no assurance that our
assumptions will be realized or that we will generate the
Estimated Consolidated Adjusted EBITDA or the expected level of
available cash, in which event we will not be able to pay the
initial quarterly distribution of $1.60 per year on our
units.
When considering our Estimated Consolidated Adjusted EBITDA, you
should keep in mind the risk factors and other cautionary
statements, including those under the headings “Risk
Factors” and “Forward-Looking Statements,”
included in elsewhere in this prospectus. Any of these factors
or the other risks discussed in this prospectus could cause our
financial condition and consolidated results of operations to
vary significantly from those set forth in the table,
“Estimated Cash Available to Pay Distributions.”
As a matter of policy, we do not make public projections
regarding our future sales, earnings, or other results. However,
we have prepared the prospective financial information set forth
below to present the table entitled “Estimated Cash
Available to Pay Distributions.” We do not undertake any
obligation to publicly release the results of any future
revisions we may make to the financial forecast or to update
this financial forecast to reflect events or circumstances after
the date in this prospectus. Therefore, you are cautioned not to
place undue reliance on this information.
In the following table entitled “Estimated Cash Available
to Pay Distributions,” we estimate that our Estimated
Consolidated Adjusted EBITDA will be approximately
$77.1 million for the four quarters ending
December 31, 2007.
Duncan
Energy Partners L.P.
Estimated Cash Available to Pay Distributions
Annualized initial quarterly
distributions per unit
$
1.60
Distributions to our general
partner
$
663
Distributions on common units held
by public unitholders (non-parent)
23,920
Distributions on common units held
by parent
8,562
Total estimated cash distributions
$
33,145
Debt Covenant Ratios
Leverage ratio(d)
4.0
x
Interest coverage ratio(d)
3.9
x
Notes to “Estimated Cash Available to Pay
Distributions” table:
(a)
Reflects $13 million of cash interest cost resulting from
an assumed $200 million borrowed at an estimated variable
interest rate of 6.5% per annum under our new revolving
credit facility. If the variable interest rate used to calculate
this interest expense were 1/8% higher, our annual cash interest
cost would increase to $13.3 million.
(b)
Reflects the cash distributions payable to Enterprise Products
Partners attributable to its interest in our subsidiaries. These
distributions are net of Enterprise Products Partners’
share of projected capital expenditures for each subsidiary.
(c)
In this table, we have included sustaining capital expenditure
estimates for the four quarters ending December 31, 2007.
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
(or sustain) existing operations but do not generate additional
revenues. For purposes of this table, we are assuming that all
of our sustaining capital expenditures for the four quarters
ending December 31, 2007 will be funded with cash flow from
operations. We may, however, borrow under our new revolving
credit facility to fund certain of our sustaining capital
expenditure needs. Borrowings to fund capital expenditures would
result in increased interest expense. This table does not
include $18.9 million net to us for the expansion of the
South Texas NGL pipeline system and $9.3 million net to us
for the expansion of brine production capacity and above-ground
storage reservoirs at Mont Belvieu, which we expect to fund with
proceeds from this offering, any expenditures for the currently
contemplated Mont Belvieu expansion projects, which we expect to
fund with borrowings under our new revolving credit facility,
equity or debt financings, or contributions from Enterprise
Products OLP, or any other growth capital expenditures.
(d)
Based on the terms of our new revolving credit facility, we
believe that we will be in compliance with our financial
covenants during 2007. These financial tests and covenants are
described under “Management’s
Based upon the specific assumptions outlined below with respect
to the four quarters ending December 31, 2007, we expect to
generate cash flow from operations in an amount sufficient to
pay the initial quarterly distribution on all units through
December 31, 2007.
While we believe that these assumptions are reasonable in light
of management’s current expectations concerning future
events, the estimates underlying these assumptions are
inherently uncertain and are subject to significant business,
economic, regulatory, environmental and competitive risks and
uncertainties that could cause actual results to differ
materially from those we anticipate. If our assumptions do not
materialize, the amount of actual cash available to pay
distributions could be substantially less than the amount we
currently estimate and could, therefore, be insufficient to
permit us to pay the full initial quarterly distribution (absent
borrowings under our new revolving credit facility), or any
amount, on all units, in which event the market price of our
units may decline substantially.
Over a period of time, if we do not set aside sufficient cash
reserves or make sufficient cash expenditures to maintain our
asset base, we will be unable to pay distributions at the
current level from cash generated from operations and would
therefore expect to reduce our distributions. We will not be
able to sustain our current level of distributions without
making accretive acquisitions or capital expenditures that
maintain or grow our asset base. Decreases in throughput volumes
or an increase in natural gas prices from current levels will
adversely affect our ability to pay distributions. If our asset
base decreases and we do not reduce our distributions, a portion
of the distributions you receive may be considered a return of
part of your investment in us as opposed to a return on your
investment.
Revenues
The following table shows the selected operating data and
segment revenues that support our Estimated Consolidated
Adjusted EBITDA for the four quarters ending December 31,2007 along with a comparison of historical volumetric and
revenue data underlying our Pro Forma Consolidated Adjusted
EBITDA for the year ended December 31, 2005 and four
quarters ended September 30, 2006.
Operating data presented in the preceding table for the year
ended December 31, 2005 and four quarters ended
September 30, 2006 reflect actual volumes.
(b)
Natural gas throughput represents combined transportation and
sales volumes for the Acadian Gas pipeline system, including our
50% share of Evangeline’s transportation volumes.
Throughput volumes forecast for
2007 on the Acadian Gas system are expected to be
60 billion British thermal units per day, or Bbtu/d, higher
than those posted for the year ended December 31, 2005. The
increase in transportation volumes between the two periods is
primarily due to the addition of new customers and an increase
in transport activity by customers related to pricing
differentials. Throughput volumes for the four quarters ended
December 31, 2007 are based on similar levels realized
during the four quarters ending September 30, 2006.
(c)
The South Texas NGL pipeline became operational in January 2007.
No volumetric data or revenue information is provided for the
year ended December 31, 2005 and four quarters ended
September 30, 2006. The estimated volumes shown in this
table are based on expected production at Enterprise Products
Partners’ Shoup and Armstrong fractionation facilities. We
expect production from these facilities in 2007 to be slightly
higher than production levels in 2006 due to higher processed
gas volumes in the South Texas region.
(d)
We expect petrochemical transportation volumes for the four
quarters ending December 31, 2007 to exceed realized
volumes for the year ended December 31, 2005 and four
quarters ended September 30, 2006. Throughput volumes on
these pipelines were lower following Hurricanes Katrina and Rita
in 2005. The change in revenues between periods is primarily
attributable to the change in volumes.
(e)
The
period-to-period
fluctuation in revenues from our Natural Gas
Pipelines & Services segment is largely due to changes
in the price of natural gas. Revenues from this segment are
primarily generated from the sale of natural gas to customers in
South Louisiana (using industry index prices). The market price
of natural gas, as measured at Henry Hub in Louisiana, averaged
$8.64 per MMBtu and $8.85 per MMBtu for the year ended
December 31, 2005 and four quarters ended
September 30, 2006, respectively. Forecast revenues for the
year ended December 31, 2007 are based on an estimated
natural gas price of $8.20 per MMBtu. As of
December 31, 2006, the Henry Hub spot price for natural gas
was expected (based on an average monthly price of NYMEX futures
for 2007 deliveries) to average $7.07 per MMBtu in 2007.
(f)
Revenues from our NGL & Petrochemical Storage Services
segment for the year ended December 31, 2007 are
$11.4 million higher than those presented for the year
ended December 31, 2005. Revenues for the four quarters
ending December 31, 2007 are $3.3 million higher than
those presented for the four quarters ended September 30,2006. The increase in revenues for the 2007 period relative to
the pro forma periods is primarily due to the renegotiation of
related-party revenue contracts with Enterprise Products
Partners.
Costs
and Expenses
The following table shows the components of costs and expenses
used to determine our Estimated Consolidated Adjusted EBITDA for
the four quarters ending December 31, 2007 along with a
comparison of cost and expense data underlying our Pro Forma
Consolidated Adjusted EBITDA for the year ended
December 31, 2005 and four quarters ended
September 30, 2006.
Pro forma cost and expense data
(dollars in millions):
Cost of natural gas sales(a)
$
836.5
$
920.5
$
706.9
Operating costs and expenses,
excluding non-cash costs(b)
50.0
49.5
59.2
General and administrative costs,
including pro forma incremental public company costs(c)
7.0
5.7
6.5
Total
$
893.5
$
975.7
$
772.6
Notes to “Costs and Expenses” table:
(a)
The
period-to-period
change in the cost of natural gas sales is largely due to
changes in the price of natural gas. We purchase natural gas at
industry index-based prices to satisfy our contractual sales
obligations.
The market price of natural gas, as measured at Henry Hub in
Louisiana, averaged $8.64 per MMBtu and $9.34 per
MMBtu for the year ended December 31, 2005 and four
quarters ended September 30, 2006, respectively. Forecast
revenues for the year ended December 31, 2007 are based on
an estimated natural gas price of $8.20 per MMBtu. As of
December 31, 2006, the Henry Hub spot price for natural gas
was expected (based on an average monthly price of NYMEX futures
for 2007 deliveries) to average $7.07 per MMBtu in 2007.
(b)
We forecast our operating costs and expenses, excluding non-cash
costs, for the four quarters ending December 31, 2007 to
approximate $59.2 million. This amount is $9.2 million
higher than pro forma operating costs and expenses for the year
ended December 31, 2005 and $9.7 million higher than
those for the four quarters ended September 30, 2006. The
2007 period includes $3.7 million of operating costs and
expenses associated with our South Texas NGL pipeline system,
which became operational in January 2007. In addition, forecast
operating costs and expenses for 2007 includes pipeline
integrity-related expenses of $2.8 million, which is
$2 million higher than those recorded for the year ended
December 31, 2005 and $1 million lower than those for
the four quarters ended September 30, 2006.
(c)
Costs and expenses for all periods include the pro forma effect
of $2.5 million of incremental general and administrative
expenses that we expect to incur as a result of becoming a
publicly traded entity. These costs include fees associated with
annual and quarterly reports to unitholders, tax return and
Schedule K-1
preparation and distribution, investor relations, registrar and
transfer agent fees, incremental insurance costs, accounting and
legal services. These costs also include estimated related party
amounts payable to EPCO, Inc. in connection with the
administrative services agreement. For additional information
regarding the administrative services agreement, please read
“Certain Relationships and Related Party
Transactions — Administrative Services
Agreement.” Estimated general and administrative costs for
the four quarters ending December 31, 2007 include
$0.6 million attributed to our South Texas NGL pipeline
system.
Capital
Expenditures
Our capital expenditures consist of sustaining capital
expenditures and those related to growth projects. 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 (or
sustain) existing operations but do not generate additional
revenues. Growth capital spending relates to projects that
(i) result in additional revenue streams from existing
assets or (ii) expand our asset base through construction
of new facilities that will generate additional revenue streams.
Combined capital spending, net of contributions in aid of
construction costs, was $19.5 million for the year ended
December 31, 2005 and $61.1 million for the four
quarters ended September 30, 2006. Construction of
additional brine production capacity and above-ground storage
reservoirs at the facility owned by Mont Belvieu Caverns
accounted for $11.4 million and $38.2 million of
capital expenditures for the year ended December 31, 2005
and nine months ended September 30, 2006. All of these
projects are estimated to be completed and placed in service by
the end of the first quarter of 2007. The remainder of combined
capital spending for the year ended December 31, 2005 and
nine months ended September 30, 2006 is attributable to
sustaining capital projects, the majority of which relate to
pipeline integrity projects.
During 2007, we expect that South Texas NGL will make capital
expenditures of $28.6 million to complete planned
expansions (Phase II) to the South Texas NGL pipeline
system. In addition, we expect that Mont Belvieu Caverns will
make additional capital expenditures of $14.1 million to
complete brine production and above-ground storage projects. We
expect to fund our 66% share of these expenditures
(approximately $28.2 million) with proceeds from this
offering. We may also incur $25 million to $75 million
of additional growth capital expenditures in 2007 in connection
with currently contemplated expansion projects at Mont Belvieu
Caverns. We expect to finance any such projects through
borrowings under our new revolving credit facility, the issuance
of debt or additional equity, or contributions from Enterprise
Products OLP. The tables in this section do not reflect these
planned and potential capital expenditures.
Our Estimated Cash Available to Pay Distributions for the four
quarters ending December 31, 2007 includes an anticipated
$5.9 million of sustaining capital expenditures.
Our interest cost reflects $13 million of cash interest
cost resulting from an assumed $200 million borrowed at an
estimated variable interest rate of 6.5% per annum under our new
$300 million revolving credit facility. If the variable
interest rate used to calculate this interest expense were 1/8%
higher, our annual cash interest cost would increase to
$13.3 million.
Supplemental
Forecast Data
Our forecast of total gross operating margin for the four
quarters ending December 31, 2007 is approximately
$83.6 million. A reconciliation of forecast GAAP operating
income for 2007 to forecast non-GAAP gross operating margin in
total is as follows:
Revenues
$
849,692
Costs and expenses:
Cash costs and expenses
772,620
Depreciation and amortization
26,877
Total costs and expenses
799,497
Operating income
50,195
Adjustments to derive non-GAAP
forecast gross operating margin:
Add general and administrative
costs, including pro forma incremental public company costs
6,569
Add non-cash depreciation and
amortization
26,877
Gross operating margin in total
$
83,641
For a description of non-GAAP gross operating margin, please
read “Summary — Summary Historical and Pro Forma
Financial and Operating Data — Non-GAAP Financial
Measures.” On a percentage basis, we expect forecast gross
operating margin by segment for 2007 to approximate 49% for the
NGL and Petrochemical Storage Services segment, 20% for the NGL
Pipeline Services segment, 18% for the Natural Gas Pipelines and
Services segment, and 13% for the Petrochemical Pipeline
Services segment.
Following is a description of the relative rights and
preferences of holders of our common units in and to cash
distributions. The information presented in this section assumes
that our general partner continues to make capital contributions
to Duncan Energy Partners in order to maintain its 2% general
partner interest in Duncan Energy Partners.
General. Within approximately 45 days
after the end of each quarter, commencing with the quarter
ending on March 31, 2007, we will distribute all of our
available cash to unitholders of record on the applicable record
date. We will distribute 98% of our available cash to our common
unitholders, pro rata, and 2% to our general partner. Unlike
many publicly traded limited partnerships, our general partner
is not entitled to any incentive distributions and we do not
have any subordinated units.
Definition of Available Cash. Available cash
is defined in our partnership agreement and generally means,
with respect to any fiscal quarter, all cash and cash
equivalents on the date of determination of available cash for
such quarter:
•
less the amount of cash reserves established by the general
partner:
•
provide for the proper conduct of our business (including
reserves for future capital expenditures and for our future
credit needs);
•
comply with applicable law or any debt instrument or other
agreement; or
•
provide funds for distributions to unitholders and our general
partner in respect of any one or more of the next four quarters.
If we dissolve in accordance with our partnership agreement, we
will sell or otherwise dispose of our assets in a process called
a liquidation. We will first apply the proceeds of liquidation
to the payment of our creditors and the liquidator in the order
of priority provided in our partnership agreement and by law
and, thereafter, we will distribute any remaining proceeds to
our unitholders and our general partner in accordance with their
respective capital account balances as so adjusted.
Manner of Adjustments for Gain. The manner of
the adjustment is set forth in our partnership agreement. Upon
our liquidation, we will allocate any net gain (or unrealized
gain attributable to assets distributed in kind to our partners)
as follows:
•
first, to our general partner and the holders of our
common units having negative balances in their capital accounts
to the extent of and in proportion to such negative
balances; and
•
thereafter, 98% to all of our unitholders, pro rata, and
2% to our general partner.
Manner of Adjustments for Losses. Upon our
liquidation, any loss will generally be allocated to our general
partner and our unitholders as follows:
•
first, 98% to the holders of our common units in
proportion to the positive balances in their respective capital
accounts and 2% to our general partner, until the capital
accounts of our unitholders have been reduced to zero; and
•
thereafter, 100% to our general partner.
Adjustments to Capital Accounts. In addition,
interim adjustments to capital accounts will be made at the time
we issue additional partnership interests or make distributions
of property. Such adjustments will be based on the fair market
value of the partnership interests or the property distributed
and any gain or loss resulting therefrom will be allocated to
our unitholders and our general partner in the same manner as
gain or loss is allocated upon liquidation.
Duncan Energy Partners L.P. was formed on September 29,2006; therefore, it does not have any historical financial
statements prior to its formation. The following tables set
forth, for the periods and at the dates indicated, the selected
historical combined financial and operating data of Duncan
Energy Partners Predecessor, which was derived from the books
and records of Enterprise Products Partners.
The selected historical financial data for the nine months
ended September 30, 2006 and for the years ended
December 31, 2005, 2004 and 2003 and combined balance sheet
data at September 30, 2006 and at December 31, 2005
and 2004 is derived from and should be read in conjunction with
the audited combined financial statements of Duncan Energy
Partners Predecessor included elsewhere in this prospectus
beginning on
page F-13.
The selected historical financial data for the nine months ended
September 30, 2005 and combined balance sheet data at
September 30, 2005 is derived from the unaudited condensed
combined financial statements of Duncan Energy Predecessor. The
operating data for all periods are unaudited. The selected
unaudited pro forma combined financial data of Duncan Energy
Partners was derived from and should be read in conjunction with
our unaudited pro forma condensed combined financial statements
included in this prospectus beginning on
page F-2.
The following information should be read together with the
“Management’s Discussion and Analysis of Financial
Condition and Results of Operations.”
Enterprise Products Partners, through its subsidiaries, has
owned controlling interests and operated the underlying assets
of Mont Belvieu Caverns, Acadian Gas, Lou-Tex Propylene and
Sabine Propylene for several years. Enterprise Products Partners
will retain a 34% ownership interest in each of these four
entities (as well as South Texas NGL). Enterprise Products
Partners will own our general partner, DEP Holdings, which owns
a 2% general partner interest in us, and therefore indirectly
has the ability to control us. In addition, Enterprise Products
Partners will own approximately 36.0% of our outstanding common
units after completion of this proposed offering, or
approximately 26.4% of our outstanding common units if the
underwriters exercise their option to purchase additional common
units in full. For financial reporting purposes, the ownership
interests of Enterprise Products Partners are deemed to
represent the parent (or sponsor) interest in our pro forma
results of operations and financial position.
Our selected unaudited pro forma combined financial data gives
effect to the following significant transactions and events:
•
The August 2006 purchase of a pipeline by Enterprise Products
Partners for approximately $97.7 million in cash, the
subsequent contribution of this pipeline to South Texas NGL, and
estimated additional costs of $37.7 million, including
$8 million spent to acquire a pipeline asset from an
affiliate of TEPPCO Partners, to make this system operational in
January 2007. The pro forma financial data does not reflect
estimated additional capital expenditures of $28.6 million
that will be made by South Texas NGL in 2007 to complete planned
expansions to this system. We will retain cash in an amount
equal to our 66% share (approximately $18.9 million) of
these estimated capital expenditures from the net proceeds of
this offering in order to fund our share of the planned
expansion costs. The pro forma combined results of operations
data does not reflect any results attributable to the historical
activities of this pipeline.
•
The expenditure of $21.3 million in connection with the
construction of additional brine production capacity and
above-ground storage reservoirs at Mont Belvieu. The pro forma
financial data does not reflect estimated additional capital
expenditures of $14.1 million that will be made by Mont
Belvieu Caverns subsequent to December 31, 2006 to complete
these projects. We will retain cash in an amount equal to our
66% share (approximately $9.3 million) of these additional
capital expenditures from the net proceeds of this offering in
order to fund our share of the planned expansion costs.
•
The contribution of a 66% interest in each of Mont Belvieu
Caverns, Acadian Gas, Lou-Tex Propylene, Sabine Propylene and
South Texas NGL, all of which are wholly-owned subsidiaries of
Enterprise Products Partners, and the retention of Enterprise
Products Partners of a 34% interest in these entities.
•
The revision of related party storage contracts between us and
Enterprise Products Partners to (1) increase certain
storage fees paid by Enterprise Products Partners and
(2) reflect the allocation to
Enterprise Products Partners of all storage measurement gains
and losses relating to products under these agreements, and the
execution of a limited liability company agreement for Mont
Belvieu Caverns providing for the special allocation and other
agreements relating to other measurement gains and losses to
Enterprise Products Partners.
•
The assignment to us of certain third-party agreements that
effectively reduce tariff rates received by us compared to rates
previously charged by Lou-Tex Propylene and Sabine Propylene to
Enterprise Products Partners for the transport of propylene
volumes.
Our unaudited pro forma, as adjusted financial data also gives
effect to the following:
•
our borrowing of $200 million under a new $300 million
revolving credit facility;
•
our issuance and sale of 13,000,000 common units in this
offering;
•
our payment of estimated underwriting discounts and commissions,
a structuring fee and other offering expenses; and
•
our use of net proceeds from the borrowing and this offering as
consideration for the contributed ownership interests in Mont
Belvieu Caverns, Acadian Gas, Lou-Tex Propylene, Sabine
Propylene and South Texas NGL from Enterprise Products Partners.
The selected unaudited pro forma combined financial data for the
nine months ended September 30, 2006 and for the year ended
December 31, 2005 assume the pro forma transactions noted
herein occurred at the beginning of each period presented or on
September 30, 2006 for the balance sheet data.
The following table presents the selected historical combined
financial and operating data of Duncan Energy Partners
Predecessor and our selected pro forma financial information for
the annual periods indicated (dollars in thousands, except per
unit amounts):
The following table presents the selected historical combined
financial and operating data of Duncan Energy Partners
Predecessor and our pro forma combined financial information for
the interim periods indicated (dollars in thousands, except per
unit amounts):
The non-GAAP financial measures of gross operating margin and
earnings before interest, income taxes, depreciation and
amortization, which we refer to as “EBITDA,” are
presented in the selected historical and pro forma financial
data for Duncan Energy Partners Predecessor. For a description
of the non-GAAP financial measures that we use in this
prospectus and reconciliations of such non-GAAP financial
measures to their most directly comparable financial measure or
measures calculated and presented in accordance with GAAP,
please read “Summary — Summary Historical and Pro
Forma Financial and Operating Data —
Non-GAAP
Financial Measures.”
The following information is provided to highlight significant
trends and other information regarding Duncan Energy Partners
Predecessor’s historical operating results, financial
position and other financial data. Each section below represents
a footnote to the tables above:
(1) We view the combined financial statements of Duncan
Energy Partners Predecessor as the predecessor of the
Partnership, a Delaware limited partnership formed on
September 29, 2006. The financial statements of Mont
Belvieu Caverns, Acadian Gas, Lou-Tex Propylene and Sabine
Propylene combined to create Duncan Energy Partners Predecessor
were derived from the accounts and records of Enterprise
Products Partners, which did not own certain of the businesses
for all periods presented in this “Selected Historical and
Pro Forma Financial and Operating Data” section. As a
result, the selected data reflects the following information:
•
Enterprise Products Partners owned Mont Belvieu Caverns and
Lou-Tex Propylene for all periods presented. Our pro forma
balance sheet data reflects assumed capital expenditures of
$21.3 million by Mont Belvieu Caverns in connection with
the construction of additional brine production capacity and
above-ground storage reservoirs. Our pro forma financial
statements do not reflect estimated additional capital
expenditures of $14.1 million that will be made by Mont
Belvieu Caverns subsequent to December 31, 2006 to complete
these projects. We will retain cash in an amount equal to our
66% share of the additional capital expenditures (approximately
$9.3 million) from the net proceeds of this offering in
order to fund our share of the planned expansion costs.
•
Enterprise Products Partners acquired Acadian Gas in April 2001;
therefore, the selected data includes Acadian Gas from the date
of its acquisition. No financial data was available from the
seller prior to April 2001.
•
Enterprise Products Partners constructed the pipeline owned by
Sabine Propylene and placed it in service in November 2001;
therefore, the selected data includes Sabine Propylene from
November 2001 to present.
•
In August 2006, Enterprise Products Partners purchased
223 miles of NGL pipelines extending from Corpus Christi,
Texas to Pasadena, Texas from ExxonMobil Pipeline Company. The
purchase price for this asset was approximately
$97.7 million. This pipeline system will be contributed to
South Texas NGL (along with others being constructed and to be
acquired) and will be used to transport NGLs from two Enterprise
Products Partners’ facilities located in South Texas to
Mont Belvieu, Texas. The total estimated cost to acquire and
construct the additional pipelines is $66.3 million. Our
pro forma balance sheet data reflects assumed capital
expenditures of $37.7 million, including $8 million
spent to acquire a
10-mile
pipeline from an affiliate of TEPPCO Partners, to make this
system operational in January 2007. We expect that it will cost
an additional $28.6 million to complete planned expansions
of the South Texas NGL pipeline after the closing of this
offering, of which our 66% share will be approximately
$18.9 million. This expenditure is not reflected in the pro
forma financial data because we expect to use cash on hand from
the proceeds of this offering to fund this cost. The pro forma
combined results of operations data does not reflect any results
of operations attributable to the historical activities of the
existing NGL pipelines.
Furthermore, the pro forma adjustments are limited to those
required to present an estimate of owners’ net investment
immediately prior to the Partnership’s initial public
offering.
With respect to the pipeline acquired in August 2006, the seller
has informed us that no discrete and separable financial
information existed for the pipeline, which was comprised of two
separately operated pipelines prior to our purchase. The seller
had previously utilized these pipelines for a different product
and
the pipeline was out of service when we acquired it. With
respect to the
10-mile
pipeline acquired from an affiliate of TEPPCO Partners, this
pipeline was used as a feeder line for NGL products and operated
by different management. We understand no financial statements
information is available for this minor component asset. There
is no meaningful financial data available regarding the prior
use of these pipelines by the sellers that would be meaningful
to our investors. In addition, such data, if available, would
not assist investors in understanding either the evolution of
the business (which is a new NGL transportation network) nor the
track record of management (which will be different).
(2) Duncan Energy Partners Predecessor operated within the
Enterprise Products Partners cash management program for all
periods presented. Cash flows used in financing activities
represent transfers of excess cash from Duncan Energy Partners
Predecessor to Enterprise Products Partners equal to cash
provided by operations less cash used in investing activities.
Conversely, cash flows provided by financing activities
represent contributions from Enterprise Products Partners. These
cash transfers have been reflected in owner’s net
investment.
The historical combined financial statements included in this
prospectus reflect assets, liabilities and operations to be
contributed to us by Enterprise Products Partners L.P. and
various wholly owned subsidiaries upon the closing of this
offering. We refer to these assets, liabilities and operations
as the assets, liabilities and operations of Duncan Energy
Partners Predecessor. The following discussion analyzes the
financial condition and results of operations of Duncan Energy
Partners Predecessor, which reflects ownership of 100% of the
assets, liabilities and operations to be contributed to us.
However, we will only have a 66% interest in the assets,
liabilities and operations being contributed to us, and
Enterprise Products Partners will retain the remaining 34%
interest. You should read the following discussion of the
financial condition and results of operations for Duncan Energy
Partners Predecessor in conjunction with the historical combined
financial statements and notes of Duncan Energy Partners
Predecessor and the unaudited pro forma condensed combined
financial statements for Duncan Energy Partners L.P. included
elsewhere in this prospectus.
We are a Delaware limited partnership formed by Enterprise
Products Partners in September 2006 to own, operate and acquire
a diversified portfolio of midstream energy assets. For the
period discussed below, our operations were organized into the
following three business segments:
•
our NGL & Petrochemical Storage Services segment, which
consists of 33 salt dome caverns located in Mont Belvieu, Texas,
with an underground storage capacity of approximately
100 MMBbls, and certain related assets;
•
our Natural Gas Pipelines & Services segment, which
consists of an onshore natural gas pipeline system that gathers,
transports, stores and markets natural gas in Louisiana;
•
our Petrochemical Pipeline Services segment, which consists of
two petrochemical pipeline systems totaling 284 miles, including
the 263-mile
Lou-Tex Propylene pipeline system and the
21-mile
Sabine Propylene pipeline system; and
Our South Texas NGL pipeline system became operational in
January 2007. This business will be accounted for under a
fourth reporting segment, NGL Pipeline Services. The South Texas
NGL pipeline system consists of a
290-mile
pipeline system used to transport NGLs from two of Enterprise
Products Partners’ facilities located in South Texas to
Mont Belvieu, Texas and related interconnections. The historical
combined financial statements of Duncan Energy Partners
Predecessor do not include any results of operations for this
pipeline segment.
Our operating revenues from each of our segments (other than our
NGL Pipeline Services segment which became operational in
January 2007), and their relative percentages of our total
revenues, consisted of the following (dollars in millions):
Please read “Summary — Summary Historical
and Pro Forma Financial and Operating Data —
Non-GAAP Financial Measures” for a reconciliation of
total segment gross operating margin to operating income.
Our segment operating assets will be held by various
subsidiaries. In connection with this offering, Enterprise
Products OLP will contribute to us equity interests representing
a 66% interest in the following subsidiaries:
•
Mont Belvieu Caverns;
•
Acadian Gas;
•
Sabine Propylene and Lou-Tex Propylene; and
•
South Texas NGL (the assets of which became operational in
January 2007).
NGL & Petrochemical Storage Services
Segment. Our NGL & Petrochemical Storage
Services segment consists of 33 salt dome caverns located in
Mont Belvieu, Texas, with an underground storage capacity of
approximately 100 MMBbls, and certain related assets. These
assets receive, store and deliver NGLs and petrochemical
products for industrial customers located along the upper Texas
Gulf Coast, which has the largest concentration of petrochemical
plants and refineries in the United States.
We charge our customers monthly storage reservation fees to
reserve a specific storage capacity in our underground caverns
to meet their storage requirements. Customers pay reservation
fees based on the quantity of capacity reserved even if that
capacity is not actually utilized. When a customer exceeds its
reserved capacity, we will 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. Lastly, brine production revenues are derived from
customers that use brine in the production of feedstocks for
production of polyvinyl chloride (PVC).
We have a broad range of customers with contract terms that vary
from
month-to-month
to long-term contracts with durations of one to ten years. We
currently offer our customers, in various quantities and at
varying terms, two main types of storage contracts:
•
multi-product fungible storage contracts, which allow customers
to store any combination of fungible products; and
•
segregated product storage contracts, which are available to
customers who desire to store non-fungible products such as
propylene, ethylene and naphtha.
We evaluate pricing, volume and availability for storage on a
case-by-case
basis. Segregated storage allows a customer to reserve an entire
storage cavern and have its own product injected and withdrawn
without having its product commingled.
Natural Gas Pipelines & Services
Segment. Our Natural Gas Pipelines &
Services segment consists of the Acadian Gas system, which is an
onshore natural gas pipeline system that gathers, transports,
stores and markets natural gas in Louisiana. The Acadian Gas
system links natural gas supplies from onshore and offshore Gulf
of Mexico developments (including offshore pipelines,
continental shelf and deepwater production) with local gas
distribution companies, electric generation plants and
industrial customers, including those in the Baton Rouge-New
Orleans-Mississippi River corridor.
Natural gas throughput in our Natural Gas Pipelines &
Services segment consists of a combination of natural gas
marketing sales volumes and transportation volumes delivered on
behalf of third-party shippers, with marketing volumes and
transportation volumes representing approximately 45% and 55%,
respectively, of the average daily gas volumes for the first
nine months of 2006.
In our gas marketing activities, we purchase natural gas
supplies for our gas marketing business under contracts with
quantities and market-based pricing indices that correspond to
the quantities and the pricing indices utilized in our gas sales
activities, thereby limiting our commodity price risk. We do not
enter into
“back-to-back”
agreements in which the terms of any purchase agreement are
matched directly with any sales agreement.
In addition to our gas marketing activities, the Natural Gas
Pipelines & Services segment provides fee-based gas
transportation services for producers and gas marketing
companies under intrastate and Section 311 interruptible
transportation contracts. The primary term of these
transportation service contracts may vary from
month-to-month
to longer-term contracts, with durations typically of one to
three years. The revenues derived from these gas transportation
contracts are based on the quantities of gas delivered
multiplied by the per-unit transportation rate paid.
Our Natural Gas Pipelines & Services segment includes
our indirect ownership of 49.5% of the ownership interests in
the Evangeline pipeline, a
27-mile
pipeline extending from Taft, Louisiana to Westwego, Louisiana.
The Natural Gas Pipelines & Services segment’s
most significant natural gas sales contract is a
21-year
arrangement with Evangeline, which was entered into in 1991, and
includes minimum annual quantities. Evangeline uses these
natural gas volumes to meet its own supply obligation under a
corresponding sales agreement with Entergy Louisiana, its only
customer. We include equity earnings from Evangeline in our
measurement of segment gross operating margin and operating
income. Our equity investments in midstream energy operations,
such as those conducted by Evangeline, are a vital component of
our long-term business strategy and important to the operations
of our Natural Gas Pipelines & Services segment.
Our combined Natural Gas Pipelines & Services segment
revenues and operating costs and expenses are significantly
influenced by changes in natural gas prices. In general, higher
natural gas prices result in increased revenues from the sale of
natural gas; however, these same higher commodity prices also
increase the associated cost of sales as purchase prices rise.
Petrochemical Pipeline Services Segment. Our
Petrochemical Pipeline Services segment consists of two
petrochemical pipeline systems with an aggregate of
284 miles of pipeline. The Lou-Tex Propylene pipeline
system consists of a
263-mile
pipeline used to transport chemical-grade propylene between
Sorrento, Louisiana and Mont Belvieu, Texas. The Sabine
Propylene pipeline system consists of a
21-mile
pipeline used to transport polymer-grade propylene from Port
Arthur, Texas to a pipeline interconnect in Cameron Parish,
Louisiana on a
transport-or-pay
basis.
Shell and ExxonMobil are the only customers that use the Lou-Tex
Propylene pipeline. We have entered into separate product
exchange agreements with Shell and ExxonMobil through which we
agree to receive
propylene product in one location and deliver like product to
another location. The following is a summary of certain terms of
our exchange agreements for the use of the Lou-Tex Propylene
pipeline:
•
Shell Exchange Agreement. This agreement
expires on March 1, 2020, but will continue on an annual
basis subject to termination by either party. The exchange fees
paid by Shell are fixed until such time as a published power
index in Louisiana becomes available and the parties agree to
use such index. Shell is obligated to meet minimum delivery
requirements under this agreement. If Shell fails to meet these
requirements, it will be obligated to pay us a deficiency fee.
•
ExxonMobil Exchange Agreement. This agreement
expires on June 1, 2008, but will continue on a monthly
basis subject to termination by either party. The exchange fees
paid by ExxonMobil are based on the volume of chemical grade
propylene delivered to us.
Shell is the only current customer that uses the Sabine
Propylene pipeline. We are a party to a product exchange
agreement with Shell for the use of the Sabine Propylene
pipeline. This agreement expires on November 1, 2011, but
will continue on an annual basis subject to termination by
either party. The exchange fees paid by Shell are adjusted
yearly based on the U.S. Department of Labor wage index and
the yearly operating costs of the Sabine Propylene pipeline.
Shell is obligated to meet minimum delivery requirements under
this agreement. If Shell fails to meet these minimum delivery
requirements, it will be obligated to pay us a deficiency fee.
NGL Pipeline Services Segment. Our NGL
Pipeline Services segment consists of a
290-mile
pipeline system used to transport NGLs from two Enterprise
Products Partners’ facilities located in South Texas to
Mont Belvieu, Texas and related interconnections. We acquired a
223-mile
segment of the system in August 2006, and we are in the process
of acquiring and constructing other segments of the pipeline
system. The system was placed into operation and began
transporting NGLs in January 2007, after undergoing
modifications, extensions and interconnections. Additional
expansions are scheduled to be completed during the remainder of
2007.
The sole customer of our NGL Pipeline Services segment is
Enterprise Products Partners, which will use the South Texas NGL
pipeline system to ship the following products to Mont Belvieu,
Texas:
•
NGLs processed at its Shoup fractionation plant in Corpus
Christi, Texas;
•
NGLs processed at its Armstrong fractionation plant located near
Victoria, Texas; and
•
NGLs purchased by Enterprise Products Partners from third
parties in South Texas.
Prior to the closing of this offering, we will enter into a
ten-year transportation contract with Enterprise Products
Partners that will include all of the volumes of NGLs
transported on the South Texas NGL pipeline system. Under this
contract, Enterprise Products Partners will pay us a dedication
fee of $0.02 per gallon for all NGLs produced at the Shoup
and Armstrong fractionation plants. This dedication fee is
payable whether or not Enterprise Products Partners ships any
NGLs on the South Texas NGL pipeline system. For the nine months
ended September 30, 2006, the Shoup and Armstrong
fractionation plants collectively produced 65,884 Bbls/d of
NGLs. We will not take title to the products transported on the
South Texas NGL pipeline system; rather, Enterprise Products
Partners will retain title and the associated commodity risk.
Our management uses a variety of financial and operational
measurements to analyze our performance. These measurements
include the following: (1) pipeline volumes, (2) gross
operating margin and (3) EBITDA.
Pipeline Throughput Volumes. We view pipeline
throughput volumes as an important component of maximizing our
profitability. We gather and transport natural gas, NGLs and
propylene under fee-based contracts. Pipeline throughput volumes
from existing wells connected to our pipelines will naturally
decline over time as wells deplete. Accordingly, to maintain or
increase throughput levels on these pipelines, we must
continually obtain new supplies of natural gas. Our ability to
maintain existing supplies of natural gas and NGLs and obtain
new supplies are impacted by (1) the level of workovers or
recompletions of existing
connected wells and successful drilling activity in areas
currently dedicated to our pipelines and (2) our ability to
compete for volumes from successful new wells in other areas. We
regularly monitor producer activity in the areas served by the
Acadian Gas pipeline system, and the areas served by South Texas
NGL pipeline system and Enterprise Products Partners’ Shoup
and Armstrong fractionation facilities. The throughput volumes
of propylene on our Lou-Tex Propylene and Sabine Propylene
pipelines are substantially dependent upon the quantities of
propylene produced at third-party plants that have pipeline
connections with our propylene pipelines.
Gross Operating Margin. We evaluate segment
performance based on gross operating margin, which is a non-GAAP
financial measure. 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 most directly comparable GAAP
measure to total segment gross operating margin is operating
income. Our gross operating margin should not be considered as
an alternative to operating income.
We define total (or combined) segment gross operating margin as
operating income before:
•
depreciation, amortization and accretion expense;
•
gains and losses on the sale of assets; and
•
general and administrative expenses.
Gross operating margin is exclusive of other income and expense
transactions, provision for income taxes, minority interest,
extraordinary charges and the cumulative effect of changes in
accounting principles. Gross operating margin by segment is
calculated by subtracting segment operating costs and expenses
(net of the adjustments noted above) from segment revenues, with
both segment totals before the elimination of any intersegment
and intrasegment transactions. Our combined revenues reflect the
elimination of all material intercompany transactions.
We include equity earnings from Evangeline in our measurement of
segment gross operating margin and operating income. This method
of operation enables us to achieve favorable economies of scale
relative to our level of investment and also lowers our exposure
to business risks compared to the profile we would have on a
stand-alone basis. Our equity investments are within the same
industry as our combined operations; therefore, we believe
treatment of earnings from our equity method investee as a
component of gross operating margin and operating income is
appropriate.
Gross operating margin should not be considered an alternative
to, or more meaningful than, net income, operating income, cash
flows from operating activities or any other measure of
financial performance presented in accordance with GAAP. Please
read “Summary — Summary Historical and Pro
Forma Financial and Operating Data —
Non-GAAP Financial Measures.”
EBITDA. We define EBITDA as net income or loss
plus interest expense, provision for income taxes and
depreciation, accretion and amortization expense. EBITDA is
commonly used as a supplemental financial measure by management
and by external users of our financial statements, such as
investors, commercial banks, research analysts and rating
agencies, to assess:
•
the financial performance of our assets without regard to
financing methods, capital structures or historical cost basis;
•
the ability of our assets to generate cash sufficient to pay
interest cost and support our indebtedness;
•
our operating performance and return on capital as compared to
those of other companies in the midstream energy industry,
without regard to financing and capital structure; and
•
the viability of projects and the overall rates of return on
alternative investment opportunities.
Because EBITDA excludes some, but not all, items that affect net
income or loss and because these measures may vary among other
companies, the EBITDA data presented in this prospectus may not
be comparable to similarly titled measures of other companies.
The GAAP measure most directly comparable to EBITDA is net cash
flows provided by operating activities.
EBITDA should not be considered an alternative to, or more
meaningful than, net income, operating income, cash flows from
operating activities or any other measure of financial
performance presented in accordance with GAAP. Please read
“Summary — Summary Historical and Pro Forma
Financial and Operating Data — Non-GAAP Financial
Measures.”
We believe that current natural gas prices will continue to
cause relatively high levels of natural gas-related drilling in
the United States, including Texas and Louisiana, as producers
seek to increase their level of natural gas production. Although
the number of natural gas wells drilled in the United States has
increased overall in recent years, a corresponding increase in
production has not been realized, primarily as a result of
smaller discoveries and the decline in production from existing
wells. We believe that an increase in United States drilling
activity, additional sources of supply such as liquefied natural
gas, and imports of natural gas will be required for the natural
gas industry to meet the expected increased demand for, and to
compensate for the slowing production of, natural gas in the
United States. A number of the areas in which we operate are
experiencing significant drilling activity as a result of recent
high natural gas prices, increased drilling for deeper natural
gas formations and the implementation of new exploration and
production techniques.
While we anticipate continued high levels of exploration and
production activities in a number of the areas in which we
operate, fluctuations in energy prices can greatly affect
production rates and investments by third parties in the
development of new natural gas reserves. Drilling activity
generally decreases as natural gas prices decrease. We have no
control over the level of drilling activity in the areas of our
operations.
You should read the discussion of our financial condition and
results of operations in conjunction with our historical and pro
forma financial statements included elsewhere in this
prospectus. Our future results could differ materially from our
historical results due to a variety of factors, including the
following:
Partial Ownership of Operating Assets. After
this offering, we will own 66% of the equity interests in the
subsidiaries that hold our operating assets and affiliates of
Enterprise Products Partners will continue to own the remaining
34%. The historical combined financial statements of Duncan
Energy Partners Predecessor were prepared from Enterprise
Products Partners’ separate historical accounting records
related to our operating assets. Accordingly, the discussion
that follows includes 100% of the results of operations for our
operating assets, but in the future we will only have a 66%
interest in those results.
No Historical Results for Our NGL Pipeline Services
Segment. The discussion of our historical results
that follows does not reflect any operations related to our NGL
Pipeline Services segment, which includes a
223-mile
pipeline, a
10-mile
pipeline acquired by an affiliate of Enterprise Products
Partners from an affiliate of TEPPCO Partners for
$8 million and subsequently contributed to us, and a
12-mile
pipeline leased from TEPPCO Partners until planned completion
during the third quarter of 2007 of a parallel pipeline
currently under construction by us. We acquired the
223-mile
pipeline in August 2006, at which time the seller informed us
that no discrete and separable financial information existed for
the pipeline. In addition, the seller had previously utilized
the pipeline for a different product and the pipeline was out of
service when we acquired it. The
10-mile
pipeline acquired by an affiliate of Enterprise Products
Partners from an affiliate of TEPPCO Partners and contributed to
us was used as a feeder line for NGL products and operated by
different management. We understand no financial statement
information is available for this minor component asset. There
is no meaningful financial data available regarding the prior
use of these pipelines by the sellers that would be meaningful
to our investors. In addition, such data, if available, would
not assist investors in understanding either the evolution of
the business (which is a new NGL transportation network) nor the
track record of management (which will be different).
Increase in Outstanding
Indebtedness. Historically, we have not had any
consolidated indebtedness and, therefore, we have not had
consolidated interest expense. We expect to borrow approximately
$200 million under a new revolving credit facility in
connection with this offering, which amount will be paid to
Enterprise Products Partners in connection with its contribution
of our operating assets to us. These additional borrowings are
expected to increase interest expense by approximately
$13 million per year assuming an interest rate of 6.5% and
amortization of debt issuance costs.
Increased Storage Fees. In connection with
this offering, we will increase certain storage fees charged to
Enterprise Products Partners for use of the facilities owned by
Mont Belvieu Caverns. Historically, such intercompany charges
were below market and eliminated in the consolidated revenues
and costs and expenses of Enterprise Products Partners.
Prospectively, such rates will be market-related. The pro forma
increase in storage revenues is $9.8 million for the nine
months ended September 30, 2006 and $11.6 million for
the year ended December 31, 2005.
Special Allocation of Measurement Gains and
Losses. Storage well gains and losses occur when
product movements into a storage well are different from those
redelivered to customers. In general, such variations result
from difficulties in precisely measuring significant volumes of
liquids at varying flow rates and temperatures. It is expected
that substantially all product delivered into storage will be
withdrawn over time. A measurement loss in one period is
expected to be offset by a measurement gain in a subsequent
period, unless product is physically lost in a storage well due
to problems with cavern integrity.
Historically, storage well measurement gains and losses, and
associated reserve accounts, have been included in our financial
statements. Operating costs and expenses reflect well loss
accruals of $3.1 million, $0.6 million and
$2.4 million for the years ended December 31, 2005,
2004 and 2003, respectively, and $0 and $2.5 million for
the nine months ended September 30, 2006 and 2005,
respectively. At September 30, 2006, the financial
statements of Duncan Energy Partners Predecessor included
$1.8 million in a measurement gain and loss reserve account.
In addition, operating gains and losses due to measurement
variances for product movements to and from storage wells
relating primarily to pipeline and well connection activities
are included in our financial statements. Many of our customer
storage arrangements allow us to retain a small amount of liquid
volumes to help offset any measurement losses. These variances
are estimated and settled at current prices each reporting
period as a net credit or charge to operating costs and
expenses. We do not retain volumes in inventory. The net amounts
for each of the years ended December 31, 2005, 2004 and
2003 were a $2.1 million charge, a $0.2 million credit
and a $1.4 million credit, respectively, and a
$1.0 million charge and a $3.2 million charge for the
nine months ended September 30, 2006 and 2005, respectively.
In connection with storage agreements for a variety of products
entered into between Enterprise Products Partners and Mont
Belvieu Caverns effective concurrently with the closing of this
offering, Enterprise Products Partners will agree to the
allocation of all measurement gains and losses relating to these
products.
In addition, the limited liability company agreement for Mont
Belvieu Caverns will specially allocate to Enterprise Products
Partners any items of income and gain or loss and deduction
relating to net measurement losses and measurement gains,
including amounts that Mont Belvieu Caverns may retain or deduct
as handling losses. Enterprise Products Partners will also be
required to contribute cash to Mont Belvieu Caverns, or will be
entitled to receive distributions from Mont Belvieu Caverns,
based on the then-current net measurement gains or measurement
losses. As a result, we will continue to record measurement
gains and losses associated with the operation of our Mont
Belvieu storage facility for parties other than Enterprise
Products Partners after the closing date of this offering on a
combined basis as operating costs and expenses. However, these
measurement gains and losses should not affect our net income or
have a significant impact on us with respect to our cash flows
from operating activities and, accordingly, no reserve account
will be established by us for measurement losses on our balance
sheet.
We will be responsible for product losses attributable to cavern
integrity events. During the three years ended December 31,2005 and nine months ended September 30, 2006, we did not
experience any significant physical loss of product due to a
loss of cavern integrity.
Decrease in Propylene Transportation
Rates. The transportation rates that we receive
for our Lou-Tex Propylene pipeline and our Sabine Propylene
pipeline for periods after our initial public offering will be
lower than our historical transportation rates. Historically,
Enterprise Products Partners was the shipper of record, and we
charged it the maximum tariff rate for using these assets.
Enterprise Products Partners then contracted with third parties
to ship volumes on these pipelines under exchange agreements. In
general, the revenues recognized by Enterprise Products Partners
in connection with these exchange agreements were less than the
maximum tariff rate it paid us. In connection with this
offering, Enterprise Products Partners will assign its exchange
agreements to us. Accordingly, the transportation rates we
receive for use of our Lou-Tex Propylene pipeline and Sabine
Propylene pipeline will be less than the historical rates that
we received from Enterprise Products Partners. The pro forma
reduction in revenues was $16.5 million for the
nine months ended September 30, 2006 and
$18.4 million for the year ended December 31, 2005.
Additional General and Administrative
Expenses. We expect to incur approximately $2.5
million in incremental general and administrative expenses as a
result of becoming a publicly traded entity. These costs include
fees associated with annual and quarterly reports to
unitholders, tax returns and
Schedule K-1
preparation and distribution, investor relations, registrar and
transfer agent fees, incremental insurance costs, accounting and
legal services. These costs also include estimated related party
amounts payable to EPCO in connection with the administrative
services agreement. For additional information regarding the
administrative services agreement, please read “Certain
Relationships and Related Party Transactions —
Administrative Services Agreement.”
Combined Revenues. Combined revenues for the
first nine months of 2006 were $740.1 million compared to
$649.4 million for the first nine months of 2005. The
period-to-period
increase in combined revenues is primarily due to a
$79.9 million increase in revenues associated with natural
gas marketing activities, which benefited from higher natural
gas sales volumes and prices. In addition, revenues from the
NGL & Petrochemical Storage Services segment increased
$6.8 million
period-to-period
primarily due to higher storage volumes.
Combined Costs and Expenses. Combined
operating costs and expenses were $698 million for the
first nine months of 2006 compared to $614.3 million for
the first nine months of 2005. The
period-to-period
increase in costs and expenses is primarily due to an
$84 million increase in purchase costs associated with our
natural gas marketing activities. General and administrative
costs decreased $1.3 million
period-to-period.
Changes in our combined revenues and costs and expenses
period-to-period
are explained in part by changes in energy commodity prices. In
general, higher natural gas prices result in an increase in our
combined revenues attributable to the sale of natural gas by
Acadian Gas; however, these same commodity prices also increase
the associated cost of sales as purchase prices rise. The Henry
Hub market price of natural
gas averaged $7.47 per MMBtu for the first nine months of
2006 versus $7.18 per MMBtu for the first nine months of
2005.
To a lesser extent, changes in our revenues and costs and
expenses are attributable to demand for NGL and petrochemical
storage services and activity on our propylene pipelines. Demand
for storage services affects the reservation, excess storage and
throughput fees earned by our NGL and petrochemical storage
business. In turn, demand for our storage services is driven by
such factors such as demand for petrochemical feedstocks by the
petrochemical industry and the quantity of NGLs extracted from
natural gas streams at regional gas processing facilities.
Segment Results. The following information
highlights significant
period-to-period
variances in gross operating margin by business segment.
Gross operating margin from the NGL & Petrochemical
Storage Services segment was $15.1 million for the first
nine months of 2006 compared to $7.8 million for the first
nine months of 2005. Revenues increased $6.8 million
period-to-period
primarily due to (i) higher excess storage and throughput
fees and (ii) brine production revenues. Operating costs
and expenses decreased $0.5 million
period-to-period
attributable to reduced measurement losses in 2006 compared to
2005, which were partially offset by higher utility and
maintenance costs.
Storage revenues for the first nine months of 2006 were
$5.5 million higher than the first nine months of 2005
primarily due to an increase in excess storage and throughput
fees. These fees were higher
period-to-period
due to an increase in storage volumes. We attribute the increase
in storage volumes to strong demand for petrochemical feedstocks
by the petrochemical industry and improved NGL processing
economics. Strong NGL processing economics in recent years have
increased the quantity of NGLs extracted from natural gas
streams at regional gas processing facilities, which increases
the demand for storage services. Also, brine production revenues
increase $1.2 million
period-to-period,
which reflects contractual changes made to the sales agreements
with our customers during 2006.
Gross operating margin from the Natural Gas Pipelines &
Services segment was $17.1 million for the first nine
months of 2006 versus $19.7 million for the first nine
months of 2005. Natural gas transportation volumes increased to
773 Bbtu/d during the first nine months of 2006 from 657 Bbtu/d
during the same period in 2005. Gross operating margin decreased
$2.6 million
period-to-period
primarily due to lower margins on natural gas sales during the
first nine months of 2006 relative to the same period of 2005.
Also, gross operating margin for the first nine months of 2006
includes a $2.3 million benefit from the collection of a
contingent asset related to a prior business acquisition. Equity
earnings from our investment in Evangeline increased
$0.3 million
period-to-period.
We realized higher natural gas sales margins during the first
nine months of 2005, as compared to the same period in 2006,
primarily due to the effects of Hurricane Katrina. This
hurricane impacted supply and demand for natural gas, NGLs,
crude oil and motor gasoline. In general, this resulted in an
increase in energy commodity prices, which was exacerbated in
certain regions due to local supply and demand imbalances. Our
natural gas sales margins, subsequent to Hurricane Katrina,
benefited from increased regional demand for natural gas and the
general increase in commodity prices.
Gross operating margin from the Petrochemical Pipeline Services
segment was $26.1 million for the first nine months of 2006
compared to $22.1 million for the first nine months of
2005. Petrochemical transportation volumes were 36 MBPD
during the first nine months of 2006 versus 34 MBPD during
the 2005 period. Transportation revenues increased
$3.1 million
period-to-period
primarily due to higher transportation volumes and a higher
average transportation fee on our Lou-Tex Propylene pipeline.
Operating costs and expenses decreased $0.9 million
period-to-period
primarily due to a reduction in property taxes associated with
the Lou-Tex Propylene pipeline. During 2006, we successfully
negotiated a lower property tax rate with the Louisiana state
taxing authority, which we estimate will provide an annual
benefit of approximately $1.9 million in 2006.
The Lou-Tex Propylene pipeline transports chemical-grade
propylene from multiple receipt points to multiple delivery
points. The contractual transportation fee we charge our
customers is based upon the
distance that product moves through the Lou-Tex Propylene
pipeline. During the first nine months of 2006 compared to the
same period of 2005, we earned a higher average transportation
fee due to our customers’ election to move chemical-grade
propylene over a greater distance through the Lou-Tex Propylene
pipeline.
Combined Revenues. Combined revenues for 2005
were $953.4 million compared to $748.9 million for
2004. The
year-to-year
increase in combined revenues is primarily due to higher natural
gas sales prices during 2005 relative to 2004, which accounted
for a $208.2 million increase in combined revenues
associated with natural gas marketing activities.
Combined Costs and Expenses. Combined
operating costs and expenses for 2005 were $909 million
compared to $685.5 million for 2004. The
year-to-year
increase in costs and expenses is primarily due to an increase
in the cost of sales associated with natural gas marketing
activities. Such costs increased $213 million
year-to-year
as a result of higher natural gas prices. General and
administrative costs decreased $1 million
year-to-year.
Changes in our combined revenues and costs and expenses
period-to-period
are explained in part by changes in energy commodity prices. In
general, higher natural gas prices result in an increase in our
combined revenues attributable to the sale of natural gas by
Acadian Gas; however, these same commodity prices also increase
the associated cost of sales as purchase prices rise. The Henry
Hub market price of natural gas averaged $8.64 per MMBtu
during 2005 versus $6.13 per MMBtu during 2004.
Other Income (Expense), Net. The amount in
2005 relates to interest accrued on potential assessments
related to a state sales tax dispute.
Segment Results. The following information
highlights significant
year-to-year
variances in gross operating margin by business segment:
Gross operating margin from the NGL & Petrochemical
Storage Services segment was $16.6 million for 2005
compared to $19.8 million for 2004. Revenues increased
$3.3 million
year-to-year
primarily due to higher excess storage and throughput fees.
These fees were higher in 2005 compared to 2004 due an increase
in storage volumes, which resulted from strong demand for
petrochemical feedstocks by the petrochemical industry and
improved NGL processing economics. The $3.3 million
increase in revenues was offset by a $6 million
year-to-year
increase in operating costs and expenses primarily due to higher
utility costs and higher measurement losses recognized in 2005.
Historically, operating costs and expenses of our NGL and
petrochemical storage business have been affected each period by
measurement gains and losses. Operating costs and expenses
reflect measurement losses of $5.2 million for 2005
compared to losses of $0.4 million for 2004. Prospectively,
effective concurrent with the closing of this offering, we will
specifically allocate to Enterprise Products Partners any items
of income and gain or loss and deduction relating to net
measurement gains and losses. Accordingly, in the future, these
measurement gains and losses should not affect our net income or
have a significant impact on us with respect to our cash flows
or operating activities.
Gross operating margin from the Natural Gas Pipelines &
Services segment was $18.9 million for 2005 compared to
$25.3 million for 2004. Natural gas throughput was 640
Bbtu/d during 2005 compared to 645 Bbtu/d during 2004. Gross
operating margin decreased $6.4 million
year-to-year
primarily due to lower margins on natural gas sales during 2005
relative to 2004. In general, Acadian Gas purchases natural gas
at prices that are based upon the Henry Hub index. In turn,
Acadian Gas generally wholesales natural gas to its customers at
the Henry Hub price plus a contractual margin. Acadian Gas’
natural gas sales contract with Evangeline contains a provision
whereby a portion of the contractual margin is determined
through a comparison of (i) Acadian Gas’s annual
weighted average natural gas purchase cost to (ii) a
benchmark determined by reference to a weighted average grouping
of natural gas market indices. As a result of this benchmarking
mechanism, we realized $4.8 million in higher natural gas
sales margins in 2004 relative to 2005. In addition, operating
costs and expenses increased $1.7 million
year-to-year
primarily due to higher
sales tax and pipeline integrity costs during 2005 as compared
to 2004. Equity earnings from our investment in Evangeline
increased $0.1 million
year-to-year.
Gross operating margin from the Petrochemical Pipeline Services
segment was $28.6 million for 2005 compared to
$36.9 million for 2004. Petrochemical transportation
volumes decreased to 33 MBPD during 2005 from 39 MBPD
during 2004. Gross operating margin decreased $8.3 million
year-to-year
primarily due to reduced transportation volumes on our Lou-Tex
Propylene pipeline. Lower transportation volumes accounted for
$6.8 million of the
year-to-year
decrease in gross operating margin. In addition, operating costs
and expenses increased $1.1 million
year-to-year
primarily due to higher pipeline integrity costs during 2005
compared to 2004.
Cumulative Effect of Change in Accounting
Principle. Net income for 2005 includes a
$0.6 million noncash charge for the cumulative effect of
change in accounting principle related to asset retirement
obligations. For additional information regarding this
accounting change, please read “— Other
Items” below.
Combined Revenues. Combined revenues were
$748.9 million for 2004 compared to $668.2 million for
2003. The
year-to-year
increase is primarily due to higher natural gas sales prices
during 2004 relative to 2003, which accounted for an
$80.5 million increase in combined revenues associated with
natural gas marketing activities.
Combined Costs and Expenses. Combined
operating costs and expenses were $685.5 million for 2004
compared to $609.8 million for 2003. The
year-to-year
increase in costs and expenses is primarily due to an increase
in the cost of sales associated with natural gas marketing
activities. Such costs increased $76.8 million
year-to-year
primarily due to higher natural gas prices. General and
administrative costs decreased $0.7 million
year-to-year.
Changes in our combined revenues and costs and expenses
period-to-period
are explained in part by changes in energy commodity prices. In
general, higher natural gas prices result in an increase in our
combined revenues attributable to the sale of natural gas by
Acadian Gas; however, these same commodity prices also increase
the associated cost of sales as purchase prices rise. The Henry
Hub market price of natural gas averaged $6.13 per MMBtu
during 2004 versus $5.38 per MMBtu during 2003.
Segment Results. The following information
highlights significant
year-to-year
variances in gross operating margin by business segment:
Gross operating margin from the NGL & Petrochemical
Storage Services segment was $19.8 million for 2004 and
2003. Revenues and operating costs and expenses were essentially
unchanged
period-to-period.
A decrease of $1.0 million in net measurement losses in
2004 relative to 2003 was offset by a $1.1 million increase
in repair and other maintenance costs in 2004.
Gross operating margin from the Natural Gas Pipelines &
Services segment was $25.3 million for 2004 versus
$18.3 million for 2003. Natural gas throughput increased to
645 Bbtu/d during 2004 from 600 Bbtu/d during 2003. Gross
operating margin increased $7 million
year-to-year
primarily due to improved margins on natural gas sales and
higher natural gas transportation volumes. Higher natural gas
sales margins, primarily due to the benchmarking mechanism in
Acadian Gas’ natural gas sales contract with Evangeline,
accounted for $3.6 million of the
period-to-period
increase in gross operating margin. Approximately
$1.7 million of the
period-to-period
increase in gross operating margin is attributable to higher
transportation volumes in 2004 compared to 2003. Also, gross
operating margin for 2004 includes a $1.7 million benefit
from the collection of a contingent asset related to a prior
business acquisition. Equity earnings from our investment in
Evangeline increased $0.1 million
year-to-year.
Gross operating margin from the Petrochemical Pipeline Services
segment was $36.9 million for 2004 compared to
$38.4 million for 2003. Petrochemical transportation
volumes were 39 MBPD during 2004 versus 40 MBPD during
2003. Gross operating margin from the Lou-Tex Propylene pipeline
decreased $1.5 million
year-to-year
as a result of reduced transportation volumes.
Our primary cash requirements will be normal operating and
general and administrative expenses, capital expenditures,
business acquisitions, distributions to partners and debt
service. We expect to fund our short-term needs for such items
as operating expenses and sustaining capital expenditures with
operating cash flows and borrowings under a new revolving credit
facility. Capital expenditures for long-term needs resulting
from internal growth projects and business acquisitions are
expected to be funded by a variety of sources (either separately
or in combination), including cash flows from operating
activities, borrowings under the new revolving credit facility,
and the issuance of additional debt or equity securities. We
expect to fund cash distributions to partners primarily with
operating cash flows. Debt service requirements are expected to
be funded by operating cash flows or refinancing arrangements.
Duncan
Energy Partners Predecessor Cash Flow
The following table summarizes our cash flows from operating,
investing and financing activities for the periods indicated
(dollars in thousands). For information regarding the individual
components of our cash flow amounts, please read the Statements
of Combined Cash Flows included elsewhere in this prospectus.
We have operated within the Enterprise Products Partners’
cash management program for all periods presented. For purposes
of presentation in the Statements of Combined Cash Flows, cash
flows from financing activities represent transfers of excess
cash from us to Enterprise Products Partners equal to cash
provided by operations less cash used in investing activities.
Such transfers of excess cash are shown as distributions to
owners in the Statements of Combined Owners’ Net
Investment. Conversely, if cash used in investing activities is
greater than cash provided by operations, then a deemed
contribution by owners is presented. As a result, the combined
financial statements do not present cash balances for any of the
periods presented.
Due to the foregoing method of presentation, our owners were
deemed to have paid $4.1 million and $20.6 million in
net cash distributions during the first nine months of 2006 and
2005, respectively.
Cash used in investing activities primarily represents
expenditures for capital projects. Cash used in financing
activities generally consists of contributions from and
distributions to owners.
The following information highlights the significant
period-to-period
variances in our cash flow amounts:
Operating activities. Net cash provided by
operating activities was $62.3 million for the first nine
months of 2006 compared to $37.2 million for the first nine
months of 2005. The $25.1 million increase in net cash
provided by operating activities is primarily due to higher
earnings for the first nine months of 2006 relative to the same
period in 2005 and the timing of cash receipts from sales and
cash payments for purchases and other expenses between periods.
For information regarding changes in revenues and costs and
expenses between the two nine month periods, please read
“— Results of Operations” above.
Investing activities. Cash used in investing
activities was $58.2 million for the first nine months of
2006 compared to $16.7 million for the first nine months of
2005. The $41.5 million increase in cash used in investing
activities is primarily due to an expansion of our Mont Belvieu,
Texas storage complex. The expansion includes the drilling of
two new brine production wells and the construction of two
above-ground brine storage reservoirs.
Financing activities. Net cash distributions
to owners were $4.1 million for the first nine months of
2006 compared to $20.6 million for the first nine months of
2005. The net change in cash distributions
resulted from an increase in cash provided by operating
activities and an increase in cash used for capital expenditures
for the first nine months of 2006.
Operating activities. Net cash provided by
operating activities was $40.6 million for 2005 compared to
$79.5 million for 2004. The $38.9 million decrease in
net cash provided by operating activities is primarily due to
lower earnings in 2005 relative to 2004 and the timing of cash
receipts from sales and cash payments for purchases and other
expenses between periods. For information regarding changes in
revenues and costs and expenses between the two years, please
read “— Results of Operations” above.
Investing activities. Cash used in investing
activities was $19.5 million for 2005 compared to
$6.9 million for 2004. The $12.6 million increase in
cash used in investing activities was primarily due to the
expansion of brine production and storage reservoirs at our Mont
Belvieu storage complex.
Financing activities. Net cash distributions
to owners were $21.1 million for 2005 compared to
$72.5 million for 2004. The change in cash distributions
results from a decrease in cash provided by operating activities
in 2005 combined with an increase in cash used for capital
expenditures in 2005.
Operating activities. Net cash provided by
operating activities was $79.4 million for 2004 compared to
$64.7 million for 2003. The $14.7 million increase in
net cash provided by operating activities is due to higher
earnings in 2004 relative to 2003 and the timing of cash
receipts from sales and cash payments for purchases and other
expenses between periods. For information regarding changes in
revenues and costs and expenses between the two years, please
read “— Results of Operations” above.
Investing activities. Cash used in investing
activities was $6.9 million for 2004 compared to
$0.3 million for 2003. In January 2002, we acquired a
number of storage wells from a third-party seller. The purchase
price we paid included four wells that were later determined not
to be usable for storage. We received a $10 million refund
of the purchase price from the seller in 2003, which is
reflected as “Cash refund from prior business
combination” on our Statements of Combined Cash Flows.
Financing activities. Net cash distributions
to owners were $72.5 million for 2004 compared to
$64.4 million for 2003. The change in cash distributions
results primarily from a $14.7 million increase in cash
provided by operating activities in 2004 partially offset by a
$6.6 increase in cash used in investing activities. As noted
above, cash used in investing activities for 2003 includes a
$10 million refund, related to an asset acquisition (a
benefit).
Capital
Requirements
General. The midstream energy business can be
capital intensive, requiring significant investment to maintain
and upgrade existing operations. For example, 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
connection with the regulations for hazardous liquid pipelines,
we developed a pipeline integrity management program in 2002. In
connection with the regulations for natural gas pipelines, we
developed a pipeline integrity management program in 2004.
We expect our net cash outlay for pipeline integrity program
expenditures to approximate $2.7 million during the
remainder of 2006.
Our capital requirements have consisted primarily of, and we
anticipate will continue to consist of, the following:
•
sustaining capital expenditures, which are capital expenditures
made to replace partially or fully depreciated assets, to
maintain the existing operating capacity of our assets and to
extend their useful lives, or other capital expenditures that
are incurred in maintaining existing system volumes and related
cash flows (such as pipeline integrity costs); and
•
growth capital expenditures such as those to acquire additional
assets to grow our business, to expand and upgrade gathering
systems and processing plants and to construct or acquire
similar systems or facilities.
During the first nine months of 2006, our capital expenditures,
including sustaining and growth capital expenditures, totaled
$59.0 million. We have budgeted sustaining capital
expenditures of $5.9 million for the year ending
December 31, 2007. We expect that the costs to complete the
planned expansion of the South Texas NGL pipeline after the
closing of this offering and Mont Belvieu brine production and
above-ground storage projects will be approximately
$42.7 million, of which our 66% share will be approximately
$28.2 million. We expect to use cash on hand from the
proceeds of this offering to fund our share of these planned
expansion costs and Enterprise Products Partners will make a
capital contribution to South Texas NGL and Mont Belvieu Caverns
for its 34% share of the planned expansion costs.
We are evaluating several expansion projects at our Mont Belvieu
facilities. The projects currently contemplated may be commenced
during 2007 in the range of $25 to $75 million. Additional
expenditures of up to $200 million may be made during 2008
and 2009. Pursuant to the Mont Belvieu Caverns limited liability
company agreement, Enterprise Products OLP may, in its sole
discretion, fund a portion of any costs related to these
projects. We cannot assure you that we will pursue any expansion
projects, but if we do, we expect to finance any such projects
through borrowings under our new revolving credit facility, the
issuance of debt or additional equity, or contributions from
Enterprise Products OLP. For a further description of our
agreements with Enterprise Products Partners relating to
potential expansion opportunities, please read
“Business — NGL & Petrochemical Storage
Services Segment — Mont Belvieu Expansion
Opportunities,” and “Certain Relationships and Related
Party Transactions — Mont Belvieu Caverns Limited
Liability Company Agreement — Future Mont Belvieu
Caverns Expansion Capital.”
New
Revolving Credit Facility
We have entered into a new $300 million revolving credit
facility, all of which may be used for letters of credit, with a
$30 million sublimit for Swingline loans. The funding date of
the revolving credit facility will occur not later than ninety
days after the closing of this offering, at which point, we may
make our initial drawing under the facility. The new revolving
credit facility will mature four years from the funding date. We
may make up to two requests for one-year extensions of the
maturity date (subject to certain restrictions). The revolving
credit facility will be available to pay distributions upon the
initial contribution of assets to us, fund working capital, make
acquisitions and provide payment for general partnership
purposes. We can increase the revolving credit facility, without
consent of the lenders, by an amount not exceeding
$150 million by
adding to the facility one or more new lenders and/or increasing
the commitments of existing lenders. No lender will be required
to increase its commitment, unless it agrees to do so in its
sole discretion.
The revolving credit facility offers the following unsecured
loans, each having different minimum amount and interest
requirements:
•
LIBOR loans. LIBOR loans can be exercised in a
minimum amount of $5 million and multiples of $1 million
thereafter. No more than eight LIBOR borrowings may be
outstanding at any time under the revolving credit facility.
LIBOR loans will bear interest, at a rate per annum, equal to
LIBOR plus the applicable LIBOR margin.
•
Base Rate Loans. Base Rate Loans can be
exercised in a minimum amount of $1 million and multiples of
$500 thousand thereafter. These loans bear interest, at a rate
per annum, equal to the Base Rate plus zero. The Base Rate is
the higher of (i) the rate of interest publicly announced by the
administrative agent, Wachovia Bank, National Association, as
its Base Rate and (ii) 0.5% per annum above the Federal Funds
Rate in effect on such date.
•
Swingline Loans. Swingline loans can be
exercised in a minimum amount of $1 million and multiples
of $100 thousand thereafter. These loans bear interest at the
LIBOR Market Interest Rate plus the applicable LIBOR margin.
The revolving credit facility may be prepaid in whole or in part
at any time upon same day notice, in a minimum amount of
$3 million with respect to LIBOR loans and $1 million
with respect to Base Rate Loans (or any lesser amount equal to
outstanding borrowings), and integral multiples of
$1 million above that amount. Unless LIBOR loans are
prepaid on interest payment dates, breakage costs could be
incurred.
The revolving credit facility requires us to maintain a leverage
ratio for the prior four fiscal quarters of not more than 4.75
to 1.00 at the last day of each fiscal quarter commencing
June 30, 2007; provided, upon the closing of a permitted
acquisition, such ratio shall not exceed (a) 5.25 to 1.00
at the last day of the fiscal quarter in which such specified
acquisition occurred and at the last day of each of the two
fiscal quarters following the fiscal quarter in which such
specified acquisition occurred, and (b) 4.75 to 1.00 at the last
day of each fiscal quarter thereafter. In addition, prior to
obtaining an investment-grade rating by Standard &
Poor’s Ratings Services, Moody’s Investors Service or
Fitch Ratings, our interest coverage ratio, for the prior four
fiscal quarters shall not be less than 2.75 to 1.00 at the last
day of each fiscal quarter commencing June 30, 2007.
Our new revolving credit facility contains various operating and
financial covenants, including those restricting or limiting our
ability, and the ability of certain of our subsidiaries, to:
•
make distributions;
•
incur additional indebtedness;
•
grant liens or make certain negative pledges;
•
engage in certain asset conveyances, sales, leases, transfers,
distributions or otherwise dispose of certain assets, businesses
or operations;
•
make certain investments;
•
enter into a merger, consolidation, or dissolution;
•
engage in transactions with affiliates;
•
directly or indirectly make or permit any payment or
distribution in respect of our partnership interests; or
•
permit or incur any limitation on the ability of any of our
subsidiaries to pay dividends or make distributions to, repay
indebtedness to, or make subordinated loans or advances
to us.
If an event of default exists under the new credit agreement,
the lenders will be able to accelerate the maturity of the
credit agreement and exercise other rights and remedies. Each of
the following is an event of default under the new credit
agreement:
•
non-payment of any principal, interest or fees when due under
the credit agreement subject to grace periods to be negotiated;
•
non-performance of covenants subject to grace periods to be
negotiated;
•
failure of any representation or warranty to be true and correct
in any material respect;
•
failure to pay any other material debt exceeding
$10 million in the aggregate;
•
a change of control;
•
other customary defaults, including specified bankruptcy or
insolvency events, the Employee Retirement Income Security Act
of 1974, or ERISA, violations, and judgment defaults.
The following table summarizes our significant contractual
obligations at December 31, 2005. There have been no
material changes in the nature or amounts of such obligations
subsequent to December 31, 2005 other than the capital
expenditures related to South Texas NGL discussed below.
Payment or Settlement Due by Period
Less Than
1-3
3-5
More Than
Contractual Obligations(1)
Total
1 Year
Years
Years
5 Years
(2006)
(2007-2008)
(2009-2010)
Beyond 2010
Operating leases:
Underground natural gas storage
cavern
$
3,276
$
468
$
936
$
936
$
936
Right-of-way
agreements
$
533
$
79
$
159
$
26
$
269
Purchase obligations:
Product purchase commitments:
Estimated payment obligations:
Natural gas
$
1,518,016
$
216,690
$
433,973
$
433,380
$
433,973
Other
$
7,480
$
2,138
$
4,282
$
1,060
Underlying major volume
commitments:
Natural gas (in Bbtus)
127,850
18,250
36,550
36,500
36,550
Capital expenditure commitments
$
616
$
616
Other long-term liabilities
$
608
$
608
Total
$
1,530,529
$
219,991
$
439,350
$
435,402
$
435,786
(1)
The contractual obligations in this table reflect the
obligations of our subsidiaries on a total consolidated basis
even though we own less than a 100% equity interest in our
operating subsidiaries.
Scheduled maturities of long-term debt. The
foregoing table does not reflect approximately $200 million
of borrowings that we expect to make under our new revolving
credit facility that we will enter into at or prior to the
closing of this offering.
Estimated cash payments for interest. The
foregoing table does not reflect any estimated cash payments for
interest on expected initial borrowings of approximately
$200 million under our new revolving credit facility that
are expected to be made under variable interest rates.
Operating leases. We lease certain property,
plant and equipment under non-cancelable and cancelable
operating leases. Amounts shown in the preceding table represent
our minimum cash lease payment obligations under operating
leases with terms in excess of one year for the periods
indicated.
Our Natural Gas Pipelines & Services segment leases an
underground natural gas storage cavern that is integral to its
operations. The primary use of this cavern is to store natural
gas
held-for-sale
by us. The current term of the cavern lease expires in December
2012. The term of this contract does not provide for an
additional renewal period, but it requires the lessor to enter
into diligent negotiations with us under similar terms and
conditions if we wish to extend the lease agreement beyond
December 2012.
In addition, our pipeline operations have entered into leases
for land held pursuant to
right-of-way
agreements. Our significant
right-of-way
agreements have original terms that range from five to
50 years and include renewal options that could extend the
agreements for up to an additional 25 years. Our rental
payments are generally at fixed rates, as specified in the
individual contracts, and may be subject to escalation
provisions for inflation and other market-determined factors.
Lease expense is charged to operating costs and expenses on a
straight line basis over the period of expected economic
benefit. Contingent rental payments, if any, are expensed as
incurred. In general, we are 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
attributable to our operations are charged to expense as
incurred. We have not made any significant leasehold
improvements during the periods presented. Lease expense
included in operating income was $1.2 million for each of
the years ended December 31, 2005, 2004 and 2003 and
$0.9 million and $1.0 million for the nine months
ended September 30, 2006 and 2005, respectively.
Purchase Obligations. We define purchase
obligations as agreements to purchase goods or services that are
enforceable and legally binding (unconditional) on us that
specify all significant terms, including: fixed or minimum
quantities to be purchased; fixed, minimum or variable price
provisions; and the approximate timing of the transactions.
Our Natural Gas Pipelines & Services segment has a
product purchase commitment for the purchase of natural gas in
Louisiana from a third party. This purchase agreement expires in
January 2013. Our purchase price under this contract
approximates the market price of natural gas at the time we take
delivery of the volumes. The preceding table shows the volume we
are committed to purchase and an estimate of our future payment
obligations for the periods indicated. Our estimated future
payment obligations are based on the contractual price at
December 31, 2005 applied to all future volume commitments.
Actual future payment obligations may vary depending on market
prices at the time of delivery.
At December 31, 2005, we do not have any product purchase
commitments with fixed or minimum pricing provisions having
remaining terms in excess of one year.
We also have short-term payment obligations relating to capital
projects we have initiated. These commitments represent
unconditional payment obligations that we have agreed to pay
vendors for services to be rendered or products to be delivered
in connection with our capital spending programs. The preceding
table shows these capital project commitments for the periods
indicated.
In August 2006, Enterprise Products Partners purchased
223 miles of NGL pipelines extending from Corpus Christi,
Texas to Pasadena, Texas from ExxonMobil Pipeline Company. The
total purchase price for this asset was approximately
$97.7 million in cash. Enterprise Products Partners will
contribute this pipeline system to South Texas NGL prior to the
closing of this offering. This pipeline system is used to
transport NGLs from two Enterprise Products Partners’
facilities to Mont Belvieu, Texas. The total estimated cost to
acquire and construct the additional pipelines that will
complete this system is $66.3 million. South Texas NGL made
capital expenditures of $37.7 million to make this pipeline
system operational in January 2007. We expect that it will cost
approximately $28.6 million to complete planned expansions
of the South Texas NGL pipeline after the closing of this
offering, of which our 66% share will be approximately
$18.9 million. In addition, we expect that Mont Belvieu
Caverns will make additional capital expenditures of
$14.1 million to complete construction of brine production
capacity and above-ground storage reservoirs, of which our 66%
share will be approximately $9.3 million. Following this
offering, we expect to use cash on hand from the proceeds of
this offering to fund our share of the planned expansion costs.
The preceding contractual obligations table does not include
these capital expenditures entered into after December 31,2005.
Other Long-Term Liabilities. We have recorded
long-term liabilities on our combined balance sheet reflecting
amounts we expect to pay in future periods beyond one year.
These liabilities primarily represent the present value of our
asset retirement obligations. Amounts shown in the preceding
table represent our best estimate as to the timing of
settlements based on information currently available.
$23.2 million in principal amount of 9.9% fixed interest
rate senior secured notes due December 2010 (the
“Series B” notes); and
•
a $7.5 million subordinated note payable to Evangeline
Northwest Corporation (the “ENC Note”).
The Series B notes are collateralized by the following:
•
Evangeline’s property, plant and equipment;
•
proceeds from Evangeline’s Entergy Louisiana natural gas
sales contract; and
•
a debt service reserve requirement.
Scheduled principal repayments on the Series B notes are
$5 million annually through 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
was in compliance with such covenants during the periods
presented.
Evangeline incurred the ENC Note obligations in connection with
its acquisition of the Entergy natural gas sales contract in
1991. The ENC 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 note holders are
either fully cash secured through debt service accounts or have
been completely repaid. Variable rate interest accrues on the
subordinated note at a LIBOR rate plus 0.5%. Variable interest
rates charged on this note at December 31, 2005 and 2004
were 4.23% and 1.83%, respectively.
Except for the foregoing, we have no off-balance sheet
arrangements 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.
Inflation in the United States has been relatively low in recent
years and did not have a material impact on our results of
operations for the three-year period ended December 31,2005 or the first nine months of 2006. It may in the future,
however, increase the cost to acquire or replace property, plant
and equipment and may increase the costs of labor and supplies.
Our operating revenues and costs are influenced to a greater
extent by specific price changes in natural gas and NGLs. To the
extent permitted by competition, regulation and our existing
agreements, we have and will continue to pass along increased
costs to our customers in the form of higher fees and through
escalation provisions in specific contracts.
In our financial reporting process, we employ methods, estimates
and assumptions that will 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 is a description of the estimation risk
underlying our most significant financial statement items.
Depreciation
methods and estimated useful lives of property, plant and
equipment
In general, depreciation is the systematic and rational
allocation of an 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 on a
going forward basis. Some of these circumstances include changes
in laws and regulations relating to restoration and abandonment
requirements; changes in expected costs for dismantlement,
restoration and abandonment as a result of changes, or expected
changes, in labor, materials and other related costs associated
with these activities; changes in the useful life of an asset
based on the actual known life of similar assets, changes in
technology, or other factors; and changes in expected salvage
proceeds as a result of a change, or expected change in the
salvage market.
At September 30, 2006 and December 31, 2005, the net
book value of our property, plant and equipment was
$656.0 million and $512.2 million, respectively. We
recorded $19.2 million, $18.1 million and
$17.6 million in depreciation expense during the years
ended December 31, 2005, 2004 and 2003, respectively.
Depreciation expense was $15.4 million and
$14.2 million for the nine months ended September 30,2006 and 2005, respectively.
Measuring
recoverability of long-lived assets and equity method
investments
In general, long-lived assets 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. Fair value of a long-lived
asset is estimated through appropriate valuation techniques,
which consider quoted market prices, replacement cost estimates
and probability-weighted discounted cash flows. We did not
recognize any asset impairment charges during the periods
presented.
Equity method investments are 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 by the investee or long-term negative changes in the
investee’s industry. The carrying value of an equity method
investment is not recoverable if it exceeds the sum of the
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 did not recognize any
impairment charges related to our Evangeline affiliate during
the periods presented.
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.
Intangible assets include, but are not limited to, patents,
trademarks, trade names, contracts, customer relationships and
non-compete agreements. The method used to value each intangible
asset varies depending upon the nature of the intangible asset,
the business in which it is utilized, and the economic returns
it is generating or is expected to generate.
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.
Our intangible assets consist primarily of renewable storage
contracts with various customers that we acquired in connection
with the purchase of storage caverns from a third party in
January 2002. Due to the renewable nature of these contracts, we
amortize them on a straight-line basis over a
35-year
period, which is the estimated remaining economic life of the
storage assets to which they relate.
At September 30, 2006 and December 31, 2005, the
carrying value of our intangible asset portfolio was
$7.0 million and $7.2 million, respectively. We
recorded $0.2 million in amortization expense associated
with our intangible assets for all periods presented.
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
•
collectibility is reasonably assured.
When sales contracts are settled (i.e., either physical delivery
of product has taken place or the services designated in the
contract have been performed), we record any necessary allowance
for doubtful accounts.
We make estimates for certain revenue and expense items due to
time constraints on the financial accounting and reporting
process. At times, we must estimate revenues from a customer
before we actually bill the customer or accrue an expense we
incur before physically receiving a vendor’s invoice. Such
estimates reverse in the following period and are offset by our
recording the actual customer billing and vendor invoice
amounts. If the basis of our estimates proves to be
substantially incorrect, it could result in material adjustments
in results of operations between periods. For all periods
presented, our revenue and cost estimates are substantially
correct as compared to actual amounts.
Natural
gas imbalances
Natural gas imbalances result when a customer injects more or
less gas into a pipeline than it withdraws. The values of our
imbalance receivables and payables are based on natural gas
prices during the month such imbalances are created.
At December 31, 2005 and 2004, our imbalance receivables
were $1.6 million and $1.8 million, respectively, and
are reflected as a component of “Accounts
receivable — trade” on our Combined Balance
Sheets. At December 31, 2005 and 2004, our imbalance
payable was $2.9 million and $0.5 million
respectively, and is reflected as a component of “Accrued
gas payables” on our Combined Balance Sheets. At
September 30, 2006, our imbalance receivable was
$1.9 million and our imbalance payable was
$0.5 million.
Storage well gains and losses occur when product movements into
a storage well are different than those redelivered to
customers. In general, such variations result from difficulties
in precisely measuring significant volumes of liquids at varying
flow rates and temperatures. It is expected that substantially
all product delivered into a storage will be withdrawn over
time. A measurement loss in one period is expected to be offset
by a measurement gain in a subsequent period, unless product is
physically lost in a storage well due to problems with cavern
integrity. We did not experience any significant net losses
resulting from problems with cavern integrity during the three
years ended December 31, 2005 or for the nine month period
ended September 30, 2006.
Since we expect that storage well gains and losses will
approximate each other over time, we historically charged
storage well gains or losses to a storage imbalance account
during the month such imbalances are created based on current
pricing. The reserve was increased by measurement gains and loss
accruals and decreased by measurement losses. On an annual
basis, the storage imbalance reserve account was reviewed for
reasonableness based on historical storage well measurement
gains and losses and adjusted accordingly through a charge to
earnings. At December 31, 2005 and 2004, our storage
imbalance account was $4.5 million and $3.5 million.
At September 30, 2006, our storage imbalance was
$1.8 million. Net measurement losses of $2.0 million,
$2.2 million and $1.5 million were charged to the
reserve during the years ended December 31, 2005, 2004 and
2003, respectively, and $2.7 and $1.9 million for the nine
months ended September 30, 2006 and 2005, respectively.
Operating costs and expenses reflect well loss accruals of
$3.1 million, $0.6 million and $2.4 million for
the years ended December 31, 2005, 2004 and 2003,
respectively, and $0 and $2.5 million for the nine months
ended September 30, 2006 and 2005, respectively.
In addition, operating gains and losses due to measurement
variances for product movements to and from storage wells
relating primarily to pipeline and well connection activities
are included in our financial statements. Many of our customer
storage arrangements allow us to retain a small amount of liquid
volumes to help offset any measurement losses. These variances
are estimated and settled at current prices each reporting
period as a net credit or charge to operating costs and
expenses. We do not retain volumes in inventory. The net amounts
for each of the years ended December 31, 2005, 2004 and
2003 were a $2.1 million charge, $0.2 million credit
and $1.4 million credit, respectively, and a
$1.0 million charge and a $3.2 million charge for the
nine months ended September 30, 2006 and 2005, respectively.
In connection with storage agreements for a variety of products
entered into between Enterprise Products Partners and Mont
Belvieu Caverns effective concurrently with the closing of this
offering, Enterprise Products Partners will agree to the
allocation of all storage well measurement gains and losses
relating to these products.
In addition, the limited liability company agreement for Mont
Belvieu Caverns will specially allocate to Enterprise Products
Partners any items of income and gain or loss and deduction
relating to measurement losses and measurement gains, including
amounts that Mont Belvieu Caverns may retain or deduct as
handling losses. Enterprise Products Partners will also be
required to contribute cash to Mont Belvieu Caverns, or will be
entitled to receive distributions from Mont Belvieu Caverns,
based on the then-current net measurement gains or measurement
losses. As a result, we will continue to record measurement
gains and losses associated with the operation of our Mont
Belvieu storage facility for parties other than Enterprise
Products Partners after the closing date of this offering on a
consolidated basis as operating costs and expenses. However,
these measurement gains and losses should not affect our net
income or have a significant impact on us with respect to our
cash flows from operating activities and, accordingly, no
reserve account will be established by us for measurement losses
on our balance sheet.
Emerging Issues Task Force (“EITF”) 04-13,
“Accounting for Purchases and Sales of Inventory With the
Same Counterparty.”This accounting guidance requires
that two or more inventory transactions with the same
counterparty be viewed as a single non-monetary transaction, if
the transactions were entered into in contemplation of one
another. Exchanges of inventory between entities in the same
line of business should be
accounted for at fair value or recorded at carrying amounts,
depending on the classification of such inventory. This guidance
was effective April 1, 2006, and our adoption of this
guidance had no impact on our combined financial position,
results of operations or cash flows.
EITF 06-3,
“How Taxes Collected From Customers and Remitted to
Governmental Authorities Should Be Presented in the Income
Statement (That Is, Gross versus Net Presentation).”This accounting guidance requires companies to disclose
their policy regarding the presentation of tax receipts on the
face of their income statements. This guidance specifically
applies to taxes imposed by governmental authorities on
revenue-producing transactions between sellers and customers
(gross receipts taxes are excluded). This guidance is effective
January 1, 2007. As a matter of policy, we report such
taxes on a net basis.
Financial Accounting Standards Board Interpretation
(“FIN”) No. 48, “Accounting for Uncertainty
in Income Taxes, an Interpretation of SFAS 109, Accounting
for Income Taxes.”FIN 48 provides that the tax
effects of an uncertain tax position should be recognized in a
company’s financial statements if the position taken by the
entity is more likely than not sustainable, if it were to be
examined by an appropriate taxing authority, based on technical
merit. After determining a tax position meets such criteria, the
amount of benefit to be recognized should be the largest amount
of benefit that has more than a 50 percent chance of being
realized upon settlement. The provisions of FIN 48 are not
material to our financial statements.
Statement of Financial Accounting Standards
(“SFAS”) 155, “Accounting for Certain Hybrid
Financial Instruments.” This accounting standard
amends SFAS 133, Accounting for Derivative Instruments
and Hedging Activities, amends SFAS 140, Accounting
for Transfers and Servicing of Financial Assets and
Extinguishments of Liabilities, and resolves issues
addressed in Statement 133 Implementation Issue D1,
Application of Statement 133 to Beneficial Interests to
Securitized Financial Assets. A hybrid financial
instrument is one that embodies both an embedded derivative and
a host contract. For certain hybrid financial instruments,
SFAS 133 requires an embedded derivative instrument be
separated from the host contract and accounted for as a separate
derivative instrument. SFAS 155 amends SFAS 133 to
provide a fair value measurement alternative for certain hybrid
financial instruments that contain an embedded derivative that
would otherwise be recognized as a derivative separately from
the host contract. For hybrid financial instruments within its
scope, SFAS 155 allows the holder of the instrument to make
a one-time, irrevocable election to initially and subsequently
measure the instrument in its entirety at fair value instead of
separately accounting for the embedded derivative and host
contract. We are evaluating the effect of this recent guidance,
which is effective January 1, 2007.
SFAS 157, “Fair Value Measurements.”This
accounting standard defines fair value, establishes a framework
for measuring fair value in generally accepted accounting
principles, and expands disclosures about fair value
measurements. SFAS 157 applies only to fair-value
measurements that are already required or permitted by other
accounting standards and is expected to increase the consistency
of those measurements. The statement 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 will be required to disclose the
extent to which fair value is used to measure assets and
liabilities, the inputs used to develop the measurements, and
the effect of certain of the measurements on earnings (or
changes in net assets) for the period. SFAS 157 is
effective for fiscal years beginning after December 15,2007 and we will be required to adopt SFAS 157 as of
January 1, 2008. We are currently evaluating the impact of
adopting SFAS 157 on our financial position, results of
operations, and cash flows.
Staff Accounting Bulletin (“SAB”) No. 108,
“Considering the Effects of Prior Year Misstatements when
Quantifying Misstatements in Current Year Financial
Statements.”SAB 108 addresses how the effects of
prior-year uncorrected misstatements should be considered when
quantifying misstatements in current-year financial statements.
The SAB requires registrants to quantify misstatements using
both the balance-sheet and income-statement approaches and to
evaluate whether either approach results in quantifying an error
that is material in light of relevant quantitative and
qualitative factors. When the effect of initial adoption is
determined to be material, SAB 108 allows registrants to
record that effect as a cumulative-effect adjustment to
beginning-of-year
retained earnings. The requirements are effective for annual
financial statements covering the first fiscal year ending after
November 15, 2006. Additionally, the nature and amount of
each individual error being corrected through the
cumulative-effect adjustment, when and how each error arose, and
the fact that the errors
had previously been considered immaterial is required to be
disclosed. We are required to adopt SAB 108 for our current
fiscal year ending December 31, 2006. We do not expect the
adoption of SAB 108 to have a material impact on our
financial statements.
We have an extensive and ongoing business relationships with
EPCO and Enterprise Products Partners and each of their
affiliates, including the following:
•
Enterprise Products Partners. Enterprise
Products Partners will assign to us all of the exchange
agreements with the customers of our Sabine Propylene and
Lou-Tex Propylene pipelines but will remain jointly and
severally liable on these agreements. We also provide
underground storage services to Enterprise Products Partners and
its affiliates to store NGLs and petrochemicals. Prior to the
closing of this offering, we will become party to a ground lease
with Enterprise Products Partners as a result of an assignment
by an affiliate of Enterprise Products Partners. Upon the
completion of our offering, we expect that certain terms of the
related party storage contracts between us and Enterprise
Products Partners will change, including (1) a reduction in
transportation rates on our Lou-Tex Propylene and Sabine
Propylene pipelines, (2) an increase in underground storage
fees and (3) the allocation to Enterprise Products Partners
of all storage measurement gains and losses relating to its
products. In addition, the limited liability company agreement
for Mont Belvieu Caverns will specially allocate measurement
gains and losses to Enterprise Products Partners, and contain
related contribution and distribution provisions. Enterprise
Products Partners will also remain jointly and severally liable
for certain contracts with third parties that it will assign to
us. Concurrently with the closing of this offering, we will
enter into an omnibus agreement with Enterprise Products OLP
pursuant to which Enterprise Products OLP will agree to
(i) indemnify us for certain environmental liabilities, tax
liabilities and title and
right-of-way
defects occurring or existing before the closing of this
offering and (ii) reimburse us for our 66% share of
excess construction costs, if any, above our current estimated
cost to complete planned expansions on the South Texas NGL
pipeline and Mont Belvieu Caverns brine-related facilities. In
addition, we will grant Enterprise Products OLP a right of first
refusal on the equity interests in certain of our operating
subsidiaries and on the material assets of these entities, other
than sales of inventory and other assets in the ordinary course
of business.
•
TEPPCO Partners. During January 2007, an
affiliate of Enterprise Products Partners purchased from an
affiliate of TEPPCO Partners a
10-mile,
18-inch
segment of pipeline that forms part of the South Texas NGL
pipeline for an aggregate purchase price of $8 million.
This pipeline will be among the assets owned by South Texas NGL
at the closing of this offering. We have also entered into a
lease with TEPPCO Partners for a
12-mile,
10-inch
interconnecting pipeline extending from Pasadena, Texas to
Baytown, Texas. The primary term of this lease will expire on
September 15, 2007, and will continue on a month-to-month
basis subject to termination by either party upon
60 days’ notice. This pipeline is being leased by us
in connection with operations on our South Texas NGL pipeline
until we complete the construction of a parallel pipeline.
•
EPCO. We have no employees. Prior to the
closing of this offering, we will become party to the
administrative services agreement with EPCO. Under this
agreement, EPCO will provide general administrative, management,
engineering and operating services as may be necessary to
operate our businesses, properties and assets (in accordance
with prudent industry practices). We will be 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 EPCO
expenses reasonably allocated to us). The administrative
services agreement also contains agreements relating to business
opportunities.
•
Evangeline. We sell natural gas to Evangeline,
which, in turn, uses such natural gas to satisfy its sales
commitments to Entergy Louisiana. In addition, we also have a
service agreement with Evangeline whereby we provide Evangeline
with construction, operations, maintenance and administrative
support related to its pipeline system.
For more information, please read “Certain Relationships
and Related Party Transactions” and Note 6 of the
combined financial statements of the Duncan Energy Partners
Predecessor.
Provision for income taxes — Texas Margin
Tax. All of our operating subsidiaries are
organized as pass-through entities for income tax purposes. As a
result, the owners of such entities are responsible for federal
income taxes on their share of each entity’s taxable income.
In May 2006, the State of Texas substantially revised its
existing state franchise tax. The revised tax (the “Texas
Margin Tax”) becomes effective for franchise tax reports
due on or after January 1, 2008. In general, legal entities
that conduct business in Texas and benefit from limited
liability protection are subject to the Texas Margin Tax. We
believe that our operating subsidiaries will be subject to the
Texas Margin Tax on the portion of their revenues generated in
Texas. We recorded an estimated deferred tax liability of
approximately $21 thousand for the Texas Margin Tax in June
2006, with an offsetting expense shown as provision for income
taxes.
Cumulative effect of changes in accounting
principles. We recorded a cumulative effect of a
change in accounting principle of $0.6 million in
connection with our implementation of FASB Interpretation
No. 47, “Accounting for Conditional Asset
Requirement Obligations”(“FIN 47”) in
December 2005, which represents the depreciation and accretion
expense we would have recognized had we recorded these
conditional asset retirement obligations when incurred. The pro
forma effects of our adoption of FIN 47 are not presented
due to the immaterial nature of these amounts to our financial
statements. Based on information currently available, we
estimate that annual accretion expense will approximate
$0.1 million for each of the years 2006 through 2010.
Certain key employees of EPCO who allocate a portion of their
time to our affairs participate in long-term incentive
compensation plans managed by EPCO. These plans include the
issuance of restricted units of Enterprise Products Partners and
limited partner interests in EPE Unit L.P., a Delaware limited
partnership. Prior to January 1, 2006, EPCO accounted for
these awards using the provisions of Accounting Principles Board
Opinion 25, “Accounting for Stock Issued to
Employees.” On January 1, 2006, EPCO adopted
Statement of Financial Accounting Standards
(“SFAS”) 123(R), “Accounting for
Stock-Based Compensation,” to account for such awards.
Upon adoption of this accounting standard, we recognized a
cumulative effect of change in accounting principle of
$9 thousand (a benefit). Such awards are immaterial to our
combined financial position, results of operations and cash
flows.
General. We use financial instruments in our
Natural Gas Pipelines & Services segment to secure
certain fixed price natural gas sales contracts (referred to as
“customer fixed-price arrangements”). We also enter
into a limited number of cash flow hedges in connection with
such business. We recognize such instruments on the balance
sheet as assets or liabilities based on an instrument’s
fair value. Fair value is generally defined as the amount at
which the financial instrument could be exchanged in a current
transaction between willing parties, not in a forced or
liquidation sale. Changes in fair value of financial instrument
contracts are recognized currently in earnings unless specific
hedge accounting criteria are met.
To qualify as a hedge, the item to be hedged must expose us to
commodity price risk and the hedging instrument must reduce the
exposure and meet the hedging requirements of SFAS 133,
“Accounting for Derivative Instruments and Hedging
Activities” (as amended and interpreted). We formally
designate such financial instruments as hedges and document and
assess the effectiveness of the hedge at inception and on a
quarterly basis. Any ineffectiveness is immediately recognized
in earnings. Our customer fixed-price arrangements do not
qualify for hedge accounting under SFAS 133; therefore,
these instruments are accounted for using a
mark-to-market
approach each reporting period.
If a financial instrument meets the criteria of a cash flow
hedge, gains and losses from the instrument are recorded in
other comprehensive income. Gains and losses on cash flow hedges
are reclassified from other
comprehensive income to earnings when the forecasted transaction
occurs or, as appropriate, over the economic life of the
underlying asset. If the financial instrument meets the criteria
of a fair value hedge, gains and losses from the instrument will
be recorded on the income statement to offset corresponding
losses and gains of the hedged item. A contract designated as a
hedge of an anticipated transaction that is no longer likely to
occur is immediately recognized in earnings.
Commodity financial instrument portfolio. In
addition to its natural gas transportation business, our Natural
Gas Pipelines & Services segment engages in the
purchase and sale of natural gas to third party customers in the
Louisiana area. The price of natural gas fluctuates in response
to changes in supply, market uncertainty, and a variety of
additional factors that are beyond our control. We may use
commodity financial instruments such as futures, swaps and
forward contracts to mitigate such risks. In general, the types
of risks we attempt to hedge are those related to the
variability of future earnings and cash flows resulting from
changes in applicable commodity prices. The commodity financial
instruments we utilize may be settled in cash or with another
financial instrument. As a matter of policy, we do not use
financial instruments for speculative (or “trading”)
purposes.
Our Natural Gas Pipelines & Services segment enters
into a small number of cash flow hedges in connection with its
purchase of natural gas
held-for-sale.
In addition, our Natural Gas Pipelines & Services
segment enters into a limited number of offsetting financial
instruments that effectively fix the price of natural gas for
certain of its customers. Historically, the use of commodity
financial instruments was governed by policies established by
the general partner of Enterprise Products Partners. The
objective of this policy was to assist us in achieving its
profitability goals while maintaining a portfolio with an
acceptable level of risk, defined as remaining within the
position limits established by the general partner. In general,
we may enter into risk management transactions to manage price
risk, basis risk, physical risk or other risks related to its
commodity positions on both a short-term (less than
30 days) and long-term basis, not to exceed 24 months.
The general partner of Enterprise Products Partners monitored
the hedging strategies associated with the physical and
financial risks of our Natural Gas Pipelines & Services
segment (such as those mentioned previously), approved specific
activities subject to the policy (including authorized products,
instruments and markets) and established specific guidelines and
procedures for implementing and ensuring compliance with the
policy. Our general partner will continue such policies in the
future.
Due to the limited number and nature of the financial
instruments utilized by us, the effect on the portfolio of a
hypothetical 10% movement in the underlying quoted market prices
of natural gas is negligible at September 30, 2006 and
December 31, 2005 and 2004. The fair value of our commodity
financial instrument portfolio was a negligible amount at
September 30, 2006, a liability of $0.1 million at
December 31, 2005, and a liability of $0.3 million at
December 31, 2004.
We recorded losses of $0.2 million and $0.8 million
related to our commodity financial instruments for the years
ended December 31, 2005 and 2003, respectively. In 2004, we
recorded a gain of $0.2 million from our commodity
financial instruments. We recorded $0.3 million gain
related to our commodity financial instruments during the nine
months ended September 30, 2006. We recorded
$0.2 million of expense related to this portfolio during
the nine months ended September 30, 2005.
Product purchase commitments. Our Natural Gas
Pipelines & Services segment has a long-term natural
gas purchase contract with a third party. This purchase
agreement expires in January 2013. Our purchase price under this
contract approximates the market price of natural gas at the
time we take delivery of the volumes. For additional information
regarding our commitments, please read
“— Contractual Obligations” above.
We are a Delaware limited partnership formed by Enterprise
Products Partners in September 2006 to own, operate and acquire
a diversified portfolio of midstream energy assets. We are
engaged in the business of gathering, transporting, marketing
and storing natural gas and transporting and storing NGLs and
petrochemicals. Our assets were previously owned by Enterprise
Products Partners and are part of its integrated midstream
energy asset network or value chain, which includes natural gas
gathering, processing, transportation and storage; NGL
fractionation (or separation), transportation, storage and
import and export terminaling; crude oil transportation; and
offshore production platform services. After this offering, we
will own 66% of the equity interests in the subsidiaries that
hold our operating assets and affiliates of Enterprise Products
Partners will continue to own the remaining 34%. We believe our
relationship with Enterprise Products Partners will enable us to
maintain stable cash flows and optimize our scale, strategic
location and pipeline connections.
Our operations are organized into the following four business
segments:
•
NGL & Petrochemical Storage
Services. Our NGL & Petrochemical
Storage Services segment consists of 33 salt dome caverns
located in Mont Belvieu, Texas, with an underground storage
capacity of approximately 100 MMBbls, and certain related
assets. These assets receive, store and deliver NGLs and
petrochemical products for industrial customers located along
the upper Texas Gulf Coast, which has the largest concentration
of petrochemical plants and refineries in the United States.
•
Natural Gas Pipelines & Services. Our
Natural Gas Pipelines & Services segment consists of
the Acadian Gas system, which is an onshore natural gas pipeline
system that gathers, transports, stores and markets natural gas
in Louisiana. The Acadian Gas system links natural gas supplies
from onshore and offshore Gulf of Mexico developments (including
offshore pipelines, continental shelf and deepwater production)
with local gas distribution companies, electric generation
plants and industrial customers, including those in the Baton
Rouge-New Orleans-Mississippi River corridor. In the aggregate,
the Acadian Gas system includes over 1,000 miles of
high-pressure transmission lines and lateral and gathering lines
with an aggregate throughput capacity of approximately one Bcf/d
and a leased storage facility with approximately three Bcf of
storage capacity.
•
Petrochemical Pipeline Services. Our
Petrochemical Pipeline Services segment consists of two
petrochemical pipeline systems with an aggregate of
284 miles of pipeline. The Lou-Tex Propylene pipeline
system consists of a
263-mile
pipeline used to transport chemical-grade propylene between
Sorento, Louisiana and Mont Belvieu, Texas. The Sabine Propylene
pipeline system consists of a
21-mile
pipeline used to transport polymer-grade propylene from Port
Arthur, Texas to a pipeline interconnect in Cameron Parish,
Louisiana on a
transport-or-pay
basis.
•
NGL Pipeline Services. Our NGL Pipeline
Services segment consists of a
290-mile
pipeline system used to transport NGLs from two Enterprise
Products Partners’ facilities located in South Texas to
Mont Belvieu, Texas and related interconnections. We acquired a
223-mile
segment of the system in August 2006, and we are in the process
of acquiring and constructing other segments of the pipeline.
This system became operational and began transporting NGLs in
January 2007 after undergoing modifications, extensions and
interconnections. Additional expansions to this system are
scheduled to be completed during the remainder of 2007.
One of our principal attributes is our relationship with
Enterprise Products Partners and EPCO. Our assets connect to
various midstream energy assets of Enterprise Products Partners
and, therefore, form integral links within Enterprise Products
Partners’ value chain. Enterprise Products Partners is a
North American midstream energy company that provides a wide
range of services to producers and consumers of natural gas,
NGLs and crude oil, and is an industry leader in the development
of pipeline and other midstream infrastructure in the
continental United States and Gulf of Mexico. Enterprise
Products Partners’ value chain is an integrated midstream
energy asset network that 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 believe the operational
significance of these assets to Enterprise Products Partners, as
well as the alignment of our respective economic interests in
them, will result in a collaborative effort to promote their
operational efficiency and maximize value.
All of our and Enterprise Products Partners’ management,
administrative and operating functions will be performed by
employees of EPCO, Enterprise Products Partners’ ultimate
parent company under common control by Dan L. Duncan, pursuant
to an amended and restated administrative services agreement.
Dan L. Duncan and his affiliates will have a significant
interest in our partnership through Enterprise Products
OLP’s ownership of 34% of the equity interests in our
operating subsidiaries and Enterprise Products OLP’s direct
ownership of approximately 36.0% of our outstanding common units
(or approximately 26.4% if the underwriters’ option to
purchase additional units is exercised in full) and indirect
ownership of our 2% general partner interest. We believe our
relationship with Enterprise Products Partners and EPCO provides
us with a distinct advantage in both the operation of our
current assets and in the identification and execution of
potential future acquisitions that are not otherwise taken by
Enterprise Products Partners or Enterprise GP Holdings in
accordance with our business opportunity agreements.
Our primary business objectives are to maintain and, over time,
to increase our cash available for distributions to our
unitholders. Our business strategies to achieve these objectives
are to:
•
optimize the benefits of our economies of scale, strategic
location and pipeline connections serving our natural gas, NGL,
petrochemical and refining markets;
•
manage our existing and future asset portfolio to minimize the
volatility of our cash flows;
•
invest in organic growth projects to capitalize on market
opportunities which expand our asset base and generate
additional cash flow; and
•
pursue acquisitions of assets and businesses from related
parties, or, in accordance with our business opportunity
agreements, from third parties.
We believe we are well-positioned to achieve our primary
objectives and to execute our business strategies successfully
because of the following competitive strengths:
•
our operations currently consist of mature assets and a new NGL
pipeline which are expected to generate stable, predictable cash
flows;
•
our assets are strategically located in areas with high demand
for our services play a critical role in Enterprise Products
Partners’ midstream energy value chain;
•
Enterprise Products Partners and EPCO have established a
reputation in the midstream natural gas and NGL industry as
reliable and cost-effective operators;
•
the senior management team and board of directors of our general
partner have extensive industry experience and include some of
the most senior officers of Enterprise Products Partners and
EPCO;
•
we have a lower cost of capital than other publicly-traded
partnerships that have incentive distribution rights; and
•
our affiliation with Enterprise Products Partners and its
affiliates, may provide us access to attractive acquisition
opportunities from them and third parties.
We are currently engaged in the business of gathering,
transporting, marketing, and storing natural gas and
transporting, marketing and storing NGLs and petrochemicals. Our
business is directly impacted by changes in domestic demand for
and production of natural gas, NGLs, propylene and other
petrochemical products.
Natural
Gas Demand and Production
Natural gas continues to be a critical component of energy
consumption in the United States. According to the Energy
Information Administration, or the EIA, total annual domestic
consumption of natural gas is expected to increase from
approximately 22.4 trillion cubic feet, or Tcf,
(61.4 Bcf/d) in 2004 to approximately 26.9 Tcf
(73.7 Bcf/d) in 2030, representing an average annual growth
rate of over 1.12% per year. Most of that increase is
expected to occur before 2017, when total U.S. natural gas
consumption reaches just over 26.5 Tcf. After 2017, rising
natural gas prices are predicted to curb consumption growth and
reduce the natural gas share of total energy consumption. The
industrial and electricity generation sectors are the largest
users of natural gas in the United States. During the last three
years, these sectors accounted for approximately 56% of the
total natural gas consumed in the United States. In 2004,
natural gas represented approximately 24% of all end-user
domestic energy requirements. During the last five years, the
United States has on average consumed approximately
22.4 Tcf per year, with average annual domestic production
of approximately 18.9 Tcf during the same period. Driven by
growth in natural gas demand and high natural gas prices,
domestic natural gas production is projected to increase from
18.5 Tcf per year to 20.4 Tcf per year between 2004 and 2015.
Midstream
Industry
Once natural gas is produced from wells, producers then seek to
deliver the natural gas and its components to end-use markets.
The midstream natural gas industry is the link between upstream
exploration and production activities and downstream end-user
markets, and generally consists of natural gas gathering,
transportation, processing, storage and fractionation
activities. The midstream industry is generally characterized by
regional competition based on the proximity of gathering systems
and processing plants to natural gas producing wells.
The following diagram illustrates the natural gas gathering,
processing, fractionation, storage and transportation process.
We supply Enterprise Products Partners and our other customers
with several gathering, transportation, and storage services for
their natural gas, NGL and petrochemical products.
Natural
Gas Gathering
Once a well has been completed, the well is connected to a
gathering system. Gathering systems typically consist of a
network of small diameter pipelines and, if necessary,
compression systems that collect natural gas from points near
producing wells and transport it to larger pipelines for further
transmission. Offshore gathering uses a similar process, but
production platforms provide production handling services, which
in the case of a well producing a mixture of oil and gas
involves the separation of natural gas from the oil and water
before the natural gas enters the gathering lateral. Gathering
laterals then connect to a main or trunk line of larger diameter
pipe. The mainline then transports the natural gas collected
from the various laterals to an onshore location, typically a
treating facility or gas processing plant. Our Natural Gas
Pipelines & Services business segment provides for the
gathering, transmission, and storage of natural gas in
Louisiana, and currently consists of over 1,000 miles of
onshore natural gas pipelines.
Natural
Gas Treating
Natural gas has a varied composition depending on the field, the
formation and the reservoir from which it is produced. Treating
plants remove carbon dioxide and hydrogen sulfide from natural
gas to ensure that it meets pipeline quality specifications. The
principal component of natural gas is methane, but most natural
gas also contains varying amounts of NGLs including ethane,
propane, normal butane, isobutane and natural gasoline. NGLs
have economic value and are utilized as a feedstock in the
petrochemical and oil refining industries or directly as a
heating, engine or industrial fuel. Once separated from the
natural gas, NGLs must be handled and transported to its end
users through a dedicated pipeline system.
Natural
Gas Transportation
Natural gas transportation pipelines receive natural gas from
other mainline transportation pipelines and gathering systems
and deliver the processed natural gas to industrial end-users
and utilities and to other pipelines. Our Natural Gas
Pipelines & Services business segment currently engages
in natural gas transportation.
NGL
Fractionation
NGL fractionation facilities separate mixed NGL streams into
discrete NGL products, including ethane, propane, normal butane,
isobutane, natural gasoline and propylene, which are also called
“purity NGLs.” 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. NGLs are
fractionated by heating mixed NGL streams and passing them
through a series of distillation towers, in order to take
advantage of the differing boiling points of the various NGL
products. As the temperature of the NGL stream is increased, the
lightest (lowest boiling point) NGL product boils off to the top
of the tower where it is condensed and routed to storage. The
mixture from the bottom of the first tower is then moved into
the next tower where the process is repeated, and a heavier NGL
product is separated and stored. This process is repeated until
the NGLs have been separated into all of their components. Since
the fractionation process requires large quantities of heat,
energy costs are a major component of the total cost of
fractionation.
NGL
Transportation
NGLs are transported to market by means of pipelines,
pressurized barges, rail car and tank trucks. The method of
transportation utilized depends on, among other things, the
existing resources of the transporter, the locations of the
production points and the delivery points, cost-efficiency and
the quantity of NGLs being transported. Pipelines are generally
the most cost-efficient mode of transportation when large,
steady volumes of NGLs are to be delivered. Our Petrochemical
Pipeline Services segment consists of two petrochemical pipeline
systems with an aggregate of 284 miles of pipeline that
provide for the transportation of propylene in Texas and
Louisiana.
In general, refinery-grade propylene (a mixture of propane and
propylene) is separated into either polymer-grade propylene or
chemical-grade propylene along with by-products of propane and
mixed butane. Polymer-grade propylene can also be produced from
chemical-grade propylene feedstock. Chemical-grade propylene is
also a by-product of olefin (ethylene) production. The demand
for polymer-grade propylene is attributable to the manufacture
of polypropylene, which has a variety of end uses, including
packaging film, fiber for carpets and upholstery and molded
plastic parts for appliance, automotive, houseware and medical
products. Chemical-grade propylene is a basic petrochemical used
in plastics, synthetic fibers and foams.
After NGLs are fractionated, the fractionated products are
stored for customers when they are unable or do not wish to take
immediate delivery. NGL storage customers may include both NGL
producers, who sell to end users, and NGL end users, such as
retail propane companies and petrochemical facilities. Both the
producers and the end users seek to store NGL products to ensure
an adequate supply for their respective customers over the
course of the year, particularly during periods of increased
demand. We maintain NGL storage facilities as part of our
NGL & Petrochemical Storage Services business segment
that help us meet this industry need.
Our NGL & Petrochemical Storage Services segment
consists of three integrated and strategically located
underground storage facilities in Mont Belvieu, Texas, which we
refer to as Mont Belvieu East, West and North storage
facilities. We have multiple pipelines that interconnect these
facilities, and each facility is comprised of a network of
caverns located several hundred feet below ground. These
facilities include 33 storage caverns with an aggregate
underground storage capacity of approximately 100 MMBbls,
and a brine system with approximately 20 MMBbls of
above-ground storage pit capacity and two brine production wells.
These assets, known as Mont Belvieu Caverns, accept, store and
deliver NGLs and petrochemical products, such as ethane and
propane, for industrial customers located along the upper Texas
Gulf Coast. This area has the largest concentration of
petrochemical plants and refineries in the United States. The
storage facilities are interconnected by multiple pipelines to
other producing and offtake facilities throughout the Gulf
Coast, including the largest NGL import/export facility in this
region owned by Enterprise Products Partners, as well as
connections to the Rocky Mountain and Midwest regions via the
Seminole pipeline and to the Louisiana Gulf Coast via the
Lou-Tex NGL pipeline, which are NGL pipelines owned by
Enterprise Products Partners.
•
Mont Belvieu East Facility. The Mont Belvieu
East facility is the largest of the three facilities. This
facility consists of 13 storage caverns available for service
with an underground storage capacity of approximately
55 MMBbls and above-ground brine pit capacity of
approximately 10 MMBbls. This facility also has two brine
production wells.
•
Mont Belvieu West Facility. The Mont Belvieu
West facility consists of ten caverns available for service with
an underground storage capacity of approximately 15 MMBbls
and above-ground brine pit capacity of approximately
2 MMBbls.
•
Mont Belvieu North Facility. The Mont Belvieu
North facility consists of ten caverns available for service
with an underground storage capacity of approximately
30 MMBbls and above-ground brine pit capacity of
approximately 8 MMBbls.
Mont Belvieu Caverns derives essentially all of its revenues
from four main sources. These sources are:
•
storage reservation fees;
•
excess storage fees;
•
throughput fees; and
•
brine production and storage.
We charge our customers monthly storage reservation fees to
reserve a specific storage capacity in our underground caverns.
The customers pay reservation fees based on the quantity of
capacity reserved rather than on the amount of reserved capacity
actually 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.
Lastly, brine production revenues are derived from customers
that use brine in the production of feedstocks for production of
chlorine and caustic soda, which is
used in the production of PVC and for industrial products used
in crude oil production and fractionation. Brine is produced by
injecting fresh water into the well to create cavern space
within the salt dome. This process enables brine to be produced
for our customer as well as for developing new wells for product
storage.
The picture below depicts a typical storage cavern. Mont Belvieu
Caverns receives NGL and petrochemical products from related and
third party pipelines and facilities. As this product is
injected into the well it displaces brine that is then
transferred to the above-ground storage pit. When it is time to
redeliver the product, brine is then injected back into the well
displacing the product being stored. This product is delivered
to third party pipelines or other facilities.
During 2005 and 2006, we constructed additional brine production
capacity and above-ground storage reservoirs at Mont Belvieu.
These projects are expected to be completed during the first
quarter of 2007. We will retain $9.3 million from the
proceeds of this offering to fund our 66% share of
estimated capital expenditures to complete these projects.
Through December 31, 2006, we recorded total capital
expenditures of $71.5 million related to these projects.
Customers
Our customers include a broad range of NGL and petrochemical
producers and consumers, including many of the petrochemical
facilities and refineries in the Texas Gulf Coast and the
Louisiana Gulf Coast. Our five largest third-party customers,
which accounted for 38% of our total storage revenues for the
nine months ended September 30, 2006, were ExxonMobil,
Chevron/Phillips, Dow, Shell and Westlake Petrochemicals. Our
underground storage services to Enterprise Products Partners for
the storage of NGLs and petrochemicals accounted for 34% of our
total storage revenues for the nine months ended
September 30, 2006.
We have a broad range of customers with contract terms that vary
from
month-to-month
to long-term contracts with durations of one to ten years. We
currently offer our customers, in various quantities and at
varying terms, two main types of storage contracts:
multi-product fungible storage and segregated product storage.
Multi-product fungible storage allows customers to store any
combination of fungible products. Segregated product storage
allows customers to store non-fungible products such as
propylene, ethylene and naphtha. Segregated storage allows a
customer to reserve an entire storage cavern and have its own
product injected and withdrawn without having its product
commingled. We evaluate pricing, volume and availability for
storage on a
case-by-case
basis.
Enterprise Products OLP has seven contracts for storage with
Mont Belvieu Caverns that include multi-product fungible storage
for its NGL marketing activities, and for feedstocks for its
isomerization, iso-octane, NGL fractionation, and propylene
fractionation businesses and segregated product storage for
polymer grade propylene that is produced at propylene
fractionation facilities. These contracts have a duration of
five to ten years. Please read “Certain Relationships and
Related Party Transactions.”
For the years ended December 31, 2005, 2004 and 2003, we
recorded $17.6 million, $17.0 million and
$17.3 million, respectively, in storage revenues from
Enterprise Products Partners. For the nine months ended
September 30, 2006 and 2005, we recorded $14.8 million
and $13.9 million, respectively, in storage revenues from
Enterprise Products Partners.
Seasonality
We operate our NGL and related product storage facilities based
on the needs and requirements of our customers. 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. Typically, we
do not experience any significant seasonality with our
petrochemical customers because those customers withdraw and
inject petrochemicals on a regular basis.
Competition
Our competitors in the NGL, petrochemical and related product
storage business are integrated major oil companies, chemical
companies and other storage and pipeline companies. We compete
against Mont Belvieu Storage Partners, L.P., Targa Resources,
Texas Brine and ONEOK in the Gulf Coast region. The principal
competitive factors affecting our product storage business are
storage fees, quantity and location of pipeline connections and
operational dependability. We believe that the fees we charge
our customers are competitive with those charged by other
storage operators because we have historically been able to
renew existing contracts as they mature, yielding many
long-standing relationships. We are distinguished from our
competitors by the location and quantity of our pipeline
connections. The number of pipeline connections gives us
flexibility to offer a wide variety of receipt and delivery
options to customers and meet their requests on an efficient
basis. Our pipeline connections to the petrochemical plants, NGL
fractionators and imports from the Houston ship channel allow us
to effectively compete in this business because these are the
services required by our customers. In addition, we
differentiate ourselves through our emphasis on operational
dependability that consists of a focus on maintaining our
facilities.
NGL
and Petrochemical Sources and Transportation
Options
We generally receive the NGLs and petrochemicals that we inject
into our facilities, and our customers generally choose to
transport the NGLs that we withdraw from our facilities, through
the intrastate and interstate NGL and petrochemical pipelines
that interconnect with our storage facilities, including Black
Lake, Lakemont, Lou-Tex NGL Pipeline, Skelly-Belvieu, Cypress,
Seadrift, Chaparral, West Texas and Panola. We
are also connected to some of Enterprise Products Partners’
pipelines, including the Seminole pipeline, the Port Neches
Pipeline and the Channel Pipeline system. In addition we are
also connected to the truck and rail loading and unloading
facilities owned by Enterprise Products Partners. We are also
connected to numerous other pipelines through several
interconnecting pipelines to ARCO Junction, which is a large
pipeline hub in Mont Belvieu, Texas. We are also connected to
multiple third-party pipelines owned by Equistar, ExxonMobil,
ONEOK, Huntsman, ChevronPhillips, Dow, Valero and Shell. In
addition, we are connected to all of the NGL fractionators in
Mont Belvieu that are owned by Enterprise Products Partners,
Targa, ONEOK and Gulf Coast Fractionators. We also receive
specialized NGL products from the ExxonMobil Fractionator at
Beaumont, Texas and the ConocoPhillips Fractionator at Sweeny,
Texas.
Mont
Belvieu Expansion Opportunities
We are evaluating several projects to better integrate the three
Mont Belvieu facilities. These projects include additional
pipelines to more efficiently connect the facilities and
additional entries into certain wells to increase flow rates. We
are also evaluating projects that would allow us to store
natural gas. The contemplated Mont Belvieu expansion project
(the “Mont Belvieu Expansion”) is currently
anticipated to include new entries into existing wells, the
conversion of existing wells to store natural gas and the
installation of new piping and certain related facilities, which
may be commenced during 2007 in the estimated range of $25 to
$75 million. Additional expenditures of up to
$200 million may be made during 2008 and 2009. Pursuant to
the Mont Belvieu limited liability company agreement, Enterprise
Products OLP may, in its sole discretion, fund a portion of any
costs related to these projects. Additionally, we may finance
any such projects through borrowings under our new revolving
credit facility or the issuance of debt or additional equity.
For a further description of our agreements with Enterprise
Products Partners relating to these potential expansion
opportunities, please read “Certain Relationships and
Related Party Transactions — Mont Belvieu Caverns
Limited Liability Company Agreement — Future Mont
Belvieu Caverns Expansion Capital.”
Import/Export
Business
Enterprise Products Partners has a growing import/export
business in which it imports various NGL products and transports
these to and from our facilities in Mont Belvieu, Texas. These
products can be stored in our underground storage facilities for
our customers. Enterprise Products Partners is in the process of
expanding this import/export capability and expects to be
completed in the fourth quarter of 2006.
Our Natural Gas Pipelines & Services segment consists
of the Acadian Gas system, which is an onshore natural gas
pipeline system that gathers, transports, stores and markets
natural gas in Louisiana. The Acadian Gas system links natural
gas supplies from onshore and offshore Gulf of Mexico
developments (including offshore pipelines, continental shelf
and deepwater production) with local gas distribution companies,
electric generation plants and industrial customers, located
primarily in the natural gas market area of the Baton
Rouge — New Orleans — Mississippi River
corridor. In the aggregate, the Acadian Gas system includes over
1,000 miles of high-pressure transmission lines and
connected lateral segments with an aggregate throughput capacity
of approximately one Bcf/d and three Bcf of storage capacity.
The Acadian Gas system has over 150 physical end-user market
direct connections. In addition, the system interconnects with
12 interstate and 4 intrastate pipelines through 50 separate
interconnections, has a bi-directional interconnect with the
largest U.S. natural gas marketplace at the Henry Hub, and
is directly connected to six merchant and utility electric
generation facilities with over 6,000 megawatts of generating
capacity. The numerous interconnections allow the Acadian Gas
system to leverage basis differentials across the South
Louisiana pipeline network, maintain a diversified supply
portfolio and create capacity and transportation opportunities
for its shippers. The Acadian Gas system’s bi-directional
interconnect with the Henry Hub provides physical and financial
pricing flexibility, in addition to facilitating access to the
many buyers and sellers of natural gas at the hub.
The Acadian Gas system includes the following assets:
•
Acadian Pipeline. The Acadian pipeline is
located in southern Louisiana and consists of approximately
438 miles of high-pressure transmission lines and smaller
diameter lateral and gathering lines ranging from 12 inches
to 24 inches in diameter. The Acadian pipeline receives
natural gas at numerous interconnections with natural gas
production facilities and from third-party pipelines and
delivers the natural gas to customers’ facilities in
southern Louisiana. Through numerous interconnections with other
pipelines, including receipt and delivery capability at the
Henry Hub, the Acadian pipeline has the capability to deliver
gas to markets that it does not physically reach. The Acadian
pipeline has a throughput capacity of approximately
650 MMcf/d. The Acadian pipeline maintains multiple active
interconnects with the Cypress pipeline to facilitate gas
deliveries between the systems as may be required to meet
customer needs.
•
Cypress Pipeline. The Cypress pipeline is
located in south central Louisiana and consists of approximately
577 miles of transmission lines and smaller diameter
lateral and gathering lines ranging from 10 inches to
22 inches in diameter. This pipeline has interconnections
with many of the interstate and intrastate pipeline systems
operating in southern Louisiana and has a throughput capacity of
approximately 350 MMcf/d. The Cypress pipeline was
originally built to gather onshore Louisiana natural gas
supplies and to provide natural gas pipeline service to the
greater Baton Rouge industrial market, in particular, the
ExxonMobil Baton Rouge Refinery. Through the 1950’s and
1960’s, it was expanded to access the interstate pipeline
supply network and the Geismar, Louisiana and Donaldsonville,
Louisiana industrial market areas. The Cypress pipeline also has
the capability to access deepwater gas production through an
interconnect with the Nautilus Gas Pipeline system and numerous
third-party pipelines.
•
Evangeline Pipeline. The Evangeline pipeline
is a 27-mile
pipeline extending from Taft, Louisiana to Westwego, Louisiana.
The Evangeline pipeline, which consists mainly of transmission
lines ranging from 20 inches to 26 inches in diameter,
connects with three Entergy Louisiana natural gas fired electric
generation stations, the Acadian pipeline and a pipeline owned
by the Columbia Gulf Transmission Company. We indirectly own
approximately 49.5% of the ownership interests in the Evangeline
pipeline. A subsidiary of ConocoPhillips and a private investor
own the remaining interests in Evangeline.
•
Underground Storage Facility. The storage
assets in the Acadian Gas system consist of a leased underground
natural gas storage facility located at the center of the
Acadian Pipeline system near Napoleonville, Louisiana. The
storage facility has approximately 3.0 Bcf of storage
capacity,
220 MMcf/d
of withdrawal capacity and a maximum of 80 MMcf/d of
injection capacity. This facility is designed to handle high
levels of injections and withdrawals of natural gas to meet load
swings and to cover major supply interruption events, such as
hurricanes and temporary losses of production. In addition, the
storage facility permits sustained periods of high natural gas
deliveries and has the ability to switch quickly from full
injection to full withdrawal. An affiliate of Shell is leasing
the storage facility to Acadian Gas through December 31,2012. The term of this contract does not provide for an
additional renewal period. However, Shell has agreed to enter
into diligent negotiations with us under similar terms and
conditions for an extension if we wish to extend the lease
agreement beyond December 2012. Acadian Gas is the operator of
this underground storage facility and owns 75% of its leased
storage, withdrawal and injection capacity. A third party owns
the remaining 25% interest.
System
Throughput
Natural gas throughput on the Acadian Gas system consists of a
combination of natural gas sales volumes owned by us and
transportation volumes delivered on behalf of third-party
shippers, with marketing volumes and transportation volumes
representing approximately 38% and 62%, respectively, of the
average daily gas
volumes for the first nine months of 2006. The following table
summarizes Acadian Gas system’s sales and transportation
volumes for the periods indicated:
Average
Gas Sales and Transportation Volumes (Bbtu/d)
The Acadian Gas system transported approximately 773 Bbtu/d
of natural gas to its customers during the first
nine months of 2006. We have long-standing relationships
with a majority of our customers. Many of our customers purchase
and transport a substantial portion of their natural gas
requirements through the Acadian Gas system and for some
customers our pipelines are the only access point for their
natural gas supplies. Our customers include:
•
electric generating facilities, such as those owned by Entergy
Louisiana and Calpine Corporation;
•
integrated refining and petrochemical facilities, such as
ExxonMobil’s Baton Rouge Complex;
•
local distribution companies and various city and parish
systems; and
•
other industrial and commercial customers of varying size.
The Acadian Gas system has a diversified customer base, with its
largest customer representing only 9% of its total revenue in
2005 and the top ten customers representing only 40% of its
total revenue in 2005.
In addition to its marketing gas activities, the Acadian Gas
system provides fee-based gas transportation services for
producers and gas marketing companies under intrastate and
interruptible NGPA Section 311 transportation contracts.
The primary term of these transportation service contracts may
vary from
month-to-month
to longer-term contracts, with durations typically of one to
three years. The revenues derived from these gas transportation
contracts are based on the quantities of gas delivered
multiplied by the per-unit transportation rate paid. Based on
volumes moved, the most significant shippers on the Acadian Gas
system include ExxonMobil, Coral Energy Resources, BP Energy and
BG Energy Merchants. These shippers transport gas on the Acadian
Gas system to meet the natural gas requirements of their
affiliated industrial and power generation facilities, and to
market commodity gas services to third parties. ExxonMobil is
the most significant long-term shipper on the Acadian Gas
system, and we entered into a long-term gas transportation
agreement with ExxonMobil in 1993 in conjunction with our
acquisition of the Cypress pipeline, which was formerly owned
and operated by ExxonMobil. The primary term of this agreement
expired on December 1, 2006, but the parties entered into
an amendment to extend the term until November 2009. During the
nine months ended September 30, 2006, ExxonMobil shipped
approximately 143 Bbtu/d on the Acadian Gas system
utilizing our system as the primary fuel gas pipeline service
provider for its Baton Rouge Refinery and Chemical complex.
Natural
Gas Sales
The Acadian Gas system is currently connected to approximately
116 customers with an approximate total gas requirement of over
3.0 Bcf/d. The Acadian Gas system has maintained active and
long-term relationships, and currently has long-term natural gas
sales or transportation contracts, with most of these customers.
Our natural gas sales arrangements are implemented under
contracts with market-based pricing indices that correspond to
the pricing indices utilized in our gas purchasing activities.
The majority of gas sales on the Acadian Gas system are made
pursuant to long-term contracts, most of which are at least one
year in duration. Gas sales are also made under short-term
agreements, which generally range from one day to one month.
Much of our gas sales volume is under agreements that provide
for minimum annual volumes to be delivered at Henry Hub indexed
market prices (determined monthly), plus a predetermined
adjustment or differential. The Acadian Gas system has
historically received higher margins under long-term contracts
that provide customers with supply certainty as well as value
added services to ensure gas supplies through dedicated
facilities. These additional services are necessary to
accommodate large swings in a customers’ natural gas
requirement, which may vary hourly, daily and monthly.
The Acadian Gas system’s most significant natural gas sales
contract is a
21-year
arrangement with Evangeline, which was entered into in 1991, and
includes minimum annual quantities. Evangeline uses these
natural gas volumes to meet its own supply obligation under a
corresponding sales agreement with Entergy Louisiana, its only
customer. Under the Entergy Louisiana gas sales contract,
Evangeline is obligated to make available for sale and deliver
to Entergy Louisiana certain specified minimum quantities of gas
on a hourly, daily, monthly and annual basis. The gas sales
contract provides for minimum annual quantities of
36.75 Bbtus until the contract expires on January 1,2013 (which is coterminous with the natural gas purchase
commitment with ConocoPhillips described below). Please read
“— Evangeline Long-Term Debt” below for a
discussion regarding the use of proceeds by Evangeline from
these natural gas sales.
In connection with Acadian Gas’ gas sales contract with
Evangeline, a portion of the revenues received are attributable
to a “seller’s margin” agreement contained with
the contract. The “seller’s margin” set forth in
the contract is a fixed dollar amount paid per MMBtu per month
in the first contract year and adjusted upwards in successive
years. Seller’s margin is used to calculate fees incurred
on the contract when a buyer exercises an option to reduce the
minimum annual quantity or when firm gas is delivered pursuant
to the contract.
The electric utility and industrial customers of Acadian Gas
system normally consume the natural gas in their own operations
for fuel or feedstock, while local distribution companies and
city-gate systems generally resell the natural gas to the
customers of their respective gas pipeline systems.
Natural
Gas Purchases
The Acadian Gas system currently purchases gas supply from 41
different gas producers through 59 separate gas production
receipt locations. Substantially all of the Acadian Gas
system’s natural gas requirements are purchased under
contracts that contain market-responsive pricing provisions. The
Acadian Gas system’s most significant long-term gas
purchase commitment is with ConocoPhillips, which was entered
into in 1991 as part of the formation of Evangeline Gas Pipeline
Company, L.P. This gas purchase contract expires on
January 1, 2013 (which is coterminous with the natural gas
sales agreement with Evangeline described above) and provides
for minimum annual quantities of natural gas to be purchased by
the Acadian Gas system, similar in structure to the minimum
annual obligations between Acadian Gas system and Evangeline,
and the corresponding obligations between Evangeline and Entergy
Louisiana. The pricing terms of the gas purchase contract and
the Entergy Louisiana gas sales contract are based on a
weighted-average cost of natural gas each month (subject to
certain market index price ceilings and incentive margins), plus
a pre-determined margin. The amount of natural gas purchased
pursuant to this contract totaled 17.4 Bbtus in 2005,
18.2 Bbtus in 2004 and 18.2 Bbtus in 2003. The amounts
paid by the Acadian Gas System for natural gas purchased under
this contract totaled $148.3 million in 2005,
$112.7 million in 2004 and $100.3 million in 2003.
Natural
Gas Interconnections
General. The Acadian Gas system procures gas
supply from natural gas production facilities, third party
natural gas pipelines, and market center pipeline hubs such as
the Henry Hub and the Nautilus Hub operated by third parties.
The Acadian Gas system has approximately 50 separate
pipeline-to-pipeline
interconnects with 12 interstate pipeline systems, and four
unaffiliated intrastate pipeline systems. These third-party gas
supplies in support of Acadian Gas system’s gas marketing
activities and as receipt volumes for gas
transportation activities may be sourced from any of these
locations as pipeline pressures, facility interconnect
capacities and landed gas pricing levels will dictate.
The Henry Hub. The Acadian Gas system includes
a bi-directional interconnect with the Henry Hub which is
generally considered to be one of the most liquid natural gas
market locations in North America. The Henry Hub has
interconnects with nine interstate and four intrastate pipelines
providing shippers with access to pipelines reaching markets in
the Midwest, Northeast, Southeast, and Gulf Coast regions of the
United States. The Henry Hub is also the delivery point for the
New York Mercantile Exchange (NYMEX) natural gas futures
contract with NYMEX deliveries occurring at the Henry Hub being
handled the same as cash-market transactions, thereby providing
the connected Henry Hub participants with additional market
flexibility.
The Nautilus Hub. The Acadian Gas system is
also connected to the Nautilus Hub, which is the terminal end of
the Nautilus Gas Pipeline system. The Nautilus Gas Pipeline
system is a
101-mile,
30-inch
FERC- regulated gas transmission system that gathers deepwater
Gulf of Mexico natural gas production for delivery onshore in
St. Mary Parish, Louisiana at the Neptune natural gas processing
plant, which is operated by Enterprise Products Partners. After
natural gas is processed at the Neptune facility, it is
redelivered into the Nautilus Hub which has seven separate
interconnects with interstate and intrastate gas pipeline
systems, including the Acadian Gas system.
Evangeline
Long-Term Debt
In connection with the acquisition of the Entergy Louisiana
natural gas sales contract and construction of the Evangeline
pipeline, Evangeline entered into a long-term debt arrangement
consisting of 9.9% fixed interest rate senior secured notes due
December 2010, or the Series B Notes, and a
$7.5 million subordinated note payable to Evangeline
Northwest Corporation, or the ENC Note. The Series B notes
are collateralized by: (i) Evangeline’s property,
plant and equipment; (ii) proceeds from the Entergy
Louisiana natural gas sales contract; and (iii) a debt
service reserve requirement. Scheduled principal repayments on
the Series B notes are $5 million annually through
2009 with a final repayment in 2010 of approximately
$3.2 million. Evangeline incurred the ENC Note obligations
in connection with its acquisition of the Entergy Louisiana
natural gas sales contract in 1991. The ENC 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 note holders are either fully cash secured
through debt service accounts or have been completely repaid.
Substantially all of the net proceeds received by Evangeline
from its contracts with Entergy Louisiana are used to pay off
the Series B notes and ENC Note.
Entergy
Louisiana’s Option
Entergy Louisiana has the option to purchase the Evangeline
pipeline system for a nominal price, plus the complete
performance and compliance with the gas sales contract. The
option period begins on the earlier of July 1, 2010 or upon
the payment in full of the Series B Notes and the ENC Note,
and terminates on December 31, 2012. We cannot know when,
or if, Entergy Louisiana will exercise this option. Factors that
may influence Entergy Louisiana’s decision include, but are
not limited to, Entergy Louisiana’s future business plans,
natural gas procurement strategies, required regulatory
approvals, and the pipeline system’s residual value, if
any, at the time the option is exercisable.
Commodity
Price Risk
With regard to physical marketing gas activities, the Acadian
Gas system purchases gas in quantities and under pricing terms
that mirror its sales obligations. Within the transportation
services function, the Acadian Gas system transports quantities
of gas on behalf of others, with those shippers being
responsible for managing any commodity price risk that may be
associated with matching gas purchases with gas sale. The
Acadian Gas system does not engage in any type of commodity
hedging, nor any futures, options, or basis trading for the
purpose of attempting to create or optimize a proprietary
trading position. Accordingly, the Acadian Gas system does not
manage or utilize a strategy that would involve trading of
financial positions. Certain physical customers of the Acadian
Gas system will from time to time request the ability to control
the
volatility inherent in a monthly indexed natural gas sales
arrangement, which requires that the Acadian Gas system take a
position in the futures market corresponding to the hedge
request of that customer. When this transaction takes place, it
is only at the request of the customer, and only in a volume and
for a time period that corresponds to coverage of that
customer’s request, and as it would relate to that
customer’s physical delivery contract with the Acadian Gas
system.
Seasonality
Typically, the Acadian Gas system experiences higher throughput
rates during the summer months as gas-fired power generation
facilities increase output to satisfy residential and commercial
demand for electricity for air conditioning. Likewise,
seasonality impacts the timing of injections and withdrawals at
our natural gas storage facility. In the winter months, natural
gas is needed as fuel for residential and commercial heating,
generally increasing the need for deliveries to local
distribution companies and city-gate stations.
Competition
Our Acadian Gas system competes with several onshore natural gas
pipelines in the South Louisiana market on the basis of
price (in terms of transportation fees or natural gas selling
prices), location, service, reliability and flexibility. The
transportation fees and natural gas sales prices we charge our
customers are competitive with those charged by other onshore
pipelines in the area because we rely on certain published
indices for our pricing. We are distinguished from our
competitors within the onshore South Louisiana market because of
our long-standing customer relationships. Due to the limited
number of alternative delivery pipeline connections to those
customers, we have been able to retain our customers for many
years. Our competitors have the ability to connect into various
customers on our pipeline but at a higher cost due to new
pipelines and other related facilities. It is critical to the
customers in the region that we provide reliable service to
enable our customers flexibility of supply through the many
connections to our system. Because of our location and
long-standing presence in South Louisiana, we are able to
compete effectively in this market.
Our Petrochemical Pipeline Services segment consists of two
petrochemical pipeline systems with an aggregate of 284 miles of
pipeline that provide for the transportation of propylene in
Texas and Louisiana. This segment includes the following assets:
•
Lou-Tex Propylene Pipeline. The Lou-Tex
Propylene pipeline consists of a
263-mile,
10-inch
pipeline used to transport chemical-grade propylene between
Sorrento, Louisiana and Mont Belvieu, Texas. Currently, this
pipeline is used to transport chemical-grade propylene from
production facilities in Louisiana to customers in Louisiana and
Texas under transportation contracts that Enterprise Products
OLP has with Shell and ExxonMobil. The chemical-grade propylene
transported for Shell originates from the Shell Sorrento
underground storage facility and is delivered to various
delivery points between an underground storage facility in
Sorrento, Louisiana and an underground storage facility in Mont
Belvieu, Texas owned by Mont Belvieu Caverns. The delivery
points on the Lou-Tex Propylene pipeline include Vulcan,
Westlake Lake Charles, Beaumont Novus, and Shell’s Texas
chemical grade propylene delivery system. The chemical-grade
propylene delivered for Exxon originates from the Exxon Baton
Rouge refining and chemical complex and is delivered to an
underground storage well in Mont Belvieu, Texas owned by Mont
Belvieu Caverns. The Lou-Tex Propylene pipeline was constructed
in 1997 and acquired by Enterprise Products Partners in March
2000 from an affiliate of Shell.
•
Sabine Propylene Pipeline. The Sabine
Propylene pipeline consists of a
21-mile,
8-inch
pipeline used to transport polymer-grade propylene that begins
in Groves, Texas and terminates at a connection to Enterprise
Products Partners’ Lake Charles propylene line in Cameron
Parish, Louisiana. The polymer-grade propylene transported for
Shell originates from the TOTAL/BASF Port Arthur cracker
facility
and is delivered to the Basell polypropylene facility in Lake
Charles, Louisiana. The pipeline was constructed by Enterprise
Products Partners and placed in service in 2002.
Customers. Shell and ExxonMobil are the only
customers that use the Lou-Tex Propylene pipeline. Shell is the
only customer that uses the Sabine Propylene pipeline.
Contracts. Enterprise Products Partners has
entered into separate product exchange agreements with Shell and
ExxonMobil involving the use of our Sabine Propylene and Lou-Tex
Propylene pipelines. Concurrently with the closing of this
offering, Enterprise Products Partners will assign these
exchange agreements to us. Through these exchange agreements, we
will agree to receive propylene product in one location and
deliver it to another location.
•
Shell Exchange Agreements. We will become a
party to separate product exchange agreements with Shell for the
use of the Lou-Tex Propylene and Sabine Propylene pipelines. The
term of the Lou-Tex Propylene pipeline agreement expires on
March 1, 2020, but will continue on an annual basis subject
to termination by either party. The exchange fees paid by Shell
are fixed until such time as a published power index in
Louisiana becomes available and the parties agree to use such
index. The term of the Sabine Propylene pipeline agreement
expires on November 1, 2011, but will continue on an annual
basis subject to termination by either party. The exchange fees
paid by Shell are adjusted yearly based on the
U.S. Department of Labor wage index and the yearly
operating costs of the Sabine Propylene pipeline. Shell is
obligated to meet minimum delivery requirements under the
Lou-Tex Propylene and Sabine Propylene agreements. If Shell
fails to meet such minimum delivery requirements, it will be
obligated to pay a deficiency fee to us.
•
Exxon Exchange Agreement. We will become a
party to a product exchange agreement with ExxonMobil for the
use of the Lou-Tex Propylene pipeline. The term of the Lou-Tex
Propylene exchange agreement expires on June 1, 2008, but
will continue on a monthly basis subject to termination by
either party. The exchange fees paid by ExxonMobil are based on
the volume of chemical grade propylene delivered to Enterprise
Products Partners and us.
Enterprise Products Partners will assign the exchange agreements
for the use of the Lou-Tex Propylene and Sabine Propylene
pipelines with Shell and ExxonMobil to us concurrently with the
closing of this offering. Prior to 2004, the Sabine Propylene
pipeline was regulated by the FERC. The Lou-Tex Propylene
pipeline was also subject to the FERC’s jurisdiction until
2005. For the periods in which the Sabine Propylene pipeline and
the Lou-Tex Propylene pipeline were subject to FERC regulations,
related party revenues with Enterprise Products Partners were
based on the maximum tariff rate allowed for each system. We
continued to charge Enterprise Products Partners such maximum
transportation rates after both entities were declared exempt
from FERC oversight. The assignment of these contracts to us
concurrently with the closing of this offering will make the
tariff charged by us to equal the rates charged to ExxonMobil
and Shell.
The maximum number of barrels that these systems can transport
per day depends on the operating balance achieved at a given
time between various segments of the systems. Because the
balance is dependent upon the mix of receipt and delivery
capabilities, the exact capacities of the systems cannot be
stated. We measure the utilization rates of our NGL and
petrochemical pipelines in terms of throughput (on a net basis
in accordance with our ownership interest).
Seasonality
Our propylene transportation business has historically exhibited
little seasonality.
Competition
Our petrochemical pipelines encounter competition from fully
integrated oil companies and various petrochemical companies in
the Gulf Coast market. Our petrochemical transportation
competitors have varying levels of financial and personnel
resources, and competition generally revolves around price,
service, logistics and location. We differentiate ourselves from
the larger oil and petrochemical companies primarily through the
location of our pipelines and dedication of our pipelines to a
single product service. Our petrochemical pipelines are in
single product service due to the required purity of the product
being shipped. Because there are no other pipelines in our
market area which ship the same single product, we are able to
compete against our larger competitors for this service. In the
future, a competitor could change service of an existing
pipeline to ship single products, but they would have to incur
additional costs to connect to our customers.
Our NGL Pipeline Services segment consists of a
290-mile
intrastate pipeline system and related interconnections to be
used to transport NGLs from two fractionation facilities located
in South Texas to Mont Belvieu, Texas. The South Texas NGL
pipeline system became operational and began transporting NGLs
in January 2007 after undergoing modifications, extensions and
interconnections which we refer to as Phase I. Enterprise
Products Partners purchased the
223-mile
segment of pipeline, ranging from 12 inches to
16 inches in diameter, from ExxonMobil Pipeline Company in
August 2006. This segment of the South Texas NGL pipeline system
originates in Corpus Christi, Texas and extends to Pasadena,
Texas. Currently, the capacity of the 223-mile pipeline we
purchased from ExxonMobil Pipeline Company is approximately
100,000 Bbls/d and expandable to 175,000 Bbls/d.
During Phase I:
(1) we will construct approximately 13 miles of
pipeline and utilize an existing 32-mile pipeline to complete
pipeline laterals to connect the two fractionation facilities to
the 223-mile
segment of our South Texas NGL pipeline system; and
(2) we have entered into a lease with TEPPCO Partners for a
12-mile,
10-inch
interconnecting pipeline extending from Pasadena, Texas to
Baytown, Texas. The primary term of the pipeline lease will
expire on September 15, 2007, and will continue on a
month-to-month
basis subject to termination by either party upon
60 days’ notice.
During January 2007, an affiliate of Enterprise Products
Partners acquired an additional
10-mile,
18-inch
segment of pipeline from an affiliate of TEPPCO Partners, which
connects the leased TEPPCO pipeline to Mont Belvieu, Texas. The
purchase of the
10-mile
segment of
18-inch
pipeline from TEPPCO Partners was for an aggregate purchase
price of $8 million. This pipeline will be among the assets
owned by South Texas NGL at the closing of this offering.
During Phase II, we will construct 21 miles of
18-inch
pipeline to replace the leased
12-mile,
10-inch
pipeline and the
12-inch
segments of the pipeline acquired from ExxonMobil. The
Phase II upgrade will provide a significant increase in
pipeline capacity and is expected to be operational during the
third quarter of 2007.
The sole customer of our NGL Pipeline Services segment is
Enterprise Products Partners, which will use the South Texas NGL
pipeline system to ship NGLs processed at the Shoup
fractionation plant in Corpus Christi, Texas, the Armstrong
fractionation plant located near Victoria, Texas and NGLs
purchased from third parties in South Texas to Mont Belvieu,
Texas. We have entered into a ten-year transportation contract
with Enterprise Products Partners that includes all of the
volumes of NGLs transported on the South Texas NGL pipeline
system. Under this contract, Enterprise Products Partners will
pay us a dedication fee of no less than $0.02 per gallon
for all NGLs produced at the Shoup and Armstrong fractionation
plants whether or not Enterprise Products Partners ships any
NGLs on the South Texas NGL pipeline system. We will not take
title to the products transported on the South Texas NGL
pipeline system; rather, Enterprise Products Partners will
retain title and the associated commodity risk.
Revenues
Revenues from the dedication fee of no less than $0.02 per
gallon of NGLs produced at Enterprise Products Partners’
Shoup and Armstrong fractionation plants will represent
substantially all of the revenues for our NGL Pipeline Services
Segment and South Texas NGL pipeline system. These NGL volumes
have varied during recent periods and may vary in the future.
Because the South Texas NGL pipeline system provides
transportation services to Enterprise Products Partners on a
dedicated fee basis, the results of our operations are dependent
upon the level of production of NGLs from the Shoup and
Armstrong fractionation plants. If one of the plants shuts down
or otherwise reduces production, our revenues would decrease.
Seasonality
Our NGL Pipeline Services segment will not exhibit a significant
degree of seasonality.
The sources of the NGLs to be transported on our NGL pipeline
system originates primarily from the Shoup fractionation plant
located in Corpus Christi, Texas and the Armstrong fractionation
plant located 26 miles north of Victoria, Texas.
•
Shoup Fractionation Plant. The Shoup
fractionation plant, located in Corpus Christi, Texas, separates
a mixed NGL stream into its components such as purity ethane,
propane, mixed butane and natural gasoline. The fractionator has
a capacity of 69,000 Bbls/d and produces purity ethane,
propane and butane/gasoline streams. The facility fractionates
mixed NGLs from 6 gas processing plants located throughout South
Texas and delivered to the fractionation plant by approximately
350 miles of NGL gathering pipelines.
•
Armstrong Fractionation Plant. The Armstrong
fractionation plant is located adjacent to the Armstrong gas
processing plant in Dewitt County, Texas. The fractionator has a
capacity of 18,000 Bbls/d and fractionates mixed NGLs sourced
from the Armstrong processing plant exclusively. The facility
produces purity ethane, propane, mixed butane and natural
gasoline. The Armstrong gas processing plant is a double train
expander facility with approximately 250 MMcf/d of
processing capacity.
The Shoup and Armstrong fractionation plants produced the
following aggregate amounts of NGLs during the periods set forth
below:
NGLs Produced
Period
(Bbls/d)
2003
56,752
2004
66,557
2005
64,505
2006 (nine months ended
September 30)
65,884
Natural
Gas Supply
The natural gas that supplies the gas processing plants which
provide the NGLs for the South Texas NGL pipeline system is
sourced from the prolific Texas Gulf Coast producing area.
Production trends based on 2005 EIA data show a 1% per year
increase over the last 25 years. New drilling permits (per
IHS Inc.) and rig counts (per Baker Hughes) have also increased
5% per year over the last three years. The EIA report on
production of rich gas also shows an annual average increase of
1% over the last 25 years. New resources of rich gas may
exist in the Cretaceous sands of southwest Texas and the
Oligocene Vicksburg below 14,000’ of South Texas. In the
middle Gulf Coast, rich Wilcox gas is found in the
10,000-15,000’
depth range. Shale gas may also have a large potential in these
areas with expected high liquids content.
We do not have any employees. EPCO employs most of the persons
necessary for the operation of our business. At
September 30, 2006, EPCO had approximately
80 dedicated employees and 176 employees that share a
portion of their time in the management and operations of our
business, none of whom were members of a union. We will continue
to reimburse EPCO for the costs of all employees providing
services to us. For a detailed discussion of our related party
transactions with EPCO, please read “Certain Relationships
and Related Party Transactions.” In addition to EPCO
employees, we will engage various contract maintenance and other
personnel who will support our operations.
We are subject to extensive federal, state and local laws and
regulations, as well as orders of regulatory bodies pursuant
thereto, governing a wide variety of matters, including
environmental quality and pollution control, community
right-to-know,
safety and other matters. These laws and regulations may, in
certain instances, require us to restrict the way we handle or
dispose of our wastes, limit or prohibit construction activities
in environmentally sensitive areas, remedy the environmental
effects of the disposal or release of certain substances at
current and former operating sites or halt the operations of
facilities deemed in non-compliance with permits issued pursuant
to such environmental laws and regulations.
We may incur significant costs and liabilities in order to
comply with existing environmental laws and regulations. It is
also possible that other developments, such as claims for
damages to property, employees, other persons and the
environment resulting from current or past operations, could
result in substantial costs and liabilities in the future. It is
possible that new information or future developments, such as
increasingly strict environmental laws, could require us to
reassess our potential exposure related to environmental
matters. Although we do not believe that compliance with
federal, state or local environmental laws and regulations will
have a material adverse effect on our business, financial
position or results of operations, we cannot assure you that the
development or discovery of new facts or conditions will not
cause us to incur significant costs. As this information becomes
available, or other relevant developments occur, we will make
accruals accordingly. For a summary of our significant
environmental-related accruals, please read Note 2 of the
Notes
to Combined Financial Statements of Duncan Energy Partners
Predecessor included elsewhere in this prospectus.
We have ongoing programs designed to keep our pipelines and
storage facility in compliance with environmental and safety
requirements, and we believe that our facilities are in material
compliance with the applicable regulatory requirements. As of
September 30, 2006, we had a reserve of approximately
$0.2 million included in other current liabilities for
remediation of ground contamination related to the Acadian Gas
system. Below is a discussion of the material environmental laws
and regulations that relate to our business.
Specific
Environmental Laws and Regulations
Pipelines. Pursuant to the Pipeline Safety
Improvement Act of 2002, the DOT has adopted regulations
requiring pipeline operators to develop integrity management
programs for transportation pipelines located where a leak or
rupture could do the most harm in “high consequence
areas.” The regulations require operators to perform
ongoing assessments of pipeline integrity, identify and
characterize applicable threats to pipeline segments that could
impact a high consequence area, and repair and remediate the
pipeline as necessary.
Several other federal and state environmental statutes and
regulations may pertain specifically to the operations of our
pipelines. Among these, the Hazardous Materials Transportation
Act regulates materials capable of posing an unreasonable risk
to health, safety and property when transported in commerce, and
the Natural Gas Pipeline Safety Act and the Hazardous Liquid
Pipeline Safety Act authorize the development and enforcement of
regulations governing pipeline transportation of natural gas and
NGLs. Although federal jurisdiction is exclusive over regulated
pipelines, the statutes allow states to impose additional
requirements for intrastate lines if compatible with federal
programs. New Mexico, Texas and Louisiana have developed
regulatory programs that parallel the federal program for the
transportation of natural gas and NGLs by pipelines. For
example, our intrastate gas pipelines and gas storage operations
in Louisiana are subject to state regulations issued by the
Louisiana Public Service Commission and the Louisiana Department
of Natural Resources. Within the Louisiana Department of Natural
Resources, the Office of Conservation has the authority to
regulate all pipeline interconnections, transportation and
construction or abandonment of facilities, and the Office of
Pipeline Safety monitors the implementation of the DOT and
Louisiana pipeline safety regulations.
Solid Waste. The operations of our pipelines
may generate both hazardous and nonhazardous solid wastes that
are subject to the requirements of the Resource Conservation and
Recovery Act and its regulations, and other federal and state
statutes and regulations. Further, it is possible that some
wastes that are currently classified as nonhazardous, via
exemption or otherwise, perhaps including wastes currently
generated during pipeline operations, may, in the future, be
designated as “hazardous wastes,” which would then be
subject to more rigorous and costly treatment, storage,
transportation and disposal requirements. Such changes in the
regulations may result in additional expenditures or operating
expenses for us.
Hazardous Substances. The Comprehensive
Environmental Response, Compensation and Liability Act, or
CERCLA, and comparable state statutes, also known as
“Superfund” laws, impose liability, without regard to
fault or the legality of the original conduct, on certain
classes of persons that cause or contribute to the release of a
“hazardous substance” into the environment. These
persons include the current owner or operator of a site, the
past owner or operator of a site, and companies that transport,
dispose of, or arrange for the disposal of the hazardous
substances found at the site. CERCLA also authorizes the
Environmental Protection Agency or state agency, and in some
cases, third parties, to take actions in response to threats to
the public health or the environment and to seek to recover from
the responsible classes of persons the costs they incur. Despite
the “petroleum exclusion” of CERCLA
Section 101(14) that currently encompasses crude oil,
refined petroleum products, natural gas and NGLs, we may
nonetheless handle “hazardous substances,” within the
meaning of CERCLA or similar state statutes, in the course of
our ordinary operations.
Air. Our operations may be subject to the
Clean Air Act and other federal and state statutes and
regulations that impose certain pollution control requirements
with respect to air emissions from operations, particularly in
instances where a company constructs a new facility or modifies
an existing facility. We may be
required to incur certain capital expenditures in the next
several years for air pollution control equipment in connection
with maintaining or obtaining operating permits and approvals
addressing other air emission-related issues. However, we do not
believe these requirements will have a material adverse affect
on our operations.
Water. The Federal Water Pollution Control Act
imposes strict controls against the unauthorized discharge of
pollutants, including produced waters and other oil and natural
gas wastes, into navigable waters. It provides for civil and
criminal penalties for any unauthorized discharges of oil and
other substances and, along with the Oil Pollution Act of 1990,
or OPA, imposes substantial potential liability for the costs of
oil or hazardous substance removal, remediation and damages.
Similarly, the OPA imposes liability for the discharge of oil
into or upon navigable waters or adjoining shorelines. State
laws for the control of water pollution also provide varying
civil and criminal penalties and liabilities in the case of an
unauthorized discharge of pollutants into state waters.
Worker Safety and Hazard Communication. We are
subject to the requirements of the Occupational Safety and
Health Act, or OSHA, and comparable state statutes. These laws
and the implementing regulations strictly govern the protection
of the health and safety of employees. OSHA, the Emergency
Planning and Community
Right-to-Know
Act and comparable state statutes require those entities that
operate facilities for us to organize and disseminate
information to employees, state and local organizations, and the
public about the hazardous materials used in its operations and
its emergency planning.
Regulation
of Our Intrastate Natural Gas Pipelines and
Services
At the federal level, our gas pipelines and gas storage
facilities are subject to regulations of the FERC under the
Natural Gas Policy Act of 1978, or the NGPA. Our natural gas
intrastate systems provide transportation and storage pursuant
to Section 311 of the NGPA and Section 284 of the
FERC’s regulations. Under Section 311 of the NGPA, an
intrastate pipeline company may transport gas for an interstate
pipeline company or any local distribution company served by an
interstate pipeline. We are required to provide these services
on an open and nondiscriminatory basis and to make certain rate
and other filings and reports in compliance with the
regulations. The rates for Section 311 service can be
established by the FERC or the respective state agency. The
associated rates may not exceed a fair and equitable rate and
are subject to challenge.
In the past, the FERC has approved market-based rates for
Section 311 storage service for the storage facility in
Louisiana. Recently, we filed petitions for each of our Acadian
and Cypress pipelines requesting approval of increased rates for
interruptible transportation service performed under
Section 311, to be effective October 1, 2006, subject
to refund. Each of these petitions was protested by a single
shipper. We did not place the proposed rates for the Acadian and
Cypress pipelines into effect on October 1, 2006.
Therefore, there are no currently effective rates that are
subject to refund, although the currently effective rates remain
subject to complaint by all shippers. We are currently engaged
in settlement discussions with the shipper and the FERC staff to
establish the proposed rates for the Acadian and Cypress
pipelines. Any settlement agreement between the parties must be
approved by the FERC. The Louisiana Public Service Commission
also reviews and approves rates for pipelines providing
Section 311 service in Louisiana. For example, the
Louisiana Public Service Commission regulates Acadian Gas’s
city gate sales. We also have a natural gas underground storage
facility in Louisiana that is subject to state regulation. In
addition to the above-regulations, the natural gas industry has
historically been subject to numerous other forms of federal,
state and local regulation.
Regulation
of Our Petrochemical Pipeline Services
Our interstate Lou-Tex Propylene and Sabine Propylene pipelines
are common carrier pipelines regulated by the Surface
Transportation Board or STB under the current version of the
ICA. The ICA and its implementing regulations give the STB
authority to regulate the rates we charges for service on the
propylene pipelines and generally require that our rates and
practices be just and reasonable and nondiscriminatory.
The majority of the natural gas pipelines in the Acadian Gas
system are intrastate common carrier pipelines that are subject
to various Louisiana state laws and regulations that affect the
rates it charges and the terms of service. We also have a
natural gas underground storage facility in Louisiana that is
subject to state regulations.
For additional information regarding the potential impact of
federal, state or local regulatory measures on our business,
please read “Risk Factors.”
Our real property holdings fall into two basic categories:
(1) parcels that we own in fee, such as the land and
underlying storage caverns at Mont Belvieu, Texas and
(2) parcels in which our interest derives 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 major 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 have no knowledge of
any challenge to the underlying fee title of any material lease,
easement,
right-of-way
or license held by us or to our title to any material lease,
easement,
right-of-way,
permit or license, and we believe that we have satisfactory
title to all of our material leases, easements,
rights-of-way
and licenses.
Some of the leases, easements, rights-of-way, permits and
licenses to be transferred to us require the consent of the
grantor of such rights. Our general partner expects to obtain,
prior to the closing of this offering, sufficient third-party
consents, permits and authorizations for the transfer of the
assets necessary to enable us to operate our business in all
material respects as described in this prospectus. With respect
to any material consents, permits or authorizations that have
not been obtained prior to closing of this offering, the closing
of this offering will not occur unless reasonable basis exist
that permit our general partner to conclude that such consents,
permits or authorizations will be obtained within a reasonable
period following the closing, or the failure to obtain such
consents, permits or authorizations will have no material
adverse effect on the operation of our business.
On occasion, we are named as a defendant in litigation relating
to our normal business operations, including regulatory and
environmental matters. Although we are insured against various
business risks to the extent we believe is prudent, the nature
and amount of such insurance may not be adequate, in every case,
to indemnify us against liabilities arising from future legal
proceedings as a result of our ordinary business activity.
In 1997, Acadian Gas, along with numerous other energy
companies, were named defendants in actions brought by Jack
Grynberg on behalf of the U.S. Government under the False
Claims Act. Generally, these complaints allege an industry-wide
conspiracy to underreport the heating value as well as the
volumes of the natural gas produced from federal and Native
American lands, which deprived the U.S. Government of
royalties. The plaintiff in this case seeks royalties that he
contends the government should have received had the volume and
heating value been differently measured, analyzed, calculated
and reported, together with interest, treble damages, civil
penalties, expenses and future injunctive relief to require the
defendants to adopt allegedly appropriate gas measurement
practices. These matters have been consolidated for pretrial
purposes (In re: Natural Gas Royalties Qui Tam Litigation,
U.S. District Court for the District of Wyoming, filed June
1997). On October 20, 2006, the U.S. District Court
dismissed all of Grynberg’s claims with prejudice.
We are not aware of any other significant litigation, pending or
threatened, that may have a significant adverse effect on our
financial position or results of operations.
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 an administrative services agreement under the direction of
the Board of Directors and executive officers of our general
partner. For a description of the administrative services
agreement, please read “Certain Relationships and Related
Party Transactions.”
Our general partner 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 our
general partner. Whenever possible, our general partner intends
to make any such indebtedness or other obligations non-recourse
to itself and its general partner.
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. The following is
a brief description of certain existing practices we use to
maintain strong governance principles.
Independence of Board Members. 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 our general
partner or us (either directly or as a partner, unitholder or
officer of an organization that has a material relationship with
Enterprise Products GP or us). Based on the foregoing, the Board
has affirmatively determined that
William A. Bruckmann, III, Larry J. Casey
and Joe D. Havens are “independent” under the
NYSE rules.
Heightened Independence for Audit, Conflicts and Governance
Committee Members. As required by the
Sarbanes-Oxley Act of 2002, the SEC adopted rules that direct
national securities exchanges and associations to prohibit the
listing of securities of a public company if members of its
audit committee do not satisfy a heightened independence
standard. In order to meet this standard, a member of an audit
committee may not receive any consulting fee, advisory fee or
other compensation from the public company other than fees for
service as a director or committee member and may not be
considered an affiliate of the public company. Neither our
general partner nor any individual member of its Audit,
Conflicts and Governance Committee has relied on any exemption
in the NYSE rules to establish such individual’s
independence. Based on the foregoing criteria, the Board of
Directors of our general partner has affirmatively determined
that all members of its Audit, Conflicts and Governance
Committee satisfy this heightened independence requirement.
Audit Committee Financial Expert. An audit
committee plays an important role in promoting effective
corporate governance, and it is imperative that members of an
audit committee have requisite financial literacy and expertise.
As required by the Sarbanes-Oxley Act of 2002, SEC rules require
that a public company disclose whether or not its audit
committee has an “audit committee financial expert” as
a member. An “audit committee financial expert” is
defined as a person who, based on his or her experience,
satisfies all of the following attributes:
•
An understanding of generally accepted accounting principles and
financial statements.
•
An ability to assess the general application of such principles
in connection with the accounting for estimates, accruals, and
reserves.
•
Experience preparing, auditing, analyzing or evaluating
financial statements that present a breadth and level of
complexity of accounting issues that are generally comparable to
the breadth and level of complexity of issues that can
reasonably be expected to be raised by our financial statements,
or experience actively supervising one or more persons engaged
in such activities.
An understanding of internal controls and procedures for
financial reporting.
•
An understanding of audit committee functions.
Based on the information presented, the Board of Directors has
affirmatively determined
that
satisfies the definition of “audit committee financial
expert.”
Executive Sessions of Board. The Board of
Directors of our general partner holds regular executive
sessions in which non-management board members 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. The Presiding Director will be the Chairman of the
Audit, Conflicts and Governance Committee.
In accordance with the rules of the NYSE, we have designated our
toll-free, confidential Hotline as the method for interested
parties to communicate with the Presiding Director, alone, or
with the non-management Directors of our general partner as a
group. All calls to this Hotline are reported to the Chairman of
the Audit, Conflicts and Governance Committee of our general
partner, who is responsible for communicating any necessary
information to the other non-management directors as a group.
The number of our confidential Hotline is 877-888-0002. The
Hotline is operated by The Network, an independent contractor
that specializes in providing feedback and reporting services to
more than 1,000 companies in a variety of industries.
Committees
of Board of Directors
After giving effect to this offering, the Board of Directors of
our general partner will have one committee, the Audit,
Conflicts and Governance Committee, which we refer to in this
prospectus as the ACG Committee.
Audit,
Conflicts and Governance Committee
In accordance with NYSE rules and Section 3(a)(58)(A) of
the Exchange Act, the Board of Directors of our general partner
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
committee shall have accounting or related financial management
expertise. The members of the ACG Committee will be Messrs.
Bruckmann, Casey and Havens. The primary responsibilities of the
ACG Committee include:
