sv3
As filed with the Securities and
Exchange Commission on June 16, 2009
Registration
No. 333-
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form S-3
REGISTRATION
STATEMENT
UNDER
THE SECURITIES ACT OF
1933
ENERGY TRANSFER PARTNERS,
L.P.
(Exact name of registrant as
specified in its charter)
|
|
|
Delaware
(State or other jurisdiction
of incorporation or organization)
|
|
73-1493906
(I.R.S. Employer
Identification No.)
|
3738 Oak Lawn Avenue
Dallas, TX 75219
(214) 981-0700
(Address, including zip code,
and telephone number,
including area code, of
registrants principal executive offices)
Martin Salinas, Jr.
Chief Financial
Officer
Energy Transfer Partners,
L.P.
3738 Oak Lawn Avenue
Dallas, TX 75219
(214) 981-0700
(Name, address, including zip
code, and telephone number,
including area code, of agent
for service)
Copies to:
|
|
|
Thomas P. Mason
Vice President, General Counsel and Secretary
Energy Transfer Partners, L.P.
3738 Oak Lawn Avenue
Dallas, TX 75219
(214) 981-0700
|
|
Douglas E. McWilliams
Vinson & Elkins L.L.P.
First City Tower
1001 Fannin Street, Suite 2500
Houston, TX 77002
(713) 758-2222
|
Approximate date of commencement of proposed sale to the
public: As soon as practicable after this
registration statement becomes effective.
If the only securities being registered on this form are being
offered pursuant to dividend or interest reinvestment plans,
please check the following
box. o
If any of the securities registered on this form are being
offered on a delayed or continuous basis pursuant to
Rule 415 under the Securities Act of 1933, other than
securities offered only in connection with dividend or interest
reinvestment plans, check the following
box. þ
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 registration statement pursuant to General
Instruction I.D. or a post-effective amendment thereto that
shall become effective upon filing with the Commission pursuant
to Rule 462(e) under the Securities Act, check the
following
box. o
If this form is a post-effective amendment to a registration
statement filed pursuant to General Instruction I.D. filed to
register additional securities or additional classes of
securities pursuant to Rule 413(b) under the Securities
Act, check the following
box. o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in Rule
12b-2 of the
Exchange Act. (Check one):
|
|
|
|
Large
accelerated
filer þ
|
Accelerated
filer o
|
Non-accelerated
filer o
|
Smaller reporting
company o
|
(Do not check if a smaller
reporting company)
CALCULATION
OF REGISTRATION FEE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proposed Maximum
|
|
|
Proposed Maximum
|
|
|
Amount of
|
|
|
|
Amount to be
|
|
|
Offering
|
|
|
Aggregate Offering
|
|
|
Registration
|
Title of Each Class of Securities to be Registered
|
|
|
Registered
|
|
|
Price per Unit
|
|
|
Price (1)
|
|
|
Fee
|
Primary Offering
|
|
|
|
|
|
|
|
|
$1,000,000,000
|
|
|
$55,800
|
Common Units(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt Securities of Energy Transfer Partners, L.P.(2)(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
Secondary Offering of Common Units
|
|
|
12,000,000
|
|
|
$42.255(4)
|
|
|
$507,060,000
|
|
|
$28,293.95(5)
|
Total
|
|
|
|
|
|
|
|
|
$1,507,060,000
|
|
|
$84,093.95(6)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Rule 457(o) permits the
registration fee to be calculated on the basis of the maximum
offering price of all of the securities listed and, therefore,
the table does not specify by each class information as to the
amount to be registered or the proposed maximum offer price per
security.
|
|
(2)
|
|
An indeterminate principal amount
or number of common units and debt securities may be issued from
time to time at indeterminate prices, with an aggregate offering
price not to exceed $1,000,000,000.
|
|
(3)
|
|
If any debt securities are issued
at an original issue discount, then the offering price of those
debt securities shall be in an amount that will result in an
aggregate initial offering price not to exceed $1,000,000,000,
less the dollar amount of any registered securities previously
issued.
|
|
(4)
|
|
The proposed maximum offering price
per common unit will be determined from time to time by the
selling unitholder in connection with, and at the time of, the
issuance by the selling unitholder of the securities registered
hereunder.
|
|
(5)
|
|
Pursuant to Rule 457(c) of the
Securities Act, the registration fee is calculated on the basis
of the average of the high and low sale prices for our common
units on June 15, 2009, as reported on the New York Stock
Exchange.
|
|
(6)
|
|
Securities registered under
registration statement File
No. 333-133176
previously filed by Energy Transfer Partners, L.P. on
April 10, 2006, having an aggregate offering price of
$1,000,000,000, remain unsold. In accordance with
Rule 457(p), the registration fee of $107,000 associated
with such unsold securities was offset against the total
registration fee due in connection with a registration statement
on
Form S-8,
File
No. 333-159878,
filed by Energy Transfer Partners, L.P. on June 10, 2009,
in the amount of $11,970.50, leaving a balance of $95,029.50 in
fees associated with unsold securities to be offset against the
total registration fee due in connection with this registration
statement. Accordingly, no additional fee has been paid in
connection with the initial filing of this registration
statement.
|
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 Commission,
acting pursuant to said section 8(a), may determine.
EXPLANATORY
NOTE
This registration statement consists of two prospectuses,
covering the registration of:
|
|
|
|
|
Common units and debt securities of Energy Transfer Partners,
L.P.; and
|
|
|
|
Common units of Energy Transfer Partners, L.P. that may be sold
in one or more secondary offerings by the selling unitholder.
|
The
information in this prospectus is not complete and may be
changed. We may not sell these securities until the registration
statement filed with the Securities and Exchange Commission is
effective. This 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.
|
SUBJECT TO COMPLETION, DATED
JUNE 16, 2009
Prospectus
ENERGY TRANSFER PARTNERS,
L.P.
$1,000,000,000
Common Units
Debt Securities
We may offer and sell up to $1,000,000,000 in aggregate offering
price of common units, representing limited partner interests of
Energy Transfer Partners, L.P., and debt securities described in
this prospectus from time to time in one or more classes or
series and in amounts, at prices and on terms to be determined
by market conditions at the time of our offerings.
We may offer and sell these securities to or through one or more
underwriters, dealers and agents, or directly to purchasers, on
a continuous or delayed basis. This prospectus describes the
general terms of these common units and debt securities and the
general manner in which we will offer the common units and debt
securities. The specific terms of any common units and debt
securities we offer will be included in a supplement to this
prospectus. The prospectus supplement will also describe the
specific manner in which we will offer the common units and debt
securities.
Investing in our common units and debt securities involves
risks. Limited partnerships are inherently different from
corporations. You should carefully consider the risk factors
described under Risk Factors beginning on
page 4 of this prospectus before you make an investment in
our securities.
Our common units are traded on the New York Stock Exchange, or
the NYSE, under the symbol ETP. The last reported
sales price of our common units on the NYSE on June 15,
2009 was $42.23 per common unit. We will provide information in
the prospectus supplement for the trading market, if any, for
any debt securities we may offer.
Neither the Securities and Exchange Commission nor any state
securities commission has approved or disapproved these
securities or determined if this prospectus is truthful or
complete. Any representation to the contrary is a criminal
offense.
The date of this prospectus
is ,
2009.
TABLE OF
CONTENTS
In making your investment decision, you should rely only on
the information contained or incorporated by reference in this
prospectus. We have not authorized anyone to provide you with
any other information. If anyone provides you with different or
inconsistent information, you should not rely on it.
You should not assume that the information contained in this
prospectus is accurate as of any date other than the date on the
front cover of this prospectus. You should not assume that the
information contained in the documents incorporated by reference
in this prospectus is accurate as of any date other than the
respective dates of those documents. Our business, financial
condition, results of operations and prospects may have changed
since those dates.
ABOUT
THIS PROSPECTUS
This prospectus is part of a registration statement that we have
filed with the Securities and Exchange Commission using a
shelf registration process. Under this shelf
registration process, we may, over time, offer and sell any
combination of the securities described in this prospectus in
one or more offerings. This prospectus generally describes
Energy Transfer Partners, L.P. and the securities. Each time we
sell securities with this prospectus, we will provide you with a
prospectus supplement that will contain specific information
about the terms of that offering. The prospectus supplement may
also add to, update or change information in this prospectus.
Before you invest in our securities, you should carefully read
this prospectus and any prospectus supplement and the additional
information described under the heading Where You Can Find
More Information. To the extent information in this
prospectus is inconsistent with information contained in a
prospectus supplement, you should rely on the information in the
prospectus supplement. You should read both this prospectus and
any prospectus supplement, together with additional information
described under the heading Where You Can Find More
Information, and any additional information you may need
to make your investment decision. Unless the context requires
otherwise, all references in this prospectus to we,
us, ETP, the Partnership and
our refer to Energy Transfer Partners, L.P., and its
operating partnerships and their subsidiaries.
ENERGY
TRANSFER PARTNERS, L.P.
We are a publicly traded limited partnership that owns and
operates a diversified portfolio of energy assets. Our natural
gas operations include intrastate natural gas gathering and
transportation pipelines, an interstate pipeline, natural gas
treating and processing assets located in Texas, New Mexico,
Arizona, Louisiana, Utah and Colorado, and three natural gas
storage facilities located in Texas. These assets include
approximately 14,600 miles of intrastate gas gathering and
transportation pipeline in service, with approximately
250 miles of additional intrastate pipeline under
construction. In addition, we own approximately 2,700 miles
of interstate pipeline in service and have a 50% interest in a
joint venture with approximately 500 miles of interstate
pipeline under construction or in interim service. Our
intrastate and interstate pipeline systems transport natural gas
from several significant natural gas producing areas, including
the Barnett Shale in the Fort Worth Basin in north Texas,
the Bossier Sands in east Texas, the Permian Basin in west Texas
and New Mexico, the San Juan Basin in New Mexico and other
producing areas in south Texas and central Texas. Our gathering
and processing operations are conducted in many of these same
producing areas as well as in the Piceance and Uinta Basins in
Colorado and Utah. We are also one of the three largest retail
marketers of propane in the United States, serving more than one
million customers across the country.
Our principal executive offices are located at 3738 Oak Lawn
Avenue, Dallas, Texas 75219, and our telephone number at that
location is
(214) 981-0700.
1
CAUTIONARY
STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
This prospectus contains various forward-looking statements and
information that are based on our beliefs and those of our
general partner, as well as assumptions made by and information
currently available to us. These forward-looking statements are
identified as any statement that does not relate strictly to
historical or current facts. When used in this prospectus, words
such as anticipate, project,
expect, plan, goal,
forecast, intend, could,
believe, may, and similar expressions
and statements regarding our plans and objectives for future
operations, are intended to identify forward-looking statements.
Although we and our general partner believe that the
expectations on which such forward-looking statements are based
are reasonable, neither we nor our general partner can give
assurances that such expectations will prove to be correct.
Forward-looking statements are subject to a variety of risks,
uncertainties and assumptions. If one or more of these risks or
uncertainties materialize, or if underlying assumptions prove
incorrect, our actual results may vary materially from those
anticipated, estimated, projected or expected. Among the key
risk factors that may have a direct bearing on our results of
operations and financial condition are:
|
|
|
|
|
the amount of natural gas transported on our pipelines and
gathering systems;
|
|
|
|
the level of throughput in our natural gas processing and
treating facilities;
|
|
|
|
the fees we charge and the margins we realize for our gathering,
treating, processing, storage and transportation services;
|
|
|
|
the prices and market demand for, and the relationship between,
natural gas and natural gas liquids, or NGLs;
|
|
|
|
energy prices generally;
|
|
|
|
the prices of natural gas and propane compared to the price of
alternative and competing fuels;
|
|
|
|
the general level of petroleum product demand and the
availability and price of propane supplies;
|
|
|
|
the level of domestic oil, propane and natural gas production;
|
|
|
|
the availability of imported oil and natural gas;
|
|
|
|
the ability to obtain adequate supplies of propane for retail
sale in the event of an interruption in supply or transportation
and the availability of capacity to transport propane to market
areas;
|
|
|
|
actions taken by foreign oil and gas producing nations;
|
|
|
|
the political and economic stability of petroleum producing
nations;
|
|
|
|
the effect of weather conditions on demand for oil, natural gas
and propane;
|
|
|
|
availability of local, intrastate and interstate transportation
systems;
|
|
|
|
the continued ability to find and contract for new sources of
natural gas supply;
|
|
|
|
availability and marketing of competitive fuels;
|
|
|
|
the impact of energy conservation efforts;
|
|
|
|
energy efficiencies and technological trends;
|
|
|
|
governmental regulation and taxation;
|
|
|
|
changes to, and the application of, regulation of tariff rates
and operational requirements related to our interstate and
intrastate pipelines;
|
|
|
|
hazards or operating risks incidental to the gathering,
treating, processing and transporting of natural gas and NGLs or
to the transporting, storing and distributing of propane that
may not be fully covered by insurance;
|
|
|
|
the maturity of the propane industry and competition from other
propane distributors;
|
2
|
|
|
|
|
competition from other midstream companies, interstate pipeline
companies and propane distribution companies;
|
|
|
|
loss of key personnel;
|
|
|
|
loss of key natural gas producers or the providers of
fractionation services;
|
|
|
|
reductions in the capacity or allocations of third party
pipelines that connect with our pipelines and facilities;
|
|
|
|
the effectiveness of risk-management policies and procedures and
the ability of our liquids marketing counterparties to satisfy
their financial commitments;
|
|
|
|
the nonpayment or nonperformance by our customers;
|
|
|
|
regulatory, environmental, political and legal uncertainties
that may affect the timing and cost of our internal growth
projects, such as our construction of additional pipeline
systems;
|
|
|
|
risks associated with the construction of new pipelines and
treating and processing facilities or additions to our existing
pipelines and facilities, including difficulties in obtaining
permits and rights-of-way or other regulatory approvals and the
performance by third party contractors;
|
|
|
|
the availability and cost of capital and our ability to access
certain capital sources;
|
|
|
|
the further deterioration of the credit and capital markets;
|
|
|
|
the ability to successfully identify and consummate strategic
acquisitions at purchase prices that are accretive to our
financial results and to successfully integrate acquired
businesses;
|
|
|
|
changes in laws and regulations to which we are subject,
including tax, environmental, transportation and employment
regulations or new interpretations by regulatory agencies
concerning such laws and regulations; and
|
|
|
|
the costs and effects of legal and administrative proceedings.
|
You should not put undue reliance on any forward-looking
statements. When considering forward-looking statements, please
review the risk factors described under Risk Factors
in this prospectus.
3
RISK
FACTORS
An investment in our securities involves a high degree of
risk. You should carefully consider the following risk factors,
together with all of the other information included in, or
incorporated by reference into, this prospectus in evaluating an
investment in our securities. If any of these risks were to
occur, our business, financial condition or results of
operations could be adversely affected. In that case, the
trading price of our common units or debt securities could
decline and you could lose all or part of your investment. When
we offer and sell any securities pursuant to a prospectus
supplement, we may include additional risk factors relevant to
such securities in the prospectus supplement.
Risks
Inherent In An Investment In Us
Cash
distributions are not guaranteed and may fluctuate with our
performance and other external factors.
The amount of cash we can distribute on our common units or
other partnership securities depends upon the amount of cash we
generate from our operations. The amount of cash we generate
from our operations will fluctuate from quarter to quarter and
will depend upon, among other things:
|
|
|
|
|
the amount of natural gas transported in our pipelines and
gathering systems;
|
|
|
|
the level of throughput in our processing and treating
operations;
|
|
|
|
the fees we charge and the margins we realize for our gathering,
treating, processing, storage and transportation services;
|
|
|
|
the price of natural gas;
|
|
|
|
the relationship between natural gas and NGL prices;
|
|
|
|
the weather in our operating areas;
|
|
|
|
the cost to us of the propane we buy for resale and the prices
we receive for our propane;
|
|
|
|
the level of competition from other midstream companies,
interstate pipeline companies, propane companies and other
energy providers;
|
|
|
|
the level of our operating costs;
|
|
|
|
prevailing economic conditions; and
|
|
|
|
the level of our hedging activities.
|
In addition, the actual amount of cash we will have available
for distribution will also depend on other factors, such as:
|
|
|
|
|
the level of capital expenditures we make;
|
|
|
|
the level of costs related to litigation and regulatory
compliance matters;
|
|
|
|
the cost of acquisitions, if any;
|
|
|
|
the levels of any margin calls that result from changes in
commodity prices;
|
|
|
|
our debt service requirements;
|
|
|
|
fluctuations in our working capital needs;
|
|
|
|
our ability to make working capital borrowings under our credit
facilities to make distributions;
|
|
|
|
our ability to access capital markets;
|
|
|
|
restrictions on distributions contained in our debt
agreements; and
|
4
|
|
|
|
|
the amount, if any, of cash reserves established by the general
partner in its discretion for the proper conduct of our business.
|
Because of all these factors, we cannot guarantee that we will
have sufficient available cash to pay a specific level of cash
distributions to our unitholders.
Furthermore, you should be aware that the amount of cash we have
available for distribution depends primarily upon our cash flow,
including cash flow from financial reserves and working capital
borrowings, and is not solely a function of profitability, which
will be affected by non-cash items. As a result, we may make
cash distributions during periods when we record net losses and
may not make cash distributions during periods when we record
net income.
We may
sell additional limited partner interests, diluting existing
interests of unitholders.
Our partnership agreement allows us to issue an unlimited number
of additional limited partner interests, including securities
senior to the common units, without the approval of the
unitholders. The issuance of additional common units or other
equity securities will have the following effects:
|
|
|
|
|
the current proportionate ownership interest of our unitholders
in us will decrease;
|
|
|
|
the amount of cash available for distribution on each common
unit or partnership security may decrease;
|
|
|
|
the relative voting strength of each previously outstanding
common unit may be diminished; and
|
|
|
|
the market price of the common units or partnership securities
may decline.
|
Future
sales of our units or other limited partner interests in the
trading market could reduce the market price of
unitholders limited partner interests.
As of March 31, 2009, ETE owned 62,500,797 common units.
ETE owns our general partner. If ETE were to sell
and/or
distribute its common units to the holders of its equity
interests in the future, those holders may dispose of some or
all of these units. The sale or disposition of a substantial
portion of these units in the public markets could reduce the
market price of our outstanding common units.
Our
debt level and debt agreements may limit our ability to make
distributions to unitholders and our future financial and
operating flexibility.
As of March 31, 2009, we had approximately
$5.63 billion of consolidated debt outstanding. Our level
of indebtedness affects our operations in several ways,
including, among other things:
|
|
|
|
|
a significant portion of our cash flow from operations will be
dedicated to the payment of principal and interest on
outstanding debt and will not be available for other purposes,
including payment of distributions;
|
|
|
|
covenants contained in our existing debt arrangements require us
to meet financial tests that may adversely affect our
flexibility in planning for and reacting to changes in our
business;
|
|
|
|
our ability to obtain additional financing for working capital,
capital expenditures, acquisitions and general partnership
purposes may be limited;
|
|
|
|
we may be at a competitive disadvantage relative to similar
companies that have less debt;
|
|
|
|
we may be more vulnerable to adverse economic and industry
conditions as a result of our significant debt level; and
|
|
|
|
failure to comply with the various restrictive and affirmative
covenants of the credit agreements could negatively impact our
ability and the ability of our subsidiaries to incur additional
debt and our ability to pay our distributions. We are required
to measure these financial tests and covenants quarterly and,
|
5
|
|
|
|
|
as of March 31, 2009, we were in compliance with all
financial requirements, tests, limitations, and covenants
related to financial ratios under our existing credit agreements.
|
Completion
of pipeline expansion projects will require significant amounts
of debt and equity financing which may not be available to us on
acceptable terms, or at all.
We plan to fund our expansion capital expenditures, including
any future pipeline expansion projects we may undertake, with
proceeds from sales of our debt and equity securities and
borrowings under our revolving credit facility; however, we
cannot be certain that we will be able to issue our debt and
equity securities on terms satisfactory to us, or at all. In
addition, we may be unable to obtain adequate funding under our
current revolving credit facility because our lending
counterparties may be unwilling or unable to meet their funding
obligations. If we are unable to finance our expansion projects
as expected, we could be required to seek alternative financing,
the terms of which may not be attractive to us, or to revise or
cancel our expansion plans.
As of March 31, 2009, we had approximately $5.63 billion of
consolidated debt outstanding. A significant increase in our
indebtedness that is proportionately greater than our issuances
of equity could negatively impact our credit ratings or our
ability to remain in compliance with the financial covenants
under our revolving credit agreement, which could have a
material adverse effect on our financial condition, results of
operations and cash flows.
Increases
in interest rates could materially adversely affect our
business, results of operations, cash flows and financial
condition.
In addition to our exposure to commodity prices, we have
significant exposure to increases in interest rates. As of
March 31, 2009, we had approximately $5.63 billion of
consolidated debt, of which approximately $4.75 billion was
at fixed interest rates and approximately $882.0 million
was at variable interest rates. We manage a portion of our
interest rate exposures by utilizing interest rate swaps and
similar arrangements. To the extent that we have debt with
variable interest rates that is not hedged, our results of
operations, cash flows and financial condition, could be
materially adversely affected by significant increases in
interest rates. As of March 31, 2009, we had outstanding
forward starting interest rate swaps with a notional amount of
$500.0 million for a forecasted debt issuance by the end of
2009. These swaps were not designated as cash flow hedges;
therefore, changes in interest rates could adversely affect our
results of operations until the forecasted debt is issued and
could require a cash payment upon settlement. As of
March 31, 2009, we also had outstanding forward starting
interest rate swaps with notional amounts totaling
$250.0 million, all of which have subsequently been
terminated for an insignificant amount.
An increase in interest rates may also cause a corresponding
decline in demand for equity investments, in general, and in
particular for yield-based equity investments such as our common
units. Any such reduction in demand for our common units
resulting from other more attractive investment opportunities
may cause the trading price of our common units to decline.
The
credit and risk profile of our general partner and its owners
could adversely affect our credit ratings and
profile.
The credit and business risk profiles of our general partner,
and of ETE as the indirect owner of our general partner, may be
factors in credit evaluations of us as a master limited
partnership due to the significant influence of our general
partner and its indirect owner over our business activities,
including our cash distribution 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.
ETE has significant indebtedness outstanding and is dependent
principally on the cash distributions from its general and
limited partner equity interests in us to service such
indebtedness. Any distributions by us to ETE will be made only
after satisfying our then current obligations to our creditors.
Although we have taken certain steps in our organizational
structure, financial reporting and contractual relationships to
reflect the
6
separateness of us, ETP GP and ETP LLC from the entities that
control ETP GP, ETE and its general partner, our credit ratings
and business risk profile could be adversely affected if the
ratings and risk profiles of such entities were viewed as
substantially lower or more risky than ours.
The
general partner is not elected by the unitholders and cannot be
removed without its consent.
Unlike the holders of common stock in a corporation, unitholders
have only limited voting rights on matters affecting our
business, and therefore limited ability to influence
managements decisions regarding our business. Unitholders
did not elect our general partner and will have no right to
elect our general partner on an annual or other continuing
basis. Although our general partner has a fiduciary duty to
manage us in a manner beneficial to us and our unitholders, the
directors of our general partner and its general partner, have a
fiduciary duty to manage the general partner and its general
partner in a manner beneficial to the owners of those entities.
Furthermore, if the unitholders are dissatisfied with the
performance of our general partner, they will have little
ability to remove our general partner. The general partner
generally may not be removed except upon the vote of the holders
of
662/3%
of the outstanding units voting together as a single class,
including units owned by the general partner and its affiliates.
Subsequent to our sale of common units in April 2009, ETE and
its affiliates held approximately 37% of our outstanding units,
with an approximately 1% of units held by our officers and
directors. Consequently, it could be difficult to remove the
general partner without the consent of the general partner and
our affiliates.
Furthermore, unitholders voting rights are further
restricted by the partnership agreement provision providing that
any units held by a person that owns 20% or more of any class of
units then outstanding, other than the general partner and its
affiliates, cannot be voted on any matter.
The
control of our general partner may be transferred to a third
party without unitholder consent.
The 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 the partnership
agreement on the ability of the general partner of our general
partner from transferring its general partner interest in our
general partner to a third party. Any new owner of the general
partner would be in a position to replace the officers of the
general partner with its own choices and to control the
decisions taken by such officers.
Unitholders
may be required to sell their units to the general partner at an
undesirable time or price.
If at any time less than 20% of the outstanding units of any
class are held by persons other than the general partner and its
affiliates, the general partner will have the right to acquire
all, but not less than all, of those units at a price no less
than their then-current market price. As a consequence, a
unitholder may be required to sell his common units at an
undesirable time or price. The general partner may assign this
purchase right to any of its affiliates or to us.
The
interruption of distributions to us from our operating
subsidiaries and equity investees may affect our ability to
satisfy our obligations and to make distributions to our
partners.
We are a holding company with no business operations. Our only
significant assets are the equity interests we own in our
operating subsidiaries and equity investees. As a result, we
depend upon the earnings and cash flow of our operating
subsidiaries and equity investees and the distribution of that
cash to us in order to meet our obligations and to allow us to
make distributions to our partners.
Cost
reimbursements due our general partner may be substantial and
reduce our ability to pay the distributions to
unitholders.
Prior to making any distributions to unitholders, we will
reimburse our general partner for all expenses it has incurred
on our behalf. In addition, our general partner and its
affiliates may provide us with services for
7
which we will be charged reasonable fees as determined by the
general partner. The reimbursement of these expenses and the
payment of these fees could adversely affect our ability to make
distributions to the unitholders. Our general partner has sole
discretion to determine the amount of these expenses and fees.
Unitholders
may have liability to repay distributions.
Under certain circumstances unitholders may have to repay us
amounts wrongfully distributed to them. Under Delaware law, we
may not make a distribution to unitholders if the distribution
causes our liabilities to exceed the fair value of our assets.
Liabilities to partners on account of their partnership
interests and
non-recourse
liabilities are not counted for purposes of determining whether
a distribution is permitted. Delaware law provides that a
limited partner who receives such a distribution and knew at the
time of the distribution that the distribution violated Delaware
law will be liable to the limited partnership for the
distribution amount for three years from the distribution date.
Under Delaware law, an assignee who becomes a substituted
limited partner of a limited partnership is liable for the
obligations of the assignor to make contributions to the
partnership. However, such an assignee is not obligated for
liabilities unknown to him at the time he or she became a
limited partner if the liabilities could not be determined from
the partnership agreement.
Risks
Related to Conflicts of Interest
Our
partnership agreement limits our general partners
fiduciary duties to our 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 waive or
consent to conduct by our general partner and its affiliates and
which reduce the obligations to which our general partner would
otherwise be held by state-law fiduciary duty standards. The
following is a summary of the material restrictions contained in
our partnership agreement on the fiduciary duties owed by our
general partner to the limited partners. Our partnership
agreement:
|
|
|
|
|
permits our general partner to make a number of decisions in its
sole discretion. 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;
|
|
|
|
provides that our general partner is entitled to make other
decisions in its reasonable discretion;
|
|
|
|
generally provides that affiliated transactions and resolutions
of conflicts of interest not involving a required vote of
unitholders must be fair and reasonable to us and
that, in determining whether a transaction or resolution is
fair and reasonable, our general partner may
consider the interests of all parties involved, including its
own. Unless our general partner has acted in bad faith, the
action taken by our general partner shall not constitute a
breach of its fiduciary duty; and
|
|
|
|
provides that our general partner and its officers and directors
will not be liable for monetary damages to us, our limited
partners or assignees for errors of judgment or for any acts or
omissions if our general partner and those other persons acted
in good faith.
|
In order to become a limited partner of our partnership, a
common unitholder is required to agree to be bound by the
provisions in the partnership agreement, including the
provisions discussed above.
Some
of our executive officers and directors face potential conflicts
of interest in managing our business.
Certain of our executive officers and directors are also
officers
and/or
directors of ETE. 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 us and ETE. 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.
8
The
general partners absolute discretion in determining the
level of cash reserves may adversely affect our ability to make
cash distributions to our unitholders.
Our partnership agreement requires the general partner to deduct
from operating surplus cash reserves that in its reasonable
discretion are necessary to fund our future operating
expenditures. In addition, the partnership agreement permits the
general partner to reduce available cash by establishing cash
reserves for the proper conduct of our business, to comply with
applicable law or agreements to which we are a party or to
provide funds for future distributions to partners. These cash
reserves will affect the amount of cash available for
distribution to unitholders.
Our
general partner has conflicts of interest and limited fiduciary
responsibilities, which may permit our general partner to favor
its own interests to the detriment of unitholders.
Subsequent to our sale of common units in April 2009, ETE and
its affiliates directly and indirectly owned an aggregate
limited partner interest in us of approximately 37% and our
officers and directors owned approximately 1% of the limited
partner interests in us. Conflicts of interest could arise in
the future as a result of relationships between our general
partner and its affiliates, on the one hand, and us, on the
other hand. As a result of these conflicts our general partner
may favor its own interests and those of its affiliates over the
interests of the unitholders. The nature of these conflicts
includes the following considerations:
|
|
|
|
|
Remedies available to unitholders for actions that might,
without the limitations, constitute breaches of fiduciary duty.
Unitholders are deemed to have consented to some actions and
conflicts of interest that might otherwise be deemed a breach of
fiduciary or other duties under applicable state law.
|
|
|
|
Our general partner is allowed to take into account the
interests of parties in addition to us in resolving conflicts of
interest, thereby limiting its fiduciary duties to the
unitholders.
|
|
|
|
Our general partners affiliates are not prohibited from
engaging in other businesses or activities, including those in
direct competition with us.
|
|
|
|
Our general partner determines the amount and timing of our
asset purchases and sales, capital expenditures, borrowings and
reserves, each of which can affect the amount of cash that is
distributed to unitholders.
|
|
|
|
Our general partner determines whether to issue additional units
or other equity securities of us.
|
|
|
|
Our general partner determines which costs are reimbursable by
us.
|
|
|
|
Our general partner controls the enforcement of obligations owed
to us by it.
|
|
|
|
Our general partner decides whether to retain separate counsel,
accountants or others to perform services for us.
|
|
|
|
Our general partner is not restricted 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.
|
|
|
|
In some instances our general partner may borrow funds in order
to permit the payment of distributions, even if the purpose or
effect of the borrowing is to make incentive distributions.
|
The
risk of competition with affiliates of our general partner has
increased.
Except as provided in our partnership agreement, affiliates of
our general partner are not prohibited from engaging in other
businesses or activities, including those that might be in
direct competition with us. Enterprise GP Holdings, L.P.
currently has an approximately 41% non-controlling equity
interest in LE GP, LLC, ETEs general partner. Enterprise
GP Holdings, L.P. and its subsidiaries own and operate a North
American midstream energy business that competes with us with
respect to our natural gas midstream business.
9
Risks
Related to our Business
We may
not be able to obtain funding on acceptable terms or at all
under our revolving credit facility or otherwise because of the
deterioration of the credit and capital markets. This may hinder
or prevent us from meeting our future capital
needs.
Global financial markets and economic conditions have been, and
continue to be, disrupted and volatile due to a variety of
factors, including significant write-offs in the financial
services sector and the current weak economic conditions. As a
result, the cost of raising money in the debt and equity capital
markets has increased substantially while the availability of
funds from those markets has diminished significantly. In
particular, as a result of concerns about the stability of
financial markets generally and the solvency of lending
counterparties specifically, the cost of obtaining money from
the credit markets generally has increased as many lenders and
institutional investors have increased interest rates, enacted
tighter lending standards, refused to refinance existing debt on
similar terms or at all and reduced, or in some cases ceased, to
provide funding to borrowers. In addition, lending
counterparties under existing revolving credit facilities and
other debt instruments may be unwilling or unable to meet their
funding obligations. Due to these factors, we cannot be certain
that new debt or equity financing will be available on
acceptable terms. If funding is not available when needed, or is
available only on unfavorable terms, we may be unable to meet
our obligations as they come due or we may be required to post
collateral to support our obligations. Moreover, without
adequate funding, we may be unable to execute our growth
strategy, complete future acquisitions or announced and future
pipeline construction projects, take advantage of other business
opportunities or respond to competitive pressures, any of which
could have a material adverse effect on our revenues and results
of operations.
Many
of our customers drilling activity levels and spending for
transportation on our pipeline system may be impacted by the
current deterioration in commodity prices and the credit
markets.
Many of our customers finance their drilling activities through
cash flow from operations, the incurrence of debt or the
issuance of equity. Recently, there has been a significant
decline in the credit markets and the availability of credit.
Additionally, many of our customers equity values have
substantially declined. The combination of a reduction of cash
flow resulting from recent declines in natural gas prices, a
reduction in borrowing base under reserve-based credit
facilities and the lack of availability of debt or equity
financing may result in a significant reduction in our
customers spending for natural gas drilling activity,
which could result in lower volumes being transported on our
pipeline systems. For example, a number of our customers have
announced reduced drilling capital expenditure budgets for 2009.
A significant reduction in drilling activity could have a
material adverse effect on our operations.
We are
exposed to the credit risk of our customers, and an increase in
the nonpayment and nonperformance by our customers could reduce
our ability to make distributions to our
unitholders.
The risks of nonpayment and nonperformance by our customers are
a major concern in our business. Participants in the energy
industry have been subjected to heightened scrutiny from the
financial markets in light of past collapses and failures of
other energy companies. We are subject to risks of loss
resulting from nonpayment or nonperformance by our customers.
The current tightening of credit in the financial markets may
make it more difficult for customers to obtain financing and,
depending on the degree to which this occurs, there may be a
material increase in the nonpayment and nonperformance by our
customers. Any substantial increase in the nonpayment and
nonperformance by our customers could have a material effect on
our results of operations and operating cash flows.
The
FERC is pursuing legal action against us relating to certain
natural gas trading activities, and related third party actions
have been filed against us and ETE.
On July 26, 2007, the FERC issued to us an Order to Show
Cause and Notice of Proposed Penalties (the Order and
Notice) that contains allegations that we violated FERC
rules and regulations. The FERC alleged that we engaged in
manipulative or improper trading activities in the Houston Ship
Channel, primarily on two dates during the fall of 2005
following the occurrence of Hurricanes Katrina and Rita, as well
as on eight
10
other occasions from December 2003 through August 2005, in order
to benefit financially from our commodities derivatives
positions and from certain of our index-priced physical gas
purchases in the Houston Ship Channel. The FERC alleged that
during these periods we violated the FERCs then-effective
Market Behavior Rule 2, an anti-market manipulation rule
promulgated by the FERC under authority of the Natural Gas Act
(NGA). We allegedly violated this rule by
artificially suppressing prices that were included in the Platts
Inside FERC Houston Ship Channel index, published by
McGraw-Hill Companies, on which the pricing of many physical
natural gas contracts and financial derivatives are based.
Additionally, the FERC alleged that we manipulated daily prices
at the Waha and Permian Hubs in west Texas on two dates. Our
Oasis pipeline transports interstate natural gas pursuant to
Natural Gas Policy Act (NGPA) Section 311
authority and is subject to the FERC-approved rates, terms and
conditions of service. The Order and Notice alleged that the
Oasis pipeline violated NGPA regulations from January 26,
2004 through June 30, 2006 by granting undue preference to
its affiliates for interstate NGPA Section 311 pipeline
service to the detriment of similarly situated non-affiliated
shippers and by charging in excess of the FERC-approved maximum
lawful rate for interstate NGPA Section 311 transportation.
The FERC also seeks to revoke, for a period of 12 months,
our blanket marketing authority for sales of natural gas in
interstate commerce at market-based prices. If the FERC is
successful in revoking our blanket marketing authority, our
sales of natural gas at market-based prices would be limited to
sales to retail customers (such as utilities and other
end-users) and sales from our own production, and any other
sales of natural gas by us would be required to be made at
contract prices that would be subject to individual FERC
approval.
In its Order and Notice, the FERC specified that it was seeking
$70.1 million in disgorgement of profits, plus interest,
and $97.5 million in civil penalties relating to these
matters. The FERC has taken the position that, once it receives
our response, it has several options as to how to proceed,
including issuing an order on the merits, requesting briefs, or
setting specified issues for a trial-type hearing before an
administrative law judge. On August 27, 2007, ETP filed a
request for rehearing of the Order and Notice. On
December 20, 2007, the FERC issued an order denying
rehearing and directed the FERC Enforcement Staff to file a
brief recommending disposition of issues by order or by
evidentiary hearing. ETP filed its response to the Order and
Notice with the FERC on October 9, 2007, which response
refuted the FERCs claims and requested a dismissal of the
FERC proceeding. On February 14, 2008, the Enforcement
Staff of the FERC filed a brief recommending that the FERC refer
various matters relating to its market manipulation allegations
for an evidentiary hearing before a FERC administrative law
judge. The Enforcement Staff also recommended that the FERC
issue an order assessing the $15.5 million portion of the
above-referenced penalty against ETP with respect to the
allegations related to ETPs Oasis pipeline and that the
Oasis-related penalty assessment, if not paid, then be referred
by the FERC to a federal district court for de novo
review. The Enforcement Staff also recommended that the FERC
impose certain changes in Oasiss business operations and
refunds to certain Oasis customers as previously proposed in the
Order and Notice. Finally, the Enforcement Staff recommended
that the FERC pursue market manipulation claims related to
ETPs trading activities in October 2005, for November
2005 monthly deliveries, a period not previously covered by
FERCs allegations in the Order and Notice, and that ETP be
assessed an additional civil penalty of $25.0 million and
be required to disgorge approximately $7.3 million of
alleged unjust profits related to this additional month. On
March 31, 2008, we responded to the Enforcement
Staffs brief. On May 15, 2008, the FERC ordered
hearings to be conducted by FERC administrative law judges with
respect to the FERCs Oasis claims and market manipulation
claims. In this order, the FERC set for hearing the Enforcement
Staffs claims for the additional month in 2005, bringing
the total amount of civil penalties and disgorgement of profits
sought by the FERC to approximately $200 million, excluding
interest. The hearing related to the Oasis claims was scheduled
to commence in December 2008 with the administrative law
judges initial decisions due by May 11, 2009,
however, as discussed below, we entered into a settlement
agreement with FERC Enforcement Staff and that agreement was
approved by the FERC in its entirety and without modification on
February 27, 2009. The hearing related to the market
manipulation claims is now scheduled to commence in July 2009
with the administrative law judges initial decision due by
January 7, 2010. The FERC also ordered that, following the
completion of the hearings, the administrative law judges make
initial findings with respect to whether we engaged in market
manipulation in violation of the NGA and FERC regulations and
whether Oasis violated the NGPA and FERC
11
regulations. The FERC reserved for itself the issues of possible
civil penalties, revocation of our blanket market certificate,
the method by which we and Oasis would disgorge any unjust
profits and whether any conditions should be placed on
Oasiss Section 311 authorization. Following the
issuance of each of the administrative law judges initial
decisions, the FERC would then issue an order with respect to
each of these matters. On May 23, 2008, we requested
rehearing and stay of the FERCs May 15, 2008 order
establishing hearing, and we renewed those requests on
June 26, 2008. On August 7, 2008, FERC denied
rehearing of its May 15, 2008 order. On August 8,
2008, we filed a petition with the U.S. Court of Appeals
for the Fifth Circuit to review and set aside FERCs May 15
and August 7, 2008 orders on the grounds that we are
entitled to adjudicate FERCs claims in federal district
court pursuant to the NGA and the NGPA. On August 28, 2008,
we filed an amended petition seeking review of the Order and
Notice and the December 20, 2007 order denying rehearing.
The Fifth Circuit dismissed our petition without reaching the
merits on April 28, 2009. On June 12, 2009, we sought
rehearing and rehearing en banc of the Courts
April 28, 2009 order.
On November 18, 2008, the administrative law judge
presiding over the Oasis claims granted our motion for summary
disposition of the claim that Oasis unduly discriminated in
favor of affiliates regarding the provision of
Section 311(a)(2) interstate transportation service. We
subsequently entered into an agreement with the Enforcement
Staff to settle all of the claims related to Oasis. On
January 5, 2009, this agreement was submitted under seal to
FERC by the presiding administrative law judge, for FERCs
approval as an uncontested settlement of all Oasis claims. On
February 27, 2009, the settlement agreement was approved by
the FERC in its entirety and without modification and the terms
of the settlement were made public. The FERCs order is now
final and non-appealable. We do not believe the Oasis
settlement, as approved by the FERC, will have a material
adverse effect on our business, financial condition or results
of operations.
It is our position that our trading and transportation
activities during the periods at issue complied in all material
aspects with applicable law and regulations, and we intend to
contest these cases vigorously. However, the laws and
regulations related to alleged market manipulation are vague,
subject to broad interpretation, and offer little guiding
precedent, while at the same time the FERC holds substantial
enforcement authority. At this time, we are unable to predict
the final outcome of these matters.
On July 26, 2007, the United States Commodity Futures
Trading Commission (the CFTC) filed suit in United
States District Court for the Northern District of Texas
alleging that we violated provisions of the Commodity Exchange
Act (CEA) by attempting to manipulate natural gas
prices in the Houston Ship Channel. On March 17, 2008, we
entered into a consent order with the CFTC (the Consent
Order). Pursuant to the Consent Order, we agreed to pay
the CFTC $10.0 million and the CFTC agreed to release us
and our affiliates, directors and employees from all claims or
causes of action asserted by the CFTC in this proceeding. The
Consent Order provides that we are permanently enjoined from
attempting to manipulate the price of any commodity in
interstate commerce in violation of the CEA. By consenting to
the entry of the Consent Order, we neither admitted nor denied
the allegations made by the CFTC in this proceeding. The
settlement reduced our existing accrual and was paid from cash
flow from operations in March 2008.
In addition to the FERC legal action, third parties have
asserted claims and may assert additional claims against us and
ETE alleging damages related to these matters. In this regard,
several natural gas producers and a natural gas marketing
company have initiated legal proceedings in Texas state courts
against us and ETE for claims related to the FERC claims. These
suits contain contract and tort claims relating to alleged
manipulation of natural gas prices at the Houston Ship Channel
and the Waha Hub in West Texas, as well as the natural gas price
indices related to these markets and the Permian Basin natural
gas price index during the period from December 2003 through
December 2006, and seek unspecified direct, indirect,
consequential and exemplary damages. One of the suits against us
and ETE contains an additional allegation that we and ETE
transported gas in a manner that favored our affiliates and
discriminated against the plaintiff, and otherwise artificially
affected the market price of gas to other parties in the market.
We have moved to compel arbitration
and/or
contested subject-matter jurisdiction in some of these cases.
One such case currently is on appeal before the Texas Supreme
Court on, among other things, the issue of whether the dispute
is arbitrable.
We have also been served with a complaint from an owner of
royalty interests in natural gas producing properties,
individually and on behalf of a putative class of similarly
situated royalty owners, working interest
12
owners and producer/operators, seeking arbitration to recover
damages based on alleged manipulation of natural gas prices at
the Houston Ship Channel. We filed an original action in Harris
County state court seeking a stay of the arbitration on the
ground that the action is not arbitrable, and the state court
granted our motion for summary judgment on that issue. This
action is currently on appeal before the First Court of Appeals,
Houston.
A consolidated class action complaint has been filed against us
in the United States District Court for the Southern District of
Texas. This action alleges that we engaged in intentional and
unlawful manipulation of the price of natural gas futures and
options contracts on the New York Mercantile Exchange, or NYMEX,
in violation of the CEA. It is further alleged that during the
class period December 29, 2003 to December 31, 2005,
we had the market power to manipulate index prices, and that we
used this market power to artificially depress the index prices
at major natural gas trading hubs, including the Houston Ship
Channel, in order to benefit our natural gas physical and
financial trading positions, and that we intentionally submitted
price and volume trade information to trade publications. This
complaint also alleges that we violated the CEA by knowingly
aiding and abetting violations of the CEA. The plaintiffs state
that this allegedly unlawful depression of index prices by us
manipulated the NYMEX prices for natural gas futures and options
contracts to artificial levels during the class period, causing
unspecified damages to the plaintiffs and all other members of
the putative class who sold natural gas futures or who purchased
and/or sold
natural gas options contracts on NYMEX during the class period.
The plaintiffs have requested certification of their suit as a
class action and seek unspecified damages, court costs and other
appropriate relief. On January 14, 2008, we filed a motion
to dismiss this suit on the grounds of failure to allege facts
sufficient to state a claim. On March 20, 2008, the
plaintiffs filed a second consolidated class action complaint.
In response to this new pleading, on May 5, 2008, we filed
a motion to dismiss the complaint. On March 26, 2009, the
court issued an order dismissing the complaint, with prejudice,
for failure to state a claim. The plaintiffs have since moved
for reconsideration, and briefing on that motion is now complete.
On March 17, 2008, a second class action complaint was
filed against us in the United States District Court for the
Southern District of Texas. This action alleges that we engaged
in unlawful restraint of trade and intentional monopolization
and attempted monopolization of the market for fixed-price
natural gas baseload transactions at the Houston Ship Channel
from December 2003 through December 2005 in violation of federal
antitrust law. The complaint further alleges that during this
period we exerted monopoly power to suppress the price for these
transactions to non-competitive levels in order to benefit our
own physical natural gas positions. The plaintiff has,
individually and on behalf of all other similarly situated
sellers of physical natural gas, requested certification of its
suit as a class action and seeks unspecified treble damages,
court costs and other appropriate relief. On May 19, 2008,
we filed a motion to dismiss this complaint. On March 26,
2009, the court issued an order dismissing the complaint. The
court found that the plaintiffs failed to state a claim on all
causes of action and for anti-trust injury, but granted leave to
amend. On April 23, 2009, the plaintiffs filed a motion for
leave to amend to assert a claim for common law fraud, and
attached a proposed amended complaint as an exhibit. We have
opposed the motion and cross-moved to dismiss.
We are expensing the legal fees, consultants fees and
other expenses relating to these matters in the periods in which
such expenses are incurred. In addition, our existing accruals
for litigation and contingencies include an accrual related to
these matters. At this time, we are unable to predict the
outcome of these matters. However, it is possible that the
amount we become obliged to pay as a result of the final
resolution of these matters, whether on a negotiated settlement
basis or otherwise, will exceed the amount of our existing
accrual related to these matters. In accordance with applicable
accounting standards, we will review the amount of our accrual
related to these matters as developments related to these
matters occur and we will adjust our accrual if we determine
that it is probable that the amount we may ultimately become
obliged to pay as a result of the final resolution of these
matters is greater than the amount of our existing accrual for
these matters. As our accrual amounts are non-cash, any cash
payment of an amount in resolution of these matters would likely
be made from cash from operations or borrowings, which payments
would reduce our cash available to service our indebtedness
either directly or as a result of increased principal and
interest payments necessary to service any borrowings incurred
to finance such payments. If these payments are substantial, we
may experience a material adverse impact on our results of
operations and our liquidity.
13
The
profitability of our midstream and intrastate transportation and
storage operations are largely dependent upon natural gas
commodity prices, price spreads between two or more physical
locations and market demand for natural gas and NGLs, which are
factors beyond our control and have been volatile.
Income from our midstream and intrastate transportation and
storage operations is exposed to risks due to fluctuations in
commodity prices. For a portion of the natural gas gathered at
the North Texas System, Southeast Texas System and at the HPL
System, we purchase natural gas from producers at the wellhead
and then gather and deliver the natural gas to pipelines where
we typically resell the natural gas under various arrangements,
including sales at index prices. Generally, the gross margins we
realize under these arrangements decrease in periods of low
natural gas prices.
For a portion of the natural gas gathered and processed at the
North Texas System and Southeast Texas System, we enter into
percentage-of-proceeds arrangements, keep-whole arrangements,
and processing fee agreements pursuant to which we agree to
gather and process natural gas received from the producers.
Under percentage-of-proceeds arrangements, we generally sell the
residue gas and NGLs at market prices and remit to the producers
an agreed upon percentage of the proceeds based on an index
price. In other cases, instead of remitting cash payments to the
producer, we deliver an agreed upon percentage of the residue
gas and NGL volumes to the producer and sell the volumes we keep
to third parties at market prices. Under these arrangements our
revenues and gross margins decline when natural gas prices and
NGL prices decrease. Accordingly, a decrease in the price of
natural gas or NGLs could have an adverse effect on our results
of operations. Under keep-whole arrangements, we generally sell
the NGLs produced from our gathering and processing operations
to third parties at market prices. Because the extraction of the
NGLs from the natural gas during processing reduces the Btu
content of the natural gas, we must either purchase natural gas
at market prices for return to producers or make a cash payment
to producers equal to the value of this natural gas. Under these
arrangements, our revenues and gross margins decrease when the
price of natural gas increases relative to the price of NGLs if
we are not able to bypass our processing plants and sell the
unprocessed natural gas. Under processing fee agreements, we
process the gas for a fee. If recoveries are less than those
guaranteed the producer, we may suffer a loss by having to
supply liquids or its cash equivalent to keep the producer whole
with regard to contractual recoveries.
In the past, the prices of natural gas and NGLs have been
extremely volatile, and we expect this volatility to continue.
For example, during the year ended December 31, 2008, the
NYMEX settlement price for the prompt month contract ranged from
a high of $13.11 per MMBtu to a low of $6.47 per MMBtu. A
composite of the Mt. Belvieu average NGLs price based upon our
average NGLs composition during the year ended December 31,
2008 ranged from a high of approximately $1.96 per gallon to a
low of approximately $0.66 per gallon.
Our Oasis pipeline, East Texas pipeline, ET Fuel System and HPL
System receive fees for transporting natural gas for our
customers. Although a significant amount of the pipeline
capacity of the East Texas pipeline and various pipeline
segments of the ET Fuel and HPL Systems is committed under
long-term fee-based contracts, the remaining capacity of our
transportation pipelines is subject to fluctuation in demand
based on the markets and prices for natural gas and NGLs, which
factors may result in decisions by natural gas producers to
reduce production of natural gas during periods of lower prices
for natural gas and NGLs or may result in decisions by end users
of natural gas and NGLs to reduce consumption of these fuels
during periods of higher prices for these fuels. Our fuel
retention fees are also directly impacted by changes in natural
gas prices. Increases in natural gas prices tend to increase our
fuel retention fees, and decreases in natural gas prices tend to
decrease our fuel retention fees.
The markets and prices for natural gas and NGLs depend upon
factors beyond our control. These factors include demand for
oil, natural gas and NGLs, which fluctuate with changes in
market and economic conditions, and other factors, including:
|
|
|
|
|
the impact of weather on the demand for oil and natural gas;
|
|
|
|
the level of domestic oil and natural gas production;
|
|
|
|
the availability of imported oil and natural gas;
|
14
|
|
|
|
|
actions taken by foreign oil and gas producing nations;
|
|
|
|
the availability of local, intrastate and interstate
transportation systems;
|
|
|
|
the price, availability and marketing of competitive fuels;
|
|
|
|
the demand for electricity;
|
|
|
|
the impact of energy conservation efforts; and
|
|
|
|
the extent of governmental regulation and taxation.
|
The
use of derivative financial instruments could result in material
financial losses by us.
From time to time, we have sought to limit a portion of the
adverse effects resulting from changes in natural gas and other
commodity prices and interest rates by using derivative
financial instruments and other risk management mechanisms and
by our marketing and/or system optimization activities. To the
extent that we hedge our commodity price and interest rate
exposures, we forego the benefits we would otherwise experience
if commodity prices or interest rates were to change in our
favor. In addition, even though monitored by management, our
derivative activities can result in losses. Such losses could
occur under various circumstances, including if a counterparty
does not perform its obligations under the derivative
arrangement, the hedge is imperfect, commodity prices move
unfavorably related to our physical or financial positions, or
hedging policies and procedures are not followed.
Our
success depends upon our ability to continually contract for new
sources of natural gas supply.
In order to maintain or increase throughput levels on our
gathering and transportation pipeline systems and asset
utilization rates at our treating and processing plants, we must
continually contract for new natural gas supplies and natural
gas transportation services. We may not be able to obtain
additional contracts for natural gas supplies for our natural
gas gathering systems, and we may be unable to maintain or
increase the levels of natural gas throughput on our
transportation pipelines. The primary factors affecting our
ability to connect new supplies of natural gas to our gathering
systems include our success in contracting for existing natural
gas supplies that are not committed to other systems and the
level of drilling activity and production of natural gas near
our gathering systems or in areas that provide access to our
transportation pipelines or markets to which our systems
connect. The primary factors affecting our ability to attract
customers to our transportation pipelines consist of our access
to other natural gas pipelines, natural gas markets, natural
gas-fired power plants and other industrial end-users and the
level of drilling and production of natural gas in areas
connected to these pipelines and systems.
Fluctuations in energy prices can greatly affect production
rates and investments by third parties in the development of new
oil and natural gas reserves. Drilling activity and production
generally decrease as oil and natural gas prices decrease. We
have no control over the level of drilling activity in our areas
of operation, the amount of reserves underlying the wells and
the rate at which production from a well will decline, sometimes
referred to as the decline rate. In addition, we
have no control over producers or their production decisions,
which are affected by, among other things, prevailing and
projected energy prices, demand for hydrocarbons, the level of
reserves, geological considerations, governmental regulation and
the availability and cost of capital. Natural gas prices have
been high in recent years compared to historical periods, but
have decreased significantly during the fourth quarter of 2008
and thus far in 2009. This decline in natural gas prices coupled
with the effect of illiquid capital markets has led to a
decrease in drilling activity in some of our areas of operation.
A substantial portion of our assets, including our gathering
systems and our processing and treating plants, are connected to
natural gas reserves and wells for which the production will
naturally decline over time. Accordingly, our cash flows will
also decline unless we are able to access new supplies of
natural gas by connecting additional production to these systems.
Our transportation pipelines are also dependent upon natural gas
production in areas served by our pipelines or in areas served
by other gathering systems or transportation pipelines that
connect with our transportation pipelines. A material decrease
in natural gas production in our areas of operation or in other
areas that are connected to our areas of operation by third
party gathering systems or pipelines, as a result of depressed
commodity prices or otherwise,
15
would result in a decline in the volume of natural gas we
handle, which would reduce our revenues and operating income. In
addition, our future growth will depend, in part, upon whether
we can contract for additional supplies at a greater rate than
the rate of natural decline in our currently connected supplies.
Transwestern Pipeline Company LLC, or Transwestern, derives a
significant portion of its revenue from charging to its
customers for reservation of capacity, which charges
Transwestern receives regardless of whether these customers
actually use the reserved capacity. Transwestern also generates
revenue from transportation of natural gas for customers without
reserved capacity. As the reserves available through the supply
basins connected to Transwesterns systems naturally
decline, a decrease in development or production activity could
cause a decrease in the volume of natural gas available for
transmission or a decrease in demand for natural gas
transportation on the Transwestern system over the long run.
Investments by third parties in the development of new natural
gas reserves connected to Transwesterns facilities depend
on many factors beyond Transwesterns control.
The volumes of natural gas we transport on our intrastate
transportation pipelines may be reduced in the event that the
prices at which natural gas is purchased and sold at the Waha
Hub, the Katy Hub, the Carthage Hub and the Houston Ship Channel
Hub, the four major natural gas trading hubs served by our
pipelines, become unfavorable in relation to prices for natural
gas at other natural gas trading hubs or in other markets as
customers may elect to transport their natural gas to these
other hubs or markets using pipelines other than those we
operate.
We may
not be able to fully execute our growth strategy if we encounter
increased competition for qualified assets.
Our strategy contemplates growth through the development and
acquisition of a wide range of midstream, transportation,
storage, propane and other energy infrastructure assets while
maintaining a strong balance sheet. This strategy includes
constructing and acquiring additional assets and businesses to
enhance our ability to compete effectively and diversify our
asset portfolio, thereby providing more stable cash flow. We
regularly consider and enter into discussions regarding, and are
currently contemplating, the acquisition of additional assets
and businesses, stand alone development projects or other
transactions that we believe will present opportunities to
realize synergies and increase our cash flow.
Consistent with our acquisition strategy, we are continuously
engaged in discussions with potential sellers regarding the
possible acquisition of additional assets or businesses. Such
acquisition efforts may involve our participation in processes
that involve a number of potential buyers, commonly referred to
as auction processes, as well as situations in which
we believe we are the only party or one of a very limited number
of potential buyers in negotiations with the potential seller.
We cannot assure you that our current or future acquisition
efforts will be successful or that any such acquisition will be
completed on terms considered favorable to us.
In addition, we are experiencing increased competition for the
assets we purchase or contemplate purchasing. Increased
competition for a limited pool of assets could result in us
losing to other bidders more often or acquiring assets at higher
prices, both of which would limit our ability to fully execute
our growth strategy. Inability to execute our growth strategy
may materially adversely impact our results of operations.
An
impairment of goodwill and intangible assets could reduce our
earnings.
At March 31, 2009, our consolidated balance sheet reflected
$734.9 million of goodwill and $219.3 million of
intangible assets. Goodwill is recorded when the purchase price
of a business exceeds the fair market value of the tangible and
separately measurable intangible net assets. Accounting
principles generally accepted in the United States require us to
test goodwill for impairment on an annual basis or when events
or circumstances occur indicating that goodwill might be
impaired. Long-lived assets such as intangible assets with
finite useful lives are reviewed for impairment whenever events
or changes in circumstances indicate that the carrying amount
may not be recoverable. If we determine that any of our goodwill
or intangible assets were impaired, we would be required to take
an immediate charge to earnings with a correlative effect on
partners equity and balance sheet leverage as measured by
debt to total capitalization.
16
If we
do not make acquisitions on economically acceptable terms, our
future growth could be limited.
Our results of operations and our ability to grow and to
increase distributions to unitholders have depended principally
on our ability to make acquisitions that are accretive to our
distributable cash flow per unit.
We may be unable to make accretive acquisitions for any of the
following reasons, among others:
|
|
|
|
|
because we are unable to identify attractive acquisition
candidates or negotiate acceptable purchase contracts with them;
|
|
|
|
because we are unable to raise financing for such acquisitions
on economically acceptable terms; or
|
|
|
|
because we are outbid by competitors, some of which are
substantially larger than us and have greater financial
resources and lower costs of capital then we do.
|
Furthermore, even if we consummate acquisitions that we believe
will be accretive, those acquisitions may in fact adversely
affect our results of operations or result in a decrease in
distributable cash flow per unit. Any acquisition involves
potential risks, including the risk that we may:
|
|
|
|
|
fail to realize anticipated benefits, such as new customer
relationships, cost-savings or cash flow enhancements;
|
|
|
|
decrease our liquidity by using a significant portion of our
available cash or borrowing capacity to finance acquisitions;
|
|
|
|
significantly increase our interest expense or financial
leverage if we incur additional debt to finance acquisitions;
|
|
|
|
encounter difficulties operating in new geographic areas or new
lines of business;
|
|
|
|
incur or assume unanticipated liabilities, losses or costs
associated with the business or assets acquired for which we are
not indemnified or for which the indemnity is inadequate;
|
|
|
|
be unable to hire, train or retrain qualified personnel to
manage and operate our growing business and assets;
|
|
|
|
less effectively manage our historical assets, due to the
diversion of managements attention from other business
concerns; or
|
|
|
|
incur other significant charges, such as impairment of goodwill
or other intangible assets, asset devaluation or restructuring
charges.
|
If we consummate future acquisitions, our capitalization and
results of operations may change significantly. As we determine
the application of our funds and other resources, you will not
have an opportunity to evaluate the economics, financial and
other relevant information that we will consider.
If we
do not continue to construct new pipelines, our future growth
could be limited.
During the past several years, we have constructed several new
pipelines, and we are currently involved in constructing several
new pipelines. Our results of operations and our ability to grow
and to increase distributable cash flow per unit will depend, in
part, on our ability to construct pipelines that are accretive
to our distributable cash flow. We may be unable to construct
pipelines that are accretive to distributable cash flow for any
of the following reasons, among others:
|
|
|
|
|
We are unable to identify pipeline construction opportunities
with favorable projected financial returns;
|
|
|
|
We are unable to raise financing for our identified pipeline
construction opportunities; or
|
|
|
|
We are unable to secure sufficient natural gas transportation
commitments from potential customers due to competition from
other pipeline construction projects or for other reasons.
|
17
Furthermore, even if we construct a pipeline that we believe
will be accretive, the pipeline may in fact adversely affect our
results of operations or results from those projected prior to
commencement of construction and other factors.
Expanding
our business by constructing new pipelines and treating and
processing facilities subjects us to risks.
One of the ways that we have grown our business is through the
construction of additions to our existing gathering,
compression, treating, processing and transportation systems.
The construction of a new pipeline or the expansion of an
existing pipeline, by adding additional compression capabilities
or by adding a second pipeline along an existing pipeline, and
the construction of new processing or treating facilities,
involve numerous regulatory, environmental, political and legal
uncertainties beyond our control and require the expenditure of
significant amounts of capital that we will be required to
finance through borrowings, the issuance of additional equity or
from operating cash flow. If we undertake these projects, they
may not be completed on schedule or at all or at the budgeted
cost. We currently have several major expansion and new build
projects planned or underway, including the Texas Independence
pipeline, the Midcontinent Express pipeline joint venture, the
Fayetteville Express pipeline joint venture and the Tiger
pipeline. A variety of factors outside our control, such as
weather, natural disasters and difficulties in obtaining permits
and rights-of-way or other regulatory approvals, as well as the
performance by third party contractors has resulted in, and may
continue to result in, increased costs or delays in
construction. Cost overruns or delays in completing a project
could have a material adverse effect on our results of
operations and cash flows. Moreover, our revenues may not
increase immediately following the completion of particular
projects. For instance, if we build a new pipeline, the
construction will occur over an extended period of time, but we
may not materially increase our revenues until long after the
projects completion. In addition, the success of a
pipeline construction project will likely depend upon the level
of natural gas exploration and development drilling activity and
the demand for pipeline transportation in the areas proposed to
be serviced by the project as well as our ability to obtain
commitments from producers in this area to utilize the newly
constructed pipelines. In this regard, we may construct
facilities to capture anticipated future growth in production in
a region in which such growth does not materialize. As a result,
new facilities may be unable to attract enough throughput or
contracted capacity reservation commitments to achieve our
expected investment return, which could adversely affect our
results of operations and financial condition.
We
depend on certain key producers for our supply of natural gas on
the Southeast Texas System and North Texas System, and the loss
of any of these key producers could adversely affect our
financial results.
For the year ended December 31, 2008, ConocoPhillips
Company, XTO Energy Inc., Encana Oil and Gas (USA) Inc., and
Sandridge Energy Inc. supplied us with approximately 75% of the
Southeast Texas Systems natural gas supply. For the year
ended December 31, 2008, Encana Oil and Gas (USA), Inc.,
EOG Resources, Inc., XTO Energy Inc., and Chesapeake Energy
Marketing, Inc. supplied us with approximately 75% of the North
Texas Systems natural gas supply. We are not the only
option available to these producers for disposition of the
natural gas they produce. To the extent that these and other
producers may reduce the volumes of natural gas that they supply
us, we would be adversely affected unless we were able to
acquire comparable supplies of natural gas from other producers.
We
depend on key customers to transport natural gas through our
pipelines.
We have nine- and ten-year fee-based transportation contracts
with XTO Energy, Inc. (XTO) that terminate in 2013
and 2017, respectively, pursuant to which XTO has committed to
transport certain minimum volumes of natural gas on pipelines in
our ET Fuel System. We also have an eight-year fee-based
transportation contract with TXU Portfolio Management Company,
L.P., a subsidiary of TXU Corp. (TXU Shipper)
to transport natural gas on the ET Fuel System to TXUs
electric generating power plants. We have also entered into two
eight-year natural gas storage contracts that terminate in 2012
with TXU Shipper to store natural gas at the two natural gas
storage facilities that are part of the ET Fuel System. Each of
the contracts with TXU Shipper may be extended by TXU Shipper
for two additional five-year terms. The
18
failure of XTO Energy or TXU Shipper to fulfill their
contractual obligations under these contracts could have a
material adverse effect on our cash flow and results of
operations if we were not able to replace these customers under
arrangements that provide similar economic benefits as these
existing contracts.
The major shippers on our intrastate transportation pipelines
include XTO, EOG Resources, Inc., Chesapeake Energy Marketing,
Inc., EnCana Marketing (USA), Inc. and Quicksilver Resources,
Inc. These shippers have long-term contracts that have remaining
terms ranging from three to fifteen years. The failure of these
shippers to fulfill their contractual obligations could have a
material adverse effect on our cash flow and results of
operations if we were not able to replace these customers under
arrangements that provide similar economic benefits as these
existing contracts.
With respect to our interstate transportation operations, MEP,
the joint venture entity formed to construct and operate the
Midcontinent Express pipeline, has secured predominantly
10-year firm
transportation contracts from a small number of major shippers
for all of the initial 1.5 Bcf/d of capacity on the
Midcontinent Express pipeline. MEP has also secured firm
transportation commitments for an additional 0.3 Bcf/d of
capacity on the Midcontinent Express pipeline, which expansion
is subject to regulatory approval. FEP, the joint venture entity
formed to construct and operate the Fayetteville Express
pipeline, has secured a binding
10-year
commitment for approximately 1.85 Bcf/d of firm
transportation service on the 2.0 Bcf/d Fayetteville
Express pipeline project. In connection with our Tiger pipeline
project, we have entered into an agreement with Chesapeake
Energy Marketing, Inc. that provides for a
15-year
commitment for firm transportation capacity of approximately
1.0 Bcf/d.
We have also entered into agreements with EnCana Marketing
(USA), Inc. and another shipper that provide for 10-year
commitments for firm transportation capacity on the Tiger
pipeline of not less than 0.5 Bcf/d. The failure of these
key shippers to fulfill their contractual obligations could have
a material adverse effect on our cash flow and results of
operations if we were not able to replace these customers under
arrangements that provide similar economic benefits as these
existing contracts.
Federal,
state or local regulatory measures could adversely affect the
business and operations of our midstream and intrastate
assets.
Our midstream and intrastate transportation and storage
operations are generally exempt from FERC regulation under the
NGA, but FERC regulation still significantly affects our
business and the market for our products. The rates, terms and
conditions of some of the transportation and storage services we
provide on the HPL System, the East Texas pipeline, the Oasis
pipeline and the ET Fuel System are subject to FERC regulation
under Section 311 of the Natural Gas Policy Act, or NGPA.
Under Section 311, rates charged for transportation and
storage must be fair and equitable amounts. Amounts collected in
excess of fair and equitable rates are subject to refund with
interest, and the terms and conditions of service, set forth in
the pipelines statement of operating conditions, are
subject to FERC review and approval. Should FERC determine not
to authorize rates equal to or greater than our currently
approved rates, we may suffer a loss of revenue. Failure to
observe the service limitations applicable to storage and
transportation service under Section 311, and failure to
comply with the rates approved by FERC for Section 311
service, and failure to comply with the terms and conditions of
service established in the pipelines FERC-approved
statement of operating conditions could result in an alteration
of jurisdictional status
and/or the
imposition of administrative, civil and criminal penalties.
Our intrastate transportation and storage operations are subject
to state regulation in Texas, New Mexico, Arizona, Louisiana,
Utah and Colorado, the states in which we operate these types of
natural gas facilities. Our intrastate transportation operations
located in Texas are subject to regulation as common purchasers
and as gas utilities by the Texas Railroad Commission, or TRRC.
The TRRCs jurisdiction extends to both rates and pipeline
safety. The rates we charge for transportation and storage
services are deemed just and reasonable under Texas law unless
challenged in a complaint. Should a complaint be filed or should
regulation become more active, our business may be adversely
affected.
Our midstream and intrastate transportation operations are also
subject to ratable take and common purchaser statutes in Texas,
New Mexico, Arizona, Louisiana, Utah and Colorado. Ratable take
statutes generally require gatherers to take, without undue
discrimination, natural gas production that may be tendered to
the gatherer for handling. Similarly, common purchaser statutes
generally require gatherers to purchase
19
without undue discrimination as to source of supply or producer.
These statutes have the effect of restricting our right as an
owner of gathering facilities to decide with whom we contract to
purchase or transport natural gas. Federal law leaves any
economic regulation of natural gas gathering to the states, and
some of the states in which we operate have adopted
complaint-based or other limited economic regulation of natural
gas gathering activities. States in which we operate that have
adopted some form of complaint-based regulation, like Texas,
generally allow natural gas producers and shippers to file
complaints with state regulators in an effort to resolve
grievances relating to natural gas gathering rates and access.
Other state and local regulations also affect our business.
Our storage facilities are also subject to the jurisdiction of
the TRRC. Generally, the TRRC has jurisdiction over all
underground storage of natural gas in Texas, unless the facility
is part of an interstate gas pipeline facility. Because the
natural gas storage facilities of the ET Fuel System and HPL
System are only connected to intrastate gas pipelines, they fall
within the TRRCs jurisdiction and must be operated
pursuant to TRRC permit. Certain changes in ownership or
operation of TRCC-jurisdictional storage facilities, such as
facility expansions and increases in the maximum operating
pressure, must be approved by the TRRC through an amendment to
the facilitys existing permit. In addition, the TRRC must
approve transfers of the permits. Texas laws and regulations
also require all natural gas storage facilities to be operated
to prevent waste, the uncontrolled escape of gas, pollution and
danger to life or property. Accordingly, the TRRC requires
natural gas storage facilities to implement certain safety,
monitoring, reporting and record-keeping measures. Violations of
the terms and provisions of a TRRC permit or a TRRC order or
regulation can result in the modification, cancellation or
suspension of an operating permit
and/or civil
penalties, injunctive relief, or both.
The states in which we conduct operations administer federal
pipeline safety standards under the Pipeline Safety Act of 1968,
which requires certain pipeline companies to comply with safety
standards in constructing and operating the pipelines, and
subjects pipelines to regular inspections. Some of our gathering
facilities are exempt from the requirements of this Act. In
respect to recent pipeline accidents in other parts of the
country, Congress and the Department of Transportation have
passed or are considering heightened pipeline safety
requirements.
Failure to comply with applicable laws and regulations could
result in the imposition of administrative, civil and criminal
remedies.
Our
interstate pipelines are subject to laws, regulations and
policies governing the rates they are allowed to charge for
their services.
Laws, regulations and policies governing interstate natural gas
pipeline rates could affect the ability of our interstate
pipelines to establish rates, to charge rates that would cover
future increases in its costs, or to continue to collect rates
that cover current costs. NGA-jurisdictional natural gas
companies must charge rates that are just and reasonable by
FERC. The rates charged by natural gas companies are generally
required to be on file with FERC in FERC-approved tariffs.
Pursuant to the NGA, existing tariff rates may be challenged by
complaint and rate increases proposed by the natural gas company
may be challenged by protest. We also may be limited by the
terms of negotiated rate agreements from seeking future rate
increases, or constrained by competitive factors from charging
our FERC-approved maximum just and reasonable rates. Further,
rates must, for the most part, be cost-based and FERC may, on a
prospective basis, order refunds of amounts collected under
rates that have been found by FERC to be in excess of a just and
reasonable level.
Transwestern filed a general rate case in September 2006. The
rates in this proceeding were settled and are final and no
longer subject to refund. Transwestern is not required to file a
new general rate case until October 2011. However, shippers
(other than shippers that have agreed, as parties to the
Stipulation and Agreement, not to challenge Transwesterns
tariff rates through the remaining term of the settlement) may
challenge the lawfulness of tariff rates that have become final
and effective. FERC may also investigate such rates absent
shipper complaint.
Most of the rates to be paid by the initial shippers on the
Midcontinent Express pipeline are established pursuant to
long-term, negotiated rate transportation agreements. Other
prospective shippers on Midcontinent Express pipeline that elect
not to pay a negotiated rate for service may opt instead to pay
a cost-based recourse rate established by FERC as part of
Midcontinent Express pipelines certificate of public
convenience
20
and necessity. Negotiated rate agreements generally provide a
degree of certainty to the pipeline and shipper as to a fixed
rate during the term of the relevant transportation agreement,
but such agreements can limit the pipelines future ability
to collect costs associated with construction and operation of
the pipeline that might be higher than anticipated at the time
the negotiated rate agreement was entered. The certificate order
authorizing construction, ownership and operation of
Midcontinent Express pipeline is subject to pending requests for
clarification and rehearing, and we cannot guarantee that this
order will not be altered on rehearing or that judicial review,
if any, will not result in any change to FERCs
Midcontinent Express pipeline certificate order on remand.
Any successful complaint or protest against the rates of our
interstate natural gas companies could reduce our revenues
associated with providing transportation services on a
prospective basis. We cannot assure you that our interstate
pipelines will be able to recover all of their costs through
existing or future rates.
The
ability of interstate pipelines held in tax-pass-through
entities, like us, to include an allowance for income taxes in
their regulated rates has been subject to extensive litigation
before FERC and the courts, and the FERCs current policy
is subject to future refinement or change.
The ability of interstate pipelines held in tax-pass-through
entities, like us, to include an allowance for income taxes as a
cost-of-service element in their regulated rates has been
subject to extensive litigation before FERC and the courts for a
number of years. It is currently FERCs policy to permit
pipelines to include in cost-of-service a tax allowance to
reflect actual or potential income tax liability on their public
utility income attributable to all partnership or limited
liability company interests, if the ultimate owner of the
interest has an actual or potential income tax liability on such
income. Whether a pipelines owners have such actual or
potential income tax liability will be reviewed by FERC on a
case-by-case
basis.Under FERCs policy, we thus remain eligible to
include an income tax allowance in the tariff rates we charge
for interstate natural gas transportation. The application of
that policy remains subject to future refinement or change by
FERC. With regard to rates charged and collected by
Transwestern, the allowance for income taxes as a
cost-of-service element in our tariff rates is generally not
subject to challenge prior to the expiration of our settlement
agreement in 2011.
The
intrastate pipelines are subject to laws, regulations and
policies governing terms and conditions of service, which could
adversely affect their business and operations.
In addition to rate oversight, FERCs regulatory authority
extends to many other aspects of Transwesterns business
and operations of our interstate pipelines, including:
|
|
|
|
|
operating terms and conditions of service;
|
|
|
|
the types of services Transwestern may offer to its customers;
|
|
|
|
construction of new facilities;
|
|
|
|
acquisition, extension or abandonment of services or facilities;
|
|
|
|
reporting and information posting requirements;
|
|
|
|
accounts and records; and
|
|
|
|
relationships with affiliated companies involved in all aspects
of the natural gas and energy businesses.
|
Compliance with these requirements can be costly and burdensome.
Future changes to laws, regulations and policies in these areas
may impair the ability of our interstate pipelines to compete
for business, may impair their ability to recover costs or may
increase the cost and burden of operation.
We must on occasion rely upon rulings by FERC or other
governmental authorities to carry out certain of our business
plans. For example, in order to carry out our plan to construct
the Fayetteville Express pipeline we must, among other things,
file and support before FERC an NGA Section 7(c)
application for a certificate of public convenience and
necessity to build, own and operate such a facility. We cannot
guarantee that FERC will authorize construction and operation of
this facility. Moreover, there is no guarantee that, if granted,
such certificate authority will be granted in a timely manner or
will be free from potentially burdensome conditions.
21
Similarly, we were required to obtain from FERC a certificate of
public convenience and necessity to build, own and operate the
Midcontinent Express pipeline. Although FERC has granted us such
certificate authority, there are pending requests for
clarification and rehearing of that order. We cannot guarantee
that FERC will, on rehearing, reaffirm in all materials respects
its July 25, 2008 Midcontinent Express certificate order.
Nor can we guarantee that FERCs certificate order will not
be subject to judicial review and, ultimately, to possible
material alteration if remanded to FERC.
Failure to comply with all applicable FERC-administered
statutes, rules, regulations and orders, could bring substantial
penalties and fines. Under the Energy Policy Act of 2005, FERC
has civil penalty authority under the NGA to impose penalties
for current violations of up to $1.0 million per day for
each violation. FERC possesses similiar authority under the NGPA.
Finally, we cannot give any assurance regarding the likely
future regulations under which we will operate our interstate
pipelines or the effect such regulation could have on our
business, financial condition, and results of operations.
Our
business involves hazardous substances and may be adversely
affected by environmental regulation.
Our natural gas as well as our propane operations are subject to
stringent federal, state, and local environmental laws and
regulations governing the discharge of materials into the
environment or otherwise relating to environmental protection.
These laws and regulations may require the acquisition of
permits for our operations, result in capital expenditures to
manage, limit, or prevent emissions, discharges, or releases of
various materials from our pipelines, plants, and facilities,
and impose substantial liabilities for pollution resulting from
our operations. Several governmental authorities, such as the
U.S. Environmental Protection Agency, have the power to
enforce compliance with these laws and regulations and the
permits issued under them and frequently mandate difficult and
costly remediation measures and other actions. Failure to comply
with these laws, regulations, and permits may result in the
assessment of administrative, civil, and criminal penalties, the
imposition of remedial obligations, and the issuance of
injunctive relief.
We may incur substantial environmental costs and liabilities
because of the underlying risk inherent to our operations.
Environmental laws provide joint and several, strict liability
for clean up costs incurred to address discharges or releases of
petroleum hydrocarbons or wastes on, under, or from our
properties and facilities, many of which have been used for
industrial activities for a number of years even if such
discharges were caused by our predecressors. Private parties,
including the owners of properties through which our gathering
systems pass or facilities where our petroleum hydrocarbons or
wastes are taken for reclamation or disposal, may also have the
right to pursue legal actions to enforce compliance as well as
to seek damages for non-compliance with environmental laws and
regulations or for personal injury or property damage. As of
March 31, 2009, the total accrued future estimated cost of
remediation activities relating to our Transwestern pipeline
operations is approximately $9.0 million, which activities
are expected to continue through 2018.
Changes in environmental laws and regulations occur frequently,
and any such changes that result in more stringent and costly
waste handling, emission standards, or storage, transport,
disposal or remediation requirements could have a material
adverse effect on our operations or financial position. For
example, the EPA in 2008 lowered the federal ozone standard from
0.08 parts per million to 0.075 parts per million, which will
require the environmental agencies in states with areas that do
not currently meet this standard to adopt new rules between to
further reduce NOx and other ozone precursor emissions. We have
previously been able to satisfy the more stringent NOx emission
reduction requirements that affect our compressor units in ozone
non-attainment areas at reasonable cost, but there is no
guarantee that the changes we may have to make in the future to
meet the new ozone standard or other evolving standards will not
require us to incur costs that could be material to our
operations.
In response to scientific studies suggesting that emissions of
certain gases, commonly referred to as greenhouse
gases and including carbon dioxide and methane, may be
contributing to the warming of the Earths atmosphere,
President Obama has expressed support for, and it is anticipated
that the current session of Congress will consider, legislation
to restrict or regulate emissions of greenhouse gases. In
addition, more than one-third of the states, either individually
or through multi-state regional initiatives, already have begun
implementing legal measures to reduce emissions of greenhouse
gases, primarily through the planned
22
development of emission inventories or regional greenhouse gas
cap and trade programs. These cap and
trade programs could require major sources of emissions,
such as electric power plants, or major producers of fuels, such
as refineries or gas processing plants, to acquire emission
allowances from other businesses that emit greenhouse gases at
levels lower than the limits specified in those programs and
then surrender these allowances as a credit against such
emissions. Depending on the particular program, we could be
required to purchase and surrender allowances, either for
greenhouse gas emissions resulting from our operations
(e.g., compressor stations) or from the combustion of
fuels (e.g., natural gas) that we process.
Also, as a result of the United States Supreme Courts
decision on April 2, 2007 in Massachusetts, et
al. v. EPA, the EPA may regulate greenhouse gas
emissions from mobile sources such as cars and trucks even if
Congress does not adopt new legislation specifically addressing
emissions of greenhouse gases. The Courts holding in
Massachusetts that greenhouse gases including carbon
dioxide fall under the federal Clean Air Acts definition
of air pollutant may also result in future
regulation of carbon dioxide and other greenhouse gas emissions
from stationary sources. In July 2008, EPA released an
Advance Notice of Proposed Rulemaking regarding
possible future regulation of greenhouse gas emissions under the
Clean Air Act, in response to the Supreme Courts decision
in Massachusetts. In the notice, EPA evaluated the
potential regulation of greenhouse gases under the Clean Air Act
and other potential methods of regulating greenhouse gases.
Although the notice did not propose any specific, new regulatory
requirements for greenhouse gases, it indicates that federal
regulation of greenhouse gas emissions could occur in the near
future even if Congress does not adopt new legislation
specifically addressing emissions of greenhouse gases. Although
it is not possible at this time to predict how legislation or
new regulations that may be adopted to address greenhouse gas
emissions would impact our business, any such new federal,
regional or state restrictions on emissions of carbon dioxide or
other greenhouse gases that may be imposed in areas in which we
conduct business could also have an adverse affect on our cost
of doing business and demand for the natural gas we process and
transport.
Any
reduction in the capacity of, or the allocations to, our
shippers in interconnecting, third-party pipelines could cause a
reduction of volumes transported in our pipelines, which would
adversely affect our revenues and cash flow.
Users of our pipelines are dependent upon connections to and
from third-party pipelines to receive and deliver natural gas
and NGLs. Any reduction in the capacities of these
interconnecting pipelines due to testing, line repair, reduced
operating pressures, or other causes could result in reduced
volumes being transported in our pipelines. Similarly, if
additional shippers begin transporting volumes of natural gas
and NGLs over interconnecting pipelines, the allocations to
existing shippers in these pipelines would be reduced, which
could also reduce volumes transported in our pipelines. Any
reduction in volumes transported in our pipelines would
adversely affect our revenues and cash flow.
We
encounter competition from other midstream, transportation and
storage companies and propane companies.
We experience competition in all of our markets. Our principal
areas of competition include obtaining natural gas supplies for
the Southeast Texas System, North Texas System and HPL System
and natural gas transportation customers for our transportation
pipeline systems. Our competitors include major integrated oil
companies, interstate and intrastate pipelines and companies
that gather, compress, treat, process, transport, store and
market natural gas. The Southeast Texas System competes with
natural gas gathering and processing systems owned by DCP
Midstream, LLC. The North Texas System competes with Crosstex
North Texas Gathering, LP and Devon Gas Services, LP for
gathering and processing. The East Texas pipeline competes with
other natural gas transportation pipelines that serve the
Bossier Sands area in east Texas and the Barnett Shale region in
north Texas. The ET Fuel System and the Oasis pipeline compete
with a number of other natural gas pipelines, including
interstate and intrastate pipelines that link the Waha Hub. The
ET Fuel System competes with other natural gas
transportation pipelines serving the Dallas/Ft. Worth area
and other pipelines that serve the east central Texas and south
Texas markets. Pipelines that we compete with in these areas
include those owned by Atmos Energy Corporation, Enterprise
Products Partners, L.P., and Enbridge, Inc. Some of our
competitors may have greater financial resources and access to
larger natural gas supplies than we do.
23
The acquisitions of the HPL System and the Transwestern pipeline
increased the number of interstate pipelines and natural gas
markets to which we have access and expanded our principal areas
of competition to areas such as southeast Texas and the Texas
Gulf Coast. As a result of our expanded market presence and
diversification, we face additional competitors, such as major
integrated oil companies, interstate and intrastate pipelines
and companies that gather, compress, treat, process, transport,
store and market natural gas, that may have greater financial
resources and access to larger natural gas supplies than we do.
The Transwestern pipeline competes with, and upon completion,
the Midcontinent Express pipeline and Fayetteville Express
pipeline will complete with, other interstate and intrastate
pipeline companies in the transportation and storage of natural
gas. The principal elements of competition among pipelines are
rates, terms of service and the flexibility and reliability of
service. Natural gas competes with other forms of energy
available to our customers and end-users, including electricity,
coal and fuel oils. The primary competitive factor is price.
Changes in the availability or price of natural gas and other
forms of energy, the level of business activity, conservation,
legislation and governmental regulations, the capability to
convert to alternate fuels and other factors, including weather
and natural gas storage levels, affect the levels of natural gas
transportation volumes in the areas served by our pipelines.
Our propane business competes with a number of large national
and regional propane companies and several thousand small
independent propane companies. Because of the relatively low
barriers to entry into the retail propane market, there is
potential for small independent propane retailers, as well as
other companies that may not currently be engaged in retail
propane distribution, to compete with our retail outlets. As a
result, we are always subject to the risk of additional
competition in the future. Generally, warmer-than-normal weather
further intensifies competition. Most of our propane retail
branch locations compete with several other marketers or
distributors in their service areas. The principal factors
influencing competition with other retail propane marketers are:
|
|
|
|
|
price,
|
|
|
|
reliability and quality of service,
|
|
|
|
responsiveness to customer needs,
|
|
|
|
safety concerns,
|
|
|
|
long-standing customer relationships,
|
|
|
|
the inconvenience of switching tanks and suppliers, and
|
|
|
|
the lack of growth in the industry.
|
The
inability to continue to access tribal lands could adversely
affect Transwesterns ability to operate its pipeline
system and the inability to recover the cost of right-of-way
grants on tribal lands could adversely affect its financial
results.
Transwesterns ability to operate its pipeline system on
certain lands held in trust by the United States for the benefit
of a Native American Tribe, which we refer to as tribal lands,
will depend on its success in maintaining existing rights-of-way
and obtaining new rights-of-way on those tribal lands. Securing
additional rights-of-way is also critical to Transwesterns
ability to pursue expansion projects. We cannot provide any
assurance that Transwestern will be able to acquire new
rights-of-way on tribal lands or maintain access to existing
rights-of-way upon the expiration of the current grants. Our
financial position could be adversely affected if the costs of
new or extended right-of-way grants cannot be recovered in rates.
We may
be unable to bypass the processing plants, which could expose us
to the risk of unfavorable processing margins.
Because of our ownership of the Oasis pipeline and ET Fuel
System, we can generally elect to bypass our processing plants
when processing margins are unfavorable and instead deliver
pipeline-quality gas by blending rich gas from the gathering
systems with lean gas transported on the Oasis pipeline and ET
Fuel
24
System. In some circumstances, such as when we do not have a
sufficient amount of lean gas to blend with the volume of rich
gas that we receive at the processing plant, we may have to
process the rich gas. If we have to process when processing
margins are unfavorable, our results of operations will be
adversely affected.
We may
be unable to retain existing customers or secure new customers,
which would reduce our revenues and limit our future
profitability.
The renewal or replacement of existing contracts with our
customers at rates sufficient to maintain current revenues and
cash flows depends on a number of factors beyond our control,
including competition from other pipelines, and the price of,
and demand for, natural gas in the markets we serve.
For the year ended December 31, 2008, approximately 27.3%
of our sales of natural gas were to industrial end-users and
utilities. As a consequence of the increase in competition in
the industry and volatility of natural gas prices, end-users and
utilities are increasingly reluctant to enter into long-term
purchase contracts. Many end-users purchase natural gas from
more than one natural gas company and have the ability to change
providers at any time. Some of these end-users also have the
ability to switch between gas and alternate fuels in response to
relative price fluctuations in the market. Because there are
many companies of greatly varying size and financial capacity
that compete with us in the marketing of natural gas, we often
compete in the end-user and utilities markets primarily on the
basis of price. The inability of our management to renew or
replace our current contracts as they expire and to respond
appropriately to changing market conditions could have a
negative effect on our profitability.
Our
storage business depends on neighboring pipelines to transport
natural gas.
To obtain natural gas, our storage business depends on the
pipelines to which they have access. Many of these pipelines are
owned by parties not affiliated with us. Any interruption of
service on those pipelines or adverse change in their terms and
conditions of service could have a material adverse effect on
our ability, and the ability of our customers, to transport
natural gas to and from our facilities and a corresponding
material adverse effect on our storage revenues. In addition,
the rates charged by those interconnected pipelines for
transportation to and from our facilities affect the utilization
and value of our storage services. Significant changes in the
rates charged by those pipelines or the rates charged by other
pipelines with which the interconnected pipelines compete could
also have a material adverse effect on our storage revenues.
Our
pipeline integrity program may cause us to incur significant
costs and liabilities.
Our operations are subject to regulation by the
U.S. Department of Transportation (DOT) under
the Pipeline Hazardous Materials Safety Administration
(PHMSA) pursuant to which the PHMSA has established
regulations relating to the design, installation, testing,
construction, operation, replacement and management of pipeline
facilities. Moreover, the PHMSA, through the Office of Pipeline
Safety, has promulgated a rule requiring pipeline operators to
develop integrity management programs to comprehensively
evaluate their pipelines, and take measures to protect pipeline
segments located in what the rule refers to as high
consequence areas. Based on the results of our current
pipeline integrity testing programs, we estimate that compliance
with these federal regulations and analogous state pipeline
integrity requirements for its existing transportation assets
other than the Transwestern pipeline will result in capital
costs of $27.1 million during the twelve months ending
December 31, 2009, as well as operating and maintenance
costs of $27.6 million during that period. During this same
time period, we estimate that we will incur pipeline integrity
capital cost of $8.9 million, as well as operating and
maintenance costs of $1.7 million with respect to our
Transwestern pipeline. Through March 31, 2009, Transwestern
did not incur any costs associated with the IMP Rule and has
satisfied all of the requirements. Through March 31, 2009,
a total of $19.9 million of capital costs and
$16.0 million of operating and maintenance costs have been
incurred for pipeline integrity testing for transportation
assets other than Transwestern, including $3.5 million of
capital costs and $3.3 million of operating and maintenance
costs during the first quarter of 2009. Through March 31,
2009, a total of $7.1 million of capital costs and
$0.5 million of operating and maintenance costs have been
incurred for pipeline integrity testing for Transwestern,
including $0.2 million of capital costs and
$0.1 million of operating and maintenance costs during the
first quarter of 2009. Integrity testing and assessment of all
of these assets
25
will continue, and the potential exists that results of such
costs and assessment could cause us to incur even greater
capital and operating expenditures for repairs or upgrades
deemed necessary to ensure the continued safe and reliable
operation of our pipelines.
Since
weather conditions may adversely affect demand for propane, our
financial conditions may be vulnerable to warm
winters.
Weather conditions have a significant impact on the demand for
propane for heating purposes because the majority of our
customers rely heavily on propane as a heating fuel. Typically,
we sell approximately two-thirds of our retail propane volume
during the peak-heating season of October through March. Our
results of operations can be adversely affected by warmer winter
weather which results in lower sales volumes. In addition, to
the extent that warm weather or other factors adversely affect
our operating and financial results, our access to capital and
our acquisition activities may be limited. Variations in weather
in one or more of the regions where we operate can significantly
affect the total volume of propane that we sell and the profits
realized on these sales. Agricultural demand for propane may
also be affected by weather, including periods of unseasonably
cold or hot periods or dry weather conditions that impact
agricultural operations.
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.
Virtually all of our operations are exposed to potential natural
disasters, including hurricanes, tornadoes, storms, floods
and/or
earthquakes.
If one or more facilities that are owned by us or that deliver
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 to our unitholders and, accordingly,
adversely affect the market price of our common units.
As a result of market conditions, premiums and deductibles for
certain insurance policies can increase substantially, and in
some instances, certain insurance may become unavailable or
available only for reduced amounts of coverage. As a result, we
may not be able to renew existing insurance policies 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.
Terrorist
attacks aimed at our facilities could adversely affect our
business, results of operations, cash flows and financial
condition.
Since the September 11, 2001 terrorist attacks on the
United States, the United States government has issued warnings
that energy assets, including our nations pipeline
infrastructure, may be the future target of terrorist
organizations. Any terrorist attack on our facilities or
pipelines or those of our customers could have a material
adverse effect on our business.
26
Sudden
and sharp propane price increases that cannot be passed on to
customers may adversely affect our profit margins.
The propane industry is a margin-based business in
which gross profits depend on the excess of sales prices over
supply costs. As a result, our profitability is sensitive to
changes in energy prices, and in particular, changes in
wholesale prices of propane. When there are sudden and sharp
increases in the wholesale cost of propane, we may be unable to
pass on these increases to our customers through retail or
wholesale prices. Propane is a commodity and the price we pay
for it can fluctuate significantly in response to changes in
supply or other market conditions over which we have no control.
In addition, the timing of cost pass-throughs can significantly
affect margins. Sudden and extended wholesale price increases
could reduce our gross profits and could, if continued over an
extended period of time, reduce demand by encouraging our retail
customers to conserve their propane usage or convert to
alternative energy sources.
Our
results of operations could be negatively impacted by price and
inventory risk related to our propane business and management of
these risks.
We generally attempt to minimize our cost and inventory risk
related to our propane business by purchasing propane on a
short-term basis under supply contracts that typically have a
one-year term and at a cost that fluctuates based on the
prevailing market prices at major delivery points. In order to
help ensure adequate supply sources are available during periods
of high demand, we may purchase large volumes of propane during
periods of low demand or low price, which generally occur during
the summer months, for storage in our facilities, at major
storage facilities owned by third parties or for future
delivery. This strategy may not be effective in limiting our
cost and inventory risks if, for example, market, weather or
other conditions prevent or allocate the delivery of physical
product during periods of peak demand. If the market price falls
below the cost at which we made such purchases, it could
adversely affect our profits.
Some of our propane sales are pursuant to commitments at fixed
prices. To mitigate the price risk related to our anticipated
sales volumes under the commitments, we may purchase and store
physical product
and/or enter
into fixed price over-the-counter energy commodity forward
contracts and options. Generally, over-the-counter energy
commodity forward contracts have terms of less than one year. We
enter into such contracts and exercise such options at volume
levels that we believe are necessary to manage these
commitments. The risk management of our inventory and contracts
for the future purchase of product could impair our
profitability if the customers do not fulfill their obligations.
We also engage in other trading activities, and may enter into
other types of over-the-counter energy commodity forward
contracts and options. These trading activities are based on our
managements estimates of future events and prices and are
intended to generate a profit. However, if those estimates are
incorrect or other market events outside of our control occur,
such activities could generate a loss in future periods and
potentially impair our profitability.
We are
dependent on our principal propane suppliers, which increases
the risk of an interruption in supply.
During 2008, we purchased approximately 50.7%, 15.0% and 14.9%
of our propane from Enterprise, Targa Liquids and M.P. Oils,
Ltd., respectively. Enterprise is a subsidiary of
Enterprise GP, an entity that owns approximately 17.6% of
ETEs outstanding common units and a 40.6% non-controlling
equity interest in the General Partner of ETE. Titan purchases
substantially all of its propane from Enterprise pursuant to an
agreement that expires in 2010. If supplies from these sources
were interrupted, the cost of procuring replacement supplies and
transporting those supplies from alternative locations might be
materially higher and, at least on a short-term basis, margins
could be adversely affected. Supply from Canada is subject to
the additional risk of disruption associated with foreign trade
such as trade restrictions, shipping delays and political,
regulatory and economic instability.
Historically, a substantial portion of the propane that we
purchase has originated from one of the industrys major
markets located in Mt. Belvieu, Texas and has been shipped to us
through major common
27
carrier pipelines. Any significant interruption in the service
at Mt. Belvieu or other major market points, or on the common
carrier pipelines we use, would adversely affect our ability to
obtain propane.
Competition
from alternative energy sources may cause us to lose propane
customers, thereby reducing our revenues.
Competition in our propane business from alternative energy
sources has been increasing as a result of reduced regulation of
many utilities. Propane is generally not competitive with
natural gas in areas where natural gas pipelines already exist
because natural gas is a less expensive source of energy than
propane. The gradual expansion of natural gas distribution
systems and the availability of natural gas in many areas that
previously depended upon propane could cause us to lose
customers, thereby reducing our revenues. Fuel oil also competes
with propane and is generally less expensive than propane. In
addition, the successful development and increasing usage of
alternative energy sources could adversely affect our operations.
Energy
efficiency and technological advances may affect the demand for
propane and adversely affect our operating
results.
The national trend toward increased conservation and
technological advances, including installation of improved
insulation and the development of more efficient furnaces and
other heating devices, has decreased the demand for propane by
retail customers. Stricter conservation measures in the future
or technological advances in heating, conservation, energy
generation or other devices could adversely affect our
operations.
Tax Risks
to Common Unitholders
In addition to reading the following risk factors, you should
read Material Income Tax Considerations 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 become
subject to a material amount of entity-level taxation for state
tax purposes, it would substantially reduce the amount of cash
available for distribution to unitholders.
The anticipated after-tax economic benefit of an investment in
our common units depends largely on our being treated as a
partnership for federal income tax purposes. We have not
requested, and do not plan to request, a ruling from the IRS
with respect to our classification as a partnership for federal
income tax purposes.
Despite the fact that we are a limited partnership under
Delaware law, it is possible in certain circumstances for a
partnership such as ours may be treated as a corporation for
federal income tax purposes.
If we are so treated, we would pay federal income tax on our
taxable income at the corporate tax rate, which is currently a
maximum of 35%, and we would likely pay additional state income
taxes as well. Distributions to unitholders would generally be
taxed again as corporate distributions, and none of our income,
gains, losses or deductions would flow through to unitholders.
Because a tax would then be imposed upon us as a corporation,
our cash available for distribution to unitholders would be
substantially reduced. Therefore, treatment of us as a
corporation would result in a material reduction in the
anticipated cash flow and after-tax return to the unitholders,
likely causing a substantial reduction in the value of our
common units.
Current law may change, causing us to be treated as a
corporation for federal income tax purposes or otherwise
subjecting us to entity-level taxation.
For example, members of Congress have recently considered
substantive changes to the existing federal income tax laws that
would have affected certain publicly traded partnerships.
Specifically, federal income tax legislation has been considered
that would have eliminated partnership tax treatment for certain
publicly traded partnerships and recharacterize certain types of
income received from partnerships. We are unable to predict
28
whether any of these changes, or other proposals, will be
reintroduced or will ultimately be enacted. Any such changes
could negatively impact the value of an investment in our common
units.
We
prorate our items of income, gain, loss and deduction between
transferors and transferees of our units each month based upon
the ownership of our units on the first day of each month,
instead of on the basis of the date a particular unit is
transferred. The IRS may challenge this treatment, which could
change the allocation of items of income, gain, loss and
deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between
transferors and transferees of our units each month based upon
the ownership of our units on the first day of each month,
instead of on the basis of the date a particular unit is
transferred. If the IRS were to challenge this method or new
Treasury regulations were issued, we may be required to change
the allocation of items of income, gain, loss and deduction
among our unitholders.
If the
IRS contests the federal income tax positions we take, the
market for our common units may be adversely affected, and the
costs of any such contest will reduce cash available for
distributions to our unitholders.
The IRS may adopt positions that differ from the positions we
take. It may be necessary to resort to administrative or court
proceedings to sustain some or all of the positions we take. A
court may not agree with some or all of our counsels
conclusions or the positions we take. Any contest with the IRS
may materially and adversely impact the market for our common
units and the prices at which they trade. In addition, the costs
of any contest with the IRS will be borne by us reducing the
cash available for distribution to our unitholders.
Unitholders
may be required to pay taxes on their share of our income even
if they do not receive any cash distributions from
us.
Because our unitholders will be treated as partners to whom we
will allocate taxable income which could be different in amount
than the cash we distribute, unitholders will be required to pay
any federal income taxes and, in some cases, state and local
income taxes on your share of our taxable income even if they
receive no cash distributions from us. Unitholders may not
receive cash distributions from us equal to their share of our
taxable income or even equal to the actual tax liability that
results from the taxation of their share of our taxable income.
In such case, unitholders would still be required to pay federal
income taxes and, in some cases, state and local income taxes on
their share of our taxable income regardless of the amount, if
any, of any cash distributions they receive from us.
Tax
gain or loss on disposition of our common units could be more or
less than expected.
If unitholders sell their common units, they will recognize a
gain or loss equal to the difference between the amount realized
and the tax basis in those common units. Because distributions
in excess of the unitholders allocable share of our net
taxable income decrease the unitholders tax basis in their
common units, the amount, if any, of such prior excess
distributions with respect to the units sold will, in effect,
become taxable income to the unitholder if they sell such units
at a price greater than their tax basis in those units, even if
the price received is less than their original cost.
Furthermore, a substantial portion of the amount realized,
whether or not representing gain, may be taxed as ordinary
income due to potential recapture items, including depreciation
recapture. In addition, because the amount realized includes a
unitholders share of our nonrecourse liabilities, if a
unitholder sells units, the unitholder may incur a tax liability
in excess of the amount of cash received from the sale. Please
read Material Income Tax Considerations
Disposition of Common Units Recognition of Gain or
Loss for a further discussion of the foregoing.
29
Tax-exempt
entities and non-U.S. persons face unique tax issues from owning
common units that may result in adverse tax consequences to
them.
Investment in common units by tax-exempt entities, including
employee benefit plans and individual retirement accounts
(IRAs) and
non-U.S. persons
raises issues unique to them. For example, virtually all of our
income allocated to unitholders who are organizations exempt
from federal income tax, may be taxable to them as
unrelated business taxable income. 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 federal income tax returns and
generally 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
treat each purchaser of common units as having the same tax
benefits without regard to the actual common units purchased.
The IRS may challenge this treatment, which could result in a
unitholder owing more tax and may adversely affect the value of
the common units.
The IRS may challenge the manner in which we calculate our
unitholders basis adjustment under Section 743(b). If
so, because neither we nor a unitholder can identify the units
to which this issue relates once the initial holder has traded
them, the IRS may assert adjustments to all unitholders selling
units within the period under audit as if all unitholders owned
such units.
Any position we take that is inconsistent with applicable
Treasury Regulations may have to be disclosed on our federal
income tax return. This disclosure increases the likelihood that
the IRS will challenge our positions and propose adjustments to
some or all of our unitholders.
A successful IRS challenge to this position or other positions
we may take could adversely affect the amount of taxable income
or loss allocated to our unitholders. It also could affect the
gain from a unitholders sale of common units and could
have a negative impact on the value of the common units or
result in audit adjustments to our unitholders tax returns
without the benefit of additional deductions. Moreover, because
one of our subsidiaries that is organized as a C corporation for
federal income tax purposes owns units in us, a successful IRS
challenge could result in this subsidiary having more tax
liability than we anticipate and, therefore, reduce the cash
available for distribution to our partnership and, in turn, to
our unitholders.
A
unitholder whose units are loaned to a short seller
to cover a short sale of units may be considered as having
disposed of those units. If so, he would no longer be treated
for tax purposes as a partner with respect to those units during
the period of the loan and may recognize gain or loss from the
disposition.
Because a unitholder whose units are loaned to a short
seller to cover a short sale of units may be considered as
having disposed of the loaned units, he may no longer be treated
for tax purposes as a partner with respect to those units during
the period of the loan to the short seller and the unitholder
may recognize gain or loss from such disposition. Moreover,
during the period of the loan to the short seller, any of our
income, gain, loss or deduction with respect to those units may
not be reportable by the unitholder and any cash distributions
received by the unitholder as to those units could be fully
taxable as ordinary income. Unitholders desiring to assure their
status as partners and avoid the risk of gain recognition from a
loan to a short seller are urged to modify any applicable
brokerage account agreements to prohibit their brokers from
borrowing their units.
We
have adopted certain valuation methodologies that may result in
a shift of income, gain, loss and deduction between us and our
public unitholders. The IRS may challenge this treatment, which
could adversely affect the value of our common
units.
When we issue additional units or engage in certain other
transactions, we determine the fair market value of our assets
and allocate any unrealized gain or loss attributable to such
assets to the capital accounts of our unitholders and our
General Partner. Although we may from time to time consult with
professional appraisers regarding valuation matters, including
the valuation of our assets, we make many of the fair market
value estimates of our assets ourselves using a methodology
based on the market value of our common units as a means to
measure the fair market value of our assets. Our methodology may
be viewed as understating
30
the value of our assets. In that case, there may be a shift of
income, gain, loss and deduction between certain unitholders and
our General Partner, which may be unfavorable to such
unitholders. Moreover, under our current valuation methods,
subsequent purchasers of our common units may have a greater
portion of their Internal Revenue Code Section 743(b)
adjustment allocated to our tangible assets and a lesser portion
allocated to our intangible assets. The IRS may challenge our
valuation methods, or our allocation of Section 743(b)
adjustment attributable to our tangible and intangible assets,
and allocations of income, gain, loss and deduction between our
General Partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could
adversely affect the amount of taxable income or loss being
allocated to our unitholders. It also could affect the amount of
gain on the sale of common units by our unitholders and could
have a negative impact on the value of our common units or
result in audit adjustments to the tax returns of our
unitholders without the benefit of additional deductions.
The
sale or exchange of 50% or more of our capital and profit
interests during any twelve month period will result in the
termination of our partnership for federal income tax
purposes.
We will be considered 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. For purposes of determining whether the 50% threshold
has been met, multiple sales of the same unit will be counted
only once. Our termination would, among other things, result in
the closing of our taxable year which would require us to file
two tax returns (and could result in our unitholders receiving
two Schedules K-1) for one fiscal year, and could result in a
deferral of depreciation deductions allowable in computing our
taxable income. In the case of a unitholder reporting on a
taxable year other than a fiscal year ending December 31,
the closing of our taxable year may also result in more than
twelve months of our taxable income or loss being includable in
such unitholders taxable income for the year of
termination. Our termination currently would not affect our
classification as a partnership for federal income tax purposes.
We would be treated as a new partnership for tax purposes and
would be required to make new tax elections and could be subject
to penalties if we were unable to determine in a timely manner
that a termination occurred.
You
will likely be subject to state and local taxes and return
filing requirements in states where you do not live as a result
of investing in our common units.
In addition to federal income taxes, the unitholders may be
subject to other taxes, including state and local 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 now or in the future,
even if they do not live in any of those jurisdictions.
Unitholders may be required to file state and local income tax
returns and pay state and local income taxes in some or all of
the jurisdictions. Further, unitholders may be subject to
penalties for failure to comply with those requirements. It is
the responsibility of each unitholder to file all federal, state
and local tax returns.
31
USE OF
PROCEEDS
Except as otherwise provided in the applicable prospectus
supplement, we will use the net proceeds we receive from the
sale of the securities for general partnership purposes, which
may include repayment of indebtedness, the acquisition of
businesses and other capital expenditures and additions to
working capital.
Any specific allocation of the net proceeds of an offering of
securities to a specific purpose will be determined at the time
of the offering and will be described in a prospectus supplement.
32
RATIO OF
EARNINGS TO FIXED CHARGES
The following table sets forth our historical consolidated ratio
of earnings to fixed charges for the periods indicated therein:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Four Months
|
|
Year
|
|
Three Months
|
|
|
|
|
|
|
|
|
|
|
|
|
Ended
|
|
Ended
|
|
Ended
|
|
|
|
|
Year Ended August 31,
|
|
December 31,
|
|
December 31,
|
|
March 31,
|
|
|
|
|
2004
|
|
2005
|
|
2006
|
|
2007
|
|
2007(1)
|
|
2008
|
|
2009
|
|
|
|
Ratio of earnings to fixed charges
|
|
|
3.28
|
|
|
|
3.02
|
|
|
|
5.14
|
|
|
|
4.28
|
|
|
|
4.31
|
|
|
|
3.95
|
|
|
|
4.48
|
|
|
|
|
|
|
|
|
(1)
|
|
In November 2007, we changed our
fiscal year end from a year ending August 31 to a year ending
December 31. Accordingly, the four months ended December 31,
2007 is treated as a transition period.
|
For these ratios earnings is the amount resulting
from adding the following items:
|
|
|
|
|
pre-tax income from continuing operations, before minority
interest and equity in earnings of affiliates;
|
|
|
|
amortization of capitalized interest;
|
|
|
|
distributed income of equity investees; and
|
|
|
|
fixed charges.
|
The term fixed charges means the sum of the
following:
|
|
|
|
|
interest expensed;
|
|
|
|
interest capitalized;
|
|
|
|
amortized debt issuance costs; and
|
|
|
|
estimated interest element of rentals.
|
33
DESCRIPTION
OF UNITS
As of June 1, 2009, there were approximately
123,000 individual common unitholders, which includes
common units held in street name. Our common units represent
limited partner interests in us that entitle the holders to the
rights and privileges specified our Amended and Restated
Agreement of Limited Partnership, as amended to date.
Common
Units
As of June 1, 2009, we had 168,786,459 common units
outstanding, of which 106,285,662 were held by the public,
including approximately 510,000 common units held by our
officers and directors, and 62,500,797 were held by ETE. As of
such date, the common units represent an aggregate 98.0% limited
partner interest in us. Our general partner owns an aggregate
2.0% general partner interest in us. Our common units are
registered under the Securities Exchange Act of 1934, as amended
and are listed for trading on the NYSE. The common units are
entitled to distributions of Available Cash as described below
under Cash Distribution Policy.
Class E
Units
In conjunction with our purchase of the capital stock of
Heritage Holdings in January 2004, the 4,426,916 common
units held by Heritage Holdings were converted into 4,426,916
Class E Units. Pursuant to our two-for-one unit split
completed on March 15, 2005, there are currently 8,853,832
Class E Units outstanding, all of which are owned by
Heritage Holdings. The Class E Units generally do not have
any voting rights. These Class E Units are entitled to
aggregate cash distributions equal to 11.1% of the total amount
of cash distributed to all unitholders, including the
Class E unitholders, up to $1.41 per unit per year.
Management plans to continue its ownership of the Class E
Units by Heritage Holdings indefinitely.
Issuance
of Additional Securities
Our partnership agreement authorizes us to issue an unlimited
number of additional partnership securities and rights to buy
partnership securities for the consideration and on the terms
and conditions established by our general partner in its sole
discretion, without the approval of the unitholders. Any such
additional partnership securities may be senior to the common
units.
It is possible that we will fund acquisitions through the
issuance of additional common units or other equity securities.
Holders of any additional common units we issue will be entitled
to share equally with the then-existing holders of common units
in our distributions of available cash. In addition, the
issuance of additional partnership interests may dilute the
value of the interests of the then-existing holders of common
units in our net assets.
In accordance with Delaware law and the provisions of our
partnership agreement, we may also issue additional partnership
securities that, in the sole discretion of the general partner,
have special voting rights to which the common units are not
entitled.
Upon issuance of additional partnership securities, our general
partner will be required to make additional capital
contributions to the extent necessary to maintain its 2.0%
general partner interest in us. Moreover, our general partner
will have the right, which it may from time to time assign in
whole or in part to any of its affiliates, to purchase common
units or other equity securities whenever, and on the same terms
that, we issue those securities to persons other than the
general partner and its affiliates, to the extent necessary to
maintain its percentage interest, including its interest
represented by common units, that existed immediately prior to
each issuance. The holders of common units will not have
preemptive rights to acquire additional common units or other
partnership securities.
34
Unitholder
Approval
The following matters require the approval of the majority of
the outstanding common units, including the common units owned
by the general partner and its affiliates:
|
|
|
|
|
a merger of our partnership;
|
|
|
|
a sale or exchange of all or substantially all of our assets;
|
|
|
|
dissolution or reconstitution of our partnership upon
dissolution;
|
|
|
|
certain amendments to the partnership agreement;
|
|
|
|
the transfer to another person of the incentive distribution
rights at any time, except for transfers to affiliates of the
general partner or transfers in connection with the general
partners merger or consolidation with or into, or sale of
all or substantially all of its assets to, another
person; and
|
The removal of our general partner requires the approval of not
less than
662/3%
of all outstanding units, including units held by our general
partner and its affiliates. Any removal is subject to the
election of a successor general partner by the holders of a
majority of the outstanding common units, including units held
by our general partner and its affiliates.
Amendments
to Our Partnership Agreement
Amendments to our partnership agreement may be proposed only by
our general partner. Certain amendments require the approval of
a majority of the outstanding common units, including common
units owned by the general partner and its affiliates. Any
amendment that materially and adversely affects the rights or
preferences of any class of partnership interests in relation to
other classes of partnership interests will require the approval
of at least a majority of the class of partnership interests so
affected. Our general partner may make amendments to the
partnership agreement without unitholder approval to reflect:
|
|
|
|
|
a change in our name, the location of our principal place of
business or our registered agent or office;
|
|
|
|
the admission, substitution, withdrawal or removal of partners;
|
|
|
|
a change to qualify or continue our qualification as a limited
partnership or a partnership in which the limited partners have
limited liability or to ensure that neither we nor our operating
partnership will be treated as an association taxable as a
corporation or otherwise taxed as an entity for federal income
tax purposes;
|
|
|
|
a change that does not affect our unitholders in any material
respect;
|
|
|
|
a change to (i) satisfy any requirements, conditions or
guidelines contained in any opinion, directive, order, ruling or
regulation of any federal or state agency or judicial authority
or contained in any federal or state statute,
(ii) facilitate the trading of common units or comply with
any rule, regulation, guideline or requirement of any national
securities exchange on which the common units are or will be
listed for trading, (iii) that is necessary or advisable in
connection with action taken by our general partner with respect
to subdivision and combination of our securities or
(iv) that is required to effect the intent expressed in our
partnership agreement;
|
|
|
|
a change in our fiscal year or taxable year and any changes that
are necessary or advisable as a result of a change in our fiscal
year or taxable year;
|
|
|
|
an amendment that is necessary to prevent us, or our general
partner or its directors, officers, trustees or agents from
being subjected to the provisions of the Investment Company Act
of 1940, as amended, the Investment Advisors Act of 1940, as
amended, or plan asset regulations adopted under the
Employee Retirement Income Security Act of 1974, as amended;
|
|
|
|
an amendment that is necessary or advisable in connection with
the authorization or issuance of any class or series of our
securities;
|
|
|
|
any amendment expressly permitted in our partnership agreement
to be made by our general partner acting alone;
|
35
|
|
|
|
|
an amendment effected, necessitated or contemplated by a merger
agreement approved in accordance with our partnership agreement;
|
|
|
|
an amendment that is necessary or advisable to reflect, account
for and deal with appropriately our formation of, or investment
in, any corporation, partnership, joint venture, limited
liability company or other entity other than our operating
partnership, in connection with our conduct of activities
permitted by our partnership agreement;
|
|
|
|
a merger or conveyance to effect a change in our legal
form; or
|
|
|
|
any other amendment substantially similar to the foregoing.
|
Withdrawal
or Removal of Our General Partner
Our general partner may withdraw as general partner without
first obtaining approval of any unitholder by giving
90 days written notice, and that withdrawal will not
constitute a violation of our partnership agreement. In
addition, our general partner may withdraw without unitholder
approval upon 90 days notice to our limited partners
if at least 50% of our outstanding common units are held or
controlled by one person and its affiliates other than our
general partner and its affiliates.
Upon the voluntary withdrawal of our general partner, the
holders of a majority of our outstanding common units, excluding
the common units held by the withdrawing general partner and its
affiliates, may elect a successor to the withdrawing general
partner. If a successor is not elected, or is elected but an
opinion of counsel regarding limited liability and tax matters
cannot be obtained, we will be dissolved, wound up and
liquidated, unless within 90 days after that withdrawal,
the holders of a majority of our outstanding units, excluding
the common units held by the withdrawing general partner and its
affiliates, agree to continue our business and to appoint a
successor general partner.
Our general partner may not be removed unless that removal is
approved by the vote of the holders of not less than two-thirds
of our outstanding units, including units held by our general
partner and its affiliates, and we receive an opinion of counsel
regarding limited liability and tax matters. In addition, if our
general partner is removed as our general partner under
circumstances where cause does not exist, our general partner
will have the right to receive cash in exchange for its
partnership interest as a general partner in us, its partnership
interest as the general partner of any member of the Energy
Transfer partnership group and its incentive distribution
rights. Cause is narrowly defined to mean that a court of
competent jurisdiction has entered a final, non-appealable
judgment finding the general partner liable for actual fraud,
gross negligence or willful or wanton misconduct in its capacity
as our general partner. Any removal of this kind is also subject
to the approval of a successor general partner by the vote of
the holders of the majority of our outstanding common units,
including those held by our general partner and its affiliates.
While our partnership agreement limits the ability of our
general partner to withdraw, it allows the general partner
interest to be transferred to an affiliate or to a third party
in conjunction with a merger or sale of all or substantially all
of the assets of our general partner. In addition, our
partnership agreement expressly permits the sale, in whole or in
part, of the ownership of our general partner. Our general
partner may also transfer, in whole or in part, any common units
it owns.
Liquidation
and Distribution of Proceeds
Upon our dissolution, unless we are reconstituted and continue
as a new limited partnership, the person authorized to wind up
our affairs (the liquidator) will, acting with all the powers of
our general partner that the liquidator deems necessary or
desirable in its good faith judgment, liquidate our assets. The
proceeds of the liquidation will be applied as follows:
|
|
|
|
|
first, towards the payment of all of our creditors and the
creation of a reserve for contingent liabilities; and
|
|
|
|
then, to all partners in accordance with the positive balance in
their respective capital accounts.
|
36
Under some circumstances and subject to some limitations, the
liquidator may defer liquidation or distribution of our assets
for a reasonable period of time. If the liquidator determines
that a sale would be impractical or would cause a loss to our
partners, our general partner may distribute assets in kind to
our partners.
Limited
Call Right
If at any time less than 20% of the outstanding common units of
any class are held by persons other than our general partner and
its affiliates, our general partner will have the right to
acquire all, but not less than all, of those common units at a
price no less than their then-current market price. As a
consequence, a unitholder may be required to sell his common
units at an undesirable time or price. Our general partner may
assign this purchase right to any of its affiliates or us.
Indemnification
Under our partnership agreement, in most circumstances, we will
indemnify our general partner, its affiliates and their officers
and directors to the fullest extent permitted by law, from and
against all losses, claims or damages any of them may suffer by
reason of their status as general partner, officer or director,
as long as the person seeking indemnity acted in good faith and
in a manner believed to be in or not opposed to our best
interest. Any indemnification under these provisions will only
be out of our assets. Our general partner shall not be
personally liable for, or have any obligation to contribute or
loan funds or assets to us to effectuate any indemnification. We
are authorized to purchase insurance against liabilities
asserted against and expenses incurred by persons for our
activities, regardless of whether we would have the power to
indemnify the person against liabilities under our partnership
agreement.
Listing
Our outstanding common units are listed on the NYSE under the
symbol ETP. Any additional common units we issue
also will be listed on the NYSE.
Transfer
Agent and Registrar
The transfer agent and registrar for the common units is
American Stock Transfer & Trust Company.
Transfer
of Common Units
Each purchaser of common units offered by this prospectus must
execute a transfer application. By executing and delivering a
transfer application, the purchaser of common units:
|
|
|
|
|
becomes the record holder of the common units and is an assignee
until admitted into our partnership as a substituted limited
partner;
|
|
|
|
automatically requests admission as a substituted limited
partner in our partnership;
|
|
|
|
agrees to be bound by the terms and conditions of, and executes,
our partnership agreement;
|
|
|
|
represents that such person has the capacity, power and
authority to enter into the partnership agreement;
|
|
|
|
grants to our general partner the power of attorney to execute
and file documents required for our existence and qualification
as a limited partnership, the amendment of the partnership
agreement, our dissolution and liquidation, the admission,
withdrawal, removal or substitution of partners, the issuance of
additional partnership securities and any merger or
consolidation of the partnership.
|
|
|
|
makes the consents and waivers contained in the partnership
agreement, including the waiver of the fiduciary duties of the
general partner to unitholders as described in Risk
Factors Risks Inherent in an Investment in
Us Our partnership agreement limits our general
partners fiduciary duties to our unitholders and restricts
the remedies available to unitholders for actions taken by our
general partner that might otherwise constitute breaches of
fiduciary duty.
|
37
An assignee will become a substituted limited partner of our
partnership for the transferred common units upon the consent of
our general partner and the recording of the name of the
assignee on our books and records. Although the general partner
has no current intention of doing so, it may withhold its
consent in its sole discretion. An assignee who is not admitted
as a limited partner will remain an assignee. An assignee is
entitled to an interest equivalent to that of a limited partner
for the right to share in allocations and distributions from us,
including liquidating distributions. Furthermore, our general
partner will vote and exercise other powers attributable to
common units owned by an assignee at the written direction of
the assignee.
Transfer applications may be completed, executed and delivered
by a purchasers broker, agent or nominee. We are entitled
to treat the nominee holder of a common unit as the absolute
owner. In that case, the beneficial holders rights are
limited solely to those that it has against the nominee holder
as a result of any agreement between the beneficial owner and
the nominee holder.
Common units are securities and are transferable according to
the laws governing transfer of securities. In addition to other
rights acquired, the purchaser has the right to request
admission as a substituted limited partner in our partnership
for the purchased common units. A purchaser of common units who
does not execute and deliver a transfer application obtains only:
|
|
|
|
|
the right to assign the common unit to a purchaser or
transferee; and
|
|
|
|
the right to transfer the right to seek admission as a
substituted limited partner in our partnership for the purchased
common units.
|
Thus, a purchaser of common units who does not execute and
deliver a transfer application:
|
|
|
|
|
will not receive cash distributions or federal income tax
allocations, unless the common units are held in a nominee or
street name account and the nominee or broker has
executed and delivered a transfer application; and
|
|
|
|
may not receive some federal income tax information or reports
furnished to record holders of common units.
|
Until a common unit has been transferred on our books, we and
the transfer agent, notwithstanding any notice to the contrary,
may treat the record holder of the unit as the absolute owner
for all purposes, except as otherwise required by law or NYSE
regulations.
Status as
Limited Partner or Assignee
Except as described under Limited
Liability, the common units will be fully paid, and the
unitholders will not be required to make additional capital
contributions to us.
Limited
Liability
Assuming that a limited partner does not participate in the
control of our business within the meaning of the Delaware
Revised Uniform Limited Partnership Act (the Delaware
Act) and that he otherwise acts in conformity with the
provisions of our partnership agreement, his liability under the
Delaware Act will be limited, subject to possible exceptions, to
the amount of capital he is obligated to contribute to us for
his common units plus his share of any undistributed profits and
assets. If it were determined, however, that the right or
exercise of the right by the limited partners as a group:
|
|
|
|
|
to remove or replace the general partner;
|
|
|
|
to approve some amendments to our partnership agreement; or
|
|
|
|
to take other action under our partnership agreement;
|
|
|
|
constituted participation in the control of our
business for the purposes of the Delaware Act, then the limited
partners could be held personally liable for our obligations
under Delaware law, to the same extent as the general partner.
This liability would extend to persons who transact business
with us and who reasonably believe that the limited partner is a
general partner. Neither our partnership agreement
|
38
|
|
|
|
|
nor the Delaware Act specifically provides for legal recourse
against our general partner if a limited partner were to lose
limited liability through any fault of the general partner.
While this does not mean that a limited partner could not seek
legal recourse, we have found no precedent for this type of a
claim in Delaware case law.
|
Under the Delaware Act, a limited partnership may not make a
distribution to a partner if after the distribution all
liabilities of the limited partnership, other than liabilities
to partners on account of their partnership interests and
liabilities for which the recourse of creditors is limited to
specific property of our partnership, exceed the fair value of
the assets of the limited partnership. For the purpose of
determining the fair value of the assets of a limited
partnership, the Delaware Act provides that the fair value of
property subject to liability for which recourse of creditors is
limited shall be included in the assets of the limited
partnership only to the extent that the fair value of that
property exceeds the nonrecourse liability. The Delaware Act
provides that a limited partner who receives a distribution and
knew at the time of the distribution that the distribution was
in violation of the Delaware Act shall be liable to the limited
partnership for the amount of the distribution for three years.
Under the Delaware Act, an assignee who becomes a substituted
limited partner of a limited partnership is liable for the
obligations of his assignor to make contributions to our
partnership, except the assignee is not obligated for
liabilities unknown to him at the time he became a limited
partner and which could not be ascertained from our partnership
agreement.
Our subsidiaries currently conduct business in 45 states:
Alabama, Arizona, Arkansas, California, Colorado, Connecticut,
Delaware, Florida, Georgia, Idaho, Illinois, Indiana, Kansas,
Kentucky, Louisiana, Maine, Maryland, Massachusetts, Michigan,
Missouri, Minnesota, Mississippi, Montana, Nevada, New
Hampshire, New Jersey, New Mexico, New York, North Carolina,
Ohio, Oklahoma, Oregon, Pennsylvania, Rhode Island, South
Carolina, South Dakota, Tennessee, Texas, Utah, Vermont,
Virginia, Wisconsin, Washington, West Virginia and Wyoming. To
maintain the limited liability for Energy Transfer Partners,
L.P., as the holder of a 100% limited partner interest in
Heritage Operating, L.P., we may be required to comply with
legal requirements in the jurisdictions in which Heritage
Operating, L.P. conducts business, including qualifying our
subsidiaries to do business there. Limitations on the liability
of limited partners for the obligations of a limited partnership
have not been clearly established in many jurisdictions. If it
were determined that we were, by virtue of our limited partner
interest in Heritage Operating, L.P. or otherwise, conducting
business in any state without compliance with the applicable
limited partnership statute, or that our right or the exercise
of our right to remove or replace Heritage Operating,
L.P.s general partner, to approve some amendments to
Heritage Operating, L.P.s partnership agreement, or to
take other action under Heritage Operating, L.P.s
partnership agreement constituted participation in the
control of Heritage Operating, L.P.s business for
purposes of the statutes of any relevant jurisdiction, then we
could be held personally liable for Heritage Operating,
L.P.s obligations under the law of that jurisdiction to
the same extent as our general partner under the circumstances.
We will operate in a manner as our general partner considers
reasonable and necessary or appropriate to preserve our limited
liability.
Meetings;
Voting
Except as described below regarding a person or group owning 20%
or more of any class of units then outstanding, unitholders or
assignees who are record holders of units on the record date
will be entitled to notice of, and to vote at, meetings of our
limited partners and to act upon matters for which approvals may
be solicited. Common units that are owned by an assignee who is
a record holder, but who has not yet been admitted as a limited
partner, shall be voted by our general partner at the written
direction of the record holder. Absent direction of this kind,
the common units will not be voted, except that, in the case of
common units held by our general partner on behalf of
non-citizen assignees, our general partner shall distribute the
votes on those common units in the same ratios as the votes of
limited partners on other units are cast.
Our general partner does not anticipate that any meeting of
unitholders will be called in the foreseeable future. Any action
that is required or permitted to be taken by the unitholders may
be taken either at a meeting of the unitholders or without a
meeting if consents in writing describing the action so taken
are signed by holders of the number of units as would be
necessary to authorize or take that action at a meeting.
Meetings of the unitholders may be called by our general partner
or by unitholders owning at least 20% of the
39
outstanding units of the class for which a meeting is proposed.
Unitholders may vote either in person or by proxy at meetings.
The holders of a majority of the outstanding units of the class
or classes for which a meeting has been called represented in
person or by proxy shall constitute a quorum unless any action
by the unitholders requires approval by holders of a greater
percentage of the units, in which case the quorum shall be the
greater percentage.
Each record holder of a unit has a vote according to his
percentage interest in us, although additional limited partner
interests having special voting rights could be issued. However,
if at any time any person or group, other than our general
partner and its affiliates, owns, in the aggregate, beneficial
ownership of 20% or more of the common units then outstanding,
the person or group will lose voting rights on all of its common
units and its common units may not be voted on any matter and
will not be considered to be outstanding when sending notices of
a meeting of unitholders, calculating required votes,
determining the presence of a quorum or for other similar
purposes. Common units held in nominee or street name account
will be voted by the broker or other nominee in accordance with
the instruction of the beneficial owner unless the arrangement
between the beneficial owner and his nominee provides otherwise.
Any notice, demand, request, report or proxy material required
or permitted to be given or made to record holders of common
units under our partnership agreement will be delivered to the
record holder by us or by the transfer agent.
Books and
Reports
Our general partner is required to keep appropriate books of our
business at our principal offices. The books will be maintained
for both tax and financial reporting purposes on an accrual
basis. Reporting for tax purposes is done on a calendar year
basis.
We will furnish or make available to record holders of common
units, within 75 days after the close of each fiscal year,
an annual report containing audited financial statements and a
report on those financial statements by our independent public
accountants. Except for our fourth quarter, we will also furnish
or make available summary financial information within
45 days after the close of each quarter.
We will furnish each record holder of a unit with information
reasonably required for tax reporting purposes within
90 days after the close of each calendar year. This
information is expected to be furnished in summary form so that
some complex calculations normally required of partners can be
avoided. Our ability to furnish this summary information to
unitholders will depend on the cooperation of unitholders in
supplying us with specific information. Every unitholder will
receive information to assist him in determining his federal and
state tax liability and filing his federal and state income tax
returns, regardless of whether he supplies us with information.
Our partnership agreement provides that a limited partner can,
for a purpose reasonably related to his interest as a limited
partner, upon reasonable demand and at his own expense, have
furnished to him:
|
|
|
|
|
a current list of the name and last known address of each
partner;
|
|
|
|
a copy of our tax returns;
|
|
|
|
information as to the amount of cash, and a description and
statement of the agreed value of any other property or services,
contributed or to be contributed by each partner and the date on
which each became a partner;
|
|
|
|
copies of our partnership agreement, the certificate of limited
partnership of the partnership, related amendments and powers of
attorney under which they have been executed;
|
|
|
|
information regarding the status of our business and financial
condition; and
|
|
|
|
any other information regarding our affairs as is just and
reasonable.
|
Our general partner may, and intends to, keep confidential from
the limited partners trade secrets or other information the
disclosure of which our general partner believes in good faith
is not in our best interests or that we are required by law or
by agreements with third parties to keep confidential.
40
CASH
DISTRIBUTION POLICY
Distributions
of Available Cash
General. We will distribute all of our
available cash to our unitholders and our general
partner within 45 days following the end of each fiscal
quarter. Definition of Available Cash. Available Cash is defined
in our partnership agreement and generally means, with respect
to any calendar quarter, all cash on hand at the end of such
quarter:
|
|
|
|
|
less the amount of cash reserves that are necessary or
appropriate in the reasonable discretion of the general partner
to:
|
|
|
|
|
|
provide for the proper conduct of our business;
|
|
|
|
comply with applicable law or any debt instrument or other
agreement (including reserves for future capital expenditures
and for our future credit needs); or
|
|
|
|
provide funds for distributions to unitholders and our general
partner in respect of any one or more of the next four quarters;
|
|
|
|
|
|
plus all cash on hand on the date of determination of available
cash for the quarter resulting from working capital borrowings
made after the end of the quarter. Working capital borrowings
are generally borrowings that are made under our credit
facilities and in all cases are used solely for working capital
purposes or to pay distributions to partners.
|
Operating
Surplus and Capital Surplus
General. All cash distributed to unitholders
will be characterized as either operating surplus or
capital surplus. We distribute available cash from
operating surplus differently than available cash from capital
surplus.
Definition of Operating Surplus. Operating
surplus for any period generally means:
|
|
|
|
|
our cash balance on the closing date of our initial public
offering; plus
|
|
|
|
$10.0 million (as described below); plus
|
|
|
|
all of our cash receipts since the closing of our initial public
offering, excluding cash from interim capital transactions such
as borrowings that are not working capital borrowings, sales of
equity and debt securities and sales or other dispositions of
assets outside the ordinary course of business; plus
|
|
|
|
our working capital borrowings made after the end of a quarter
but before the date of determination of operating surplus for
the quarter; less
|
|
|
|
all of our operating expenditures after the closing of our
initial public offering, including the repayment of working
capital borrowings, but not the repayment of other borrowings,
and including maintenance capital expenditures; less
|
|
|
|
the amount of cash reserves that the general partner deems
necessary or advisable to provide funds for future operating
expenditures.
|
Definition of Capital Surplus. Generally,
capital surplus will be generated only by:
|
|
|
|
|
borrowings other than working capital borrowings;
|
|
|
|
sales of debt and equity securities; and
|
|
|
|
sales or other disposition of assets for cash, other than
inventory, accounts receivable and other current assets sold in
the ordinary course of business or as part of normal retirements
or replacements of assets.
|
Characterization of Cash Distributions. We
will treat all available cash distributed as coming from
operating surplus until the sum of all available cash
distributed since we began operations equals the operating
41
surplus as of the most recent date of determination of available
cash. We will treat any amount distributed in excess of
operating surplus, regardless of its source, as capital surplus.
As reflected above, operating surplus includes
$10.0 million in addition to our cash balance on the
closing date of our initial public offering, cash receipts from
our operations and cash from working capital borrowings. This
amount does not reflect actual cash on hand that is available
for distribution to our unitholders. Rather, it is a provision
that enables us, if we choose, to distribute as operating
surplus up to $10.0 million of cash we receive in the
future from non-operating sources, such as asset sales,
issuances of securities, and long-term borrowings, that would
otherwise be distributed as capital surplus. We have not made,
and we anticipate that we will not make, any distributions from
capital surplus.
Incentive
Distribution Rights
Incentive distribution rights represent the contractual right to
receive an increasing percentage of quarterly distributions of
available cash from operating surplus after the minimum
quarterly distribution as been paid. Please read
Distributions of Available Cash from Operating
Surplus below. The general partner owns all of the
incentive distribution rights, except that in conjunction with
the August 2000 transaction with U.S. Propane, L.P., we
issued 1,000,000 class C units to Heritage Holdings, Inc.,
our general partner at that time, in conversion of that portion
of Heritage Holdings, Inc.s incentive distribution rights
that entitled it to receive any distribution made by us of funds
attributable to the net amount received by us in connection with
the settlement, judgment, award or other final nonappealable
resolution of the SCANA litigation. In January 2004, the
class C units were distributed by Heritage Holdings, Inc.
to the owners of its equity interests. On July 14, 2006,
all 1,000,000 outstanding class C units were retired and
cancelled.
Distributions
of Available Cash from Operating Surplus
The terms of our partnership agreement require that we make cash
distributions with respect to each calendar quarter within
45 days following the end of each calendar quarter. We are
required to make distributions of available cash from operating
surplus for any quarter in the following manner:
|
|
|
|
|
First, 98% to all common and class E unitholders, in
accordance with their percentage interests, and 2% to the
general partner, until each common unit has received $0.25 per
unit for such quarter (the minimum quarterly
distribution);
|
|
|
|
Second, 98% to all common and class E unitholders, in
accordance with their percentage interests, and 2% to the
general partner, until each common unit has received $0.275 per
unit for such quarter (the first target
distribution);
|
|
|
|
Third, 85% to all common and class E unitholders, in
accordance with their percentage interests, 13% to the holders
of incentive distribution rights, pro rata, and 2% to the
general partner, until each common unit has received $0.3175 per
unit for such quarter (the second target
distribution);
|
|
|
|
Fourth, 75% to all common and class E unitholders, in
accordance with their percentage interests, 23% to the holders
of incentive distribution rights, pro rata, and 2% to the
general partner, until each common unit has received $0.4125 per
unit for such quarter (the third target
distribution); and
|
|
|
|
Fifth, thereafter, 50% to all common and class E
unitholders, in accordance with their percentage interests, 48%
to the holders of incentive distribution rights, pro rata, and
2% to the general partner.
|
Notwithstanding the foregoing, the distributions on each
class E unit may not exceed $1.41 per year.
Distributions
of Available Cash from Capital Surplus
The terms of our partnership agreement require that we make cash
distributions with respect to each calendar quarter with 45 days
following the and of each calender generator. We will make
distributions of available cash from capital surplus, if any, in
the following manner:
|
|
|
|
|
First, 98% to all unitholders, pro rata, and 2% to the general
partner, until we distribute for each common unit, an amount of
available cash from capital surplus equal to the initial public
offering price;
|
42
|
|
|
|
|
Thereafter, we will make all distributions of available cash
from capital surplus as if they were from operating surplus.
|
Our partnership agreement treats a distribution of capital
surplus as the repayment of the initial unit price from the
initial public offering, which is a return of capital. The
initial public offering price per common unit less any
distributions of capital surplus per unit is referred to as the
unrecovered capital.
If we combine our units into fewer units or subdivide our units
into a greater number of units, we will proportionately adjust
our minimum quarterly distribution; our target cash distribution
levels; and our unrecovered capital.
For example, if a two-for-one split of our common units should
occur, our unrecovered capital would each be reduced to 50% of
our initial level. We will not make any adjustment by reason of
our issuance of additional units for cash or property.
On January 14, 2005, our general partner announced a
two-for-one split of our common units that was effected on
March 15, 2005. As a result, our minimum quarterly
distribution and the target cash distribution levels were
reduced to 50% of their initial levels. Our adjusted minimum
quarterly distribution and the adjusted target cash distribution
levels are reflected in the discussion above under the caption
Distributions of Available Cash from Operating
Surplus.
In addition, if legislation is enacted or if existing law is
modified or interpreted in a manner that causes us to become
taxable as a corporation or otherwise subject to taxation as an
entity for federal, state or local income tax purposes, we will
reduce our minimum quarterly distribution and the target cash
distribution levels by multiplying the same by one minus the sum
of the highest marginal federal corporate income tax rate that
could apply and any increase in the effective overall state and
local income tax rates.
Distributions
of Cash Upon Liquidation
General. If we dissolve in accordance with our
partnership agreement, we will sell or otherwise dispose of our
assets in a process called liquidation. We will first apply the
proceeds of liquidation to the payment of our creditors. We will
distribute any remaining proceeds to the unitholders and the
general partner, in accordance with their capital account
balances, as adjusted to reflect any gain or loss upon the sale
or other disposition of our assets in liquidation.
Any further net gain recognized upon liquidation will be
allocated in a manner that takes into account the incentive
distribution rights of the general partner.
Manner of Adjustments for Gain. The manner of
the adjustment for gain is set forth in our partnership
agreement in the following manner:
|
|
|
|
|
First, to the general partner and the holders of units who have
negative balances in their capital accounts to the extent of and
in proportion to those negative balances;
|
|
|
|
Second, 98% to the common unitholders, pro rata, and 2% to the
general partner, until the capital account for each common unit
is equal to the sum of:
|
|
|
|
|
|
the unrecovered capital; and
|
|
|
|
the amount of the minimum quarterly distribution for the quarter
during which our liquidation occurs;
|
|
|
|
|
|
Third, 98% to all unitholders, pro rata, and 2% to the general
partner, until we allocate under this paragraph an amount per
unit equal to:
|
|
|
|
|
|
the sum of the excess of the first target distribution per unit
over the minimum quarterly distribution per unit for each
quarter of our existence; less
|
43
|
|
|
|
|
the cumulative amount per unit of any distributions of available
cash from operating surplus in excess of the minimum quarterly
distribution per unit that we distributed 98% to the
unitholders, pro rata, and 2% to the general partner, for each
quarter of our existence;
|
|
|
|
|
|
Fourth, 85% to all unitholders, pro rata, 13% to the holders of
the incentive distribution rights, pro rata, and 2% to the
general partner, until we allocate under this paragraph an
amount per unit equal to:
|
|
|
|
|
|
the sum of the excess of the second target distribution per unit
over the first target distribution per unit for each quarter of
our existence; less
|
|
|
|
the cumulative amount per unit of any distributions of available
cash from operating surplus in excess of the first target
distribution per unit that we distributed 85% to the
unitholders, pro rata, 13% to the holders of the incentive
distribution rights, pro rata, and 2% to the general partner for
each quarter of our existence;
|
|
|
|
|
|
Fifth, 75% to all unitholders, pro rata, 23% to the holders of
the incentive distribution rights, pro rata, and 2% to the
general partner, until we allocate under this paragraph an
amount per unit equal to:
|
|
|
|
|
|
the sum of the excess of the third target distribution per unit
over the second target distribution per unit for each quarter of
our existence; less
|
|
|
|
the cumulative amount per unit of any distributions of available
cash from operating surplus in excess of the second target
distribution per unit that we distributed 75% to the
unitholders, pro rata, 23% to the holders of the incentive
distribution rights, pro rata, and 2% to the general partner for
each quarter of our existence; and
|
|
|
|
|
|
Sixth, thereafter, 50% to all unitholders, pro rata, 48% to the
holders of the incentive distribution rights, pro rata, and 2%
to the general partner.
|
Manner of Adjustments for Losses. Upon our
liquidation, we will generally allocate any loss to the general
partner and the unitholders in the following manner:
|
|
|
|
|
First, 98% to the holders of common units in proportion to the
positive balances in their capital accounts and 2% to the
general partner, until the capital accounts of the common
unitholders have been reduced to zero; and
|
|
|
|
Second, thereafter, 100% to the general partner.
|
Adjustments to Capital Accounts upon the Issuance of
Additional Units. We will make adjustments to
capital accounts upon the issuance of additional units. In doing
so, we will allocate any unrealized and, for tax purposes,
unrecognized gain or loss resulting from the adjustments to the
unitholders and the general partner in the same manner as we
allocate gain or loss upon liquidation. In the event that we
make positive adjustments to the capital accounts upon the
issuance of additional units, we will allocate any later
negative adjustments to the capital accounts resulting from the
issuance of additional units or upon our liquidation in a manner
which results, to the extent possible, in the general
partners capital account balances equaling the amount
which they would have been if no earlier positive adjustments to
the capital accounts had been made.
44
DESCRIPTION
OF THE DEBT SECURITIES
Energy Transfer Partners, L.P. may issue senior debt securities
on a senior unsecured basis under an indenture among Energy
Transfer Partners, L.P., as issuer, the Subsidiary Guarantors,
if any, and a trustee that we will name in the related
prospectus supplement. We refer to this senior indenture as the
indenture. The debt securities will be governed by the
provisions of the indenture and those made part of the indenture
by reference to the Trust Indenture Act.
We have summarized material provisions of the indenture and the
debt securities below. This summary is not complete. We have
filed the indenture with the SEC as an exhibit to the
registration statement, and you should read the indenture for
provisions that may be important to you.
References in this Description of the Debt
Securities to we, us and
our mean Energy Transfer Partners, L.P.
Provisions
Applicable to the Indenture
General. Any series of debt securities will be
general obligations of the issuer.
The indenture does not limit the amount of debt securities that
may be issued under the indenture, and does not limit the amount
of other unsecured debt or securities that we may issue. We may
issue debt securities under the indenture from time to time in
one or more series, each in an amount authorized prior to
issuance.
The indenture does not contain any covenants or other provisions
designed to protect holders of the debt securities in the event
we participate in a highly leveraged transaction or upon a
change of control. The indenture also does not contain
provisions that give holders the right to require us to
repurchase their securities in the event of a decline in our
credit ratings for any reason, including as a result of a
takeover, recapitalization or similar restructuring or otherwise.
Terms. We will prepare a prospectus supplement
and either a supplemental indenture, or authorizing resolutions
of the board of directors of our general partners general
partner, accompanied by an officers certificate, relating
to any series of debt securities that we offer, which will
include specific terms relating to some or all of the following:
|
|
|
|
|
the form and title of the debt securities of that series;
|
|
|
|
the total principal amount of the debt securities of that series;
|
|
|
|
whether the debt securities will be issued in individual
certificates to each holder or in the form of temporary or
permanent global securities held by a depositary on behalf of
holders;
|
|
|
|
the date or dates on which the principal of and any premium on
the debt securities of that series will be payable;
|
|
|
|
any interest rate which the debt securities of that series will
bear, the date from which interest will accrue, interest payment
dates and record dates for interest payments;
|
|
|
|
any right to extend or defer the interest payment periods and
the duration of the extension;
|
|
|
|
whether and under what circumstances any additional amounts with
respect to the debt securities will be payable;
|
|
|
|
whether debt securities are entitled to the benefits of any
guarantee of any Subsidiary Guarantor;
|
|
|
|
the place or places where payments on the debt securities of
that series will be payable;
|
|
|
|
any provisions for optional redemption or early repayment;
|
|
|
|
any provisions that would require the redemption, purchase or
repayment of debt securities;
|
|
|
|
the denominations in which the debt securities will be issued;
|
|
|
|
whether payments on the debt securities will be payable in
foreign currency or currency units or another form and whether
payments will be payable by reference to any index or formula;
|
45
|
|
|
|
|
the portion of the principal amount of debt securities that will
be payable if the maturity is accelerated, if other than the
entire principal amount;
|
|
|
|
any additional means of defeasance of the debt securities, any
additional conditions or limitations to defeasance of the debt
securities or any changes to those conditions or limitations;
|
|
|
|
any changes or additions to the events of default or covenants
described in this prospectus;
|
|
|
|
any restrictions or other provisions relating to the transfer or
exchange of debt securities;
|
|
|
|
any terms for the conversion or exchange of the debt securities
for our other securities or securities of any other
entity; and
|
|
|
|
any other terms of the debt securities of that series.
|
This description of debt securities will be deemed modified,
amended or supplemented by any description of any series of debt
securities set forth in a prospectus supplement related to that
series.
We may sell the debt securities at a discount, which may be
substantial, below their stated principal amount. These debt
securities may bear no interest or interest at a rate that at
the time of issuance is below market rates. If we sell these
debt securities, we will describe in the prospectus supplement
any material United States federal income tax consequences and
other special considerations.
If we sell any of the debt securities for any foreign currency
or currency unit or if payments on the debt securities are
payable in any foreign currency or currency unit, we will
describe in the prospectus supplement the restrictions,
elections, tax consequences, specific terms and other
information relating to those debt securities and the foreign
currency or currency unit.
The Subsidiary Guarantees. Certain of our
subsidiaries, which we refer to collectively as Subsidiary
Guarantors, may fully, irrevocably and unconditionally guarantee
on an unsecured basis all series of our debt securities and will
execute a notation of guarantee as further evidence of their
guarantee. The applicable prospectus supplement will describe
the terms of any guarantee by the Subsidiary Guarantors.
If a series of debt securities is so guaranteed, the Subsidiary
Guarantors guarantee of the debt securities will be the
Subsidiary Guarantors unsecured and unsubordinated general
obligation, and will rank on a parity with all of the Subsidiary
Guarantors other unsecured and unsubordinated
indebtedness. The obligations of each Subsidiary Guarantor under
its guarantee of the debt securities will be limited to the
maximum amount that will not result in the obligations of the
Subsidiary Guarantor under the guarantee constituting a
fraudulent conveyance or fraudulent transfer under federal or
state law, after giving effect to:
|
|
|
|
|
all other contingent and fixed liabilities of the Subsidiary
Guarantor; and
|
|
|
|
any collections from or payments made by or on behalf of any
other Subsidiary Guarantors in respect of the obligations of the
Subsidiary Guarantor under its guarantee.
|
The guarantee of any Subsidiary Guarantor may be released under
certain circumstances. If we exercise our legal or covenant
defeasance option with respect to debt securities of a
particular series as described below in
Defeasance, then any Subsidiary
Guarantor will be released with respect to that series. Further,
if no default has occurred and is continuing under the
indenture, and to the extent not otherwise prohibited by the
indenture, a Subsidiary Guarantor will be unconditionally
released and discharged from the guarantee:
|
|
|
|
|
automatically upon any sale, exchange or transfer, whether by
way of merger or otherwise, to any person that is not our
affiliate, of all of our direct or indirect limited partnership
or other equity interests in the Subsidiary Guarantor;
|
|
|
|
automatically upon the merger of the Subsidiary Guarantor into
us or any other Subsidiary Guarantor or the liquidation and
dissolution of the Subsidiary Guarantor; or
|
|
|
|
following delivery of a written notice by us to the trustee,
upon the release of all guarantees by the Subsidiary Guarantor
of any debt of ours for borrowed money for a purchase money
obligation or for a guarantee of either, except for any series
of debt securities.
|
46
Events of Default. Unless we inform you
otherwise in the applicable prospectus supplement, the following
are events of default with respect to a series of debt
securities:
|
|
|
|
|
failure to pay interest on that series of debt securities for
30 days when due;
|
|
|
|
default in the payment of principal of or premium, if any, on
any debt securities of that series when due at its stated
maturity, upon redemption, upon required repurchase or otherwise;
|
|
|
|
default in the payment of any sinking fund payment on any debt
securities of that series when due;
|
|
|
|
failure by us or, if the series of debt securities is guaranteed
by any Subsidiary Guarantors, by such Subsidiary Guarantors, to
comply with the other agreements contained in the indenture, any
supplement to the indenture or any board resolution authorizing
the issuance of that series for 60 days after written
notice by the trustee or by the holders of at least 25% in
principal amount of the outstanding debt securities issued under
the indenture that are affected by that failure;
|
|
|
|
certain events of bankruptcy, insolvency or reorganization of us
or, if the series of debt securities is guaranteed by any
Subsidiary Guarantor, of any such Subsidiary Guarantor;
|
|
|
|
if the series of debt securities is guaranteed by any Subsidiary
Guarantor:
|
|
|
|
|
|
any of the guarantees ceases to be in full force and effect,
except as otherwise provided in the indenture;
|
|
|
|
any of the guarantees is declared null and void in a judicial
proceeding; or
|
|
|
|
any Subsidiary Guarantor denies or disaffirms its obligations
under the indenture or its guarantee; and
|
|
|
|
|
|
any other event of default provided for with respect to that
series of debt securities.
|
A default under one series of debt securities will not
necessarily be a default under another series. The trustee may
withhold notice to the holders of the debt securities of any
default or event of default (except in any payment on the debt
securities) if the trustee considers it in the interest of the
holders of the debt securities to do so.
If an event of default for any series of debt securities occurs
and is continuing, the trustee or the holders of at least 25% in
principal amount of the outstanding debt securities of the
series affected by the default (or, in the case of the fourth
bullet point appearing above under the heading
Events of Default, at least 25% in
principal amount of all debt securities issued under the
indenture that are affected, voting as one class) may declare
the principal of and all accrued and unpaid interest on those
debt securities to be due and payable. If an event of default
relating to certain events of bankruptcy, insolvency or
reorganization occurs, the principal of and interest on all the
debt securities issued under the indenture will become
immediately due and payable without any action on the part of
the trustee or any holder. The holders of a majority in
principal amount of the outstanding debt securities of the
series affected by the default may in some cases rescind this
accelerated payment requirement (other than acceleration for
nonpayment of principal of or premium or interest on or any
additional amounts with respect to the debt securities).
A holder of a debt security of any series issued under the
indenture may pursue any remedy under the indenture only if:
|
|
|
|
|
the holder gives the trustee written notice of a continuing
event of default for that series;
|
|
|
|
the holders of at least 25% in principal amount of the
outstanding debt securities of that series make a written
request to the trustee to pursue the remedy;
|
|
|
|
the holders offer to the trustee security or indemnity
satisfactory to the trustee;
|
|
|
|
the trustee fails to act for a period of 60 days after
receipt of the request and offer of security or
indemnity; and
|
|
|
|
during that
60-day
period, the holders of a majority in principal amount of the
debt securities of that series do not give the trustee a
direction inconsistent with the request.
|
This provision does not, however, affect the right of a holder
of a debt security to sue for enforcement of any overdue payment.
47
In most cases, holders of a majority in principal amount of the
outstanding debt securities of a series (or of all debt
securities issued under the indenture that are affected, voting
as one class) may direct the time, method and place of:
|
|
|
|
|
conducting any proceeding for any remedy available to the
trustee; and
|
|
|
|
exercising any trust or power conferred upon the trustee
relating to or arising as a result of an event of default.
|
Under the indenture we are required to file each year with the
trustee a written statement as to our compliance with the
covenants contained in the indenture.
Modification and Waiver. The indenture may be
amended or supplemented if the holders of a majority in
principal amount of the outstanding debt securities of all
series issued under the indenture that are affected by the
amendment or supplement (acting as one class) consent to it.
Without the consent of the holder of each debt security
affected, however, no modification may:
|
|
|
|
|
reduce the percentage in principal amount of debt securities
whose holders must consent to an amendment, a supplement or a
waiver;
|
|
|
|
reduce the rate of or extend the time for payment of interest on
the debt security;
|
|
|
|
reduce the principal of, or any premium on, the debt security or
change its stated maturity;
|
|
|
|
reduce any premium payable on the redemption of the debt
security or change the time at which the debt security may or
must be redeemed;
|
|
|
|
change any obligation to pay additional amounts on the debt
security;
|
|
|
|
make payments on the debt security payable in currency other
than as originally stated in the debt security;
|
|
|
|
impair the holders right to receive payment of principal
of and premium, if any, and interest on or any additional
amounts with respect to such holders debt securities or to
institute suit for the enforcement of any payment on or with
respect to the debt security;
|
|
|
|
make any change in the percentage of principal amount of debt
securities necessary to waive compliance with certain provisions
of the indenture or to make any change in the provision related
to modification;
|
|
|
|
waive a continuing default or event of default regarding any
payment on the debt securities;
|
|
|
|
except as provided in the indenture, release any security that
may have been granted in respect of any debt securities; or
|
|
|
|
except as provided in the indenture, release, or modify the
guarantee any Subsidiary Guarantor in any manner adverse to the
holders.
|
The indenture may be amended or supplemented or any provision of
the indenture may be waived without the consent of any holders
of debt securities issued under the indenture:
|
|
|
|
|
to cure any ambiguity, omission, defect or inconsistency;
|
|
|
|
to provide for the assumption of our obligations under the
indenture by a successor upon any merger, consolidation or asset
transfer permitted under the indenture;
|
|
|
|
to provide for uncertificated debt securities in addition to or
in place of certificated debt securities or to provide for
bearer debt securities;
|
|
|
|
to provide any security for, any guarantees of or any additional
obligors on any series of debt securities or the related
guarantees;
|
|
|
|
to comply with any requirement to effect or maintain the
qualification of the indenture under the Trust Indenture
Act of 1939;
|
|
|
|
to add covenants that would benefit the holders of any debt
securities or to surrender any rights we have under the
indenture;
|
|
|
|
to add events of default with respect to any debt
securities; and
|
48
|
|
|
|
|
to make any change that does not adversely affect any
outstanding debt securities of any series issued under the
indenture.
|
The holders of a majority in principal amount of the outstanding
debt securities of any series (or, in some cases, of all debt
securities issued under the indenture that are affected, voting
as one class) may waive any existing or past default or event of
default with respect to those debt securities. Those holders may
not, however, waive any default or event of default in any
payment on any debt security or compliance with a provision that
cannot be amended or supplemented without the consent of each
holder affected.
Defeasance. When we use the term defeasance,
we mean discharge from some or all of our obligations under the
indenture. If any combination of funds or government securities
are deposited with the trustee under the indenture sufficient to
make payments on the debt securities of a series issued under
the indenture on the dates those payments are due and payable,
then, at our option, either of the following will occur:
|
|
|
|
|
we will be discharged from our or their obligations with respect
to the debt securities of that series and, if applicable, the
related guarantees (legal defeasance); or
|
|
|
|
we will no longer have any obligation to comply with the
restrictive covenants, the merger covenant and other specified
covenants under the indenture, and the related events of default
will no longer apply (covenant defeasance).
|
If a series of debt securities is defeased, the holders of the
debt securities of the series affected will not be entitled to
the benefits of the indenture, except for obligations to
register the transfer or exchange of debt securities, replace
stolen, lost or mutilated debt securities or maintain paying
agencies and hold moneys for payment in trust. In the case of
covenant defeasance, our obligation to pay principal, premium
and interest on the debt securities and, if applicable,
guarantees of the payments will also survive.
Unless we inform you otherwise in the prospectus supplement, we
will be required to deliver to the trustee an opinion of counsel
that the deposit and related defeasance would not cause the
holders of the debt securities to recognize income, gain or loss
for U.S. federal income tax purposes. If we elect legal
defeasance, that opinion of counsel must be based upon a ruling
from the U.S. Internal Revenue Service or a change in law
to that effect.
No Personal Liability of General Partner. Our
general partner, and its directors, officers, employees,
incorporators and partners, in such capacity, will not be liable
for the obligations of Energy Transfer Partners, L.P. or any
Subsidiary Guarantor under the debt securities, the indenture or
the guarantees or for any claim based on, in respect of, or by
reason of, such obligations or their creation. By accepting a
debt security, each holder of that debt security will have
agreed to this provision and waived and released any such
liability on the part of our general partner and its directors,
officers, employees, incorporators and partners. This waiver and
release are part of the consideration for our issuance of the
debt securities. It is the view of the SEC that a waiver of
liabilities under the federal securities laws is against public
policy and unenforceable.
Governing Law. New York law will govern the
indenture and the debt securities.
Trustee. We may appoint a separate trustee for
any series of debt securities. We use the term
trustee to refer to the trustee appointed with
respect to any such series of debt securities. We may maintain
banking and other commercial relationships with the trustee and
its affiliates in the ordinary course of business, and the
trustee may own debt securities.
Form, Exchange, Registration and Transfer. The
debt securities will be issued in registered form, without
interest coupons. There will be no service charge for any
registration of transfer or exchange of the debt securities.
However, payment of any transfer tax or similar governmental
charge payable for that registration may be required.
Debt securities of any series will be exchangeable for other
debt securities of the same series, the same total principal
amount and the same terms but in different authorized
denominations in accordance with the indenture. Holders may
present debt securities for registration of transfer at the
office of the security registrar or any transfer agent we
designate. The security registrar or transfer agent will effect
the transfer or exchange if its requirements and the
requirements of the indenture are met.
49
The trustee will be appointed as security registrar for the debt
securities. If a prospectus supplement refers to any transfer
agents we initially designate, we may at any time rescind that
designation or approve a change in the location through which
any transfer agent acts. We are required to maintain an office
or agency for transfers and exchanges in each place of payment.
We may at any time designate additional transfer agents for any
series of debt securities.
In the case of any redemption, we will not be required to
register the transfer or exchange of:
|
|
|
|
|
any debt security during a period beginning 15 business days
prior to the mailing of the relevant notice of redemption and
ending on the close of business on the day of mailing of such
notice; or
|
|
|
|
any debt security that has been called for redemption in whole
or in part, except the unredeemed portion of any debt security
being redeemed in part.
|
Payment and Paying Agents. Unless we inform
you otherwise in a prospectus supplement, payments on the debt
securities will be made in U.S. dollars at the office of
the trustee and any paying agent. At our option, however,
payments may be made by wire transfer for global debt securities
or by check mailed to the address of the person entitled to the
payment as it appears in the security register. Unless we inform
you otherwise in a prospectus supplement, interest payments may
be made to the person in whose name the debt security is
registered at the close of business on the record date for the
interest payment.
Unless we inform you otherwise in a prospectus supplement, the
trustee under the indenture will be designated as the paying
agent for payments on debt securities issued under the
indenture. We may at any time designate additional paying agents
or rescind the designation of any paying agent or approve a
change in the office through which any paying agent acts.
If the principal of or any premium or interest on debt
securities of a series is payable on a day that is not a
business day, the payment will be made on the following business
day. For these purposes, unless we inform you otherwise in a
prospectus supplement, a business day is any day
that is not a Saturday, a Sunday or a day on which banking
institutions in New York, New York or a place of payment on the
debt securities of that series is authorized or obligated by
law, regulation or executive order to remain closed.
Subject to the requirements of any applicable abandoned property
laws, the trustee and paying agent will pay to us upon written
request any money held by them for payments on the debt
securities that remains unclaimed for two years after the date
upon which that payment has become due. After payment to us,
holders entitled to the money must look to us for payment. In
that case, all liability of the trustee or paying agent with
respect to that money will cease.
Book-Entry Debt Securities. The debt
securities of a series may be issued in the form of one or more
global debt securities that would be deposited with a depositary
or its nominee identified in the prospectus supplement. Global
debt securities may be issued in either temporary or permanent
form. We will describe in the prospectus supplement the terms of
any depositary arrangement and the rights and limitations of
owners of beneficial interests in any global debt security.
50
MATERIAL
INCOME TAX CONSIDERATIONS
This section is a summary of the material tax considerations
that may be relevant to prospective unitholders who are
individual citizens or residents of the United States and,
unless otherwise noted in the following discussion, is the
opinion of Vinson & Elkins L.L.P., counsel to our
general partner and us, insofar as it relates to legal
conclusions with respect to matters of U.S. federal income
tax law. This section is based upon current provisions of the
Internal Revenue Code of 1986, as amended (the Internal
Revenue Code), existing and proposed Treasury regulations
promulgated under the Internal Revenue Code (the Treasury
Regulations) and current administrative rulings and court
decisions, all of which are subject to change. Later changes in
these authorities may cause the tax consequences to vary
substantially from the consequences described below. Unless the
context otherwise requires, references in this section to
us or we are references to Energy
Transfer Partners, L.P. and our operating company.
The following discussion does not comment on all federal income
tax matters affecting us or our unitholders. Moreover, the
discussion focuses on unitholders who are individual citizens or
residents of the United States and has only limited application
to corporations, estates, trusts, nonresident aliens or other
unitholders subject to specialized tax treatment, such as
tax-exempt institutions, foreign persons, individual retirement
accounts (IRAs), real estate investment trusts (REITs) or mutual
funds. Accordingly, we encourage each prospective unitholder to
consult, and depend on, his own tax advisor in analyzing the
federal, state, local and foreign tax consequences particular to
him of the ownership or disposition of common units.
No ruling has been or will be requested from the IRS regarding
our characterization as a partnership for tax purposes. Instead,
we will rely on opinions of Vinson & Elkins L.L.P.
Unlike a ruling, an opinion of counsel represents only that
counsels best legal judgment and does not bind the IRS or
the courts. Accordingly, the opinions and statements made herein
may not be sustained by a court if contested by the IRS. Any
contest of this sort with the IRS may materially and adversely
impact the market for the common units and the prices at which
common units trade. In addition, the costs of any contest with
the IRS, principally legal, accounting and related fees, will
result in a reduction in cash available for distribution to our
unitholders and our general partner and thus will be borne
indirectly by our unitholders and our general partner.
Furthermore, the tax treatment of us, or of an investment in us,
may be significantly modified by future legislative or
administrative changes or court decisions. Any modifications may
or may not be retroactively applied.
All statements as to matters of law and legal conclusions, but
not as to factual matters, contained in this section, unless
otherwise noted, are the opinion of Vinson & Elkins
L.L.P. and are based on the accuracy of the representations made
by us.
For the reasons described below, Vinson & Elkins
L.L.P. has not rendered an opinion with respect to the following
specific federal income tax issues: (1) the treatment of a
unitholder whose common units are loaned to a short seller to
cover a short sale of common units (please read
Tax Consequences of Unit
Ownership Treatment of Short Sales);
(2) whether our monthly convention for allocating taxable
income and losses is permitted by existing Treasury Regulations
(please read Disposition of Common
Units Allocations Between Transferors and
Transferees); and (3) whether our method for
depreciating Section 743 adjustments is sustainable in
certain cases (please read Tax Consequences of
Unit Ownership Section 754 Election).
Partnership
Status
A partnership is not a taxable entity and incurs no federal
income tax liability. Instead, each partner of a partnership is
required to take into account his share of items of income,
gain, loss and deduction of the partnership in computing his
federal income tax liability, regardless of whether cash
distributions are made to him by the partnership. Distributions
by a partnership to a partner are generally not taxable to the
partnership or the partner unless the amount of cash distributed
to him is in excess of the partners adjusted basis in his
partnership interest.
51
Section 7704 of the Internal Revenue Code provides that
publicly traded partnerships will, as a general rule, be taxed
as corporations. However, an exception, referred to as the
Qualifying Income Exception, exists with respect to
publicly traded partnerships of which 90% or more of the gross
income for every taxable year consists of qualifying
income. Qualifying income includes income and gains
derived from the transportation, storage, processing and
marketing of crude oil, natural gas and products thereof,
including the retail and wholesale marketing of propane, certain
hedging activities and the transportation of propane and natural
gas liquids. Other types of qualifying income include interest
(other than from a financial business), dividends, gains from
the sale of real property and gains from the sale or other
disposition of capital assets held for the production of income
that otherwise constitutes qualifying income. We estimate that
less than 5% of our gross income is not qualifying income;
however, this estimate could change from time to time. Based
upon and subject to this estimate, the factual representations
made by us and our general partner and a review of the
applicable legal authorities, Vinson & Elkins L.L.P.
is of the opinion that at least 90% of our current gross income
constitutes qualifying income.
No ruling has been or will be sought from the IRS and the IRS
has made no determination as to our status or the status of the
operating partnership for federal income tax purposes. Instead,
we will rely on the opinion of Vinson & Elkins L.L.P.
on such matters. It is the opinion of Vinson & Elkins
L.L.P. that, based upon the Internal Revenue Code, its Treasury
Regulations, published revenue rulings and court decisions and
the representations described below, we will be classified as a
partnership and our operating company will be disregarded as an
entity separate from us for federal income tax purposes. In
rendering its opinion, Vinson & Elkins L.L.P. has
relied on factual representations made by us and our general
partner. The representations made by us and our general partner
upon which Vinson & Elkins L.L.P. has relied are:
(a) Except for Oasis Pipeline Company, we nor our operating
entities have elected or will elect to be treated as a
corporation;
(b) For each taxable year, more than 90% of our gross
income has been and will be income that Vinson &
Elkins L.L.P. has opined or will opine is qualifying
income within the meaning of Section 7704(d) of the
Internal Revenue Code; and
(c) Each hedging transaction that we treat as resulting in
qualifying income has been and will be appropriately identified
as a hedging transaction pursuant to applicable Treasury
Regulations, and has been and will be associated with oil, gas,
or products thereof that are held or to be held by us in
activities that Vinson & Elkins L.L.P. has opined or
will opine result in qualifying income.
We believe that these representations have been true in the past
and expect that these representations will be true in the future.
If we fail to meet the Qualifying Income Exception, other than a
failure that is determined by the IRS to be inadvertent and that
is cured within a reasonable time after discovery (in which case
the IRS may also require us to make adjustments with respect to
our unitholders or pay other amounts) we will be treated as if
we had transferred all of our assets, subject to liabilities, to
a newly formed corporation, on the first day of the year in
which we fail to meet the Qualifying Income Exception, in return
for stock in that corporation, and then distributed that stock
to the unitholders in liquidation of their interests in us. This
deemed contribution and liquidation should be tax-free to
unitholders and us so long as we, at that time, do not have
liabilities in excess of the tax basis of our assets.
Thereafter, we would be treated as a corporation for federal
income tax purposes.
If we were treated as an association taxable as a corporation in
any taxable year, either as a result of a failure to meet the
Qualifying Income Exception or otherwise, our items of income,
gain, loss and deduction would be reflected only on our tax
return rather than being passed through to our unitholders, and
our net income would be taxed to us at corporate rates. In
addition, any distribution made to a unitholder would be treated
as either taxable dividend income, to the extent of our current
or accumulated earnings and profits, or, in the absence of
earnings and profits, a nontaxable return of capital, to the
extent of the unitholders tax basis in his common units,
or taxable capital gain, after the unitholders tax basis
in his common units is reduced to zero. Accordingly, taxation as
a corporation would result in a material reduction in a
unitholders cash flow
52
and after-tax return and thus would likely result in a
substantial reduction of the value of the units. The discussion
below is based on Vinson & Elkins L.L.P.s
opinion that we will be classified as a partnership for federal
income tax purposes.
Limited
Partner Status
Unitholders who have become limited partners of Energy Transfer
Partners, L.P. will be treated as partners of Energy Transfer
Partners, L.P. for federal income tax purposes. Also:
(a) assignees who have executed and delivered transfer
applications, and are awaiting admission as limited
partners, and
(b) unitholders whose common units are held in street name
or by a nominee and who have the right to direct the nominee in
the exercise of all substantive rights attendant to the
ownership of their common units
will be treated as partners of Energy Transfer Partners, L.P.
for federal income tax purposes. As there is no direct or
indirect controlling authority addressing assignees of common
units who are entitled to execute and deliver transfer
applications and thereby become entitled to direct the exercise
of attendant rights, but who fail to execute and deliver
transfer applications, Vinson & Elkins L.L.P.s
opinion does not extend to these persons. Furthermore, a
purchaser or other transferee of common units who does not
execute and deliver a transfer application may not receive some
federal income tax information or reports furnished to record
holders of common units unless the common units are held in a
nominee or street name account and the nominee or broker has
executed and delivered a transfer application for those common
units. A beneficial owner of common units whose units have been
transferred to a short seller to complete a short sale would
appear to lose his status as a partner with respect to those
units for federal income tax purposes. Please read
Tax Consequences of Unit
Ownership Treatment of Short Sales. Income,
gain, deductions or losses would not appear to be reportable by
a unitholder who is not a partner for federal income tax
purposes, and any cash distributions received by a unitholder
who is not a partner for federal income tax purposes would
therefore appear to be fully taxable as ordinary income. These
holders are urged to consult their own tax advisors with respect
to their tax consequences of holding common units in Energy
Transfer Partners, L.P.
Tax
Consequences of Unit Ownership
Flow-Through of Taxable Income. We will
not pay any federal income tax. Instead, each unitholder will be
required to report on his income tax return his share of our
income, gains, losses and deductions without regard to whether
we make cash distributions to him. Consequently, we may allocate
income to a unitholder even if he has not received a cash
distribution. Each unitholder will be required to include in
income his allocable share of our income, gains, losses and
deductions for our taxable year ending with or within his
taxable year. Our taxable year ends on December 31.
Treatment of
Distributions. Distributions by us to a
unitholder generally will not be taxable to the unitholder for
federal income tax purposes, except to the extent the amount of
any such cash distribution exceeds his tax basis in his common
units immediately before the distribution. Our cash
distributions in excess of a unitholders tax basis
generally will be considered to be gain from the sale or
exchange of the common units, taxable in accordance with the
rules described under Disposition of Common
Units below. Any reduction in a unitholders share of
our liabilities for which no partner, including the general
partner, bears the economic risk of loss, known as
nonrecourse liabilities, will be treated as a
distribution of cash to that unitholder. To the extent our
distributions cause a unitholders at risk
amount to be less than zero at the end of any taxable year, he
must recapture any losses deducted in previous years. Please
read Limitations on Deductibility of
Losses.
A decrease in a unitholders percentage interest in us
because of our issuance of additional common units will decrease
his share of our nonrecourse liabilities, and thus will result
in a corresponding deemed distribution of cash. This deemed
distribution may constitute a non-pro rata distribution. A
non-pro rata distribution of money or property may result in
ordinary income to a unitholder, regardless of his tax basis in
his common units, if the distribution reduces the
unitholders share of our unrealized
receivables, including
53
depreciation recapture,
and/or
substantially appreciated inventory items, both as
defined in the Internal Revenue Code, and collectively,
Section 751 Assets. To that extent, he will be
treated as having been distributed his proportionate share of
the Section 751 Assets and then having exchanged those
assets with us in return for the non-pro rata portion of the
actual distribution made to him. This latter deemed exchange
will generally result in the unitholders realization of
ordinary income, which will equal the excess of (1) the
non-pro rata portion of that distribution over (2) the
unitholders tax basis (generally zero) for the share of
Section 751 Assets deemed relinquished in the exchange.
Basis of Common Units. A
unitholders initial tax basis for his common units will be
the amount he paid for the common units plus his share of our
nonrecourse liabilities. That basis will be increased by his
share of our income and by any increases in his share of our
nonrecourse liabilities. That basis will be decreased, but not
below zero, by distributions from us, by the unitholders
share of our losses, by any decreases in his share of our
nonrecourse liabilities and by his share of our expenditures
that are not deductible in computing taxable income and are not
required to be capitalized. A unitholder will have no share of
our debt that is recourse to our general partner, but will have
a share, generally based on his share of profits, of our
nonrecourse liabilities. Please read
Disposition of Common Units
Recognition of Gain or Loss.
Limitations on Deductibility of
Losses. The deduction by a unitholder of his
share of our losses will be limited to the tax basis in his
units and, in the case of an individual unitholder estate,
trust, or a corporate unitholder (if more than 50% of the value
of the corporate unitholders stock is owned directly or
indirectly by or for five or fewer individuals or some
tax-exempt organizations) to the amount for which the unitholder
is considered to be at risk with respect to our
activities, if that is less than his tax basis. A common
unitholder subject to these allowances must recapture losses
deducted in previous years to the extent that distributions
cause his at risk amount to be less than zero at the end of any
taxable year. Losses disallowed to a unitholder or recaptured as
a result of these limitations will carry forward and will be
allowable as a deduction to the extent that his at-risk amount
is subsequently increased, provided such losses do not exceed
such common unitholders tax basis in his common units.
Upon the taxable disposition of a unit, any gain recognized by a
unitholder can be offset by losses that were previously
suspended by the at risk limitation but may not be offset by
losses suspended by the basis limitation. Any loss previously
suspended by the at-risk limitation in excess of that gain would
no longer be utilizable. In general, a unitholder will be at
risk to the extent of the tax basis of his units, excluding any
portion of that basis attributable to his share of our
nonrecourse liabilities, reduced by (i) any portion of that
basis representing amounts otherwise protected against loss
because of a guarantee, stop loss agreement or other similar
arrangement and (ii) any amount of money he borrows to
acquire or hold his units, if the lender of those borrowed funds
owns an interest in us, is related to the unitholder or can look
only to the units for repayment. A unitholders at risk
amount will increase or decrease as the tax basis of the
unitholders units increases or decreases, other than tax
basis increases or decreases attributable to increases or
decreases in his share of our nonrecourse liabilities.
In addition to the basis and at-risk limitations on the
deductibility of losses, the passive loss limitations generally
provide that individuals, estates, trusts and some closely-held
corporations and personal service corporations can deduct losses
from passive activities, which are generally trade or business
activities in which the taxpayer does not materially
participate, only to the extent of the taxpayers income
from those passive activities. The passive loss limitations are
applied separately with respect to each publicly traded
partnership. Consequently, any passive losses we generate will
only be available to offset our passive income generated in the
future and will not be available to offset income from other
passive activities or investments, including our investments or
investments in other publicly traded partnerships, or salary or
active business income. Passive losses that are not deductible
because they exceed a unitholders share of income we
generate may be deducted in full when he disposes of his entire
investment in us in a fully taxable transaction with an
unrelated party. The passive loss limitations are applied after
other applicable limitations on deductions, including the at
risk rules and the basis limitation.
A unitholders share of our net income may be offset by any
of our suspended passive losses, but it may not be offset by any
other current or carryover losses from other passive activities,
including those attributable to other publicly traded
partnerships.
54
Limitations on Interest Deductions. The
deductibility of a non-corporate taxpayers
investment interest expense is generally limited to
the amount of that taxpayers net investment
income. Investment interest expense includes:
|
|
|
|
|
interest on indebtedness properly allocable to property held for
investment;
|
|
|
|
our interest expense attributed to portfolio income; and
|
|
|
|
the portion of interest expense incurred to purchase or carry an
interest in a passive activity to the extent attributable to
portfolio income.
|
The computation of a unitholders investment interest
expense will take into account interest on any margin account
borrowing or other loan incurred to purchase or carry a unit.
Net investment income includes gross income from property held
for investment and amounts treated as portfolio income under the
passive loss rules, less deductible expenses, other than
interest, directly connected with the production of investment
income, but generally does not include gains attributable to the
disposition of property held for investment or qualified
dividend income. The IRS has indicated that the net passive
income earned by a publicly traded partnership will be treated
as investment income to its unitholders. In addition, the
unitholders share of our portfolio income will be treated
as investment income.
Entity-Level Collections. If we
are required or elect under applicable law to pay any federal,
state, local or foreign income tax on behalf of any unitholder
or our general partner or any former unitholder, we are
authorized to pay those taxes from our funds. That payment, if
made, will be treated as a distribution of cash to the
unitholder on whose behalf the payment was made. If the payment
is made on behalf of a person whose identity cannot be
determined, we are authorized to treat the payment as a
distribution to all current unitholders. We are authorized to
amend our partnership agreement in the manner necessary to
maintain uniformity of intrinsic tax characteristics of units
and to adjust later distributions, so that after giving effect
to these distributions, the priority and characterization of
distributions otherwise applicable under our partnership
agreement is maintained as nearly as is practicable. Payments by
us as described above could give rise to an overpayment of tax
on behalf of an individual unitholder in which event the
unitholder would be required to file a claim in order to obtain
a credit or refund.
Allocation of Income, Gain, Loss and
Deduction. In general, if we have a net
profit, our items of income, gain, loss and deduction will be
allocated among our general partner and the unitholders in
accordance with their percentage interests in us. At any time
that distributions are made to the common units in excess of
distributions to the subordinated units, or incentive
distributions are made to our general partner, gross income will
be allocated to the recipients to the extent of these
distributions. If we have a net loss, that loss will be
allocated first to our general partner and the unitholders in
accordance with their percentage interests in us to the extent
of their positive capital accounts and, second, to our general
partner. Specified items of our income, gain, loss and deduction
will be allocated to account for the difference between the tax
basis and fair market value of our assets at the time of an
offering, referred to in this discussion as Contributed
Property. The effect of these allocations, referred to as
Section 704(c) Allocations, to a unitholder purchasing
common units from us in an offering will be essentially the same
as if the tax bases of our assets were equal to their fair
market value at the time of this offering. In the event we issue
additional common units or engage in certain other transactions
in the future reverse Section 704(c)
Allocations, similar to the Section 704(c)
Allocations described above, will be made to all holders of
partnership interests immediately prior to such other
transactions, including purchasers of common units in this
offering, to account for the difference between the
book basis for purposes of maintaining capital
accounts and the fair market value of all property held by us at
the time of the future transaction. In addition, items of
recapture income will be allocated to the extent possible to the
unitholder who was allocated the deduction giving rise to the
treatment of that gain as recapture income in order to minimize
the recognition of ordinary income by some unitholders. Finally,
although we do not expect that our operations will result in the
creation of negative capital accounts, if negative capital
accounts nevertheless result, items of our income and gain will
be allocated in an amount and manner to eliminate the negative
balance as quickly as possible. An allocation of items of our
income, gain, loss or deduction, other than an allocation
required by the Internal Revenue Code to eliminate the
difference between a partners book capital
account, credited with the fair market value of Contributed
Property, and tax
55
capital account, credited with the tax basis of Contributed
Property, referred to in this discussion as the Book-Tax
Disparity, will generally be given effect for federal
income tax purposes in determining a partners share of an
item of income, gain, loss or deduction only if the allocation
has substantial economic effect. In any other case, a
partners share of an item will be determined on the basis
of his interest in us, which will be determined by taking into
account all the facts and circumstances, including:
|
|
|
|
|
his relative contributions to us;
|
|
|
|
the interests of all the partners in profits and losses;
|
|
|
|
the interest of all the partners in cash flow; and
|
|
|
|
the rights of all the partners to distributions of capital upon
liquidation.
|
Vinson & Elkins L.L.P. is of the opinion that, with
the exception of the issues described in
Section 754 Election and
Disposition of Common Units
Allocations Between Transferors and Transferees,
allocations under our partnership agreement will be given effect
for federal income tax purposes in determining a partners
share of an item of income, gain, loss or deduction.
Treatment of Short Sales. A unitholder
whose units are loaned to a short seller to cover a
short sale of units may be considered as having disposed of
those units. If so, he would no longer be treated for tax
purposes as a partner with respect to those units during the
period of the loan and may recognize gain or loss from the
disposition. As a result, during this period:
|
|
|
|
|
any of our income, gain, loss or deduction with respect to those
units would not be reportable by the unitholder;
|
|
|
|
any cash distributions received by the unitholder as to those
units would be fully taxable; and
|
|
|
|
all of these distributions would appear to be ordinary income.
|
Vinson & Elkins L.L.P. has not rendered an opinion
regarding the treatment of a unitholder where common units are
loaned to a short seller to cover a short sale of common units;
therefore, unitholders desiring to assure their status as
partners and avoid the risk of gain recognition from a loan to a
short seller are urged to modify any applicable brokerage
account agreements to prohibit their brokers from loaning their
units. The IRS has announced that it is actively studying issues
relating to the tax treatment of short sales of partnership
interests. Please also read Disposition of
Common Units Recognition of Gain or Loss.
Alternative Minimum Tax. Each
unitholder will be required to take into account his
distributive share of any items of our income, gain, loss or
deduction for purposes of the alternative minimum tax. The
current minimum tax rate for noncorporate taxpayers is 26% on
the first $175,000 of alternative minimum taxable income in
excess of the exemption amount and 28% on any additional
alternative minimum taxable income. Prospective unitholders are
urged to consult with their tax advisors as to the impact of an
investment in units on their liability for the alternative
minimum tax.
Tax Rates. Under current law, the
highest marginal U.S. federal income tax rate applicable to
ordinary income of individuals is 35% and the highest marginal
U.S. federal income tax rate applicable to long-term
capital gains (generally, capital gains on certain assets held
for more than 12 months) of individuals is 15%. However,
absent new legislation extending the current rates, beginning
January 1, 2011, the highest marginal U.S. federal
income tax rate applicable to ordinary income and long-term
capital gains of individuals will increase to 39.6% and 20%,
respectively. Moreover, these rates are subject to change by new
legislation at any time.
Section 754 Election. We have made
the election permitted by Section 754 of the Internal
Revenue Code. That election is irrevocable without the consent
of the IRS. The election will generally permit us to adjust a
common unit purchasers tax basis in our assets
(inside basis) under Section 743(b) of the
Internal Revenue Code to reflect his purchase price. This
election does not apply to a person who purchases common units
directly from us. The Section 743(b) adjustment belongs to
the purchaser and not to other unitholders. For purposes of this
discussion, a unitholders inside basis in our assets will
be considered to have two
56
components: (1) his share of our tax basis in our assets
(common basis) and (2) his Section 743(b)
adjustment to that basis.
Where the remedial allocation method is adopted (which we have
historically adopted as to all property other than certain
goodwill properties and which we will generally adopt as to all
properties going forward), the Treasury Regulations under
Section 743 of the Internal Revenue Code require a portion
of the Section 743(b) adjustment that is attributable to
recovery property under Section 168 of the Internal Revenue
Code whose book basis is in excess of its tax basis to be
depreciated over the remaining cost recovery period for the
propertys unamortized Book-Tax Disparity. Under Treasury
Regulation Section 1.167(c)-1(a)(6),
a Section 743(b) adjustment attributable to property
subject to depreciation under Section 167 of the Internal
Revenue Code, rather than cost recovery deductions under
Section 168, is generally required to be depreciated using
either the straightline method or the 150% declining balance
method. If we elect a method other than the remedial method, the
depreciation and amortization methods and useful lives
associated with the Section 743(b) adjustment, therefore,
may differ from the methods and useful lives generally used to
depreciate the inside basis in such properties. Under our
partnership agreement, our general partner is authorized to take
a position to preserve the uniformity of units even if that
position is not consistent with these and any other Treasury
Regulations. If we elect a method other than the remedial method
with respect to a goodwill property, the common basis of such
property is not amortizable. Please read
Uniformity of Units.
Although Vinson & Elkins L.L.P. is unable to opine as
to the validity of this approach because there is no direct or
indirect controlling authority on this issue, we intend to
depreciate the portion of a Section 743(b) adjustment
attributable to unrealized appreciation in the value of
Contributed Property, to the extent of any unamortized Book-Tax
Disparity, using a rate of depreciation or amortization derived
from the depreciation or amortization method and useful life
applied to the propertys unamortized Book-Tax Disparity,
or treat that portion as
non-amortizable
to the extent attributable to property which is not amortizable.
This method is consistent with the methods employed by other
publicly traded partnerships but is arguably inconsistent with
Treasury
Regulation Section 1.167(c)-1(a)(6),
which is not expected to directly apply to a material portion of
our assets, and Treasury
Regulation Section 1.197-2(g)(3).
To the extent this Section 743(b) adjustment is
attributable to appreciation in value in excess of the
unamortized Book-Tax Disparity, we will apply the rules
described in the Treasury Regulations and legislative history.
If we determine that this position cannot reasonably be taken,
we may take a depreciation or amortization position under which
all purchasers acquiring units in the same month would receive
depreciation or amortization, whether attributable to common
basis or a Section 743(b) adjustment, based upon the same
applicable rate as if they had purchased a direct interest in
our assets. This kind of aggregate approach may result in lower
annual depreciation or amortization deductions than would
otherwise be allowable to some unitholders. Please read
Uniformity of Units. A unitholders
tax basis for his common units is reduced by his share of our
deductions (whether or not such deductions were claimed on an
individuals income tax return) so that any position we
take that understates deductions will overstate the common
unitholders basis in his common units, which may cause the
unitholder to understate gain or overstate loss on any sale of
such units. Please read Disposition of Common
Units Recognition of Gain or Loss. The IRS may
challenge our position with respect to depreciating or
amortizing the Section 743(b) adjustment we take to
preserve the uniformity of the units. If such a challenge were
sustained, the gain from the sale of units might be increased
without the benefit of additional deductions.
A Section 754 election is advantageous if the
transferees tax basis in his units is higher than the
units share of the aggregate tax basis of our assets
immediately prior to the transfer. In that case, as a result of
the election, the transferee would have, among other items, a
greater amount of depreciation deductions and his share of any
gain or loss on a sale of our assets would be less. Conversely,
a Section 754 election is disadvantageous if the
transferees tax basis in his units is lower than those
units share of the aggregate tax basis of our assets
immediately prior to the transfer. Thus, the fair market value
of the units may be affected either favorably or unfavorably by
the election. A basis adjustment is required regardless of
whether a Section 754 election is made in the case of a
transfer of an interest in us if we have a substantial built-in
loss immediately after the transfer, or if we distribute
property and have a substantial basis reduction. Generally a
built-in loss or a basis reduction is substantial if it exceeds
$250,000.
57
The calculations involved in the Section 754 election are
complex and will be made on the basis of assumptions as to the
value of our assets and other matters. For example, the
allocation of the Section 743(b) adjustment among our
assets must be made in accordance with the Internal Revenue
Code. The IRS could seek to reallocate some or all of any
Section 743(b) adjustment allocated by us to our tangible
assets to goodwill instead. Goodwill, as an intangible asset, is
generally nonamortizable or amortizable over a longer period of
time or under a less accelerated method than our tangible
assets. We cannot assure you that the determinations we make
will not be successfully challenged by the IRS and that the
deductions resulting from them will not be reduced or disallowed
altogether. Should the IRS require a different basis adjustment
to be made, and should, in our opinion, the expense of
compliance exceed the benefit of the election, we may seek
permission from the IRS to revoke our Section 754 election.
If permission is granted, a subsequent purchaser of units may be
allocated more income than he would have been allocated had the
election not been revoked.
Tax
Treatment of Operations
Accounting Method and Taxable Year. We
use the year ending December 31 as our taxable year and the
accrual method of accounting for federal income tax purposes.
Each unitholder will be required to include in income his share
of our income, gain, loss and deduction for our taxable year
ending within or with his taxable year. In addition, a
unitholder who has a taxable year ending on a date other than
December 31 and who disposes of all of his units following the
close of our taxable year but before the close of his taxable
year must include his share of our income, gain, loss and
deduction in income for his taxable year, with the result that
he will be required to include in income for his taxable year
his share of more than one year of our income, gain, loss and
deduction. Please read Disposition of Common
Units Allocations Between Transferors and
Transferees.
Initial Tax Basis, Depreciation and
Amortization. The tax basis of our assets
will be used for purposes of computing depreciation and cost
recovery deductions and, ultimately, gain or loss on the
disposition of these assets. The federal income tax burden
associated with the difference between the fair market value of
our assets and their tax basis immediately prior to an offering
will be borne by our partners holding interest in us prior to
such offering. Please read Tax Consequences of Unit
Ownership Allocation of Income, Gain, Loss and
Deduction.
To the extent allowable, we may elect to use the depreciation
and cost recovery methods that will result in the largest
deductions being taken in the early years after assets subject
to these allowances are placed in service. Because our general
partner may determine not to adopt the remedial method of
allocation with respect to any difference between the tax basis
and the fair market value of goodwill immediately prior to this
or any future offering, we may not be entitled to any
amortization deductions with respect to any goodwill properties
conveyed to us on formation or held by us at the time of any
future offering. Please read Uniformity of
Units. Property we subsequently acquire or construct may
be depreciated using accelerated methods permitted by the
Internal Revenue Code.
If we dispose of depreciable property by sale, foreclosure or
otherwise, all or a portion of any gain, determined by reference
to the amount of depreciation previously deducted and the nature
of the property, may be subject to the recapture rules and taxed
as ordinary income rather than capital gain. Similarly, a
unitholder who has taken cost recovery or depreciation
deductions with respect to property we own will likely be
required to recapture some or all of those deductions as
ordinary income upon a sale of his interest in us. Please read
Tax Consequences of Unit Ownership
Allocation of Income, Gain, Loss and Deduction and
Disposition of Common Units
Recognition of Gain or Loss.
The costs incurred in selling our units (called
syndication expenses) must be capitalized and cannot
be deducted currently, ratably or upon our termination. There
are uncertainties regarding the classification of costs as
organization expenses, which may be amortized by us, and as
syndication expenses, which may not be amortized by us. The
underwriting discounts and commissions we incur will be treated
as syndication expenses.
Valuation and Tax Basis of Our
Properties. The federal income tax
consequences of the ownership and disposition of units will
depend in part on our estimates of the relative fair market
values, and the initial tax
58
bases, of our assets. Although we may from time to time consult
with professional appraisers regarding valuation matters, we
will make many of the relative fair market value estimates
ourselves. These estimates and determinations of basis are
subject to challenge and will not be binding on the IRS or the
courts. If the estimates of fair market value or basis are later
found to be incorrect, the character and amount of items of
income, gain, loss or deductions previously reported by
unitholders might change, and unitholders might be required to
adjust their tax liability for prior years and incur interest
and penalties with respect to those adjustments.
Disposition
of Common Units
Recognition of Gain or Loss. Gain or
loss will be recognized on a sale of units equal to the
difference between the amount realized and the unitholders
tax basis for the units sold. A unitholders amount
realized will be measured by the sum of the cash or the fair
market value of other property received by him plus his share of
our nonrecourse liabilities. Because the amount realized
includes a unitholders share of our nonrecourse
liabilities, the gain recognized on the sale of units could
result in a tax liability in excess of any cash received from
the sale.
Prior distributions from us in excess of cumulative net taxable
income for a common unit that decreased a unitholders tax
basis in that common unit will, in effect, become taxable income
if the common unit is sold at a price greater than the
unitholders tax basis in that common unit, even if the
price received is less than his original cost.
Except as noted below, gain or loss recognized by a unitholder,
other than a dealer in units, on the sale or
exchange of a unit will generally be taxable as capital gain or
loss. Capital gain recognized by an individual on the sale of
units held for more than twelve months will generally be taxed
at a maximum U.S. federal income tax rate of 15% through
December 31, 2010 and 20% thereafter (absent new
legislation extending or adjusting the current rate). However, a
portion of this gain or loss, which will likely be substantial,
will be separately computed and taxed as ordinary income or loss
under Section 751 of the Internal Revenue Code to the
extent attributable to assets giving rise to depreciation
recapture or other unrealized receivables or to
inventory items we own. The term unrealized
receivables includes potential recapture items, including
depreciation recapture. Ordinary income attributable to
unrealized receivables, inventory items and depreciation
recapture may exceed net taxable gain realized upon the sale of
a unit and may be recognized even if there is a net taxable loss
realized on the sale of a unit. Thus, a unitholder may recognize
both ordinary income and a capital loss upon a sale of units.
Net capital losses may offset capital gains and no more than
$3,000 of ordinary income, in the case of individuals, and may
only be used to offset capital gains in the case of corporations.
The IRS has ruled that a partner who acquires interests in a
partnership in separate transactions must combine those
interests and maintain a single adjusted tax basis for all those
interests. Upon a sale or other disposition of less than all of
those interests, a portion of that tax basis must be allocated
to the interests sold using an equitable
apportionment method, which generally means that the tax
basis allocated to the interest sold equals an amount that bears
the same relation to the partners tax basis in his entire
interest in the partnership as the value of the interest sold
bears to the value of the partners entire interest in the
partnership. Treasury Regulations under Section 1223 of the
Internal Revenue Code allow a selling unitholder who can
identify common units transferred with an ascertainable holding
period to elect to use the actual holding period of the common
units transferred. Thus, according to the ruling, a common
unitholder will be unable to select high or low basis common
units to sell as would be the case with corporate stock, but,
according to the Treasury Regulations, may designate specific
common units sold for purposes of determining the holding period
of units transferred. A unitholder electing to use the actual
holding period of common units transferred must consistently use
that identification method for all subsequent sales or exchanges
of common units. A unitholder considering the purchase of
additional units or a sale of common units purchased in separate
transactions is urged to consult his tax advisor as to the
possible consequences of this ruling and application of the
Treasury Regulations.
59
Specific provisions of the Internal Revenue Code affect the
taxation of some financial products and securities, including
partnership interests, by treating a taxpayer as having sold an
appreciated partnership interest, one in which gain
would be recognized if it were sold, assigned or terminated at
its fair market value, if the taxpayer or related persons
enter(s) into:
|
|
|
|
|
a short sale;
|
|
|
|
an offsetting notional principal contract; or
|
|
|
|
a futures or forward contract with respect to the partnership
interest or substantially identical property.
|
Moreover, if a taxpayer has previously entered into a short
sale, an offsetting notional principal contract or a futures or
forward contract with respect to the partnership interest, the
taxpayer will be treated as having sold that position if the
taxpayer or a related person then acquires the partnership
interest or substantially identical property. The Secretary of
the Treasury is also authorized to issue regulations that treat
a taxpayer that enters into transactions or positions that have
substantially the same effect as the preceding transactions as
having constructively sold the financial position.
Allocations Between Transferors and
Transferees. In general, our taxable income
and losses will be determined annually, will be prorated on a
monthly basis and will be subsequently apportioned among the
unitholders in proportion to the number of units owned by each
of them as of the opening of the applicable exchange on the
first business day of the month, which we refer to in this
prospectus as the Allocation Date. However, gain or
loss realized on a sale or other disposition of our assets other
than in the ordinary course of business will be allocated among
the unitholders on the Allocation Date in the month in which
that gain or loss is recognized. As a result, a unitholder
transferring units may be allocated income, gain, loss and
deduction realized after the date of transfer.
Although simplifying conventions are contemplated by the
Internal Revenue Code and most publicly traded partnerships use
similar simplifying conventions, the use of this method may not
be permitted under existing Treasury Regulations. Accordingly,
Vinson & Elkins L.L.P. is unable to opine on the
validity of this method of allocating income and deductions
between transferor and transferee unitholders. If this method is
not allowed under the Treasury Regulations, or only applies to
transfers of less than all of the unitholders interest,
our taxable income or losses might be reallocated among the
unitholders. We are authorized to revise our method of
allocation between transferor and transferee unitholders, as
well as unitholders whose interests vary during a taxable year,
to conform to a method permitted under future Treasury
Regulations. A unitholder who owns units at any time during a
quarter and who disposes of them prior to the record date set
for a cash distribution for that quarter will be allocated items
of our income, gain, loss and deductions attributable to that
quarter but will not be entitled to receive that cash
distribution.
Notification Requirements. A unitholder
who sells any of his units is generally required to notify us in
writing of that sale within 30 days after the sale (or, if
earlier, January 15 of the year following the sale). A purchaser
of units who purchases units from another unitholder is also
generally required to notify us in writing of that purchase
within 30 days after the purchase. Upon receiving such
notifications, we are required to notify the IRS of that
transaction and to furnish specified information to the
transferor and transferee. Failure to notify us of a purchase
may, in some cases, lead to the imposition of penalties.
However, these reporting requirements do not apply to a sale by
an individual who is a citizen of the United States and who
effects the sale or exchange through a broker who will satisfy
such requirements.
Constructive Termination. We will be
considered to have been terminated for tax purposes if there are
sales or exchanges which, in the aggregate, constitute 50% or
more of the total interests in our capital and profits within a
twelve-month period. For purposes of measuring whether the 50%
threshold is reached, multiple sales of the same interest are
counted only once. A constructive termination results in the
closing of our taxable year for all unitholders. In the case of
a unitholder reporting on a taxable year other than a fiscal
year ending December 31, the closing of our taxable year
may result in more than twelve months of our taxable income or
loss being includable in his taxable income for the year of
termination. A constructive termination occurring on a date
other than December 31 will result in us filing two tax returns
(and unitholders receiving two Schedules K-1) for one fiscal
year and the cost of the preparation of these returns will be
borne
60
by all common unitholders. We would be required to make new tax
elections after a termination, including a new election under
Section 754 of the Internal Revenue Code, and a termination
would result in a deferral of our deductions for depreciation. A
termination could also result in penalties if we were unable to
determine that the termination had occurred. Moreover, a
termination might either accelerate the application of, or
subject us to, any tax legislation enacted before the
termination.
Uniformity
of Units
Because we cannot match transferors and transferees of units, we
must maintain uniformity of the economic and tax characteristics
of the units to a purchaser of these units. In the absence of
uniformity, we may be unable to completely comply with a number
of federal income tax requirements, both statutory and
regulatory. A lack of uniformity can result from a literal
application of Treasury
Regulation Section 1.167(c)-1(a)(6)
and Treasury
Regulation Section 1.197-2(g)(3).
Any non-uniformity could have a negative impact on the value of
the units. Please read Tax Consequences of
Unit Ownership Section 754 Election.
We intend to depreciate the portion of a Section 743(b)
adjustment attributable to unrealized appreciation in the value
of Contributed Property, to the extent of any unamortized
Book-Tax Disparity, using a rate of depreciation or amortization
derived from the depreciation or amortization method and useful
life applied to the propertys unamortized Book-Tax
Disparity, or treat that portion as nonamortizable, to the
extent attributable to property the common basis of which is not
amortizable, consistent with the Treasury Regulations under
Section 743 of the Internal Revenue Code, even though that
position may be inconsistent with Treasury
Regulation Section 1.167(c)-1(a)(6),
which is not expected to directly apply to a material portion of
our assets, and Treasury
Regulation Section 1.197-2(g)(3).
Please read Tax Consequences of Unit
Ownership Section 754 Election. To the
extent that the Section 743(b) adjustment is attributable
to appreciation in value in excess of the unamortized Book-Tax
Disparity, we will apply the rules described in the Treasury
Regulations and legislative history. If we determine that this
position cannot reasonably be taken, we may adopt a depreciation
and amortization position under which all purchasers acquiring
units in the same month would receive depreciation and
amortization deductions, whether attributable to a common basis
or Section 743(b) adjustment, based upon the same
applicable rate as if they had purchased a direct interest in
our property. If this position is adopted, it may result in
lower annual depreciation and amortization deductions than would
otherwise be allowable to some unitholders and risk the loss of
depreciation and amortization deductions not taken in the year
that these deductions are otherwise allowable. This position
will not be adopted if we determine that the loss of
depreciation and amortization deductions will have a material
adverse effect on the unitholders. If we choose not to utilize
this aggregate method, we may use any other reasonable
depreciation and amortization method to preserve the uniformity
of the intrinsic tax characteristics of any units that would not
have a material adverse effect on the unitholders. The IRS may
challenge any method of depreciating the Section 743(b)
adjustment described in this paragraph. If this challenge were
sustained, the uniformity of units might be affected, and the
gain from the sale of units might be increased without the
benefit of additional deductions. Please read
Disposition of Common Units
Recognition of Gain or Loss.
Tax-Exempt
Organizations and Other Investors
Ownership of units by employee benefit plans, other tax-exempt
organizations, non-resident aliens, foreign corporations and
other foreign persons raises issues unique to those investors
and, as described below, may have substantially adverse tax
consequences to them. 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.
Employee benefit plans and most other organizations exempt from
federal income tax, including individual retirement accounts and
other retirement plans, are subject to federal income tax on
unrelated business taxable income. Virtually all of our income
allocated to a unitholder that is a tax-exempt organization will
be unrelated business taxable income and will be taxable to them.
61
Non-resident aliens and foreign corporations, trusts or estates
that own units will be considered to be engaged in business in
the United States because of the ownership of units. As a
consequence, they will be required to file federal tax returns
to report their share of our income, gain, loss or deduction and
pay federal income tax at regular rates on their share of our
net income or gain. Moreover, under rules applicable to publicly
traded partnerships, we will withhold at the highest applicable
effective tax rate from cash distributions made quarterly to
foreign unitholders. Each foreign unitholder must obtain a
taxpayer identification number from the IRS and submit that
number to our transfer agent on a
Form W-8BEN
or applicable substitute form in order to obtain credit for
these withholding taxes. A change in applicable law may require
us to change these procedures.
In addition, because a foreign corporation that owns units will
be treated as engaged in a United States trade or business, that
corporation may be subject to the United States branch profits
tax at a rate of 30%, in addition to regular federal income tax,
on its share of our income and gain, as adjusted for changes in
the foreign corporations U.S. net equity,
which is effectively connected with the conduct of a United
States trade or business. That tax may be reduced or eliminated
by an income tax treaty between the United States and the
country in which the foreign corporate unitholder is a
qualified resident. In addition, this type of
unitholder is subject to special information reporting
requirements under Section 6038C of the Internal Revenue
Code.
A foreign unitholder who sells or otherwise disposes of a common
unit will be subject to U.S. federal income tax on gain
realized from the sale or disposition of that unit to the extent
the gain is effectively connected with a U.S. trade or
business of the foreign unitholder. Under a ruling published by
the IRS, interpreting the scope of effectively connected
income, a foreign unitholder would be considered to be
engaged in a trade or business in the U.S. by virtue of the
U.S. activities of the partnership, and part or all of that
unitholders gain would be effectively connected with that
unitholders indirect U.S. trade or business.
Moreover, under the Foreign Investment in Real Property Tax Act,
a foreign common unitholder generally will be subject to
U.S. federal income tax upon the sale or disposition of a
common unit if (i) he owned (directly or constructively
applying certain attribution rules) more than 5% of our common
units at any time during the five-year period ending on the date
of such disposition and (ii) 50% or more of the fair market
value of all of our assets consisted of U.S. real property
interests at any time during the shorter of the period during
which such unitholder held the common units or the
5-year
period ending on the date of disposition. Currently, more than
50% of our assets consist of U.S. real property interests
and we do not expect that to change in the foreseeable future.
Therefore, foreign unitholders may be subject to federal income
tax on gain from the sale or disposition of their units.
Administrative
Matters
Information Returns and Audit
Procedures. We intend to furnish to each
unitholder, within 90 days after the close of each calendar
year, specific tax information, including a
Schedule K-1,
which describes his share of our income, gain, loss and
deduction for our preceding taxable year. In preparing this
information, which will not be reviewed by counsel, we will take
various accounting and reporting positions, some of which have
been mentioned earlier, to determine each unitholders
share of income, gain, loss and deduction. We cannot assure you
that those positions will yield a result that conforms to the
requirements of the Internal Revenue Code, Treasury Regulations
or administrative interpretations of the IRS. Neither we nor
Vinson & Elkins L.L.P. can assure prospective
unitholders that the IRS will not successfully contend in court
that those positions are impermissible. Any challenge by the IRS
could negatively affect the value of the units. The IRS may
audit our federal income tax information returns. Adjustments
resulting from an IRS audit may require each unitholder to
adjust a prior years tax liability, and possibly may
result in an audit of his return. Any audit of a
unitholders return could result in adjustments not related
to our returns as well as those related to our returns.
Partnerships generally are treated as separate entities for
purposes of federal tax audits, judicial review of
administrative adjustments by the IRS and tax settlement
proceedings. The tax treatment of partnership items of income,
gain, loss and deduction are determined in a partnership
proceeding rather than in separate proceedings with the
partners. The Internal Revenue Code requires that one partner be
designated as the Tax
62
Matters Partner for these purposes. Our partnership
agreement names our general partner as our Tax Matters Partner.
The Tax Matters Partner will make some elections on our behalf
and on behalf of unitholders. In addition, the Tax Matters
Partner can extend the statute of limitations for assessment of
tax deficiencies against unitholders for items in our returns.
The Tax Matters Partner may bind a unitholder with less than a
1% profits interest in us to a settlement with the IRS unless
that unitholder elects, by filing a statement with the IRS, not
to give that authority to the Tax Matters Partner. The Tax
Matters Partner may seek judicial review, by which all the
unitholders are bound, of a final partnership administrative
adjustment and, if the Tax Matters Partner fails to seek
judicial review, judicial review may be sought by any unitholder
having at least a 1% interest in profits or by any group of
unitholders having in the aggregate at least a 5% interest in
profits. However, only one action for judicial review will go
forward, and each unitholder with an interest in the outcome may
participate.
A unitholder must file a statement with the IRS identifying the
treatment of any item on his federal income tax return that is
not consistent with the treatment of the item on our return.
Intentional or negligent disregard of this consistency
requirement may subject a unitholder to substantial penalties.
Nominee Reporting. Persons who hold an
interest in us as a nominee for another person are required to
furnish to us:
(a) the name, address and taxpayer identification number of
the beneficial owner and the nominee;
(b) whether the beneficial owner is:
1. a person that is not a United States person;
2. a foreign government, an international organization or
any wholly owned agency or instrumentality of either of the
foregoing; or
3. a tax-exempt entity;
(c) the amount and description of units held, acquired or
transferred for the beneficial owner; and
(d) specific information including the dates of
acquisitions and transfers, means of acquisitions and transfers,
and acquisition cost for purchases, as well as the amount of net
proceeds from sales. Brokers and financial institutions are
required to furnish additional information, including whether
they are United States persons and specific information on units
they acquire, hold or transfer for their own account. A penalty
of $50 per failure, up to a maximum of $100,000 per calendar
year, is imposed by the Internal Revenue Code for failure to
report that information to us. The nominee is required to supply
the beneficial owner of the units with the information furnished
to us.
Accuracy-Related Penalties. An
additional tax equal to 20% of the amount of any portion of an
underpayment of tax that is attributable to one or more
specified causes, including negligence or disregard of rules or
regulations, substantial understatements of income tax and
substantial valuation misstatements, is imposed by the Internal
Revenue Code. No penalty will be imposed, however, for any
portion of an underpayment if it is shown that there was a
reasonable cause for that portion and that the taxpayer acted in
good faith regarding that portion.
For individuals, a substantial understatement of income tax in
any taxable year exists if the amount of the understatement
exceeds the greater of 10% of the tax required to be shown on
the return for the taxable year or $5,000. The amount of any
understatement subject to penalty generally is reduced if any
portion is attributable to a position adopted on the return:
(1) for which there is, or was, substantial
authority; or
(2) as to which there is a reasonable basis and the
pertinent facts of that position are disclosed on the return.
63
If any item of income, gain, loss or deduction included in the
distributive shares of unitholders might result in that kind of
an understatement of income for which no
substantial authority exists, we must disclose the
pertinent facts on our return. In addition, we will make a
reasonable effort to furnish sufficient information for
unitholders to make adequate disclosure on their returns and to
take other actions as may be appropriate to permit unitholders
to avoid liability for this penalty. More stringent rules apply
to tax shelters, which we do not believe includes
us, or any of our investments, plans or arrangements.
A substantial valuation misstatement exists if (a) the
value of any property, or the tax basis of any property, claimed
on a tax return is 150% or more of the amount determined to be
the correct amount of the valuation or tax basis, (b) the
price for any property or services (or for the use of property)
claimed on any such return with respect to any transaction
between persons described in Internal Revenue Code
Section 482 is 200% or more (or 50% or less) of the amount
determined under Section 482 to be the correct amount of
such price, or (c) the net Internal Revenue Code
Section 482 transfer price adjustment for the taxable year
exceeds the lesser of $5 million or 10% of the
taxpayers gross receipts. No penalty is imposed unless the
portion of the underpayment attributable to a substantial
valuation misstatement exceeds $5,000 ($10,000 for a corporation
other than an S Corporation or a personal holding company).
The penalty is increased to 40% in the event of a gross
valuation misstatement. We do not anticipate making any
valuation misstatements.
Reportable Transactions. If we were to
engage in a reportable transaction, we (and possibly
you and others) would be required to make a detailed disclosure
of the transaction to the IRS. A transaction may be a reportable
transaction based upon any of several factors, including the
fact that it is a type of tax avoidance transaction publicly
identified by the IRS as a listed transaction or
that it produces certain kinds of losses for partnerships,
individuals, S corporations, and trusts in excess of
$2 million in any single year, or $4 million in any
combination of 6 successive tax years. Our participation in a
reportable transaction could increase the likelihood that our
federal income tax information return (and possibly your tax
return) would be audited by the IRS. Please read
Information Returns and Audit Procedures.
Moreover, if we were to participate in a reportable transaction
with a significant purpose to avoid or evade tax, or in any
listed transaction, you may be subject to the following
provisions of the American Jobs Creation Act of 2004:
|
|
|
|
|
accuracy-related penalties with a broader scope, significantly
narrower exceptions, and potentially greater amounts than
described above at Accuracy-Related
Penalties,
|
|
|
|
for those persons otherwise entitled to deduct interest on
federal tax deficiencies, nondeductibility of interest on any
resulting tax liability and
|
|
|
|
in the case of a listed transaction, an extended statute of
limitations.
|
We do not expect to engage in any reportable
transactions.
State,
Local, Foreign and Other Tax Considerations
In addition to federal income taxes, you likely will be subject
to other taxes, such as state, local and foreign income taxes,
unincorporated business taxes, and estate, inheritance or
intangible taxes that may be imposed by the various
jurisdictions in which we conduct business or own property or in
which you are a resident. Although an analysis of those various
taxes is not presented here, each prospective unitholder should
consider their potential impact on his investment in us. We will
currently own property or conduct business in more than
40 states. Most of these states impose an income tax on
individuals, corporations and other entities. We may also own
property or do business in other jurisdictions in the future.
Although you may not be required to file a return and pay taxes
in some jurisdictions because your income from that jurisdiction
falls below the filing and payment requirement, you will be
required to file income tax returns and to pay income taxes in
many of these jurisdictions in which we do business or own
property and may be subject to penalties for failure to comply
with those requirements. In some jurisdictions, tax losses may
not produce a tax benefit in the year incurred and may not be
available to offset income in subsequent taxable years. Some of
the jurisdictions may require us, or we may elect, to withhold a
percentage of income from amounts to be distributed to a
unitholder who is not a resident of the jurisdiction.
Withholding, the amount of which may be
64
greater or less than a particular unitholders income tax
liability to the jurisdiction, generally does not relieve a
nonresident unitholder from the obligation to file an income tax
return. Amounts withheld will be treated as if distributed to
unitholders for purposes of determining the amounts distributed
by us. Please read Tax Consequences of Unit
Ownership Entity-Level Collections. Based
on current law and our estimate of our future operations, our
general partner anticipates that any amounts required to be
withheld will not be material.
It is the responsibility of each unitholder to investigate the
legal and tax consequences, under the laws of pertinent
jurisdictions, of his investment in us. Accordingly, each
prospective unitholder is urged to consult, and depend upon, his
tax counsel or other advisor with regard to those matters.
Further, it is the responsibility of each unitholder to file all
state, local and foreign, as well as United States federal tax
returns, that may be required of him. Vinson & Elkins
L.L.P. has not rendered an opinion on the state, local or
foreign tax consequences of an investment in us.
65
INVESTMENTS
IN US BY EMPLOYEE BENEFIT PLANS
An investment in our units or debt securities by an employee
benefit plan is subject to certain additional considerations
because the investments of such plans are subject to the
fiduciary responsibility and prohibited transaction provisions
of the Employee Retirement Income Security Act of 1974, as
amended, or ERISA, and restrictions imposed by Section 4975
of the Internal Revenue Code of 1986, as amended, or the Code,
and provisions under any federal, state, local,
non-U.S. or
other laws or regulations that are similar to such provisions of
the Internal Revenue Code or ERISA, which we refer to
collectively as Similar Laws. As used herein, the term
employee benefit plan includes, but is not limited
to, qualified pension, profit-sharing and stock bonus plans,
Keogh plans, simplified employee pension plans and tax deferred
annuities or individual retirement accounts or other
arrangements established or maintained by an employer or
employee organization, and entities whose underlying assets are
considered to include plan assets of such plans,
accounts and arrangements.
General
Fiduciary Matters
ERISA and the Code impose certain duties on persons who are
fiduciaries of an employee benefit plan that is subject to
Title I of ERISA or Section 4975 of the Code, which we
refer to as an ERISA Plan, and prohibit certain transactions
involving the assets of an ERISA Plan and its fiduciaries or
other interested parties. Under ERISA and the Code, any person
who exercises any discretionary authority or control over the
administration of such an ERISA Plan or the management or
disposition of the assets of such an ERISA Plan, or who renders
investment advice for a fee or other compensation to such an
ERISA Plan, is generally considered to be a fiduciary of the
ERISA Plan. In considering an investment in our units or debt
securities, among other things, consideration should be given to
(a) whether such investment is prudent under
Section 404(a)(1)(B) of ERISA and any other applicable
Similar Laws; (b) whether in making such investment, such
plan will satisfy the diversification requirement of
Section 404(a)(1)(C) of ERISA and any other applicable
Similar Laws; (c) whether making such an investment will
comply with the delegation of control and prohibited transaction
provisions of ERISA, the Code and any other applicable Similar
Laws. and (d) whether such investment will result in
recognition of unrelated business taxable income by such plan
and, if so, the potential after-tax investment return. Please
read Material Income Tax Considerations. The person
with investment discretion with respect to the assets of an
employee benefit plan, which we refer to as a fiduciary, should
determine whether an investment in our units or debt securities
is authorized by the appropriate governing instrument and is a
proper investment for such plan.
Prohibited
Transaction Issues
Section 406 of ERISA and Section 4975 of the Code
(which also applies to IRAs that are not considered part of an
employee benefit plan) prohibit an employee benefit plan from
engaging in certain transactions involving plan
assets with parties that are parties in
interest under ERISA or disqualified persons
under the Code with respect to the plan, unless an exemption is
available. A party in interest or disqualified person who
engages in a non-exempt prohibited transaction may be subject to
excise taxes and other penalties and liabilities under ERISA and
the Code. In addition, the fiduciary of the ERISA Plan that
engaged in such a non-exempt prohibited transaction may be
subject to penalties and liabilities under ERISA and the Code.
The acquisition
and/or
holding of the debt securities by an ERISA Plan with respect to
which we or the initial purchasers are considered a party in
interest or a disqualified person, may constitute or result in a
direct or indirect prohibited transaction under Section 406
of ERISA
and/or
Section 4975 of the Code, unless the debt securities are
acquired and held in accordance with an applicable statutory,
class or individual prohibited transaction exemption. In this
regard, the U.S. Department of Labor has issued prohibited
transaction class exemptions, or PTCEs, that may apply to the
acquisition, holding and, if applicable, conversion of the debt
securities. These class exemptions include, without limitation,
PTCE 84-14
respecting transactions determined by independent qualified
professional asset managers,
PTCE 90-1
respecting insurance company pooled separate accounts,
PTCE 91-38
respecting bank collective investment funds,
PTCE 95-60
respecting life insurance company general accounts and
PTCE 96-23
respecting transactions determined by in-house asset managers.
There can be no assurance that all of the conditions of any such
exemptions will be satisfied.
66
Because of the foregoing, the debt securities should not be
purchased or held (or converted to equity securities, in the
case of any convertible debt) by any person investing plan
assets of any employee benefit plan, unless such purchase
and holding (or conversion, if any) will not constitute a
non-exempt prohibited transaction under ERISA and the Code or
similar violation of any applicable Similar Laws.
Representation
Accordingly, by acceptance of the debt securities, each
purchaser and subsequent transferee of the debt securities will
be deemed to have represented and warranted that either
(i) no portion of the assets used by such purchaser or
transferee to acquire and hold the notes constitutes assets of
any employee benefit plan or (ii) the purchase and holding
(and any conversion, if applicable) of the notes by such
purchaser or transferee will not constitute a non-exempt
prohibited transaction under Section 406 of ERISA or
Section 4975 of the Code or similar violation under any
applicable Similar Laws.
Plan
Asset Issues
In addition to considering whether the purchase of our limited
partnership units or debt securities is a prohibited
transaction, a fiduciary of an employee benefit plan should
consider whether such plan will, by investing in our units or
debt securities, be deemed to own an undivided interest in our
assets, with the result that our general partner also would be a
fiduciary of such plan and our operations would be subject to
the regulatory restrictions of ERISA, including its prohibited
transaction rules, as well as the prohibited transaction rules
of the Code and any other applicable Similar Laws.
The Department of Labor regulations provide guidance with
respect to whether the assets of an entity in which employee
benefit plans acquire equity interests would be deemed
plan assets under certain circumstances. Pursuant to
these regulations, an entitys assets would not be
considered to be plan assets if, among other things,
(a) the equity interest acquired by employee benefit plans
are publicly offered securities i.e., the equity
interests are widely held by 100 or more investors independent
of the issuer and each other, freely transferable and registered
pursuant to certain provisions of the federal securities laws,
(b) the entity is an operating
company i.e., it is primarily engaged in the
production or sale of a product or service other than the
investment of capital either directly or through a majority
owned subsidiary or subsidiaries, or (c) there is no
significant investment by benefit plan investors, which is
defined to mean that less than 25% of the value of each class of
equity interest (disregarding certain interests held by our
general partner, its affiliates and certain other persons) is
held by the employee benefit plans that are subject to
part 4 of Title I of ERISA (which excludes
governmental plans and non-electing church plans) and/or
Section 4975 of the Code, IRAs and certain other employee
benefit plans not subject to ERISA (such as electing church
plans). With respect to an investment in our units, our assets
should not be considered plan assets under these
regulations because it is expected that the investment will
satisfy the requirements in (a) and (b) above and may
also satisfy the requirements in (c) above (although we do
not monitor the level of benefit plan investors as required for
compliance with (c)). With respect to an investment in our debt
securities, our assets should not be considered plan
assets under these regulations because such securities are
not equity securities or, even if they are issued with a feature
that allows their conversion to equity securities, the
securities into which they will be convertible will satisfy the
requirements in (a) and (b) above.
The foregoing discussion of issues arising for employee benefit
plan investments under ERISA, the Code and Similar Laws should
not be construed as legal advice. Plan fiduciaries contemplating
a purchase of our limited partnership units or debt securities
should consult with their own counsel regarding the consequences
under ERISA, the Code and other Similar Laws in light of the
serious penalties imposed on persons who engage in prohibited
transactions or other violations.
67
PLAN OF
DISTRIBUTION
We may sell or distribute the securities included in this
prospectus through underwriters, agents or broker-dealers, in
private transactions, at market prices prevailing at the time of
sale, at prices related to the prevailing market prices, or at
negotiated prices.
In addition, we may sell some or all of the securities included
in this prospectus through:
|
|
|
|
|
a block trade in which a broker-dealer may resell a portion of
the block, as principal, in order to facilitate the transaction;
|
|
|
|
purchases by a broker-dealer, as principal, and resale by the
broker-dealer for its account; or
|
|
|
|
ordinary brokerage transactions and transactions in which a
broker solicits purchasers.
|
In addition, we may enter into option or other types of
transactions that require us to deliver common units to a
broker-dealer, who will then resell or transfer the common units
under this prospectus. We may enter into hedging transactions
with respect to our securities. For example, we may:
|
|
|
|
|
enter into transactions involving short sales of the common
units by broker-dealers;
|
|
|
|
sell common units short themselves and deliver the units to
close out short positions;
|
|
|
|
enter into option or other types of transactions that require us
to deliver common units to a broker-dealer, who will then resell
or transfer the common units under this prospectus; or
|
|
|
|
loan or pledge the common units to a broker-dealer, who may sell
the loaned units or, in the event of default, sell the pledged
units.
|
We may enter into derivative transactions with third parties, or
sell securities not covered by this prospectus to third parties
in privately negotiated transactions. If the applicable
prospectus supplement indicates, in connection with those
derivatives, the third parties may sell securities covered by
this prospectus and the applicable prospectus supplement,
including in short sale transactions. If so, the third party may
use securities pledged by us or borrowed from us or others to
settle those sales or to close out any related open borrowings
of securities, and may use securities received from us in
settlement of those derivatives to close out any related open
borrowings of securities. The third party in such sale
transactions will be an underwriter and, if not identified in
this prospectus, will be identified in the applicable prospectus
supplement (or a post-effective amendment). In addition, we may
otherwise loan or pledge securities to a financial institution
or other third party that in turn may sell the securities short
using this prospectus. Such financial institution or other third
party may transfer its economic short position to investors in
our securities or in connection with a concurrent offering of
other securities.
There is currently no market for any of the securities, other
than our common units listed on the New York Stock Exchange. If
the securities are traded after their initial issuance, they may
trade at a discount from their initial offering price, depending
on prevailing interest rates, the market for similar securities
and other factors. While it is possible that an underwriter
could inform us that it intends to make a market in the
securities, such underwriter would not be obligated to do so,
and any such market making could be discontinued at any time
without notice. Therefore, we cannot assure you as to whether an
active trading market will develop for these other securities.
We have no current plans for listing the debt securities on any
securities exchange; any such listing with respect to any
particular debt securities will be described in the applicable
prospectus supplement.
Any broker-dealers or other persons acting on our behalf that
participate with us in the distribution of the common units may
be deemed to be underwriters and any commissions received or
profit realized by them on the resale of the common units may be
deemed to be underwriting discounts and commissions under the
Securities Act of 1933, as amended, or the Securities Act. As of
the date of this prospectus, we are not a party to any
agreement, arrangement or understanding between any broker or
dealer and us with respect to the offer or sale of the
securities pursuant to this prospectus.
68
We may have agreements with agents, underwriters, dealers and
remarketing firms to indemnify them against certain civil
liabilities, including liabilities under the Securities Act.
Agents, underwriters, dealers and remarketing firms, and their
affiliates, may engage in transactions with, or perform services
for, us in the ordinary course of business. This includes
commercial banking and investment banking transactions.
At the time that any particular offering of securities is made,
to the extent required by the Securities Act, a prospectus
supplement will be distributed setting forth the terms of the
offering, including the aggregate number of securities being
offered, the purchase price of the securities, the initial
offering price of the securities, the names of any underwriters,
dealers or agents, any discounts, commissions and other items
constituting compensation from us and any discounts, commissions
or concessions allowed or reallowed or paid to dealers.
Underwriters or agents could make sales in privately negotiated
transactions
and/or any
other method permitted by law, including sales deemed to be an
at the market offering as defined in Rule 415
promulgated under the Securities Act, which includes sales made
directly on or through the New York Stock Exchange, the existing
trading market for our common units, or sales made to or through
a market maker other than on an exchange.
Securities may also be sold directly by us. In this case, no
underwriters or agents would be involved.
If a prospectus supplement so indicates, underwriters, brokers
or dealers, in compliance with applicable law, may engage in
transactions that stabilize or maintain the market price of the
securities at levels above those that might otherwise prevail in
the open market.
Pursuant to a requirement by the Financial Industry Regulatory
Authority, or FINRA, the maximum commission or discount to be
received by any FINRA member or independent broker/dealer may
not be greater than eight percent (8%) of the gross proceeds
received by us for the sale of any securities being registered
pursuant to SEC Rule 415 under the Securities Act of 1933.
If more than 10% of the net proceeds of any offering of
securities made under this prospectus will be received by FINRA
members participating in the offering or affiliates or
associated persons of such FINRA members, the offering will be
conducted in accordance with the National Association of
Securities Dealers Conduct Rule 2710(h).
69
LEGAL
MATTERS
The validity of the securities offered in this prospectus will
be passed upon for us by Vinson & Elkins L.L.P.,
Houston, Texas. Vinson & Elkins L.L.P. will also
render an opinion on the material federal income tax
considerations regarding the securities. If certain legal
matters in connection with an offering of the securities made by
this prospectus and a related prospectus supplement are passed
on by counsel for the underwriters of such offering, that
counsel will be named in the applicable prospectus supplement
related to that offering.
EXPERTS
The consolidated financial statements and managements
assessment of the effectiveness of internal control over
financial reporting of Energy Transfer Partners, L.P. and the
consolidated balance sheets of Energy Transfer Partners GP, L.P.
and Energy Transfer Partners, L.L.C., all incorporated by
reference in this prospectus, have been so incorporated by
reference in reliance upon the reports of Grant Thornton LLP,
independent registered public accountants, upon the authority of
said firm as experts in giving said reports.
WHERE YOU
CAN FIND MORE INFORMATION
We have filed a registration statement with the SEC under the
Securities Act of 1933 that registers the securities offered by
this prospectus. The registration statement, including the
attached exhibits, contains additional relevant information
about us. The rules and regulations of the SEC allow us to omit
some information included in the registration statement from
this prospectus.
In addition, we file annual, quarterly and other reports and
other information with the SEC. You may read and copy any
document we file at the SECs public reference room at
100 F Street, N.E., Washington, D.C. 20549.
Please call the SEC at
1-800-732-0330
for further information on the operation of the SECs
public reference room. Our SEC filings are available on the
SECs web site at
http://www.sec.gov.
We also make available free of charge on our website, at
http://www.energytransfer.com,
all materials that we file electronically with the SEC,
including our annual report on
Form 10-K,
quarterly reports on
Form 10-Q,
current reports on
Form 8-K,
Section 16 reports and amendments to these reports as soon
as reasonably practicable after such materials are
electronically filed with, or furnished to, the SEC.
Additionally, you can obtain information about us through the
New York Stock Exchange, 20 Broad Street, New York, New
York 10005, on which our common units are listed.
The SEC allows us to incorporate by reference the
information we have filed with the SEC. This means that we can
disclose important information to you without actually including
the specific information in this prospectus by referring you to
other documents filed separately with the SEC. These other
documents contain important information about us, our financial
condition and results of operations. The information
incorporated by reference is an important part of this
prospectus. Information that we file later with the SEC will
automatically update and may replace information in this
prospectus and information previously filed with the SEC.
We incorporate by reference in this prospectus the documents
listed below:
|
|
|
|
|
our annual report on
Form 10-K
for the year ended December 31, 2008;
|
|
|
|
our quarterly report on
Form 10-Q
for the quarter ended March 31, 2009;
|
|
|
|
our current reports on
Form 8-K
filed January 21, 2009, January 26, 2009 (two
reports), January 27, 2009, February 17, 2009,
March 17, 2009, April 2, 2009, April 7, 2009,
April 9, 2009 and April 17, 2009 (excluding any
information furnished pursuant to Item 2.02 or
Item 7.01 of any such current report on
Form 8-K);
|
|
|
|
the description of our common units in our registration
statement on
Form 8-A
(File
No. 1-11727)
filed pursuant to the Securities Exchange Act of 1934 on
May 16, 1996; and
|
70
|
|
|
|
|
all documents filed by us under Sections 13(a), 13(c), 14
or 15(d) of the Securities Exchange Act of 1934 between the date
of this prospectus and the termination of the registration
statement (excluding any information furnished pursuant to
Item 2.02 or Item 7.01 of any current report on
Form 8-K).
|
You may obtain any of the documents incorporated by reference in
this prospectus from the SEC through the SECs website at
the address provided above. You also may request a copy of any
document incorporated by reference in this prospectus (including
exhibits to those documents specifically incorporated by
reference in this document), at no cost, by visiting our
internet website at www.energytransfer.com, or by writing or
calling us at the following address:
Energy
Transfer Partners, L.P.
3738 Oak Lawn Avenue
Dallas, TX 75219
Attention: Thomas P. Mason
Telephone:
(214) 981-0700
71
The
information in this prospectus is not complete and may be
changed. We may not sell these securities until the registration
statement filed with the Securities and Exchange Commission is
effective. This 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.
|
SUBJECT TO COMPLETION, DATED
JUNE 16, 2009
Prospectus
ENERGY TRANSFER PARTNERS,
L.P.
12,000,000 Common
Units
The securities to be offered and sold using this prospectus are
currently issued and outstanding common units representing
limited partner interests in us. These common units may be
offered and sold by the selling unitholder named in this
prospectus or in any supplement to this prospectus from time to
time in accordance with the provisions set forth under
Plan of Distribution.
The selling unitholder may sell the common units offered by this
prospectus from time to time on any exchange on which the common
units are listed on terms to be negotiated with buyers. It may
also sell the common units in private sales or through dealers
or agents. The selling unitholder may sell the common units at
prevailing market prices or at prices negotiated with buyers.
The selling unitholder will be responsible for any commissions
due to brokers, dealers or agents. We will be responsible for
all other offering expenses. We will not receive any of the
proceeds from the sale by the selling unitholder of the common
units offered by this prospectus.
Investing in our common units involves risks. Limited
partnerships are inherently different from corporations. You
should carefully consider the risk factors described under
Risk Factors beginning on page 4 of this
prospectus before you make an investment in our securities.
Our common units are traded on the New York Stock Exchange, or
the NYSE, under the symbol ETP. The last reported
sales price of our common units on the NYSE on June 15,
2009 was $42.23 per common unit.
Neither the Securities and Exchange Commission nor any state
securities commission has approved or disapproved these
securities or determined if this prospectus is truthful or
complete. Any representation to the contrary is a criminal
offense.
The date of this prospectus
is ,
2009.
TABLE OF
CONTENTS
|
|
|
|
|
|
|
Page
|
|
|
|
|
1
|
|
|
|
|
1
|
|
|
|
|
2
|
|
|
|
|
4
|
|
|
|
|
32
|
|
|
|
|
33
|
|
|
|
|
40
|
|
|
|
|
44
|
|
|
|
|
59
|
|
|
|
|
60
|
|
|
|
|
62
|
|
|
|
|
63
|
|
|
|
|
63
|
|
|
|
|
63
|
|
In making your investment decision, you should rely only on
the information contained or incorporated by reference in this
prospectus. We have not authorized anyone to provide you with
any other information. If anyone provides you with different or
inconsistent information, you should not rely on it.
You should not assume that the information contained in this
prospectus is accurate as of any date other than the date on the
front cover of this prospectus. You should not assume that the
information contained in the documents incorporated by reference
in this prospectus is accurate as of any date other than the
respective dates of those documents. Our business, financial
condition, results of operations and prospects may have changed
since those dates.
ABOUT
THIS PROSPECTUS
This prospectus is part of a registration statement that we have
filed with the Securities and Exchange Commission using a
shelf registration process. Under this shelf
registration process, we may, over time, offer and sell any
combination of the securities described in this prospectus in
one or more offerings. This prospectus generally describes
Energy Transfer Partners, L.P. and the securities. Each time we
sell securities with this prospectus, we will provide you with a
prospectus supplement that will contain specific information
about the terms of that offering. The prospectus supplement may
also add to, update or change information in this prospectus.
Before you invest in our securities, you should carefully read
this prospectus and any prospectus supplement and the additional
information described under the heading Where You Can Find
More Information. To the extent information in this
prospectus is inconsistent with information contained in a
prospectus supplement, you should rely on the information in the
prospectus supplement. You should read both this prospectus and
any prospectus supplement, together with additional information
described under the heading Where You Can Find More
Information, and any additional information you may need
to make your investment decision. Unless the context requires
otherwise, all references in this prospectus to we,
us, ETP, the Partnership and
our refer to Energy Transfer Partners, L.P., and its
operating partnerships and their subsidiaries.
ENERGY
TRANSFER PARTNERS, L.P.
We are a publicly traded limited partnership that owns and
operates a diversified portfolio of energy assets. Our natural
gas operations include intrastate natural gas gathering and
transportation pipelines, an interstate pipeline, natural gas
treating and processing assets located in Texas, New Mexico,
Arizona, Louisiana, Utah and Colorado, and three natural gas
storage facilities located in Texas. These assets include
approximately 14,600 miles of intrastate gas gathering and
transportation pipeline in service, with approximately
250 miles of additional intrastate pipeline under
construction. In addition, we own approximately 2,700 miles
of interstate pipeline in service and have a 50% interest in a
joint venture with approximately 500 miles of interstate
pipeline under construction or in interim service. Our
intrastate and interstate pipeline systems transport natural gas
from several significant natural gas producing areas, including
the Barnett Shale in the Fort Worth Basin in north Texas,
the Bossier Sands in east Texas, the Permian Basin in west Texas
and New Mexico, the San Juan Basin in New Mexico and other
producing areas in south Texas and central Texas. Our gathering
and processing operations are conducted in many of these same
producing areas as well as in the Piceance and Uinta Basins in
Colorado and Utah. We are also one of the three largest retail
marketers of propane in the United States, serving more than one
million customers across the country.
Our principal executive offices are located at 3738 Oak Lawn
Avenue, Dallas, Texas 75219, and our telephone number at that
location is
(214) 981-0700.
1
CAUTIONARY
STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
This prospectus contains various forward-looking statements and
information that are based on our beliefs and those of our
general partner, as well as assumptions made by and information
currently available to us. These forward-looking statements are
identified as any statement that does not relate strictly to
historical or current facts. When used in this prospectus, words
such as anticipate, project,
expect, plan, goal,
forecast, intend, could,
believe, may, and similar expressions
and statements regarding our plans and objectives for future
operations, are intended to identify forward-looking statements.
Although we and our general partner believe that the
expectations on which such forward-looking statements are based
are reasonable, neither we nor our general partner can give
assurances that such expectations will prove to be correct.
Forward-looking statements are subject to a variety of risks,
uncertainties and assumptions. If one or more of these risks or
uncertainties materialize, or if underlying assumptions prove
incorrect, our actual results may vary materially from those
anticipated, estimated, projected or expected. Among the key
risk factors that may have a direct bearing on our results of
operations and financial condition are:
|
|
|
|
|
the amount of natural gas transported on our pipelines and
gathering systems;
|
|
|
|
the level of throughput in our natural gas processing and
treating facilities;
|
|
|
|
the fees we charge and the margins we realize for our gathering,
treating, processing, storage and transportation services;
|
|
|
|
the prices and market demand for, and the relationship between,
natural gas and natural gas liquids, or NGLs;
|
|
|
|
energy prices generally;
|
|
|
|
the prices of natural gas and propane compared to the price of
alternative and competing fuels;
|
|
|
|
the general level of petroleum product demand and the
availability and price of propane supplies;
|
|
|
|
the level of domestic oil, propane and natural gas production;
|
|
|
|
the availability of imported oil and natural gas;
|
|
|
|
the ability to obtain adequate supplies of propane for retail
sale in the event of an interruption in supply or transportation
and the availability of capacity to transport propane to market
areas;
|
|
|
|
actions taken by foreign oil and gas producing nations;
|
|
|
|
the political and economic stability of petroleum producing
nations;
|
|
|
|
the effect of weather conditions on demand for oil, natural gas
and propane;
|
|
|
|
availability of local, intrastate and interstate transportation
systems;
|
|
|
|
the continued ability to find and contract for new sources of
natural gas supply;
|
|
|
|
availability and marketing of competitive fuels;
|
|
|
|
the impact of energy conservation efforts;
|
|
|
|
energy efficiencies and technological trends;
|
|
|
|
governmental regulation and taxation;
|
|
|
|
changes to, and the application of, regulation of tariff rates
and operational requirements related to our interstate and
intrastate pipelines;
|
|
|
|
hazards or operating risks incidental to the gathering,
treating, processing and transporting of natural gas and NGLs or
to the transporting, storing and distributing of propane that
may not be fully covered by insurance;
|
|
|
|
the maturity of the propane industry and competition from other
propane distributors;
|
2
|
|
|
|
|
competition from other midstream companies, interstate pipeline
companies and propane distribution companies;
|
|
|
|
loss of key personnel;
|
|
|
|
loss of key natural gas producers or the providers of
fractionation services;
|
|
|
|
reductions in the capacity or allocations of third party
pipelines that connect with our pipelines and facilities;
|
|
|
|
the effectiveness of risk-management policies and procedures and
the ability of our liquids marketing counterparties to satisfy
their financial commitments;
|
|
|
|
the nonpayment or nonperformance by our customers;
|
|
|
|
regulatory, environmental, political and legal uncertainties
that may affect the timing and cost of our internal growth
projects, such as our construction of additional pipeline
systems;
|
|
|
|
risks associated with the construction of new pipelines and
treating and processing facilities or additions to our existing
pipelines and facilities, including difficulties in obtaining
permits and rights-of-way or other regulatory approvals and the
performance by third party contractors;
|
|
|
|
the availability and cost of capital and our ability to access
certain capital sources;
|
|
|
|
the further deterioration of the credit and capital markets;
|
|
|
|
the ability to successfully identify and consummate strategic
acquisitions at purchase prices that are accretive to our
financial results and to successfully integrate acquired
businesses;
|
|
|
|
changes in laws and regulations to which we are subject,
including tax, environmental, transportation and employment
regulations or new interpretations by regulatory agencies
concerning such laws and regulations; and
|
|
|
|
the costs and effects of legal and administrative proceedings.
|
You should not put undue reliance on any forward-looking
statements. When considering forward-looking statements, please
review the risk factors described under Risk Factors
in this prospectus.
3
RISK
FACTORS
An investment in our securities involves a high degree of
risk. You should carefully consider the following risk factors,
together with all of the other information included in, or
incorporated by reference into, this prospectus in evaluating an
investment in our securities. If any of these risks were to
occur, our business, financial condition or results of
operations could be adversely affected. In that case, the
trading price of our common units could decline and you could
lose all or part of your investment. When we offer and sell any
securities pursuant to a prospectus supplement, we may include
additional risk factors relevant to such securities in the
prospectus supplement.
Risks
Inherent In An Investment In Us
Cash
distributions are not guaranteed and may fluctuate with our
performance and other external factors.
The amount of cash we can distribute on our common units or
other partnership securities depends upon the amount of cash we
generate from our operations. The amount of cash we generate
from our operations will fluctuate from quarter to quarter and
will depend upon, among other things:
|
|
|
|
|
the amount of natural gas transported in our pipelines and
gathering systems;
|
|
|
|
the level of throughput in our processing and treating
operations;
|
|
|
|
the fees we charge and the margins we realize for our gathering,
treating, processing, storage and transportation services;
|
|
|
|
the price of natural gas;
|
|
|
|
the relationship between natural gas and NGL prices;
|
|
|
|
the weather in our operating areas;
|
|
|
|
the cost to us of the propane we buy for resale and the prices
we receive for our propane;
|
|
|
|
the level of competition from other midstream companies,
interstate pipeline companies, propane companies and other
energy providers;
|
|
|
|
the level of our operating costs;
|
|
|
|
prevailing economic conditions; and
|
|
|
|
the level of our hedging activities.
|
In addition, the actual amount of cash we will have available
for distribution will also depend on other factors, such as:
|
|
|
|
|
the level of capital expenditures we make;
|
|
|
|
the level of costs related to litigation and regulatory
compliance matters;
|
|
|
|
the cost of acquisitions, if any;
|
|
|
|
the levels of any margin calls that result from changes in
commodity prices;
|
|
|
|
our debt service requirements;
|
|
|
|
fluctuations in our working capital needs;
|
|
|
|
our ability to make working capital borrowings under our credit
facilities to make distributions;
|
|
|
|
our ability to access capital markets;
|
|
|
|
restrictions on distributions contained in our debt
agreements; and
|
4
|
|
|
|
|
the amount, if any, of cash reserves established by the general
partner in its discretion for the proper conduct of our business.
|
Because of all these factors, we cannot guarantee that we will
have sufficient available cash to pay a specific level of cash
distributions to our unitholders.
Furthermore, you should be aware that the amount of cash we have
available for distribution depends primarily upon our cash flow,
including cash flow from financial reserves and working capital
borrowings, and is not solely a function of profitability, which
will be affected by non-cash items. As a result, we may make
cash distributions during periods when we record net losses and
may not make cash distributions during periods when we record
net income.
We may
sell additional limited partner interests, diluting existing
interests of unitholders.
Our partnership agreement allows us to issue an unlimited number
of additional limited partner interests, including securities
senior to the common units, without the approval of the
unitholders. The issuance of additional common units or other
equity securities will have the following effects:
|
|
|
|
|
the current proportionate ownership interest of our unitholders
in us will decrease;
|
|
|
|
the amount of cash available for distribution on each common
unit or partnership security may decrease;
|
|
|
|
the relative voting strength of each previously outstanding
common unit may be diminished; and
|
|
|
|
the market price of the common units or partnership securities
may decline.
|
Future
sales of our units or other limited partner interests in the
trading market could reduce the market price of
unitholders limited partner interests.
As of March 31, 2009, ETE owned 62,500,797 common units.
ETE owns our general partner. If ETE were to sell
and/or
distribute its common units to the holders of its equity
interests in the future, those holders may dispose of some or
all of these units. The sale or disposition of a substantial
portion of these units in the public markets could reduce the
market price of our outstanding common units.
Our
debt level and debt agreements may limit our ability to make
distributions to unitholders and our future financial and
operating flexibility.
As of March 31, 2009, we had approximately
$5.63 billion of consolidated debt outstanding. Our level
of indebtedness affects our operations in several ways,
including, among other things:
|
|
|
|
|
a significant portion of our cash flow from operations will be
dedicated to the payment of principal and interest on
outstanding debt and will not be available for other purposes,
including payment of distributions;
|
|
|
|
covenants contained in our existing debt arrangements require us
to meet financial tests that may adversely affect our
flexibility in planning for and reacting to changes in our
business;
|
|
|
|
our ability to obtain additional financing for working capital,
capital expenditures, acquisitions and general partnership
purposes may be limited;
|
|
|
|
we may be at a competitive disadvantage relative to similar
companies that have less debt;
|
|
|
|
we may be more vulnerable to adverse economic and industry
conditions as a result of our significant debt level; and
|
|
|
|
failure to comply with the various restrictive and affirmative
covenants of the credit agreements could negatively impact our
ability and the ability of our subsidiaries to incur additional
debt and our ability to pay our distributions. We are required
to measure these financial tests and covenants quarterly and,
|
5
|
|
|
|
|
as of March 31, 2009, we were in compliance with all
financial requirements, tests, limitations, and covenants
related to financial ratios under our existing credit agreements.
|
Completion
of pipeline expansion projects will require significant amounts
of debt and equity financing which may not be available to us on
acceptable terms, or at all.
We plan to fund our expansion capital expenditures, including
any future pipeline expansion projects we may undertake, with
proceeds from sales of our debt and equity securities and
borrowings under our revolving credit facility; however, we
cannot be certain that we will be able to issue our debt and
equity securities on terms satisfactory to us, or at all. In
addition, we may be unable to obtain adequate funding under our
current revolving credit facility because our lending
counterparties may be unwilling or unable to meet their funding
obligations. If we are unable to finance our expansion projects
as expected, we could be required to seek alternative financing,
the terms of which may not be attractive to us, or to revise or
cancel our expansion plans.
As of March 31, 2009, we had approximately $5.63 billion of
consolidated debt outstanding. A significant increase in our
indebtedness that is proportionately greater than our issuances
of equity could negatively impact our credit ratings or our
ability to remain in compliance with the financial covenants
under our revolving credit agreement, which could have a
material adverse effect on our financial condition, results of
operations and cash flows.
Increases
in interest rates could materially adversely affect our
business, results of operations, cash flows and financial
condition.
In addition to our exposure to commodity prices, we have
significant exposure to increases in interest rates. As of
March 31, 2009, we had approximately $5.63 billion of
consolidated debt, of which approximately $4.75 billion was
at fixed interest rates and approximately $882.0 million
was at variable interest rates. We manage a portion of our
interest rate exposures by utilizing interest rate swaps and
similar arrangements. To the extent that we have debt with
variable interest rates that is not hedged, our results of
operations, cash flows and financial condition, could be
materially adversely affected by significant increases in
interest rates. As of March 31, 2009, we had outstanding
forward starting interest rate swaps with a notional amount of
$500.0 million for a forecasted debt issuance by the end of
2009. These swaps were not designated as cash flow hedges;
therefore, changes in interest rates could adversely affect our
results of operations until the forecasted debt is issued and
could require a cash payment upon settlement. As of
March 31, 2009, we also had outstanding forward starting
interest rate swaps with notional amounts totaling
$250.0 million, all of which have subsequently been
terminated for an insignificant amount.
An increase in interest rates may also cause a corresponding
decline in demand for equity investments, in general, and in
particular for yield-based equity investments such as our common
units. Any such reduction in demand for our common units
resulting from other more attractive investment opportunities
may cause the trading price of our common units to decline.
The
credit and risk profile of our general partner and its owners
could adversely affect our credit ratings and
profile.
The credit and business risk profiles of our general partner,
and of ETE as the indirect owner of our general partner, may be
factors in credit evaluations of us as a master limited
partnership due to the significant influence of our general
partner and its indirect owner over our business activities,
including our cash distribution 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.
ETE has significant indebtedness outstanding and is dependent
principally on the cash distributions from its general and
limited partner equity interests in us to service such
indebtedness. Any distributions by us to ETE will be made only
after satisfying our then current obligations to our creditors.
Although we have taken certain steps in our organizational
structure, financial reporting and contractual relationships to
reflect the
6
separateness of us, ETP GP and ETP LLC from the entities that
control ETP GP, ETE and its general partner, our credit ratings
and business risk profile could be adversely affected if the
ratings and risk profiles of such entities were viewed as
substantially lower or more risky than ours.
The
general partner is not elected by the unitholders and cannot be
removed without its consent.
Unlike the holders of common stock in a corporation, unitholders
have only limited voting rights on matters affecting our
business, and therefore limited ability to influence
managements decisions regarding our business. Unitholders
did not elect our general partner and will have no right to
elect our general partner on an annual or other continuing
basis. Although our general partner has a fiduciary duty to
manage us in a manner beneficial to us and our unitholders, the
directors of our general partner and its general partner, have a
fiduciary duty to manage the general partner and its general
partner in a manner beneficial to the owners of those entities.
Furthermore, if the unitholders are dissatisfied with the
performance of our general partner, they will have little
ability to remove our general partner. The general partner
generally may not be removed except upon the vote of the holders
of
662/3%
of the outstanding units voting together as a single class,
including units owned by the general partner and its affiliates.
Subsequent to our sale of common units in April 2009, ETE and
its affiliates held approximately 37% of our outstanding units,
with an approximately 1% of units held by our officers and
directors. Consequently, it could be difficult to remove the
general partner without the consent of the general partner and
our affiliates.
Furthermore, unitholders voting rights are further
restricted by the partnership agreement provision providing that
any units held by a person that owns 20% or more of any class of
units then outstanding, other than the general partner and its
affiliates, cannot be voted on any matter.
The
control of our general partner may be transferred to a third
party without unitholder consent.
The 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 the partnership
agreement on the ability of the general partner of our general
partner from transferring its general partner interest in our
general partner to a third party. Any new owner of the general
partner would be in a position to replace the officers of the
general partner with its own choices and to control the
decisions taken by such officers.
Unitholders
may be required to sell their units to the general partner at an
undesirable time or price.
If at any time less than 20% of the outstanding units of any
class are held by persons other than the general partner and its
affiliates, the general partner will have the right to acquire
all, but not less than all, of those units at a price no less
than their then-current market price. As a consequence, a
unitholder may be required to sell his common units at an
undesirable time or price. The general partner may assign this
purchase right to any of its affiliates or to us.
The
interruption of distributions to us from our operating
subsidiaries and equity investees may affect our ability to
satisfy our obligations and to make distributions to our
partners.
We are a holding company with no business operations. Our only
significant assets are the equity interests we own in our
operating subsidiaries and equity investees. As a result, we
depend upon the earnings and cash flow of our operating
subsidiaries and equity investees and the distribution of that
cash to us in order to meet our obligations and to allow us to
make distributions to our partners.
Cost
reimbursements due our general partner may be substantial and
reduce our ability to pay the distributions to
unitholders.
Prior to making any distributions to unitholders, we will
reimburse our general partner for all expenses it has incurred
on our behalf. In addition, our general partner and its
affiliates may provide us with services for
7
which we will be charged reasonable fees as determined by the
general partner. The reimbursement of these expenses and the
payment of these fees could adversely affect our ability to make
distributions to the unitholders. Our general partner has sole
discretion to determine the amount of these expenses and fees.
Unitholders
may have liability to repay distributions.
Under certain circumstances unitholders may have to repay us
amounts wrongfully distributed to them. Under Delaware law, we
may not make a distribution to unitholders if the distribution
causes our liabilities to exceed the fair value of our assets.
Liabilities to partners on account of their partnership
interests and
non-recourse
liabilities are not counted for purposes of determining whether
a distribution is permitted. Delaware law provides that a
limited partner who receives such a distribution and knew at the
time of the distribution that the distribution violated Delaware
law will be liable to the limited partnership for the
distribution amount for three years from the distribution date.
Under Delaware law, an assignee who becomes a substituted
limited partner of a limited partnership is liable for the
obligations of the assignor to make contributions to the
partnership. However, such an assignee is not obligated for
liabilities unknown to him at the time he or she became a
limited partner if the liabilities could not be determined from
the partnership agreement.
Risks
Related to Conflicts of Interest
Our
partnership agreement limits our general partners
fiduciary duties to our 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 waive or
consent to conduct by our general partner and its affiliates and
which reduce the obligations to which our general partner would
otherwise be held by state-law fiduciary duty standards. The
following is a summary of the material restrictions contained in
our partnership agreement on the fiduciary duties owed by our
general partner to the limited partners. Our partnership
agreement:
|
|
|
|
|
permits our general partner to make a number of decisions in its
sole discretion. 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;
|
|
|
|
provides that our general partner is entitled to make other
decisions in its reasonable discretion;
|
|
|
|
generally provides that affiliated transactions and resolutions
of conflicts of interest not involving a required vote of
unitholders must be fair and reasonable to us and
that, in determining whether a transaction or resolution is
fair and reasonable, our general partner may
consider the interests of all parties involved, including its
own. Unless our general partner has acted in bad faith, the
action taken by our general partner shall not constitute a
breach of its fiduciary duty; and
|
|
|
|
provides that our general partner and its officers and directors
will not be liable for monetary damages to us, our limited
partners or assignees for errors of judgment or for any acts or
omissions if our general partner and those other persons acted
in good faith.
|
In order to become a limited partner of our partnership, a
common unitholder is required to agree to be bound by the
provisions in the partnership agreement, including the
provisions discussed above.
Some
of our executive officers and directors face potential conflicts
of interest in managing our business.
Certain of our executive officers and directors are also
officers
and/or
directors of ETE. 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 us and ETE. 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.
8
The
general partners absolute discretion in determining the
level of cash reserves may adversely affect our ability to make
cash distributions to our unitholders.
Our partnership agreement requires the general partner to deduct
from operating surplus cash reserves that in its reasonable
discretion are necessary to fund our future operating
expenditures. In addition, the partnership agreement permits the
general partner to reduce available cash by establishing cash
reserves for the proper conduct of our business, to comply with
applicable law or agreements to which we are a party or to
provide funds for future distributions to partners. These cash
reserves will affect the amount of cash available for
distribution to unitholders.
Our
general partner has conflicts of interest and limited fiduciary
responsibilities, which may permit our general partner to favor
its own interests to the detriment of unitholders.
Subsequent to our sale of common units in April 2009, ETE and
its affiliates directly and indirectly owned an aggregate
limited partner interest in us of approximately 37% and our
officers and directors owned approximately 1% of the limited
partner interests in us. Conflicts of interest could arise in
the future as a result of relationships between our general
partner and its affiliates, on the one hand, and us, on the
other hand. As a result of these conflicts our general partner
may favor its own interests and those of its affiliates over the
interests of the unitholders. The nature of these conflicts
includes the following considerations:
|
|
|
|
|
Remedies available to unitholders for actions that might,
without the limitations, constitute breaches of fiduciary duty.
Unitholders are deemed to have consented to some actions and
conflicts of interest that might otherwise be deemed a breach of
fiduciary or other duties under applicable state law.
|
|
|
|
Our general partner is allowed to take into account the
interests of parties in addition to us in resolving conflicts of
interest, thereby limiting its fiduciary duties to the
unitholders.
|
|
|
|
Our general partners affiliates are not prohibited from
engaging in other businesses or activities, including those in
direct competition with us.
|
|
|
|
Our general partner determines the amount and timing of our
asset purchases and sales, capital expenditures, borrowings and
reserves, each of which can affect the amount of cash that is
distributed to unitholders.
|
|
|
|
Our general partner determines whether to issue additional units
or other equity securities of us.
|
|
|
|
Our general partner determines which costs are reimbursable by
us.
|
|
|
|
Our general partner controls the enforcement of obligations owed
to us by it.
|
|
|
|
Our general partner decides whether to retain separate counsel,
accountants or others to perform services for us.
|
|
|
|
Our general partner is not restricted 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.
|
|
|
|
In some instances our general partner may borrow funds in order
to permit the payment of distributions, even if the purpose or
effect of the borrowing is to make incentive distributions.
|
The
risk of competition with affiliates of our general partner has
increased.
Except as provided in our partnership agreement, affiliates of
our general partner are not prohibited from engaging in other
businesses or activities, including those that might be in
direct competition with us. Enterprise GP Holdings, L.P.
currently has an approximately 41% non-controlling equity
interest in LE GP, LLC, ETEs general partner. Enterprise
GP Holdings, L.P. and its subsidiaries own and operate a North
American midstream energy business that competes with us with
respect to our natural gas midstream business.
9
Risks
Related to our Business
We may
not be able to obtain funding on acceptable terms or at all
under our revolving credit facility or otherwise because of the
deterioration of the credit and capital markets. This may hinder
or prevent us from meeting our future capital
needs.
Global financial markets and economic conditions have been, and
continue to be, disrupted and volatile due to a variety of
factors, including significant write-offs in the financial
services sector and the current weak economic conditions. As a
result, the cost of raising money in the debt and equity capital
markets has increased substantially while the availability of
funds from those markets has diminished significantly. In
particular, as a result of concerns about the stability of
financial markets generally and the solvency of lending
counterparties specifically, the cost of obtaining money from
the credit markets generally has increased as many lenders and
institutional investors have increased interest rates, enacted
tighter lending standards, refused to refinance existing debt on
similar terms or at all and reduced, or in some cases ceased, to
provide funding to borrowers. In addition, lending
counterparties under existing revolving credit facilities and
other debt instruments may be unwilling or unable to meet their
funding obligations. Due to these factors, we cannot be certain
that new debt or equity financing will be available on
acceptable terms. If funding is not available when needed, or is
available only on unfavorable terms, we may be unable to meet
our obligations as they come due or we may be required to post
collateral to support our obligations. Moreover, without
adequate funding, we may be unable to execute our growth
strategy, complete future acquisitions or announced and future
pipeline construction projects, take advantage of other business
opportunities or respond to competitive pressures, any of which
could have a material adverse effect on our revenues and results
of operations.
Many
of our customers drilling activity levels and spending for
transportation on our pipeline system may be impacted by the
current deterioration in commodity prices and the credit
markets.
Many of our customers finance their drilling activities through
cash flow from operations, the incurrence of debt or the
issuance of equity. Recently, there has been a significant
decline in the credit markets and the availability of credit.
Additionally, many of our customers equity values have
substantially declined. The combination of a reduction of cash
flow resulting from recent declines in natural gas prices, a
reduction in borrowing base under reserve-based credit
facilities and the lack of availability of debt or equity
financing may result in a significant reduction in our
customers spending for natural gas drilling activity,
which could result in lower volumes being transported on our
pipeline systems. For example, a number of our customers have
announced reduced drilling capital expenditure budgets for 2009.
A significant reduction in drilling activity could have a
material adverse effect on our operations.
We are
exposed to the credit risk of our customers, and an increase in
the nonpayment and nonperformance by our customers could reduce
our ability to make distributions to our
unitholders.
The risks of nonpayment and nonperformance by our customers are
a major concern in our business. Participants in the energy
industry have been subjected to heightened scrutiny from the
financial markets in light of past collapses and failures of
other energy companies. We are subject to risks of loss
resulting from nonpayment or nonperformance by our customers.
The current tightening of credit in the financial markets may
make it more difficult for customers to obtain financing and,
depending on the degree to which this occurs, there may be a
material increase in the nonpayment and nonperformance by our
customers. Any substantial increase in the nonpayment and
nonperformance by our customers could have a material effect on
our results of operations and operating cash flows.
The
FERC is pursuing legal action against us relating to certain
natural gas trading activities, and related third party actions
have been filed against us and ETE.
On July 26, 2007, the FERC issued to us an Order to Show
Cause and Notice of Proposed Penalties (the Order and
Notice) that contains allegations that we violated FERC
rules and regulations. The FERC alleged that we engaged in
manipulative or improper trading activities in the Houston Ship
Channel, primarily on two dates during the fall of 2005
following the occurrence of Hurricanes Katrina and Rita, as well
as on eight
10
other occasions from December 2003 through August 2005, in order
to benefit financially from our commodities derivatives
positions and from certain of our index-priced physical gas
purchases in the Houston Ship Channel. The FERC alleged that
during these periods we violated the FERCs then-effective
Market Behavior Rule 2, an anti-market manipulation rule
promulgated by the FERC under authority of the Natural Gas Act
(NGA). We allegedly violated this rule by
artificially suppressing prices that were included in the Platts
Inside FERC Houston Ship Channel index, published by
McGraw-Hill Companies, on which the pricing of many physical
natural gas contracts and financial derivatives are based.
Additionally, the FERC alleged that we manipulated daily prices
at the Waha and Permian Hubs in west Texas on two dates. Our
Oasis pipeline transports interstate natural gas pursuant to
Natural Gas Policy Act (NGPA) Section 311
authority and is subject to the FERC-approved rates, terms and
conditions of service. The Order and Notice alleged that the
Oasis pipeline violated NGPA regulations from January 26,
2004 through June 30, 2006 by granting undue preference to
its affiliates for interstate NGPA Section 311 pipeline
service to the detriment of similarly situated non-affiliated
shippers and by charging in excess of the FERC-approved maximum
lawful rate for interstate NGPA Section 311 transportation.
The FERC also seeks to revoke, for a period of 12 months,
our blanket marketing authority for sales of natural gas in
interstate commerce at market-based prices, which activity is
expected to account for approximately 1.0% of our operating
income for our 2008 year. If the FERC is successful in
revoking our blanket marketing authority, our sales of natural
gas at market-based prices would be limited to sales to retail
customers (such as utilities and other end-users) and sales from
our own production, and any other sales of natural gas by us
would be required to be made at contract prices that would be
subject to individual FERC approval.
In its Order and Notice, the FERC specified that it was seeking
$70.1 million in disgorgement of profits, plus interest,
and $97.5 million in civil penalties relating to these
matters. The FERC has taken the position that, once it receives
our response, it has several options as to how to proceed,
including issuing an order on the merits, requesting briefs, or
setting specified issues for a trial-type hearing before an
administrative law judge. On August 27, 2007, ETP filed a
request for rehearing of the Order and Notice. On
December 20, 2007, the FERC issued an order denying
rehearing and directed the FERC Enforcement Staff to file a
brief recommending disposition of issues by order or by
evidentiary hearing. ETP filed its response to the Order and
Notice with the FERC on October 9, 2007, which response
refuted the FERCs claims and requested a dismissal of the
FERC proceeding. On February 14, 2008, the Enforcement
Staff of the FERC filed a brief recommending that the FERC refer
various matters relating to its market manipulation allegations
for an evidentiary hearing before a FERC administrative law
judge. The Enforcement Staff also recommended that the FERC
issue an order assessing the $15.5 million portion of the
above-referenced penalty against ETP with respect to the
allegations related to ETPs Oasis pipeline and that the
Oasis-related penalty assessment, if not paid, then be referred
by the FERC to a federal district court for de novo
review. The Enforcement Staff also recommended that the FERC
impose certain changes in Oasiss business operations and
refunds to certain Oasis customers as previously proposed in the
Order and Notice. Finally, the Enforcement Staff recommended
that the FERC pursue market manipulation claims related to
ETPs trading activities in October 2005, for November
2005 monthly deliveries, a period not previously covered by
FERCs allegations in the Order and Notice, and that ETP be
assessed an additional civil penalty of $25.0 million and
be required to disgorge approximately $7.3 million of
alleged unjust profits related to this additional month. On
March 31, 2008, we responded to the Enforcement
Staffs brief. On May 15, 2008, the FERC ordered
hearings to be conducted by FERC administrative law judges with
respect to the FERCs Oasis claims and market manipulation
claims. In this order, the FERC set for hearing the Enforcement
Staffs claims for the additional month in 2005, bringing
the total amount of civil penalties and disgorgement of profits
sought by the FERC to approximately $200 million, excluding
interest. The hearing related to the Oasis claims was scheduled
to commence in December 2008 with the administrative law
judges initial decisions due by May 11, 2009,
however, as discussed below, we entered into a settlement
agreement with FERC Enforcement Staff and that agreement was
approved by the FERC in its entirety and without modification on
February 27, 2009. The hearing related to the market
manipulation claims is now scheduled to commence in July 2009
with the administrative law judges initial decision due by
January 7, 2010. The FERC also ordered that, following the
completion of the hearings, the administrative law judges make
initial findings with respect to whether we engaged in market
manipulation in violation of the NGA and FERC regulations and
whether Oasis violated the NGPA and FERC
11
regulations. The FERC reserved for itself the issues of possible
civil penalties, revocation of our blanket market certificate,
the method by which we and Oasis would disgorge any unjust
profits and whether any conditions should be placed on
Oasiss Section 311 authorization. Following the
issuance of each of the administrative law judges initial
decisions, the FERC would then issue an order with respect to
each of these matters. On May 23, 2008, we requested
rehearing and stay of the FERCs May 15, 2008 order
establishing hearing, and we renewed those requests on
June 26, 2008. On August 7, 2008, FERC denied
rehearing of its May 15, 2008 order. On August 8,
2008, we filed a petition with the U.S. Court of Appeals
for the Fifth Circuit to review and set aside FERCs May 15
and August 7, 2008 orders on the grounds that we are
entitled to adjudicate FERCs claims in federal district
court pursuant to the NGA and the NGPA. On August 28, 2008,
we filed an amended petition seeking review of the Order and
Notice and the December 20, 2007 order denying rehearing.
The Fifth Circuit dismissed our petition without reaching the
merits on April 28, 2009. On June 12, 2009, we sought
rehearing and rehearing en banc of the Courts
April 28, 2009 order.
On November 18, 2008, the administrative law judge
presiding over the Oasis claims granted our motion for summary
disposition of the claim that Oasis unduly discriminated in
favor of affiliates regarding the provision of
Section 311(a)(2) interstate transportation service. We
subsequently entered into an agreement with the Enforcement
Staff to settle all of the claims related to Oasis. On
January 5, 2009, this agreement was submitted under seal to
FERC by the presiding administrative law judge, for FERCs
approval as an uncontested settlement of all Oasis claims. On
February 27, 2009, the settlement agreement was approved by
the FERC in its entirety and without modification and the terms
of the settlement were made public. The FERCs order is now
final and non-appealable. We do not believe the Oasis
settlement, as approved by the FERC, will have a material
adverse effect on our business, financial condition or results
of operations.
It is our position that our trading and transportation
activities during the periods at issue complied in all material
aspects with applicable law and regulations, and we intend to
contest these cases vigorously. However, the laws and
regulations related to alleged market manipulation are vague,
subject to broad interpretation, and offer little guiding
precedent, while at the same time the FERC holds substantial
enforcement authority. At this time, we are unable to predict
the final outcome of these matters.
On July 26, 2007, the United States Commodity Futures
Trading Commission (the CFTC) filed suit in United
States District Court for the Northern District of Texas
alleging that we violated provisions of the Commodity Exchange
Act (CEA) by attempting to manipulate natural gas
prices in the Houston Ship Channel. On March 17, 2008, we
entered into a consent order with the CFTC (the Consent
Order). Pursuant to the Consent Order, we agreed to pay
the CFTC $10.0 million and the CFTC agreed to release us
and our affiliates, directors and employees from all claims or
causes of action asserted by the CFTC in this proceeding. The
Consent Order provides that we are permanently enjoined from
attempting to manipulate the price of any commodity in
interstate commerce in violation of the CEA. By consenting to
the entry of the Consent Order, we neither admitted nor denied
the allegations made by the CFTC in this proceeding. The
settlement reduced our existing accrual and was paid from cash
flow from operations in March 2008.
In addition to the FERC legal action, third parties have
asserted claims and may assert additional claims against us
alleging ETE for damages related to these matters. In this
regard, several natural gas producers and a natural gas
marketing company have initiated legal proceedings in Texas
state courts against us and ETE for claims related to the FERC
claims. These suits contain contract and tort claims relating to
alleged manipulation of natural gas prices at the Houston Ship
Channel and the Waha Hub in West Texas, as well as the natural
gas price indices related to these markets and the Permian Basin
natural gas price index during the period from December 2003
through December 2006, and seek unspecified direct, indirect,
consequential and exemplary damages. One of the suits against us
and ETE contains an additional allegation that we and ETE
transported gas in a manner that favored our affiliates and
discriminated against the plaintiff, and otherwise artificially
affected the market price of gas to other parties in the market.
We have moved to compel arbitration
and/or
contested subject-matter jurisdiction in some of these cases.
One such case currently is on appeal before the Texas Supreme
Court on, among other things, the issue of whether the dispute
is arbitrable.
We have also been served with a complaint from an owner of
royalty interests in natural gas producing properties,
individually and on behalf of a putative class of similarly
situated royalty owners, working interest
12
owners and producer/operators, seeking arbitration to recover
damages based on alleged manipulation of natural gas prices at
the Houston Ship Channel. We filed an original action in Harris
County state court seeking a stay of the arbitration on the
ground that the action is not arbitrable, and the state court
granted our motion for summary judgment on that issue. This
action is currently on appeal before the First Court of Appeals,
Houston.
A consolidated class action complaint has been filed against us
in the United States District Court for the Southern District of
Texas. This action alleges that we engaged in intentional and
unlawful manipulation of the price of natural gas futures and
options contracts on the New York Mercantile Exchange, or NYMEX,
in violation of the CEA. It is further alleged that during the
class period December 29, 2003 to December 31, 2005,
we had the market power to manipulate index prices, and that we
used this market power to artificially depress the index prices
at major natural gas trading hubs, including the Houston Ship
Channel, in order to benefit our natural gas physical and
financial trading positions, and that we intentionally submitted
price and volume trade information to trade publications. This
complaint also alleges that we violated the CEA by knowingly
aiding and abetting violations of the CEA. The plaintiffs state
that this allegedly unlawful depression of index prices by us
manipulated the NYMEX prices for natural gas futures and options
contracts to artificial levels during the class period, causing
unspecified damages to the plaintiffs and all other members of
the putative class who sold natural gas futures or who purchased
and/or sold
natural gas options contracts on NYMEX during the class period.
The plaintiffs have requested certification of their suit as a
class action and seek unspecified damages, court costs and other
appropriate relief. On January 14, 2008, we filed a motion
to dismiss this suit on the grounds of failure to allege facts
sufficient to state a claim. On March 20, 2008, the
plaintiffs filed a second consolidated class action complaint.
In response to this new pleading, on May 5, 2008, we filed
a motion to dismiss the complaint. On March 26, 2009, the
court issued an order dismissing the complaint, with prejudice,
for failure to state a claim. The plaintiffs have since moved
for reconsideration, and briefing on that motion is now complete.
On March 17, 2008, a second class action complaint was
filed against us in the United States District Court for the
Southern District of Texas. This action alleges that we engaged
in unlawful restraint of trade and intentional monopolization
and attempted monopolization of the market for fixed-price
natural gas baseload transactions at the Houston Ship Channel
from December 2003 through December 2005 in violation of federal
antitrust law. The complaint further alleges that during this
period we exerted monopoly power to suppress the price for these
transactions to non-competitive levels in order to benefit our
own physical natural gas positions. The plaintiff has,
individually and on behalf of all other similarly situated
sellers of physical natural gas, requested certification of its
suit as a class action and seeks unspecified treble damages,
court costs and other appropriate relief. On May 19, 2008,
we filed a motion to dismiss this complaint. On March 26,
2009, the court issued an order dismissing the complaint. The
court found that the plaintiffs failed to state a claim on all
causes of action and for anti-trust injury, but granted leave to
amend. On April 23, 2009, the plaintiffs filed a motion for
leave to amend to assert a claim for common law fraud, and
attached a proposed amended complaint as an exhibit. We have
opposed the motion and cross-moved to dismiss.
We are expensing the legal fees, consultants fees and
other expenses relating to these matters in the periods in which
such expenses are incurred. In addition, our existing accruals
for litigation and contingencies include an accrual related to
these matters. At this time, we are unable to predict the
outcome of these matters. However, it is possible that the
amount we become obliged to pay as a result of the final
resolution of these matters, whether on a negotiated settlement
basis or otherwise, will exceed the amount of our existing
accrual related to these matters. In accordance with applicable
accounting standards, we will review the amount of our accrual
related to these matters as developments related to these
matters occur and we will adjust our accrual if we determine
that it is probable that the amount we may ultimately become
obliged to pay as a result of the final resolution of these
matters is greater than the amount of our existing accrual for
these matters. As our accrual amounts are non-cash, any cash
payment of an amount in resolution of these matters would likely
be made from cash from operations or borrowings, which payments
would reduce our cash available to service our indebtedness
either directly or as a result of increased principal and
interest payments necessary to service any borrowings incurred
to finance such payments. If these payments are substantial, we
may experience a material adverse impact on our results of
operations and our liquidity.
13
The
profitability of our midstream and intrastate transportation and
storage operations are largely dependent upon natural gas
commodity prices, price spreads between two or more physical
locations and market demand for natural gas and NGLs, which are
factors beyond our control and have been volatile.
Income from our midstream and intrastate transportation and
storage operations is exposed to risks due to fluctuations in
commodity prices. For a portion of the natural gas gathered at
the North Texas System, Southeast Texas System and at the HPL
System, we purchase natural gas from producers at the wellhead
and then gather and deliver the natural gas to pipelines where
we typically resell the natural gas under various arrangements,
including sales at index prices. Generally, the gross margins we
realize under these arrangements decrease in periods of low
natural gas prices.
For a portion of the natural gas gathered and processed at the
North Texas System and Southeast Texas System, we enter into
percentage-of-proceeds arrangements, keep-whole arrangements,
and processing fee agreements pursuant to which we agree to
gather and process natural gas received from the producers.
Under percentage-of-proceeds arrangements, we generally sell the
residue gas and NGLs at market prices and remit to the producers
an agreed upon percentage of the proceeds based on an index
price. In other cases, instead of remitting cash payments to the
producer, we deliver an agreed upon percentage of the residue
gas and NGL volumes to the producer and sell the volumes we keep
to third parties at market prices. Under these arrangements our
revenues and gross margins decline when natural gas prices and
NGL prices decrease. Accordingly, a decrease in the price of
natural gas or NGLs could have an adverse effect on our results
of operations. Under keep-whole arrangements, we generally sell
the NGLs produced from our gathering and processing operations
to third parties at market prices. Because the extraction of the
NGLs from the natural gas during processing reduces the Btu
content of the natural gas, we must either purchase natural gas
at market prices for return to producers or make a cash payment
to producers equal to the value of this natural gas. Under these
arrangements, our revenues and gross margins decrease when the
price of natural gas increases relative to the price of NGLs if
we are not able to bypass our processing plants and sell the
unprocessed natural gas. Under processing fee agreements, we
process the gas for a fee. If recoveries are less than those
guaranteed the producer, we may suffer a loss by having to
supply liquids or its cash equivalent to keep the producer whole
with regard to contractual recoveries.
In the past, the prices of natural gas and NGLs have been
extremely volatile, and we expect this volatility to continue.
For example, during the year ended December 31, 2008, the
NYMEX settlement price for the prompt month contract ranged from
a high of $13.11 per MMBtu to a low of $6.47 per MMBtu. A
composite of the Mt. Belvieu average NGLs price based upon our
average NGLs composition during the year ended December 31,
2008 ranged from a high of approximately $1.96 per gallon to a
low of approximately $0.66 per gallon.
Our Oasis pipeline, East Texas pipeline, ET Fuel System and HPL
System receive fees for transporting natural gas for our
customers. Although a significant amount of the pipeline
capacity of the East Texas pipeline and various pipeline
segments of the ET Fuel and HPL Systems is committed under
long-term fee-based contracts, the remaining capacity of our
transportation pipelines is subject to fluctuation in demand
based on the markets and prices for natural gas and NGLs, which
factors may result in decisions by natural gas producers to
reduce production of natural gas during periods of lower prices
for natural gas and NGLs or may result in decisions by end users
of natural gas and NGLs to reduce consumption of these fuels
during periods of higher prices for these fuels. Our fuel
retention fees are also directly impacted by changes in natural
gas prices. Increases in natural gas prices tend to increase our
fuel retention fees, and decreases in natural gas prices tend to
decrease our fuel retention fees.
The markets and prices for natural gas and NGLs depend upon
factors beyond our control. These factors include demand for
oil, natural gas and NGLs, which fluctuate with changes in
market and economic conditions, and other factors, including:
|
|
|
|
|
the impact of weather on the demand for oil and natural gas;
|
|
|
|
the level of domestic oil and natural gas production;
|
|
|
|
the availability of imported oil and natural gas;
|
14
|
|
|
|
|
actions taken by foreign oil and gas producing nations;
|
|
|
|
the availability of local, intrastate and interstate
transportation systems;
|
|
|
|
the price, availability and marketing of competitive fuels;
|
|
|
|
the demand for electricity;
|
|
|
|
the impact of energy conservation efforts; and
|
|
|
|
the extent of governmental regulation and taxation.
|
The
use of derivative financial instruments could result in material
financial losses by us.
From time to time, we have sought to limit a portion of the
adverse effects resulting from changes in natural gas and other
commodity prices and interest rates by using derivative
financial instruments and other risk management mechanisms and
by our marketing and/or system optimization activities. To the
extent that we hedge our commodity price and interest rate
exposures, we forego the benefits we would otherwise experience
if commodity prices or interest rates were to change in our
favor. In addition, even though monitored by management, our
derivative activities can result in losses. Such losses could
occur under various circumstances, including if a counterparty
does not perform its obligations under the derivative
arrangement, the hedge is imperfect, commodity prices move
unfavorably related to our physical or financial positions, or
hedging policies and procedures are not followed.
Our
success depends upon our ability to continually contract for new
sources of natural gas supply.
In order to maintain or increase throughput levels on our
gathering and transportation pipeline systems and asset
utilization rates at our treating and processing plants, we must
continually contract for new natural gas supplies and natural
gas transportation services. We may not be able to obtain
additional contracts for natural gas supplies for our natural
gas gathering systems, and we may be unable to maintain or
increase the levels of natural gas throughput on our
transportation pipelines. The primary factors affecting our
ability to connect new supplies of natural gas to our gathering
systems include our success in contracting for existing natural
gas supplies that are not committed to other systems and the
level of drilling activity and production of natural gas near
our gathering systems or in areas that provide access to our
transportation pipelines or markets to which our systems
connect. The primary factors affecting our ability to attract
customers to our transportation pipelines consist of our access
to other natural gas pipelines, natural gas markets, natural
gas-fired power plants and other industrial end-users and the
level of drilling and production of natural gas in areas
connected to these pipelines and systems.
Fluctuations in energy prices can greatly affect production
rates and investments by third parties in the development of new
oil and natural gas reserves. Drilling activity and production
generally decrease as oil and natural gas prices decrease. We
have no control over the level of drilling activity in our areas
of operation, the amount of reserves underlying the wells and
the rate at which production from a well will decline, sometimes
referred to as the decline rate. In addition, we
have no control over producers or their production decisions,
which are affected by, among other things, prevailing and
projected energy prices, demand for hydrocarbons, the level of
reserves, geological considerations, governmental regulation and
the availability and cost of capital. Natural gas prices have
been high in recent years compared to historical periods, but
have decreased significantly during the fourth quarter of 2008
and thus far in 2009. This decline in natural gas prices coupled
with the effect of illiquid capital markets has led to a
decrease in drilling activity in some of our areas of operation.
A substantial portion of our assets, including our gathering
systems and our processing and treating plants, are connected to
natural gas reserves and wells for which the production will
naturally decline over time. Accordingly, our cash flows will
also decline unless we are able to access new supplies of
natural gas by connecting additional production to these systems.
Our transportation pipelines are also dependent upon natural gas
production in areas served by our pipelines or in areas served
by other gathering systems or transportation pipelines that
connect with our transportation pipelines. A material decrease
in natural gas production in our areas of operation or in other
areas that are connected to our areas of operation by third
party gathering systems or pipelines, as a result of depressed
commodity prices or otherwise,
15
would result in a decline in the volume of natural gas we
handle, which would reduce our revenues and operating income. In
addition, our future growth will depend, in part, upon whether
we can contract for additional supplies at a greater rate than
the rate of natural decline in our currently connected supplies.
Transwestern Pipeline Company LLC, or Transwestern, derives a
significant portion of its revenue from charging to its
customers for reservation of capacity, which charges
Transwestern receives regardless of whether these customers
actually use the reserved capacity. Transwestern also generates
revenue from transportation of natural gas for customers without
reserved capacity. As the reserves available through the supply
basins connected to Transwesterns systems naturally
decline, a decrease in development or production activity could
cause a decrease in the volume of natural gas available for
transmission or a decrease in demand for natural gas
transportation on the Transwestern system over the long run.
Investments by third parties in the development of new natural
gas reserves connected to Transwesterns facilities depend
on many factors beyond Transwesterns control.
The volumes of natural gas we transport on our intrastate
transportation pipelines may be reduced in the event that the
prices at which natural gas is purchased and sold at the Waha
Hub, the Katy Hub, the Carthage Hub and the Houston Ship Channel
Hub, the four major natural gas trading hubs served by our
pipelines, become unfavorable in relation to prices for natural
gas at other natural gas trading hubs or in other markets as
customers may elect to transport their natural gas to these
other hubs or markets using pipelines other than those we
operate.
We may
not be able to fully execute our growth strategy if we encounter
increased competition for qualified assets.
Our strategy contemplates growth through the development and
acquisition of a wide range of midstream, transportation,
storage, propane and other energy infrastructure assets while
maintaining a strong balance sheet. This strategy includes
constructing and acquiring additional assets and businesses to
enhance our ability to compete effectively and diversify our
asset portfolio, thereby providing more stable cash flow. We
regularly consider and enter into discussions regarding, and are
currently contemplating, the acquisition of additional assets
and businesses, stand alone development projects or other
transactions that we believe will present opportunities to
realize synergies and increase our cash flow.
Consistent with our acquisition strategy, we are continuously
engaged in discussions with potential sellers regarding the
possible acquisition of additional assets or businesses. Such
acquisition efforts may involve our participation in processes
that involve a number of potential buyers, commonly referred to
as auction processes, as well as situations in which
we believe we are the only party or one of a very limited number
of potential buyers in negotiations with the potential seller.
We cannot assure you that our current or future acquisition
efforts will be successful or that any such acquisition will be
completed on terms considered favorable to us.
In addition, we are experiencing increased competition for the
assets we purchase or contemplate purchasing. Increased
competition for a limited pool of assets could result in us
losing to other bidders more often or acquiring assets at higher
prices, both of which would limit our ability to fully execute
our growth strategy. Inability to execute our growth strategy
may materially adversely impact our results of operations.
An
impairment of goodwill and intangible assets could reduce our
earnings.
At March 31, 2009, our consolidated balance sheet reflected
$734.9 million of goodwill and $219.3 million of
intangible assets. Goodwill is recorded when the purchase price
of a business exceeds the fair market value of the tangible and
separately measurable intangible net assets. Accounting
principles generally accepted in the United States require us to
test goodwill for impairment on an annual basis or when events
or circumstances occur indicating that goodwill might be
impaired. Long-lived assets such as intangible assets with
finite useful lives are reviewed for impairment whenever events
or changes in circumstances indicate that the carrying amount
may not be recoverable. If we determine that any of our goodwill
or intangible assets were impaired, we would be required to take
an immediate charge to earnings with a correlative effect on
partners equity and balance sheet leverage as measured by
debt to total capitalization.
16
If we
do not make acquisitions on economically acceptable terms, our
future growth could be limited.
Our results of operations and our ability to grow and to
increase distributions to unitholders have depended principally
on our ability to make acquisitions that are accretive to our
distributable cash flow per unit.
We may be unable to make accretive acquisitions for any of the
following reasons, among others:
|
|
|
|
|
because we are unable to identify attractive acquisition
candidates or negotiate acceptable purchase contracts with them;
|
|
|
|
because we are unable to raise financing for such acquisitions
on economically acceptable terms; or
|
|
|
|
because we are outbid by competitors, some of which are
substantially larger than us and have greater financial
resources and lower costs of capital then we do.
|
Furthermore, even if we consummate acquisitions that we believe
will be accretive, those acquisitions may in fact adversely
affect our results of operations or result in a decrease in
distributable cash flow per unit. Any acquisition involves
potential risks, including the risk that we may:
|
|
|
|
|
fail to realize anticipated benefits, such as new customer
relationships, cost-savings or cash flow enhancements;
|
|
|
|
decrease our liquidity by using a significant portion of our
available cash or borrowing capacity to finance acquisitions;
|
|
|
|
significantly increase our interest expense or financial
leverage if we incur additional debt to finance acquisitions;
|
|
|
|
encounter difficulties operating in new geographic areas or new
lines of business;
|
|
|
|
incur or assume unanticipated liabilities, losses or costs
associated with the business or assets acquired for which we are
not indemnified or for which the indemnity is inadequate;
|
|
|
|
be unable to hire, train or retrain qualified personnel to
manage and operate our growing business and assets;
|
|
|
|
less effectively manage our historical assets, due to the
diversion of managements attention from other business
concerns; or
|
|
|
|
incur other significant charges, such as impairment of goodwill
or other intangible assets, asset devaluation or restructuring
charges.
|
If we consummate future acquisitions, our capitalization and
results of operations may change significantly. As we determine
the application of our funds and other resources, you will not
have an opportunity to evaluate the economics, financial and
other relevant information that we will consider.
If we
do not continue to construct new pipelines, our future growth
could be limited.
During the past several years, we have constructed several new
pipelines, and we are currently involved in constructing several
new pipelines. Our results of operations and our ability to grow
and to increase distributable cash flow per unit will depend, in
part, on our ability to construct pipelines that are accretive
to our distributable cash flow. We may be unable to construct
pipelines that are accretive to distributable cash flow for any
of the following reasons, among others:
|
|
|
|
|
We are unable to identify pipeline construction opportunities
with favorable projected financial returns;
|
|
|
|
We are unable to raise financing for our identified pipeline
construction opportunities; or
|
|
|
|
We are unable to secure sufficient natural gas transportation
commitments from potential customers due to competition from
other pipeline construction projects or for other reasons.
|
17
Furthermore, even if we construct a pipeline that we believe
will be accretive, the pipeline may in fact adversely affect our
results of operations or results from those projected prior to
commencement of construction and other factors.
Expanding
our business by constructing new pipelines and treating and
processing facilities subjects us to risks.
One of the ways that we have grown our business is through the
construction of additions to our existing gathering,
compression, treating, processing and transportation systems.
The construction of a new pipeline or the expansion of an
existing pipeline, by adding additional compression capabilities
or by adding a second pipeline along an existing pipeline, and
the construction of new processing or treating facilities,
involve numerous regulatory, environmental, political and legal
uncertainties beyond our control and require the expenditure of
significant amounts of capital that we will be required to
finance through borrowings, the issuance of additional equity or
from operating cash flow. If we undertake these projects, they
may not be completed on schedule or at all or at the budgeted
cost. We currently have several major expansion and new build
projects planned or underway, including the Texas Independence
pipeline, the Midcontinent Express pipeline joint venture, the
Fayetteville Express pipeline joint venture and the Tiger
pipeline. A variety of factors outside our control, such as
weather, natural disasters and difficulties in obtaining permits
and rights-of-way or other regulatory approvals, as well as the
performance by third party contractors has resulted in, and may
continue to result in, increased costs or delays in
construction. Cost overruns or delays in completing a project
could have a material adverse effect on our results of
operations and cash flows. Moreover, our revenues may not
increase immediately following the completion of particular
projects. For instance, if we build a new pipeline, the
construction will occur over an extended period of time, but we
may not materially increase our revenues until long after the
projects completion. In addition, the success of a
pipeline construction project will likely depend upon the level
of natural gas exploration and development drilling activity and
the demand for pipeline transportation in the areas proposed to
be serviced by the project as well as our ability to obtain
commitments from producers in this area to utilize the newly
constructed pipelines. In this regard, we may construct
facilities to capture anticipated future growth in production in
a region in which such growth does not materialize. As a result,
new facilities may be unable to attract enough throughput or
contracted capacity reservation commitments to achieve our
expected investment return, which could adversely affect our
results of operations and financial condition.
We
depend on certain key producers for our supply of natural gas on
the Southeast Texas System and North Texas System, and the loss
of any of these key producers could adversely affect our
financial results.
For the year ended December 31, 2008, ConocoPhillips
Company, XTO Energy Inc., Encana Oil and Gas (USA) Inc., and
Sandridge Energy Inc. supplied us with approximately 75% of the
Southeast Texas Systems natural gas supply. For the year
ended December 31, 2008, Encana Oil and Gas (USA), Inc.,
EOG Resources, Inc., XTO Energy Inc., and Chesapeake Energy
Marketing, Inc. supplied us with approximately 75% of the North
Texas Systems natural gas supply. We are not the only
option available to these producers for disposition of the
natural gas they produce. To the extent that these and other
producers may reduce the volumes of natural gas that they supply
us, we would be adversely affected unless we were able to
acquire comparable supplies of natural gas from other producers.
We
depend on key customers to transport natural gas through our
pipelines.
We have nine- and ten-year fee-based transportation contracts
with XTO Energy, Inc. (XTO) that terminate in 2013
and 2017, respectively, pursuant to which XTO has committed to
transport certain minimum volumes of natural gas on pipelines in
our ET Fuel System. We also have an eight-year fee-based
transportation contract with TXU Portfolio Management Company,
L.P., a subsidiary of TXU Corp. (TXU Shipper)
to transport natural gas on the ET Fuel System to TXUs
electric generating power plants. We have also entered into two
eight-year natural gas storage contracts that terminate in 2012
with TXU Shipper to store natural gas at the two natural gas
storage facilities that are part of the ET Fuel System. Each of
the contracts with TXU Shipper may be extended by TXU Shipper
for two additional five-year terms. The
18
failure of XTO Energy or TXU Shipper to fulfill their
contractual obligations under these contracts could have a
material adverse effect on our cash flow and results of
operations if we were not able to replace these customers under
arrangements that provide similar economic benefits as these
existing contracts.
The major shippers on our intrastate transportation pipelines
include XTO, EOG Resources, Inc., Chesapeake Energy Marketing,
Inc., EnCana Marketing (USA), Inc. and Quicksilver Resources,
Inc. These shippers have long-term contracts that have remaining
terms ranging from three to fifteen years. The failure of these
shippers to fulfill their contractual obligations could have a
material adverse effect on our cash flow and results of
operations if we were not able to replace these customers under
arrangements that provide similar economic benefits as these
existing contracts.
With respect to our interstate transportation operations, MEP,
the joint venture entity formed to construct and operate the
Midcontinent Express pipeline, has secured predominantly
10-year firm
transportation contracts from a small number of major shippers
for all of the initial 1.5 Bcf/d of capacity on the
Midcontinent Express pipeline. MEP has also secured firm
transportation commitments for an additional 0.3 Bcf/d of
capacity on the Midcontinent Express pipeline, which expansion
is subject to regulatory approval. FEP, the joint venture entity
formed to construct and operate the Fayetteville Express
pipeline, has secured a binding
10-year
commitment for approximately 1.85 Bcf/d of firm
transportation service on the 2.0 Bcf/d Fayetteville
Express pipeline project. In connection with our Tiger pipeline
project, we have entered into an agreement with Chesapeake
Energy Marketing, Inc. that provides for a
15-year
commitment for firm transportation capacity of approximately
1.0 Bcf/d.
We have also entered into agreements with EnCana Marketing
(USA), Inc. and another shipper that provide for 10-year
commitments for firm transportation capacity on the Tiger
pipeline of not less than 0.5 Bcf/d. The failure of these
key shippers to fulfill their contractual obligations could have
a material adverse effect on our cash flow and results of
operations if we were not able to replace these customers under
arrangements that provide similar economic benefits as these
existing contracts.
Federal,
state or local regulatory measures could adversely affect the
business and operations of our midstream and intrastate
assets.
Our midstream and intrastate transportation and storage
operations are generally exempt from FERC regulation under the
NGA, but FERC regulation still significantly affects our
business and the market for our products. The rates, terms and
conditions of some of the transportation and storage services we
provide on the HPL System, the East Texas pipeline, the Oasis
pipeline and the ET Fuel System are subject to FERC regulation
under Section 311 of the Natural Gas Policy Act, or NGPA.
Under Section 311, rates charged for transportation and
storage must be fair and equitable amounts. Amounts collected in
excess of fair and equitable rates are subject to refund with
interest, and the terms and conditions of service, set forth in
the pipelines statement of operating conditions, are
subject to FERC review and approval. Should FERC determine not
to authorize rates equal to or greater than our currently
approved rates, we may suffer a loss of revenue. Failure to
observe the service limitations applicable to storage and
transportation service under Section 311, and failure to
comply with the rates approved by FERC for Section 311
service, and failure to comply with the terms and conditions of
service established in the pipelines FERC-approved
statement of operating conditions could result in an alteration
of jurisdictional status
and/or the
imposition of administrative, civil and criminal penalties.
Our intrastate transportation and storage operations are subject
to state regulation in Texas, New Mexico, Arizona, Louisiana,
Utah and Colorado, the states in which we operate these types of
natural gas facilities. Our intrastate transportation operations
located in Texas are subject to regulation as common purchasers
and as gas utilities by the Texas Railroad Commission, or TRRC.
The TRRCs jurisdiction extends to both rates and pipeline
safety. The rates we charge for transportation and storage
services are deemed just and reasonable under Texas law unless
challenged in a complaint. Should a complaint be filed or should
regulation become more active, our business may be adversely
affected.
Our midstream and intrastate transportation operations are also
subject to ratable take and common purchaser statutes in Texas,
New Mexico, Arizona, Louisiana, Utah and Colorado. Ratable take
statutes generally require gatherers to take, without undue
discrimination, natural gas production that may be tendered to
the gatherer for handling. Similarly, common purchaser statutes
generally require gatherers to purchase without undue
discrimination as to source of supply or producer. These
statutes have the effect of restricting
19
our right as an owner of gathering facilities to decide with
whom we contract to purchase or transport natural gas. Federal
law leaves any economic regulation of natural gas gathering to
the states, and some of the states in which we operate have
adopted complaint-based or other limited economic regulation of
natural gas gathering activities. States in which we operate
that have adopted some form of complaint-based regulation, like
Texas, generally allow natural gas producers and shippers to
file complaints with state regulators in an effort to resolve
grievances relating to natural gas gathering rates and access.
Other state and local regulations also affect our business.
Our storage facilities are also subject to the jurisdiction of
the TRRC. Generally, the TRRC has jurisdiction over all
underground storage of natural gas in Texas, unless the facility
is part of an interstate gas pipeline facility. Because the
natural gas storage facilities of the ET Fuel System and HPL
System are only connected to intrastate gas pipelines, they fall
within the TRRCs jurisdiction and must be operated
pursuant to TRRC permit. Certain changes in ownership or
operation of TRCC-jurisdictional storage facilities, such as
facility expansions and increases in the maximum operating
pressure, must be approved by the TRRC through an amendment to
the facilitys existing permit. In addition, the TRRC must
approve transfers of the permits. Texas laws and regulations
also require all natural gas storage facilities to be operated
to prevent waste, the uncontrolled escape of gas, pollution and
danger to life or property. Accordingly, the TRRC requires
natural gas storage facilities to implement certain safety,
monitoring, reporting and record-keeping measures. Violations of
the terms and provisions of a TRRC permit or a TRRC order or
regulation can result in the modification, cancellation or
suspension of an operating permit
and/or civil
penalties, injunctive relief, or both.
The states in which we conduct operations administer federal
pipeline safety standards under the Pipeline Safety Act of 1968,
which requires certain pipeline companies to comply with safety
standards in constructing and operating the pipelines, and
subjects pipelines to regular inspections. Some of our gathering
facilities are exempt from the requirements of this Act. In
respect to recent pipeline accidents in other parts of the
country, Congress and the Department of Transportation have
passed or are considering heightened pipeline safety
requirements.
Failure to comply with applicable laws and regulations could
result in the imposition of administrative, civil and criminal
remedies.
Our
interstate pipelines are subject to laws, regulations and
policies governing the rates they are allowed to charge for
their services.
Laws, regulations and policies governing interstate natural gas
pipeline rates could affect the ability of our interstate
pipelines to establish rates, to charge rates that would cover
future increases in its costs, or to continue to collect rates
that cover current costs. NGA-jurisdictional natural gas
companies must charge rates that are just and reasonable by
FERC. The rates charged by natural gas companies are generally
required to be on file with FERC in FERC-approved tariffs.
Pursuant to the NGA, existing tariff rates may be challenged by
complaint and rate increases proposed by the natural gas company
may be challenged by protest. We also may be limited by the
terms of negotiated rate agreements from seeking future rate
increases, or constrained by competitive factors from charging
our FERC-approved maximum just and reasonable rates. Further,
rates must, for the most part, be cost-based and FERC may, on a
prospective basis, order refunds of amounts collected under
rates that have been found by FERC to be in excess of a just and
reasonable level.
Transwestern filed a general rate case in September 2006. The
rates in this proceeding were settled and are final and no
longer subject to refund. Transwestern is not required to file a
new general rate case until October 2011. However, shippers
(other than shippers that have agreed, as parties to the
Stipulation and Agreement, not to challenge Transwesterns
tariff rates through the remaining term of the settlement) may
challenge the lawfulness of tariff rates that have become final
and effective. FERC may also investigate such rates absent
shipper complaint.
Most of the rates to be paid by the initial shippers on the
Midcontinent Express pipeline are established pursuant to
long-term, negotiated rate transportation agreements. Other
prospective shippers on Midcontinent Express pipeline that elect
not to pay a negotiated rate for service may opt instead to pay
a cost-based recourse rate established by FERC as part of
Midcontinent Express pipelines certificate of public
convenience and necessity. Negotiated rate agreements generally
provide a degree of certainty to the pipeline and shipper as to
a fixed rate during the term of the relevant transportation
agreement, but such agreements can limit the
20
pipelines future ability to collect costs associated with
construction and operation of the pipeline that might be higher
than anticipated at the time the negotiated rate agreement was
entered. The certificate order authorizing construction,
ownership and operation of Midcontinent Express pipeline is
subject to pending requests for clarification and rehearing, and
we cannot guarantee that this order will not be altered on
rehearing or that judicial review, if any, will not result in
any change to FERCs Midcontinent Express pipeline
certificate order on remand.
Any successful complaint or protest against the rates of our
interstate natural gas companies could reduce our revenues
associated with providing transportation services on a
prospective basis. We cannot assure you that our interstate
pipelines will be able to recover all of their costs through
existing or future rates.
The
ability of interstate pipelines held in tax-pass-through
entities, like us, to include an allowance for income taxes in
their regulated rates has been subject to extensive litigation
before FERC and the courts, and the FERCs current policy
is subject to future refinement or change.
The ability of interstate pipelines held in tax-pass-through
entities, like us, to include an allowance for income taxes as a
cost-of-service element in their regulated rates has been
subject to extensive litigation before FERC and the courts for a
number of years. It is currently FERCs policy to permit
pipelines to include in cost-of-service a tax allowance to
reflect actual or potential income tax liability on their public
utility income attributable to all partnership or limited
liability company interests, if the ultimate owner of the
interest has an actual or potential income tax liability on such
income. Whether a pipelines owners have such actual or
potential income tax liability will be reviewed by FERC on a
case-by-case
basis.Under FERCs policy, we thus remain eligible to
include an income tax allowance in the tariff rates we charge
for interstate natural gas transportation. The application of
that policy remains subject to future refinement or change by
FERC. With regard to rates charged and collected by
Transwestern, the allowance for income taxes as a
cost-of-service element in our tariff rates is generally not
subject to challenge prior to the expiration of our settlement
agreement in 2011.
The
intrastate pipelines are subject to laws, regulations and
policies governing terms and conditions of service, which could
adversely affect their business and operations.
In addition to rate oversight, FERCs regulatory authority
extends to many other aspects of Transwesterns business
and operations of our interstate pipelines, including:
|
|
|
|
|
operating terms and conditions of service;
|
|
|
|
the types of services Transwestern may offer to its customers;
|
|
|
|
construction of new facilities;
|
|
|
|
acquisition, extension or abandonment of services or facilities;
|
|
|
|
reporting and information posting requirements;
|
|
|
|
accounts and records; and
|
|
|
|
relationships with affiliated companies involved in all aspects
of the natural gas and energy businesses.
|
Compliance with these requirements can be costly and burdensome.
Future changes to laws, regulations and policies in these areas
may impair the ability of our interstate pipelines to compete
for business, may impair their ability to recover costs or may
increase the cost and burden of operation.
We must on occasion rely upon rulings by FERC or other
governmental authorities to carry out certain of our business
plans. For example, in order to carry out our plan to construct
the Fayetteville Express pipeline we must, among other things,
file and support before FERC an NGA Section 7(c)
application for a certificate of public convenience and
necessity to build, own and operate such a facility. We cannot
guarantee that FERC will authorize construction and operation of
this facility. Moreover, there is no guarantee that, if granted,
such certificate authority will be granted in a timely manner or
will be free from potentially burdensome conditions.
Similarly, we were required to obtain from FERC a certificate of
public convenience and necessity to build, own and operate the
Midcontinent Express pipeline. Although FERC has granted us such
certificate authority, there are pending requests for
clarification and rehearing of that order. We cannot guarantee
that
21
FERC will, on rehearing, reaffirm in all materials respects its
July 25, 2008 Midcontinent Express certificate order. Nor
can we guarantee that FERCs certificate order will not be
subject to judicial review and, ultimately, to possible material
alteration if remanded to FERC.
Failure to comply with all applicable FERC-administered
statutes, rules, regulations and orders, could bring substantial
penalties and fines. Under the Energy Policy Act of 2005, FERC
has civil penalty authority under the NGA to impose penalties
for current violations of up to $1.0 million per day for
each violation. FERC possesses similiar authority under the NGPA.
Finally, we cannot give any assurance regarding the likely
future regulations under which we will operate our interstate
pipelines or the effect such regulation could have on our
business, financial condition, and results of operations.
Our
business involves hazardous substances and may be adversely
affected by environmental regulation.
Our natural gas as well as our propane operations are subject to
stringent federal, state, and local environmental laws and
regulations governing the discharge of materials into the
environment or otherwise relating to environmental protection.
These laws and regulations may require the acquisition of
permits for our operations, result in capital expenditures to
manage, limit, or prevent emissions, discharges, or releases of
various materials from our pipelines, plants, and facilities,
and impose substantial liabilities for pollution resulting from
our operations. Several governmental authorities, such as the
U.S. Environmental Protection Agency, have the power to
enforce compliance with these laws and regulations and the
permits issued under them and frequently mandate difficult and
costly remediation measures and other actions. Failure to comply
with these laws, regulations, and permits may result in the
assessment of administrative, civil, and criminal penalties, the
imposition of remedial obligations, and the issuance of
injunctive relief.
We may incur substantial environmental costs and liabilities
because of the underlying risk inherent to our operations.
Environmental laws provide joint and several, strict liability
for clean up costs incurred to address discharges or releases of
petroleum hydrocarbons or wastes on, under, or from our
properties and facilities, many of which have been used for
industrial activities for a number of years even if such
discharges were caused by our predecressors. Private parties,
including the owners of properties through which our gathering
systems pass or facilities where our petroleum hydrocarbons or
wastes are taken for reclamation or disposal, may also have the
right to pursue legal actions to enforce compliance as well as
to seek damages for non-compliance with environmental laws and
regulations or for personal injury or property damage. As of
March 31, 2009, the total accrued future estimated cost of
remediation activities relating to our Transwestern pipeline
operations is approximately $9.0 million, which activities
are expected to continue through 2018.
Changes in environmental laws and regulations occur frequently,
and any such changes that result in more stringent and costly
waste handling, emission standards, or storage, transport,
disposal or remediation requirements could have a material
adverse effect on our operations or financial position. For
example, the EPA in 2008 lowered the federal ozone standard from
0.08 parts per million to 0.075 parts per million, which will
require the environmental agencies in states with areas that do
not currently meet this standard to adopt new rules between to
further reduce NOx and other ozone precursor emissions. We have
previously been able to satisfy the more stringent NOx emission
reduction requirements that affect our compressor units in ozone
non-attainment areas at reasonable cost, but there is no
guarantee that the changes we may have to make in the future to
meet the new ozone standard or other evolving standards will not
require us to incur costs that could be material to our
operations.
In response to scientific studies suggesting that emissions of
certain gases, commonly referred to as greenhouse
gases and including carbon dioxide and methane, may be
contributing to the warming of the Earths atmosphere,
President Obama has expressed support for, and it is anticipated
that the current session of Congress will consider, legislation
to restrict or regulate emissions of greenhouse gases. In
addition, more than one-third of the states, either individually
or through multi-state regional initiatives, already have begun
implementing legal measures to reduce emissions of greenhouse
gases, primarily through the planned development of emission
inventories or regional greenhouse gas cap and trade
programs. These cap and trade programs could require
major sources of emissions, such as electric power plants, or
major producers of fuels, such as refineries or gas processing
plants, to acquire emission allowances from other businesses
that
22
emit greenhouse gases at levels lower than the limits specified
in those programs and then surrender these allowances as a
credit against such emissions. Depending on the particular
program, we could be required to purchase and surrender
allowances, either for greenhouse gas emissions resulting from
our operations (e.g., compressor stations) or from the
combustion of fuels (e.g., natural gas) that we process.
Also, as a result of the United States Supreme Courts
decision on April 2, 2007 in Massachusetts, et
al. v. EPA, the EPA may regulate greenhouse gas
emissions from mobile sources such as cars and trucks even if
Congress does not adopt new legislation specifically addressing
emissions of greenhouse gases. The Courts holding in
Massachusetts that greenhouse gases including carbon
dioxide fall under the federal Clean Air Acts definition
of air pollutant may also result in future
regulation of carbon dioxide and other greenhouse gas emissions
from stationary sources. In July 2008, EPA released an
Advance Notice of Proposed Rulemaking regarding
possible future regulation of greenhouse gas emissions under the
Clean Air Act, in response to the Supreme Courts decision
in Massachusetts. In the notice, EPA evaluated the
potential regulation of greenhouse gases under the Clean Air Act
and other potential methods of regulating greenhouse gases.
Although the notice did not propose any specific, new regulatory
requirements for greenhouse gases, it indicates that federal
regulation of greenhouse gas emissions could occur in the near
future even if Congress does not adopt new legislation
specifically addressing emissions of greenhouse gases. Although
it is not possible at this time to predict how legislation or
new regulations that may be adopted to address greenhouse gas
emissions would impact our business, any such new federal,
regional or state restrictions on emissions of carbon dioxide or
other greenhouse gases that may be imposed in areas in which we
conduct business could also have an adverse affect on our cost
of doing business and demand for the natural gas we process and
transport.
Any
reduction in the capacity of, or the allocations to, our
shippers in interconnecting, third-party pipelines could cause a
reduction of volumes transported in our pipelines, which would
adversely affect our revenues and cash flow.
Users of our pipelines are dependent upon connections to and
from third-party pipelines to receive and deliver natural gas
and NGLs. Any reduction in the capacities of these
interconnecting pipelines due to testing, line repair, reduced
operating pressures, or other causes could result in reduced
volumes being transported in our pipelines. Similarly, if
additional shippers begin transporting volumes of natural gas
and NGLs over interconnecting pipelines, the allocations to
existing shippers in these pipelines would be reduced, which
could also reduce volumes transported in our pipelines. Any
reduction in volumes transported in our pipelines would
adversely affect our revenues and cash flow.
We
encounter competition from other midstream, transportation and
storage companies and propane companies.
We experience competition in all of our markets. Our principal
areas of competition include obtaining natural gas supplies for
the Southeast Texas System, North Texas System and HPL System
and natural gas transportation customers for our transportation
pipeline systems. Our competitors include major integrated oil
companies, interstate and intrastate pipelines and companies
that gather, compress, treat, process, transport, store and
market natural gas. The Southeast Texas System competes with
natural gas gathering and processing systems owned by DCP
Midstream, LLC. The North Texas System competes with Crosstex
North Texas Gathering, LP and Devon Gas Services, LP for
gathering and processing. The East Texas pipeline competes with
other natural gas transportation pipelines that serve the
Bossier Sands area in east Texas and the Barnett Shale region in
north Texas. The ET Fuel System and the Oasis pipeline compete
with a number of other natural gas pipelines, including
interstate and intrastate pipelines that link the Waha Hub. The
ET Fuel System competes with other natural gas
transportation pipelines serving the Dallas/Ft. Worth area
and other pipelines that serve the east central Texas and south
Texas markets. Pipelines that we compete with in these areas
include those owned by Atmos Energy Corporation, Enterprise
Products Partners, L.P., and Enbridge, Inc. Some of our
competitors may have greater financial resources and access to
larger natural gas supplies than we do.
The acquisitions of the HPL System and the Transwestern pipeline
increased the number of interstate pipelines and natural gas
markets to which we have access and expanded our principal areas
of competition to
23
areas such as southeast Texas and the Texas Gulf Coast. As a
result of our expanded market presence and diversification, we
face additional competitors, such as major integrated oil
companies, interstate and intrastate pipelines and companies
that gather, compress, treat, process, transport, store and
market natural gas, that may have greater financial resources
and access to larger natural gas supplies than we do.
The Transwestern pipeline competes with, and upon completion,
the Midcontinent Express pipeline and Fayetteville Express
pipeline will complete with, other interstate and intrastate
pipeline companies in the transportation and storage of natural
gas. The principal elements of competition among pipelines are
rates, terms of service and the flexibility and reliability of
service. Natural gas competes with other forms of energy
available to our customers and end-users, including electricity,
coal and fuel oils. The primary competitive factor is price.
Changes in the availability or price of natural gas and other
forms of energy, the level of business activity, conservation,
legislation and governmental regulations, the capability to
convert to alternate fuels and other factors, including weather
and natural gas storage levels, affect the levels of natural gas
transportation volumes in the areas served by our pipelines.
Our propane business competes with a number of large national
and regional propane companies and several thousand small
independent propane companies. Because of the relatively low
barriers to entry into the retail propane market, there is
potential for small independent propane retailers, as well as
other companies that may not currently be engaged in retail
propane distribution, to compete with our retail outlets. As a
result, we are always subject to the risk of additional
competition in the future. Generally, warmer-than-normal weather
further intensifies competition. Most of our propane retail
branch locations compete with several other marketers or
distributors in their service areas. The principal factors
influencing competition with other retail propane marketers are:
|
|
|
|
|
price,
|
|
|
|
reliability and quality of service,
|
|
|
|
responsiveness to customer needs,
|
|
|
|
safety concerns,
|
|
|
|
long-standing customer relationships,
|
|
|
|
the inconvenience of switching tanks and suppliers, and
|
|
|
|
the lack of growth in the industry.
|
The
inability to continue to access tribal lands could adversely
affect Transwesterns ability to operate its pipeline
system and the inability to recover the cost of right-of-way
grants on tribal lands could adversely affect its financial
results.
Transwesterns ability to operate its pipeline system on
certain lands held in trust by the United States for the benefit
of a Native American Tribe, which we refer to as tribal lands,
will depend on its success in maintaining existing rights-of-way
and obtaining new rights-of-way on those tribal lands. Securing
additional rights-of-way is also critical to Transwesterns
ability to pursue expansion projects. We cannot provide any
assurance that Transwestern will be able to acquire new
rights-of-way on tribal lands or maintain access to existing
rights-of-way upon the expiration of the current grants. Our
financial position could be adversely affected if the costs of
new or extended right-of-way grants cannot be recovered in rates.
We may
be unable to bypass the processing plants, which could expose us
to the risk of unfavorable processing margins.
Because of our ownership of the Oasis pipeline and ET Fuel
System, we can generally elect to bypass our processing plants
when processing margins are unfavorable and instead deliver
pipeline-quality gas by blending rich gas from the gathering
systems with lean gas transported on the Oasis pipeline and ET
Fuel System. In some circumstances, such as when we do not have
a sufficient amount of lean gas to blend with
24
the volume of rich gas that we receive at the processing plant,
we may have to process the rich gas. If we have to process when
processing margins are unfavorable, our results of operations
will be adversely affected.
We may
be unable to retain existing customers or secure new customers,
which would reduce our revenues and limit our future
profitability.
The renewal or replacement of existing contracts with our
customers at rates sufficient to maintain current revenues and
cash flows depends on a number of factors beyond our control,
including competition from other pipelines, and the price of,
and demand for, natural gas in the markets we serve.
For the year ended December 31, 2008, approximately 27.3%
of our sales of natural gas were to industrial end-users and
utilities. As a consequence of the increase in competition in
the industry and volatility of natural gas prices, end-users and
utilities are increasingly reluctant to enter into long-term
purchase contracts. Many end-users purchase natural gas from
more than one natural gas company and have the ability to change
providers at any time. Some of these end-users also have the
ability to switch between gas and alternate fuels in response to
relative price fluctuations in the market. Because there are
many companies of greatly varying size and financial capacity
that compete with us in the marketing of natural gas, we often
compete in the end-user and utilities markets primarily on the
basis of price. The inability of our management to renew or
replace our current contracts as they expire and to respond
appropriately to changing market conditions could have a
negative effect on our profitability.
Our
storage business depends on neighboring pipelines to transport
natural gas.
To obtain natural gas, our storage business depends on the
pipelines to which they have access. Many of these pipelines are
owned by parties not affiliated with us. Any interruption of
service on those pipelines or adverse change in their terms and
conditions of service could have a material adverse effect on
our ability, and the ability of our customers, to transport
natural gas to and from our facilities and a corresponding
material adverse effect on our storage revenues. In addition,
the rates charged by those interconnected pipelines for
transportation to and from our facilities affect the utilization
and value of our storage services. Significant changes in the
rates charged by those pipelines or the rates charged by other
pipelines with which the interconnected pipelines compete could
also have a material adverse effect on our storage revenues.
Our
pipeline integrity program may cause us to incur significant
costs and liabilities.
Our operations are subject to regulation by the
U.S. Department of Transportation (DOT) under
the Pipeline Hazardous Materials Safety Administration
(PHMSA) pursuant to which the PHMSA has established
regulations relating to the design, installation, testing,
construction, operation, replacement and management of pipeline
facilities. Moreover, the PHMSA, through the Office of Pipeline
Safety, has promulgated a rule requiring pipeline operators to
develop integrity management programs to comprehensively
evaluate their pipelines, and take measures to protect pipeline
segments located in what the rule refers to as high
consequence areas. Based on the results of our current
pipeline integrity testing programs, we estimate that compliance
with these federal regulations and analogous state pipeline
integrity requirements for its existing transportation assets
other than the Transwestern pipeline will result in capital
costs of $27.1 million during the twelve months ending
December 31, 2009, as well as operating and maintenance
costs of $27.6 million during that period. During this same
time period, we estimate that we will incur pipeline integrity
capital cost of $8.9 million, as well as operating and
maintenance costs of $1.7 million with respect to our
Transwestern pipeline. Through March 31, 2009, Transwestern
did not incur any costs associated with the IMP Rule and has
satisfied all of the requirements. Through March 31, 2009,
a total of $19.9 million of capital costs and
$16.0 million of operating and maintenance costs have been
incurred for pipeline integrity testing for transportation
assets other than Transwestern, including $3.5 million of
capital costs and $3.3 million of operating and maintenance
costs during the first quarter of 2009. Through March 31,
2009, a total of $7.1 million of capital costs and
$0.5 million of operating and maintenance costs have been
incurred for pipeline integrity testing for Transwestern,
including $0.2 million of capital costs and
$0.1 million of operating and maintenance costs during the
first quarter of 2009. Integrity testing and assessment of all
of these assets will continue, and the potential exists that
results of such costs and assessment could cause us to incur
even
25
greater capital and operating expenditures for repairs or
upgrades deemed necessary to ensure the continued safe and
reliable operation of our pipelines.
Since
weather conditions may adversely affect demand for propane, our
financial conditions may be vulnerable to warm
winters.
Weather conditions have a significant impact on the demand for
propane for heating purposes because the majority of our
customers rely heavily on propane as a heating fuel. Typically,
we sell approximately two-thirds of our retail propane volume
during the peak-heating season of October through March. Our
results of operations can be adversely affected by warmer winter
weather which results in lower sales volumes. In addition, to
the extent that warm weather or other factors adversely affect
our operating and financial results, our access to capital and
our acquisition activities may be limited. Variations in weather
in one or more of the regions where we operate can significantly
affect the total volume of propane that we sell and the profits
realized on these sales. Agricultural demand for propane may
also be affected by weather, including periods of unseasonably
cold or hot periods or dry weather conditions that impact
agricultural operations.
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.
Virtually all of our operations are exposed to potential natural
disasters, including hurricanes, tornadoes, storms, floods
and/or
earthquakes.
If one or more facilities that are owned by us or that deliver
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 to our unitholders and, accordingly,
adversely affect the market price of our common units.
As a result of market conditions, premiums and deductibles for
certain insurance policies can increase substantially, and in
some instances, certain insurance may become unavailable or
available only for reduced amounts of coverage. As a result, we
may not be able to renew existing insurance policies 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.
Terrorist
attacks aimed at our facilities could adversely affect our
business, results of operations, cash flows and financial
condition.
Since the September 11, 2001 terrorist attacks on the
United States, the United States government has issued warnings
that energy assets, including our nations pipeline
infrastructure, may be the future target of terrorist
organizations. Any terrorist attack on our facilities or
pipelines or those of our customers could have a material
adverse effect on our business.
26
Sudden
and sharp propane price increases that cannot be passed on to
customers may adversely affect our profit margins.
The propane industry is a margin-based business in
which gross profits depend on the excess of sales prices over
supply costs. As a result, our profitability is sensitive to
changes in energy prices, and in particular, changes in
wholesale prices of propane. When there are sudden and sharp
increases in the wholesale cost of propane, we may be unable to
pass on these increases to our customers through retail or
wholesale prices. Propane is a commodity and the price we pay
for it can fluctuate significantly in response to changes in
supply or other market conditions over which we have no control.
In addition, the timing of cost pass-throughs can significantly
affect margins. Sudden and extended wholesale price increases
could reduce our gross profits and could, if continued over an
extended period of time, reduce demand by encouraging our retail
customers to conserve their propane usage or convert to
alternative energy sources.
Our
results of operations could be negatively impacted by price and
inventory risk related to our propane business and management of
these risks.
We generally attempt to minimize our cost and inventory risk
related to our propane business by purchasing propane on a
short-term basis under supply contracts that typically have a
one-year term and at a cost that fluctuates based on the
prevailing market prices at major delivery points. In order to
help ensure adequate supply sources are available during periods
of high demand, we may purchase large volumes of propane during
periods of low demand or low price, which generally occur during
the summer months, for storage in our facilities, at major
storage facilities owned by third parties or for future
delivery. This strategy may not be effective in limiting our
cost and inventory risks if, for example, market, weather or
other conditions prevent or allocate the delivery of physical
product during periods of peak demand. If the market price falls
below the cost at which we made such purchases, it could
adversely affect our profits.
Some of our propane sales are pursuant to commitments at fixed
prices. To mitigate the price risk related to our anticipated
sales volumes under the commitments, we may purchase and store
physical product
and/or enter
into fixed price over-the-counter energy commodity forward
contracts and options. Generally, over-the-counter energy
commodity forward contracts have terms of less than one year. We
enter into such contracts and exercise such options at volume
levels that we believe are necessary to manage these
commitments. The risk management of our inventory and contracts
for the future purchase of product could impair our
profitability if the customers do not fulfill their obligations.
We also engage in other trading activities, and may enter into
other types of over-the-counter energy commodity forward
contracts and options. These trading activities are based on our
managements estimates of future events and prices and are
intended to generate a profit. However, if those estimates are
incorrect or other market events outside of our control occur,
such activities could generate a loss in future periods and
potentially impair our profitability.
We are
dependent on our principal propane suppliers, which increases
the risk of an interruption in supply.
During 2008, we purchased approximately 50.7%, 15.0% and 14.9%
of our propane from Enterprise, Targa Liquids and M.P. Oils,
Ltd., respectively. Enterprise is a subsidiary of
Enterprise GP, an entity that owns approximately 17.6% of
ETEs outstanding common units and a 40.6% non-controlling
equity interest in the General Partner of ETE. Titan purchases
substantially all of its propane from Enterprise pursuant to an
agreement that expires in 2010. If supplies from these sources
were interrupted, the cost of procuring replacement supplies and
transporting those supplies from alternative locations might be
materially higher and, at least on a short-term basis, margins
could be adversely affected. Supply from Canada is subject to
the additional risk of disruption associated with foreign trade
such as trade restrictions, shipping delays and political,
regulatory and economic instability.
Historically, a substantial portion of the propane that we
purchase has originated from one of the industrys major
markets located in Mt. Belvieu, Texas and has been shipped to us
through major common
27
carrier pipelines. Any significant interruption in the service
at Mt. Belvieu or other major market points, or on the common
carrier pipelines we use, would adversely affect our ability to
obtain propane.
Competition
from alternative energy sources may cause us to lose propane
customers, thereby reducing our revenues.
Competition in our propane business from alternative energy
sources has been increasing as a result of reduced regulation of
many utilities. Propane is generally not competitive with
natural gas in areas where natural gas pipelines already exist
because natural gas is a less expensive source of energy than
propane. The gradual expansion of natural gas distribution
systems and the availability of natural gas in many areas that
previously depended upon propane could cause us to lose
customers, thereby reducing our revenues. Fuel oil also competes
with propane and is generally less expensive than propane. In
addition, the successful development and increasing usage of
alternative energy sources could adversely affect our operations.
Energy
efficiency and technological advances may affect the demand for
propane and adversely affect our operating
results.
The national trend toward increased conservation and
technological advances, including installation of improved
insulation and the development of more efficient furnaces and
other heating devices, has decreased the demand for propane by
retail customers. Stricter conservation measures in the future
or technological advances in heating, conservation, energy
generation or other devices could adversely affect our
operations.
Tax Risks
to Common Unitholders
In addition to reading the following risk factors, you should
read Material Income Tax Considerations 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 become
subject to a material amount of entity-level taxation for state
tax purposes, it would substantially reduce the amount of cash
available for distribution to unitholders.
The anticipated after-tax economic benefit of an investment in
our common units depends largely on our being treated as a
partnership for federal income tax purposes. We have not
requested, and do not plan to request, a ruling from the IRS
with respect to our classification as a partnership for federal
income tax purposes.
Despite the fact that we are a limited partnership under
Delaware law, it is possible in certain circumstances for a
partnership such as ours may be treated as a corporation for
federal income tax purposes.
If we are so treated, we would pay federal income tax on our
taxable income at the corporate tax rate, which is currently a
maximum of 35%, and we would likely pay additional state income
taxes as well. Distributions to unitholders would generally be
taxed again as corporate distributions, and none of our income,
gains, losses or deductions would flow through to unitholders.
Because a tax would then be imposed upon us as a corporation,
our cash available for distribution to unitholders would be
substantially reduced. Therefore, treatment of us as a
corporation would result in a material reduction in the
anticipated cash flow and after-tax return to the unitholders,
likely causing a substantial reduction in the value of our
common units.
Current law may change, causing us to be treated as a
corporation for federal income tax purposes or otherwise
subjecting us to entity-level taxation.
For example, members of Congress have recently considered
substantive changes to the existing federal income tax laws that
would have affected certain publicly traded partnerships.
Specifically, federal income tax legislation has been considered
that would have eliminated partnership tax treatment for certain
publicly traded partnerships and recharacterize certain types of
income received from partnerships. We are unable to predict
28
whether any of these changes, or other proposals, will be
reintroduced or will ultimately be enacted. Any such changes
could negatively impact the value of an investment in our common
units.
We
prorate our items of income, gain, loss and deduction between
transferors and transferees of our units each month based upon
the ownership of our units on the first day of each month,
instead of on the basis of the date a particular unit is
transferred. The IRS may challenge this treatment, which could
change the allocation of items of income, gain, loss and
deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between
transferors and transferees of our units each month based upon
the ownership of our units on the first day of each month,
instead of on the basis of the date a particular unit is
transferred. If the IRS were to challenge this method or new
Treasury regulations were issued, we may be required to change
the allocation of items of income, gain, loss and deduction
among our unitholders.
If the
IRS contests the federal income tax positions we take, the
market for our common units may be adversely affected, and the
costs of any such contest will reduce cash available for
distributions to our unitholders.
The IRS may adopt positions that differ from the positions we
take. It may be necessary to resort to administrative or court
proceedings to sustain some or all of the positions we take. A
court may not agree with some or all of our counsels
conclusions or the positions we take. Any contest with the IRS
may materially and adversely impact the market for our common
units and the prices at which they trade. In addition, the costs
of any contest with the IRS will be borne by us reducing the
cash available for distribution to our unitholders.
Unitholders
may be required to pay taxes on their share of our income even
if they do not receive any cash distributions from
us.
Because our unitholders will be treated as partners to whom we
will allocate taxable income which could be different in amount
than the cash we distribute, unitholders will be required to pay
any federal income taxes and, in some cases, state and local
income taxes on your share of our taxable income even if they
receive no cash distributions from us. Unitholders may not
receive cash distributions from us equal to their share of our
taxable income or even equal to the actual tax liability that
results from the taxation of their share of our taxable income.
In such case, unitholders would still be required to pay federal
income taxes and, in some cases, state and local income taxes on
their share of our taxable income regardless of the amount, if
any, of any cash distributions they receive from us.
Tax
gain or loss on disposition of our common units could be more or
less than expected.
If unitholders sell their common units, they will recognize a
gain or loss equal to the difference between the amount realized
and the tax basis in those common units. Because distributions
in excess of the unitholders allocable share of our net
taxable income decrease the unitholders tax basis in their
common units, the amount, if any, of such prior excess
distributions with respect to the units sold will, in effect,
become taxable income to the unitholder if they sell such units
at a price greater than their tax basis in those units, even if
the price received is less than their original cost.
Furthermore, a substantial portion of the amount realized,
whether or not representing gain, may be taxed as ordinary
income due to potential recapture items, including depreciation
recapture. In addition, because the amount realized includes a
unitholders share of our nonrecourse liabilities, if a
unitholder sells units, the unitholder may incur a tax liability
in excess of the amount of cash received from the sale. Please
read Material Income Tax Considerations
Disposition of Common Units Recognition of Gain or
Loss for a further discussion of the foregoing.
29
Tax-exempt
entities and non-U.S. persons face unique tax issues from owning
common units that may result in adverse tax consequences to
them.
Investment in common units by tax-exempt entities, including
employee benefit plans and individual retirement accounts
(IRAs) and
non-U.S. persons
raises issues unique to them. For example, virtually all of our
income allocated to unitholders who are organizations exempt
from federal income tax, may be taxable to them as
unrelated business taxable income. 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 federal income tax returns and
generally 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
treat each purchaser of common units as having the same tax
benefits without regard to the actual common units purchased.
The IRS may challenge this treatment, which could result in a
unitholder owing more tax and may adversely affect the value of
the common units.
The IRS may challenge the manner in which we calculate our
unitholders basis adjustment under Section 743(b). If
so, because neither we nor a unitholder can identify the units
to which this issue relates once the initial holder has traded
them, the IRS may assert adjustments to all unitholders selling
units within the period under audit as if all unitholders owned
such units.
Any position we take that is inconsistent with applicable
Treasury Regulations may have to be disclosed on our federal
income tax return. This disclosure increases the likelihood that
the IRS will challenge our positions and propose adjustments to
some or all of our unitholders.
A successful IRS challenge to this position or other positions
we may take could adversely affect the amount of taxable income
or loss allocated to our unitholders. It also could affect the
gain from a unitholders sale of common units and could
have a negative impact on the value of the common units or
result in audit adjustments to our unitholders tax returns
without the benefit of additional deductions. Moreover, because
one of our subsidiaries that is organized as a C corporation for
federal income tax purposes owns units in us, a successful IRS
challenge could result in this subsidiary having more tax
liability than we anticipate and, therefore, reduce the cash
available for distribution to our partnership and, in turn, to
our unitholders.
A
unitholder whose units are loaned to a short seller
to cover a short sale of units may be considered as having
disposed of those units. If so, he would no longer be treated
for tax purposes as a partner with respect to those units during
the period of the loan and may recognize gain or loss from the
disposition.
Because a unitholder whose units are loaned to a short
seller to cover a short sale of units may be considered as
having disposed of the loaned units, he may no longer be treated
for tax purposes as a partner with respect to those units during
the period of the loan to the short seller and the unitholder
may recognize gain or loss from such disposition. Moreover,
during the period of the loan to the short seller, any of our
income, gain, loss or deduction with respect to those units may
not be reportable by the unitholder and any cash distributions
received by the unitholder as to those units could be fully
taxable as ordinary income. Unitholders desiring to assure their
status as partners and avoid the risk of gain recognition from a
loan to a short seller are urged to modify any applicable
brokerage account agreements to prohibit their brokers from
borrowing their units.
We
have adopted certain valuation methodologies that may result in
a shift of income, gain, loss and deduction between us and our
public unitholders. The IRS may challenge this treatment, which
could adversely affect the value of our common
units.
When we issue additional units or engage in certain other
transactions, we determine the fair market value of our assets
and allocate any unrealized gain or loss attributable to such
assets to the capital accounts of our unitholders and our
General Partner. Although we may from time to time consult with
professional appraisers regarding valuation matters, including
the valuation of our assets, we make many of the fair market
value estimates of our assets ourselves using a methodology
based on the market value of our common units as a means to
measure the fair market value of our assets. Our methodology may
be viewed as understating
30
the value of our assets. In that case, there may be a shift of
income, gain, loss and deduction between certain unitholders and
our General Partner, which may be unfavorable to such
unitholders. Moreover, under our current valuation methods,
subsequent purchasers of our common units may have a greater
portion of their Internal Revenue Code Section 743(b)
adjustment allocated to our tangible assets and a lesser portion
allocated to our intangible assets. The IRS may challenge our
valuation methods, or our allocation of Section 743(b)
adjustment attributable to our tangible and intangible assets,
and allocations of income, gain, loss and deduction between our
General Partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could
adversely affect the amount of taxable income or loss being
allocated to our unitholders. It also could affect the amount of
gain on the sale of common units by our unitholders and could
have a negative impact on the value of our common units or
result in audit adjustments to the tax returns of our
unitholders without the benefit of additional deductions.
The
sale or exchange of 50% or more of our capital and profit
interests during any twelve month period will result in the
termination of our partnership for federal income tax
purposes.
We will be considered 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. For purposes of determining whether the 50% threshold
has been met, multiple sales of the same unit will be counted
only once. Our termination would, among other things, result in
the closing of our taxable year which would require us to file
two tax returns (and could result in our unitholders receiving
two Schedules K-1) for one fiscal year, and could result in a
deferral of depreciation deductions allowable in computing our
taxable income. In the case of a unitholder reporting on a
taxable year other than a fiscal year ending December 31,
the closing of our taxable year may also result in more than
twelve months of our taxable income or loss being includable in
such unitholders taxable income for the year of
termination. Our termination currently would not affect our
classification as a partnership for federal income tax purposes.
We would be treated as a new partnership for tax purposes and
would be required to make new tax elections and could be subject
to penalties if we were unable to determine in a timely manner
that a termination occurred.
You
will likely be subject to state and local taxes and return
filing requirements in states where you do not live as a result
of investing in our common units.
In addition to federal income taxes, the unitholders may be
subject to other taxes, including state and local 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 now or in the future,
even if they do not live in any of those jurisdictions.
Unitholders may be required to file state and local income tax
returns and pay state and local income taxes in some or all of
the jurisdictions. Further, unitholders may be subject to
penalties for failure to comply with those requirements. It is
the responsibility of each unitholder to file all federal, state
and local tax returns.
31
USE OF
PROCEEDS
The common units to be offered and sold using this prospectus
will be offered and sold by the selling unitholder named in this
prospectus or in any supplement to this prospectus. We will not
receive any proceeds from the sale of such common units.
32
DESCRIPTION
OF UNITS
As of June 1, 2009, there were approximately
123,000 individual common unitholders, which includes
common units held in street name. Our common units represent
limited partner interests in us that entitle the holders to the
rights and privileges specified our Amended and Restated
Agreement of Limited Partnership, as amended to date.
Common
Units
As of June 1, 2009, we had 168,786,459 common units
outstanding, of which 106,285,662 were held by the public,
including approximately 510,000 common units held by our
officers and directors, and 62,500,797 were held by ETE. As of
such date, the common units represent an aggregate 98.0% limited
partner interest in us. Our general partner owns an aggregate
2.0% general partner interest in us. Our common units are
registered under the Securities Exchange Act of 1934, as amended
and are listed for trading on the NYSE. The common units are
entitled to distributions of Available Cash as described below
under Cash Distribution Policy.
Class E
Units
In conjunction with our purchase of the capital stock of
Heritage Holdings in January 2004, the 4,426,916 common
units held by Heritage Holdings were converted into 4,426,916
Class E Units. Pursuant to our two-for-one unit split
completed on March 15, 2005, there are currently 8,853,832
Class E Units outstanding, all of which are owned by
Heritage Holdings. The Class E Units generally do not have
any voting rights. These Class E Units are entitled to
aggregate cash distributions equal to 11.1% of the total amount
of cash distributed to all unitholders, including the
Class E unitholders, up to $1.41 per unit per year.
Management plans to continue its ownership of the Class E
Units by Heritage Holdings indefinitely.
Issuance
of Additional Securities
Our partnership agreement authorizes us to issue an unlimited
number of additional partnership securities and rights to buy
partnership securities for the consideration and on the terms
and conditions established by our general partner in its sole
discretion, without the approval of the unitholders. Any such
additional partnership securities may be senior to the common
units.
It is possible that we will fund acquisitions through the
issuance of additional common units or other equity securities.
Holders of any additional common units we issue will be entitled
to share equally with the then-existing holders of common units
in our distributions of available cash. In addition, the
issuance of additional partnership interests may dilute the
value of the interests of the then-existing holders of common
units in our net assets.
In accordance with Delaware law and the provisions of our
partnership agreement, we may also issue additional partnership
securities that, in the sole discretion of the general partner,
have special voting rights to which the common units are not
entitled.
Upon issuance of additional partnership securities, our general
partner will be required to make additional capital
contributions to the extent necessary to maintain its 2.0%
general partner interest in us. Moreover, our general partner
will have the right, which it may from time to time assign in
whole or in part to any of its affiliates, to purchase common
units or other equity securities whenever, and on the same terms
that, we issue those securities to persons other than the
general partner and its affiliates, to the extent necessary to
maintain its percentage interest, including its interest
represented by common units, that existed immediately prior to
each issuance. The holders of common units will not have
preemptive rights to acquire additional common units or other
partnership securities.
33
Unitholder
Approval
The following matters require the approval of the majority of
the outstanding common units, including the common units owned
by the general partner and its affiliates:
|
|
|
|
|
a merger of our partnership;
|
|
|
|
a sale or exchange of all or substantially all of our assets;
|
|
|
|
dissolution or reconstitution of our partnership upon
dissolution;
|
|
|
|
certain amendments to the partnership agreement;
|
|
|
|
the transfer to another person of the incentive distribution
rights at any time, except for transfers to affiliates of the
general partner or transfers in connection with the general
partners merger or consolidation with or into, or sale of
all or substantially all of its assets to, another
person; and
|
The removal of our general partner requires the approval of not
less than
662/3%
of all outstanding units, including units held by our general
partner and its affiliates. Any removal is subject to the
election of a successor general partner by the holders of a
majority of the outstanding common units, including units held
by our general partner and its affiliates.
Amendments
to Our Partnership Agreement
Amendments to our partnership agreement may be proposed only by
our general partner. Certain amendments require the approval of
a majority of the outstanding common units, including common
units owned by the general partner and its affiliates. Any
amendment that materially and adversely affects the rights or
preferences of any class of partnership interests in relation to
other classes of partnership interests will require the approval
of at least a majority of the class of partnership interests so
affected. Our general partner may make amendments to the
partnership agreement without unitholder approval to reflect:
|
|
|
|
|
a change in our name, the location of our principal place of
business or our registered agent or office;
|
|
|
|
the admission, substitution, withdrawal or removal of partners;
|
|
|
|
a change to qualify or continue our qualification as a limited
partnership or a partnership in which the limited partners have
limited liability or to ensure that neither we nor our operating
partnership will be treated as an association taxable as a
corporation or otherwise taxed as an entity for federal income
tax purposes;
|
|
|
|
a change that does not affect our unitholders in any material
respect;
|
|
|
|
a change to (i) satisfy any requirements, conditions or
guidelines contained in any opinion, directive, order, ruling or
regulation of any federal or state agency or judicial authority
or contained in any federal or state statute,
(ii) facilitate the trading of common units or comply with
any rule, regulation, guideline or requirement of any national
securities exchange on which the common units are or will be
listed for trading, (iii) that is necessary or advisable in
connection with action taken by our general partner with respect
to subdivision and combination of our securities or
(iv) that is required to effect the intent expressed in our
partnership agreement;
|
|
|
|
a change in our fiscal year or taxable year and any changes that
are necessary or advisable as a result of a change in our fiscal
year or taxable year;
|
|
|
|
an amendment that is necessary to prevent us, or our general
partner or its directors, officers, trustees or agents from
being subjected to the provisions of the Investment Company Act
of 1940, as amended, the Investment Advisors Act of 1940, as
amended, or plan asset regulations adopted under the
Employee Retirement Income Security Act of 1974, as amended;
|
|
|
|
an amendment that is necessary or advisable in connection with
the authorization or issuance of any class or series of our
securities;
|
|
|
|
any amendment expressly permitted in our partnership agreement
to be made by our general partner acting alone;
|
34
|
|
|
|
|
an amendment effected, necessitated or contemplated by a merger
agreement approved in accordance with our partnership agreement;
|
|
|
|
an amendment that is necessary or advisable to reflect, account
for and deal with appropriately our formation of, or investment
in, any corporation, partnership, joint venture, limited
liability company or other entity other than our operating
partnership, in connection with our conduct of activities
permitted by our partnership agreement;
|
|
|
|
a merger or conveyance to effect a change in our legal
form; or
|
|
|
|
any other amendment substantially similar to the foregoing.
|
Withdrawal
or Removal of Our General Partner
Our general partner may withdraw as general partner without
first obtaining approval of any unitholder by giving
90 days written notice, and that withdrawal will not
constitute a violation of our partnership agreement. In
addition, our general partner may withdraw without unitholder
approval upon 90 days notice to our limited partners
if at least 50% of our outstanding common units are held or
controlled by one person and its affiliates other than our
general partner and its affiliates.
Upon the voluntary withdrawal of our general partner, the
holders of a majority of our outstanding common units, excluding
the common units held by the withdrawing general partner and its
affiliates, may elect a successor to the withdrawing general
partner. If a successor is not elected, or is elected but an
opinion of counsel regarding limited liability and tax matters
cannot be obtained, we will be dissolved, wound up and
liquidated, unless within 90 days after that withdrawal,
the holders of a majority of our outstanding units, excluding
the common units held by the withdrawing general partner and its
affiliates, agree to continue our business and to appoint a
successor general partner.
Our general partner may not be removed unless that removal is
approved by the vote of the holders of not less than two-thirds
of our outstanding units, including units held by our general
partner and its affiliates, and we receive an opinion of counsel
regarding limited liability and tax matters. In addition, if our
general partner is removed as our general partner under
circumstances where cause does not exist, our general partner
will have the right to receive cash in exchange for its
partnership interest as a general partner in us, its partnership
interest as the general partner of any member of the Energy
Transfer partnership group and its incentive distribution
rights. Cause is narrowly defined to mean that a court of
competent jurisdiction has entered a final, non-appealable
judgment finding the general partner liable for actual fraud,
gross negligence or willful or wanton misconduct in its capacity
as our general partner. Any removal of this kind is also subject
to the approval of a successor general partner by the vote of
the holders of the majority of our outstanding common units,
including those held by our general partner and its affiliates.
While our partnership agreement limits the ability of our
general partner to withdraw, it allows the general partner
interest to be transferred to an affiliate or to a third party
in conjunction with a merger or sale of all or substantially all
of the assets of our general partner. In addition, our
partnership agreement expressly permits the sale, in whole or in
part, of the ownership of our general partner. Our general
partner may also transfer, in whole or in part, any common units
it owns.
Liquidation
and Distribution of Proceeds
Upon our dissolution, unless we are reconstituted and continue
as a new limited partnership, the person authorized to wind up
our affairs (the liquidator) will, acting with all the powers of
our general partner that the liquidator deems necessary or
desirable in its good faith judgment, liquidate our assets. The
proceeds of the liquidation will be applied as follows:
|
|
|
|
|
first, towards the payment of all of our creditors and the
creation of a reserve for contingent liabilities; and
|
|
|
|
then, to all partners in accordance with the positive balance in
their respective capital accounts.
|
35
Under some circumstances and subject to some limitations, the
liquidator may defer liquidation or distribution of our assets
for a reasonable period of time. If the liquidator determines
that a sale would be impractical or would cause a loss to our
partners, our general partner may distribute assets in kind to
our partners.
Limited
Call Right
If at any time less than 20% of the outstanding common units of
any class are held by persons other than our general partner and
its affiliates, our general partner will have the right to
acquire all, but not less than all, of those common units at a
price no less than their then-current market price. As a
consequence, a unitholder may be required to sell his common
units at an undesirable time or price. Our general partner may
assign this purchase right to any of its affiliates or us.
Indemnification
Under our partnership agreement, in most circumstances, we will
indemnify our general partner, its affiliates and their officers
and directors to the fullest extent permitted by law, from and
against all losses, claims or damages any of them may suffer by
reason of their status as general partner, officer or director,
as long as the person seeking indemnity acted in good faith and
in a manner believed to be in or not opposed to our best
interest. Any indemnification under these provisions will only
be out of our assets. Our general partner shall not be
personally liable for, or have any obligation to contribute or
loan funds or assets to us to effectuate any indemnification. We
are authorized to purchase insurance against liabilities
asserted against and expenses incurred by persons for our
activities, regardless of whether we would have the power to
indemnify the person against liabilities under our partnership
agreement.
Listing
Our outstanding common units are listed on the NYSE under the
symbol ETP. Any additional common units we issue
also will be listed on the NYSE.
Transfer
Agent and Registrar
The transfer agent and registrar for the common units is
American Stock Transfer & Trust Company.
Transfer
of Common Units
Each purchaser of common units offered by this prospectus must
execute a transfer application. By executing and delivering a
transfer application, the purchaser of common units:
|
|
|
|
|
becomes the record holder of the common units and is an assignee
until admitted into our partnership as a substituted limited
partner;
|
|
|
|
automatically requests admission as a substituted limited
partner in our partnership;
|
|
|
|
agrees to be bound by the terms and conditions of, and executes,
our partnership agreement;
|
|
|
|
represents that such person has the capacity, power and
authority to enter into the partnership agreement;
|
|
|
|
grants to our general partner the power of attorney to execute
and file documents required for our existence and qualification
as a limited partnership, the amendment of the partnership
agreement, our dissolution and liquidation, the admission,
withdrawal, removal or substitution of partners, the issuance of
additional partnership securities and any merger or
consolidation of the partnership.
|
|
|
|
makes the consents and waivers contained in the partnership
agreement, including the waiver of the fiduciary duties of the
general partner to unitholders as described in Risk
Factors Risks Inherent in an Investment in
Us Our partnership agreement limits our general
partners fiduciary duties to our unitholders and restricts
the remedies available to unitholders for actions taken by our
general partner that might otherwise constitute breaches of
fiduciary duty.
|
36
An assignee will become a substituted limited partner of our
partnership for the transferred common units upon the consent of
our general partner and the recording of the name of the
assignee on our books and records. Although the general partner
has no current intention of doing so, it may withhold its
consent in its sole discretion. An assignee who is not admitted
as a limited partner will remain an assignee. An assignee is
entitled to an interest equivalent to that of a limited partner
for the right to share in allocations and distributions from us,
including liquidating distributions. Furthermore, our general
partner will vote and exercise other powers attributable to
common units owned by an assignee at the written direction of
the assignee.
Transfer applications may be completed, executed and delivered
by a purchasers broker, agent or nominee. We are entitled
to treat the nominee holder of a common unit as the absolute
owner. In that case, the beneficial holders rights are
limited solely to those that it has against the nominee holder
as a result of any agreement between the beneficial owner and
the nominee holder.
Common units are securities and are transferable according to
the laws governing transfer of securities. In addition to other
rights acquired, the purchaser has the right to request
admission as a substituted limited partner in our partnership
for the purchased common units. A purchaser of common units who
does not execute and deliver a transfer application obtains only:
|
|
|
|
|
the right to assign the common unit to a purchaser or
transferee; and
|
|
|
|
the right to transfer the right to seek admission as a
substituted limited partner in our partnership for the purchased
common units.
|
Thus, a purchaser of common units who does not execute and
deliver a transfer application:
|
|
|
|
|
will not receive cash distributions or federal income tax
allocations, unless the common units are held in a nominee or
street name account and the nominee or broker has
executed and delivered a transfer application; and
|
|
|
|
may not receive some federal income tax information or reports
furnished to record holders of common units.
|
Until a common unit has been transferred on our books, we and
the transfer agent, notwithstanding any notice to the contrary,
may treat the record holder of the unit as the absolute owner
for all purposes, except as otherwise required by law or NYSE
regulations.
Status as
Limited Partner or Assignee
Except as described under Limited
Liability, the common units will be fully paid, and the
unitholders will not be required to make additional capital
contributions to us.
Limited
Liability
Assuming that a limited partner does not participate in the
control of our business within the meaning of the Delaware
Revised Uniform Limited Partnership Act (the Delaware
Act) and that he otherwise acts in conformity with the
provisions of our partnership agreement, his liability under the
Delaware Act will be limited, subject to possible exceptions, to
the amount of capital he is obligated to contribute to us for
his common units plus his share of any undistributed profits and
assets. If it were determined, however, that the right or
exercise of the right by the limited partners as a group:
|
|
|
|
|
to remove or replace the general partner;
|
|
|
|
to approve some amendments to our partnership agreement; or
|
|
|
|
to take other action under our partnership agreement;
|
|
|
|
constituted participation in the control of our
business for the purposes of the Delaware Act, then the limited
partners could be held personally liable for our obligations
under Delaware law, to the same extent as the general partner.
This liability would extend to persons who transact business
with us and who reasonably believe that the limited partner is a
general partner. Neither our partnership agreement
|
37
|
|
|
|
|
nor the Delaware Act specifically provides for legal recourse
against our general partner if a limited partner were to lose
limited liability through any fault of the general partner.
While this does not mean that a limited partner could not seek
legal recourse, we have found no precedent for this type of a
claim in Delaware case law.
|
Under the Delaware Act, a limited partnership may not make a
distribution to a partner if after the distribution all
liabilities of the limited partnership, other than liabilities
to partners on account of their partnership interests and
liabilities for which the recourse of creditors is limited to
specific property of our partnership, exceed the fair value of
the assets of the limited partnership. For the purpose of
determining the fair value of the assets of a limited
partnership, the Delaware Act provides that the fair value of
property subject to liability for which recourse of creditors is
limited shall be included in the assets of the limited
partnership only to the extent that the fair value of that
property exceeds the nonrecourse liability. The Delaware Act
provides that a limited partner who receives a distribution and
knew at the time of the distribution that the distribution was
in violation of the Delaware Act shall be liable to the limited
partnership for the amount of the distribution for three years.
Under the Delaware Act, an assignee who becomes a substituted
limited partner of a limited partnership is liable for the
obligations of his assignor to make contributions to our
partnership, except the assignee is not obligated for
liabilities unknown to him at the time he became a limited
partner and which could not be ascertained from our partnership
agreement.
Our subsidiaries currently conduct business in 45 states:
Alabama, Arizona, Arkansas, California, Colorado, Connecticut,
Delaware, Florida, Georgia, Idaho, Illinois, Indiana, Kansas,
Kentucky, Louisiana, Maine, Maryland, Massachusetts, Michigan,
Missouri, Minnesota, Mississippi, Montana, Nevada, New
Hampshire, New Jersey, New Mexico, New York, North Carolina,
Ohio, Oklahoma, Oregon, Pennsylvania, Rhode Island, South
Carolina, South Dakota, Tennessee, Texas, Utah, Vermont,
Virginia, Wisconsin, Washington, West Virginia and Wyoming. To
maintain the limited liability for Energy Transfer Partners,
L.P., as the holder of a 100% limited partner interest in
Heritage Operating, L.P., we may be required to comply with
legal requirements in the jurisdictions in which Heritage
Operating, L.P. conducts business, including qualifying our
subsidiaries to do business there. Limitations on the liability
of limited partners for the obligations of a limited partnership
have not been clearly established in many jurisdictions. If it
were determined that we were, by virtue of our limited partner
interest in Heritage Operating, L.P. or otherwise, conducting
business in any state without compliance with the applicable
limited partnership statute, or that our right or the exercise
of our right to remove or replace Heritage Operating,
L.P.s general partner, to approve some amendments to
Heritage Operating, L.P.s partnership agreement, or to
take other action under Heritage Operating, L.P.s
partnership agreement constituted participation in the
control of Heritage Operating, L.P.s business for
purposes of the statutes of any relevant jurisdiction, then we
could be held personally liable for Heritage Operating,
L.P.s obligations under the law of that jurisdiction to
the same extent as our general partner under the circumstances.
We will operate in a manner as our general partner considers
reasonable and necessary or appropriate to preserve our limited
liability.
Meetings;
Voting
Except as described below regarding a person or group owning 20%
or more of any class of units then outstanding, unitholders or
assignees who are record holders of units on the record date
will be entitled to notice of, and to vote at, meetings of our
limited partners and to act upon matters for which approvals may
be solicited. Common units that are owned by an assignee who is
a record holder, but who has not yet been admitted as a limited
partner, shall be voted by our general partner at the written
direction of the record holder. Absent direction of this kind,
the common units will not be voted, except that, in the case of
common units held by our general partner on behalf of
non-citizen assignees, our general partner shall distribute the
votes on those common units in the same ratios as the votes of
limited partners on other units are cast.
Our general partner does not anticipate that any meeting of
unitholders will be called in the foreseeable future. Any action
that is required or permitted to be taken by the unitholders may
be taken either at a meeting of the unitholders or without a
meeting if consents in writing describing the action so taken
are signed by holders of the number of units as would be
necessary to authorize or take that action at a meeting.
Meetings of the unitholders may be called by our general partner
or by unitholders owning at least 20% of the
38
outstanding units of the class for which a meeting is proposed.
Unitholders may vote either in person or by proxy at meetings.
The holders of a majority of the outstanding units of the class
or classes for which a meeting has been called represented in
person or by proxy shall constitute a quorum unless any action
by the unitholders requires approval by holders of a greater
percentage of the units, in which case the quorum shall be the
greater percentage.
Each record holder of a unit has a vote according to his
percentage interest in us, although additional limited partner
interests having special voting rights could be issued. However,
if at any time any person or group, other than our general
partner and its affiliates, owns, in the aggregate, beneficial
ownership of 20% or more of the common units then outstanding,
the person or group will lose voting rights on all of its common
units and its common units may not be voted on any matter and
will not be considered to be outstanding when sending notices of
a meeting of unitholders, calculating required votes,
determining the presence of a quorum or for other similar
purposes. Common units held in nominee or street name account
will be voted by the broker or other nominee in accordance with
the instruction of the beneficial owner unless the arrangement
between the beneficial owner and his nominee provides otherwise.
Any notice, demand, request, report or proxy material required
or permitted to be given or made to record holders of common
units under our partnership agreement will be delivered to the
record holder by us or by the transfer agent.
Books and
Reports
Our general partner is required to keep appropriate books of our
business at our principal offices. The books will be maintained
for both tax and financial reporting purposes on an accrual
basis. Reporting for tax purposes is done on a calendar year
basis.
We will furnish or make available to record holders of common
units, within 75 days after the close of each fiscal year,
an annual report containing audited financial statements and a
report on those financial statements by our independent public
accountants. Except for our fourth quarter, we will also furnish
or make available summary financial information within
45 days after the close of each quarter.
We will furnish each record holder of a unit with information
reasonably required for tax reporting purposes within
90 days after the close of each calendar year. This
information is expected to be furnished in summary form so that
some complex calculations normally required of partners can be
avoided. Our ability to furnish this summary information to
unitholders will depend on the cooperation of unitholders in
supplying us with specific information. Every unitholder will
receive information to assist him in determining his federal and
state tax liability and filing his federal and state income tax
returns, regardless of whether he supplies us with information.
Our partnership agreement provides that a limited partner can,
for a purpose reasonably related to his interest as a limited
partner, upon reasonable demand and at his own expense, have
furnished to him:
|
|
|
|
|
a current list of the name and last known address of each
partner;
|
|
|
|
a copy of our tax returns;
|
|
|
|
information as to the amount of cash, and a description and
statement of the agreed value of any other property or services,
contributed or to be contributed by each partner and the date on
which each became a partner;
|
|
|
|
copies of our partnership agreement, the certificate of limited
partnership of the partnership, related amendments and powers of
attorney under which they have been executed;
|
|
|
|
information regarding the status of our business and financial
condition; and
|
|
|
|
any other information regarding our affairs as is just and
reasonable.
|
Our general partner may, and intends to, keep confidential from
the limited partners trade secrets or other information the
disclosure of which our general partner believes in good faith
is not in our best interests or that we are required by law or
by agreements with third parties to keep confidential.
39
CASH
DISTRIBUTION POLICY
Distributions
of Available Cash
General. We will distribute all of our
available cash to our unitholders and our general
partner within 45 days following the end of each fiscal
quarter. Definition of Available Cash. Available Cash is defined
in our partnership agreement and generally means, with respect
to any calendar quarter, all cash on hand at the end of such
quarter:
|
|
|
|
|
less the amount of cash reserves that are necessary or
appropriate in the reasonable discretion of the general partner
to:
|
|
|
|
|
|
provide for the proper conduct of our business;
|
|
|
|
comply with applicable law or any debt instrument or other
agreement (including reserves for future capital expenditures
and for our future credit needs); or
|
|
|
|
provide funds for distributions to unitholders and our general
partner in respect of any one or more of the next four quarters;
|
|
|
|
|
|
plus all cash on hand on the date of determination of available
cash for the quarter resulting from working capital borrowings
made after the end of the quarter. Working capital borrowings
are generally borrowings that are made under our credit
facilities and in all cases are used solely for working capital
purposes or to pay distributions to partners.
|
Operating
Surplus and Capital Surplus
General. All cash distributed to unitholders
will be characterized as either operating surplus or
capital surplus. We distribute available cash from
operating surplus differently than available cash from capital
surplus.
Definition of Operating Surplus. Operating
surplus for any period generally means:
|
|
|
|
|
our cash balance on the closing date of our initial public
offering; plus
|
|
|
|
$10.0 million (as described below); plus
|
|
|
|
all of our cash receipts since the closing of our initial public
offering, excluding cash from interim capital transactions such
as borrowings that are not working capital borrowings, sales of
equity and debt securities and sales or other dispositions of
assets outside the ordinary course of business; plus
|
|
|
|
our working capital borrowings made after the end of a quarter
but before the date of determination of operating surplus for
the quarter; less
|
|
|
|
all of our operating expenditures after the closing of our
initial public offering, including the repayment of working
capital borrowings, but not the repayment of other borrowings,
and including maintenance capital expenditures; less
|
|
|
|
the amount of cash reserves that the general partner deems
necessary or advisable to provide funds for future operating
expenditures.
|
Definition of Capital Surplus. Generally,
capital surplus will be generated only by:
|
|
|
|
|
borrowings other than working capital borrowings;
|
|
|
|
sales of debt and equity securities; and
|
|
|
|
sales or other disposition of assets for cash, other than
inventory, accounts receivable and other current assets sold in
the ordinary course of business or as part of normal retirements
or replacements of assets.
|
Characterization of Cash Distributions. We
will treat all available cash distributed as coming from
operating surplus until the sum of all available cash
distributed since we began operations equals the operating
40
surplus as of the most recent date of determination of available
cash. We will treat any amount distributed in excess of
operating surplus, regardless of its source, as capital surplus.
As reflected above, operating surplus includes
$10.0 million in addition to our cash balance on the
closing date of our initial public offering, cash receipts from
our operations and cash from working capital borrowings. This
amount does not reflect actual cash on hand that is available
for distribution to our unitholders. Rather, it is a provision
that enables us, if we choose, to distribute as operating
surplus up to $10.0 million of cash we receive in the
future from non-operating sources, such as asset sales,
issuances of securities, and long-term borrowings, that would
otherwise be distributed as capital surplus. We have not made,
and we anticipate that we will not make, any distributions from
capital surplus.
Incentive
Distribution Rights
Incentive distribution rights represent the contractual right to
receive an increasing percentage of quarterly distributions of
available cash from operating surplus after the minimum
quarterly distribution as been paid. Please read
Distributions of Available Cash from Operating
Surplus below. The general partner owns all of the
incentive distribution rights, except that in conjunction with
the August 2000 transaction with U.S. Propane, L.P., we
issued 1,000,000 class C units to Heritage Holdings, Inc.,
our general partner at that time, in conversion of that portion
of Heritage Holdings, Inc.s incentive distribution rights
that entitled it to receive any distribution made by us of funds
attributable to the net amount received by us in connection with
the settlement, judgment, award or other final nonappealable
resolution of the SCANA litigation. In January 2004, the
class C units were distributed by Heritage Holdings, Inc.
to the owners of its equity interests. On July 14, 2006,
all 1,000,000 outstanding class C units were retired and
cancelled.
Distributions
of Available Cash from Operating Surplus
The terms of our partnership agreement require that we make cash
distributions with respect to each calendar quarter within
45 days following the end of each calendar quarter. We are
required to make distributions of available cash from operating
surplus for any quarter in the following manner:
|
|
|
|
|
First, 98% to all common and class E unitholders, in
accordance with their percentage interests, and 2% to the
general partner, until each common unit has received $0.25 per
unit for such quarter (the minimum quarterly
distribution);
|
|
|
|
Second, 98% to all common and class E unitholders, in
accordance with their percentage interests, and 2% to the
general partner, until each common unit has received $0.275 per
unit for such quarter (the first target
distribution);
|
|
|
|
Third, 85% to all common and class E unitholders, in
accordance with their percentage interests, 13% to the holders
of incentive distribution rights, pro rata, and 2% to the
general partner, until each common unit has received $0.3175 per
unit for such quarter (the second target
distribution);
|
|
|
|
Fourth, 75% to all common and class E unitholders, in
accordance with their percentage interests, 23% to the holders
of incentive distribution rights, pro rata, and 2% to the
general partner, until each common unit has received $0.4125 per
unit for such quarter (the third target
distribution); and
|
|
|
|
Fifth, thereafter, 50% to all common and class E
unitholders, in accordance with their percentage interests, 48%
to the holders of incentive distribution rights, pro rata, and
2% to the general partner.
|
Notwithstanding the foregoing, the distributions on each
class E unit may not exceed $1.41 per year.
Distributions
of Available Cash from Capital Surplus
The terms of our partnership agreement require that we make cash
distributions with respect to each calendar quarter with 45 days
following the and of each calender generator. We will make
distributions of available cash from capital surplus, if any, in
the following manner:
|
|
|
|
|
First, 98% to all unitholders, pro rata, and 2% to the general
partner, until we distribute for each common unit, an amount of
available cash from capital surplus equal to the initial public
offering price;
|
41
|
|
|
|
|
Thereafter, we will make all distributions of available cash
from capital surplus as if they were from operating surplus.
|
Our partnership agreement treats a distribution of capital
surplus as the repayment of the initial unit price from the
initial public offering, which is a return of capital. The
initial public offering price per common unit less any
distributions of capital surplus per unit is referred to as the
unrecovered capital.
If we combine our units into fewer units or subdivide our units
into a greater number of units, we will proportionately adjust
our minimum quarterly distribution; our target cash distribution
levels; and our unrecovered capital.
For example, if a two-for-one split of our common units should
occur, our unrecovered capital would each be reduced to 50% of
our initial level. We will not make any adjustment by reason of
our issuance of additional units for cash or property.
On January 14, 2005, our general partner announced a
two-for-one split of our common units that was effected on
March 15, 2005. As a result, our minimum quarterly
distribution and the target cash distribution levels were
reduced to 50% of their initial levels. Our adjusted minimum
quarterly distribution and the adjusted target cash distribution
levels are reflected in the discussion above under the caption
Distributions of Available Cash from Operating
Surplus.
In addition, if legislation is enacted or if existing law is
modified or interpreted in a manner that causes us to become
taxable as a corporation or otherwise subject to taxation as an
entity for federal, state or local income tax purposes, we will
reduce our minimum quarterly distribution and the target cash
distribution levels by multiplying the same by one minus the sum
of the highest marginal federal corporate income tax rate that
could apply and any increase in the effective overall state and
local income tax rates.
Distributions
of Cash Upon Liquidation
General. If we dissolve in accordance with our
partnership agreement, we will sell or otherwise dispose of our
assets in a process called liquidation. We will first apply the
proceeds of liquidation to the payment of our creditors. We will
distribute any remaining proceeds to the unitholders and the
general partner, in accordance with their capital account
balances, as adjusted to reflect any gain or loss upon the sale
or other disposition of our assets in liquidation.
Any further net gain recognized upon liquidation will be
allocated in a manner that takes into account the incentive
distribution rights of the general partner.
Manner of Adjustments for Gain. The manner of
the adjustment for gain is set forth in our partnership
agreement in the following manner:
|
|
|
|
|
First, to the general partner and the holders of units who have
negative balances in their capital accounts to the extent of and
in proportion to those negative balances;
|
|
|
|
Second, 98% to the common unitholders, pro rata, and 2% to the
general partner, until the capital account for each common unit
is equal to the sum of:
|
|
|
|
|
|
the unrecovered capital; and
|
|
|
|
the amount of the minimum quarterly distribution for the quarter
during which our liquidation occurs;
|
|
|
|
|
|
Third, 98% to all unitholders, pro rata, and 2% to the general
partner, until we allocate under this paragraph an amount per
unit equal to:
|
|
|
|
|
|
the sum of the excess of the first target distribution per unit
over the minimum quarterly distribution per unit for each
quarter of our existence; less
|
42
|
|
|
|
|
the cumulative amount per unit of any distributions of available
cash from operating surplus in excess of the minimum quarterly
distribution per unit that we distributed 98% to the
unitholders, pro rata, and 2% to the general partner, for each
quarter of our existence;
|
|
|
|
|
|
Fourth, 85% to all unitholders, pro rata, 13% to the holders of
the incentive distribution rights, pro rata, and 2% to the
general partner, until we allocate under this paragraph an
amount per unit equal to:
|
|
|
|
|
|
the sum of the excess of the second target distribution per unit
over the first target distribution per unit for each quarter of
our existence; less
|
|
|
|
the cumulative amount per unit of any distributions of available
cash from operating surplus in excess of the first target
distribution per unit that we distributed 85% to the
unitholders, pro rata, 13% to the holders of the incentive
distribution rights, pro rata, and 2% to the general partner for
each quarter of our existence;
|
|
|
|
|
|
Fifth, 75% to all unitholders, pro rata, 23% to the holders of
the incentive distribution rights, pro rata, and 2% to the
general partner, until we allocate under this paragraph an
amount per unit equal to:
|
|
|
|
|
|
the sum of the excess of the third target distribution per unit
over the second target distribution per unit for each quarter of
our existence; less
|
|
|
|
the cumulative amount per unit of any distributions of available
cash from operating surplus in excess of the second target
distribution per unit that we distributed 75% to the
unitholders, pro rata, 23% to the holders of the incentive
distribution rights, pro rata, and 2% to the general partner for
each quarter of our existence; and
|
|
|
|
|
|
Sixth, thereafter, 50% to all unitholders, pro rata, 48% to the
holders of the incentive distribution rights, pro rata, and 2%
to the general partner.
|
Manner of Adjustments for Losses. Upon our
liquidation, we will generally allocate any loss to the general
partner and the unitholders in the following manner:
|
|
|
|
|
First, 98% to the holders of common units in proportion to the
positive balances in their capital accounts and 2% to the
general partner, until the capital accounts of the common
unitholders have been reduced to zero; and
|
|
|
|
Second, thereafter, 100% to the general partner.
|
Adjustments to Capital Accounts upon the Issuance of
Additional Units. We will make adjustments to
capital accounts upon the issuance of additional units. In doing
so, we will allocate any unrealized and, for tax purposes,
unrecognized gain or loss resulting from the adjustments to the
unitholders and the general partner in the same manner as we
allocate gain or loss upon liquidation. In the event that we
make positive adjustments to the capital accounts upon the
issuance of additional units, we will allocate any later
negative adjustments to the capital accounts resulting from the
issuance of additional units or upon our liquidation in a manner
which results, to the extent possible, in the general
partners capital account balances equaling the amount
which they would have been if no earlier positive adjustments to
the capital accounts had been made.
43
MATERIAL
INCOME TAX CONSIDERATIONS
This section is a summary of the material tax considerations
that may be relevant to prospective unitholders who are
individual citizens or residents of the United States and,
unless otherwise noted in the following discussion, is the
opinion of Vinson & Elkins L.L.P., counsel to our
general partner and us, insofar as it relates to legal
conclusions with respect to matters of U.S. federal income
tax law. This section is based upon current provisions of the
Internal Revenue Code of 1986, as amended (the Internal
Revenue Code), existing and proposed Treasury regulations
promulgated under the Internal Revenue Code (the Treasury
Regulations) and current administrative rulings and court
decisions, all of which are subject to change. Later changes in
these authorities may cause the tax consequences to vary
substantially from the consequences described below. Unless the
context otherwise requires, references in this section to
us or we are references to Energy
Transfer Partners, L.P. and our operating company.
The following discussion does not comment on all federal income
tax matters affecting us or our unitholders. Moreover, the
discussion focuses on unitholders who are individual citizens or
residents of the United States and has only limited application
to corporations, estates, trusts, nonresident aliens or other
unitholders subject to specialized tax treatment, such as
tax-exempt institutions, foreign persons, individual retirement
accounts (IRAs), real estate investment trusts (REITs) or mutual
funds. Accordingly, we encourage each prospective unitholder to
consult, and depend on, his own tax advisor in analyzing the
federal, state, local and foreign tax consequences particular to
him of the ownership or disposition of common units.
No ruling has been or will be requested from the IRS regarding
our characterization as a partnership for tax purposes. Instead,
we will rely on opinions of Vinson & Elkins L.L.P.
Unlike a ruling, an opinion of counsel represents only that
counsels best legal judgment and does not bind the IRS or
the courts. Accordingly, the opinions and statements made herein
may not be sustained by a court if contested by the IRS. Any
contest of this sort with the IRS may materially and adversely
impact the market for the common units and the prices at which
common units trade. In addition, the costs of any contest with
the IRS, principally legal, accounting and related fees, will
result in a reduction in cash available for distribution to our
unitholders and our general partner and thus will be borne
indirectly by our unitholders and our general partner.
Furthermore, the tax treatment of us, or of an investment in us,
may be significantly modified by future legislative or
administrative changes or court decisions. Any modifications may
or may not be retroactively applied.
All statements as to matters of law and legal conclusions, but
not as to factual matters, contained in this section, unless
otherwise noted, are the opinion of Vinson & Elkins
L.L.P. and are based on the accuracy of the representations made
by us.
For the reasons described below, Vinson & Elkins
L.L.P. has not rendered an opinion with respect to the following
specific federal income tax issues: (1) the treatment of a
unitholder whose common units are loaned to a short seller to
cover a short sale of common units (please read
Tax Consequences of Unit
Ownership Treatment of Short Sales);
(2) whether our monthly convention for allocating taxable
income and losses is permitted by existing Treasury Regulations
(please read Disposition of Common
Units Allocations Between Transferors and
Transferees); and (3) whether our method for
depreciating Section 743 adjustments is sustainable in
certain cases (please read Tax Consequences of
Unit Ownership Section 754 Election).
Partnership
Status
A partnership is not a taxable entity and incurs no federal
income tax liability. Instead, each partner of a partnership is
required to take into account his share of items of income,
gain, loss and deduction of the partnership in computing his
federal income tax liability, regardless of whether cash
distributions are made to him by the partnership. Distributions
by a partnership to a partner are generally not taxable to the
partnership or the partner unless the amount of cash distributed
to him is in excess of the partners adjusted basis in his
partnership interest.
44
Section 7704 of the Internal Revenue Code provides that
publicly traded partnerships will, as a general rule, be taxed
as corporations. However, an exception, referred to as the
Qualifying Income Exception, exists with respect to
publicly traded partnerships of which 90% or more of the gross
income for every taxable year consists of qualifying
income. Qualifying income includes income and gains
derived from the transportation, storage, processing and
marketing of crude oil, natural gas and products thereof,
including the retail and wholesale marketing of propane, certain
hedging activities and the transportation of propane and natural
gas liquids. Other types of qualifying income include interest
(other than from a financial business), dividends, gains from
the sale of real property and gains from the sale or other
disposition of capital assets held for the production of income
that otherwise constitutes qualifying income. We estimate that
less than 5% of our gross income is not qualifying income;
however, this estimate could change from time to time. Based
upon and subject to this estimate, the factual representations
made by us and our general partner and a review of the
applicable legal authorities, Vinson & Elkins L.L.P.
is of the opinion that at least 90% of our current gross income
constitutes qualifying income.
No ruling has been or will be sought from the IRS and the IRS
has made no determination as to our status or the status of the
operating partnership for federal income tax purposes. Instead,
we will rely on the opinion of Vinson & Elkins L.L.P.
on such matters. It is the opinion of Vinson & Elkins
L.L.P. that, based upon the Internal Revenue Code, its Treasury
Regulations, published revenue rulings and court decisions and
the representations described below, we will be classified as a
partnership and our operating company will be disregarded as an
entity separate from us for federal income tax purposes. In
rendering its opinion, Vinson & Elkins L.L.P. has
relied on factual representations made by us and our general
partner. The representations made by us and our general partner
upon which Vinson & Elkins L.L.P. has relied are:
(a) Except for Oasis Pipeline Company, we nor our operating
entities have elected or will elect to be treated as a
corporation;
(b) For each taxable year, more than 90% of our gross
income has been and will be income that Vinson &
Elkins L.L.P. has opined or will opine is qualifying
income within the meaning of Section 7704(d) of the
Internal Revenue Code; and
(c) Each hedging transaction that we treat as resulting in
qualifying income has been and will be appropriately identified
as a hedging transaction pursuant to applicable Treasury
Regulations, and has been and will be associated with oil, gas,
or products thereof that are held or to be held by us in
activities that Vinson & Elkins L.L.P. has opined or
will opine result in qualifying income.
We believe that these representations have been true in the past
and expect that these representations will be true in the future.
If we fail to meet the Qualifying Income Exception, other than a
failure that is determined by the IRS to be inadvertent and that
is cured within a reasonable time after discovery (in which case
the IRS may also require us to make adjustments with respect to
our unitholders or pay other amounts) we will be treated as if
we had transferred all of our assets, subject to liabilities, to
a newly formed corporation, on the first day of the year in
which we fail to meet the Qualifying Income Exception, in return
for stock in that corporation, and then distributed that stock
to the unitholders in liquidation of their interests in us. This
deemed contribution and liquidation should be tax-free to
unitholders and us so long as we, at that time, do not have
liabilities in excess of the tax basis of our assets.
Thereafter, we would be treated as a corporation for federal
income tax purposes.
If we were treated as an association taxable as a corporation in
any taxable year, either as a result of a failure to meet the
Qualifying Income Exception or otherwise, our items of income,
gain, loss and deduction would be reflected only on our tax
return rather than being passed through to our unitholders, and
our net income would be taxed to us at corporate rates. In
addition, any distribution made to a unitholder would be treated
as either taxable dividend income, to the extent of our current
or accumulated earnings and profits, or, in the absence of
earnings and profits, a nontaxable return of capital, to the
extent of the unitholders tax basis in his common units,
or taxable capital gain, after the unitholders tax basis
in his common units is reduced to zero. Accordingly, taxation as
a corporation would result in a material reduction in a
unitholders cash flow
45
and after-tax return and thus would likely result in a
substantial reduction of the value of the units. The discussion
below is based on Vinson & Elkins L.L.P.s
opinion that we will be classified as a partnership for federal
income tax purposes.
Limited
Partner Status
Unitholders who have become limited partners of Energy Transfer
Partners, L.P. will be treated as partners of Energy Transfer
Partners, L.P. for federal income tax purposes. Also:
(a) assignees who have executed and delivered transfer
applications, and are awaiting admission as limited
partners, and
(b) unitholders whose common units are held in street name
or by a nominee and who have the right to direct the nominee in
the exercise of all substantive rights attendant to the
ownership of their common units
will be treated as partners of Energy Transfer Partners, L.P.
for federal income tax purposes. As there is no direct or
indirect controlling authority addressing assignees of common
units who are entitled to execute and deliver transfer
applications and thereby become entitled to direct the exercise
of attendant rights, but who fail to execute and deliver
transfer applications, Vinson & Elkins L.L.P.s
opinion does not extend to these persons. Furthermore, a
purchaser or other transferee of common units who does not
execute and deliver a transfer application may not receive some
federal income tax information or reports furnished to record
holders of common units unless the common units are held in a
nominee or street name account and the nominee or broker has
executed and delivered a transfer application for those common
units. A beneficial owner of common units whose units have been
transferred to a short seller to complete a short sale would
appear to lose his status as a partner with respect to those
units for federal income tax purposes. Please read
Tax Consequences of Unit
Ownership Treatment of Short Sales. Income,
gain, deductions or losses would not appear to be reportable by
a unitholder who is not a partner for federal income tax
purposes, and any cash distributions received by a unitholder
who is not a partner for federal income tax purposes would
therefore appear to be fully taxable as ordinary income. These
holders are urged to consult their own tax advisors with respect
to their tax consequences of holding common units in Energy
Transfer Partners, L.P.
Tax
Consequences of Unit Ownership
Flow-Through of Taxable Income. We will
not pay any federal income tax. Instead, each unitholder will be
required to report on his income tax return his share of our
income, gains, losses and deductions without regard to whether
we make cash distributions to him. Consequently, we may allocate
income to a unitholder even if he has not received a cash
distribution. Each unitholder will be required to include in
income his allocable share of our income, gains, losses and
deductions for our taxable year ending with or within his
taxable year. Our taxable year ends on December 31.
Treatment of
Distributions. Distributions by us to a
unitholder generally will not be taxable to the unitholder for
federal income tax purposes, except to the extent the amount of
any such cash distribution exceeds his tax basis in his common
units immediately before the distribution. Our cash
distributions in excess of a unitholders tax basis
generally will be considered to be gain from the sale or
exchange of the common units, taxable in accordance with the
rules described under Disposition of Common
Units below. Any reduction in a unitholders share of
our liabilities for which no partner, including the general
partner, bears the economic risk of loss, known as
nonrecourse liabilities, will be treated as a
distribution of cash to that unitholder. To the extent our
distributions cause a unitholders at risk
amount to be less than zero at the end of any taxable year, he
must recapture any losses deducted in previous years. Please
read Limitations on Deductibility of
Losses.
A decrease in a unitholders percentage interest in us
because of our issuance of additional common units will decrease
his share of our nonrecourse liabilities, and thus will result
in a corresponding deemed distribution of cash. This deemed
distribution may constitute a non-pro rata distribution. A
non-pro rata distribution of money or property may result in
ordinary income to a unitholder, regardless of his tax basis in
his common units, if the distribution reduces the
unitholders share of our unrealized
receivables, including
46
depreciation recapture,
and/or
substantially appreciated inventory items, both as
defined in the Internal Revenue Code, and collectively,
Section 751 Assets. To that extent, he will be
treated as having been distributed his proportionate share of
the Section 751 Assets and then having exchanged those
assets with us in return for the non-pro rata portion of the
actual distribution made to him. This latter deemed exchange
will generally result in the unitholders realization of
ordinary income, which will equal the excess of (1) the
non-pro rata portion of that distribution over (2) the
unitholders tax basis (generally zero) for the share of
Section 751 Assets deemed relinquished in the exchange.
Basis of Common Units. A
unitholders initial tax basis for his common units will be
the amount he paid for the common units plus his share of our
nonrecourse liabilities. That basis will be increased by his
share of our income and by any increases in his share of our
nonrecourse liabilities. That basis will be decreased, but not
below zero, by distributions from us, by the unitholders
share of our losses, by any decreases in his share of our
nonrecourse liabilities and by his share of our expenditures
that are not deductible in computing taxable income and are not
required to be capitalized. A unitholder will have no share of
our debt that is recourse to our general partner, but will have
a share, generally based on his share of profits, of our
nonrecourse liabilities. Please read
Disposition of Common Units
Recognition of Gain or Loss.
Limitations on Deductibility of
Losses. The deduction by a unitholder of his
share of our losses will be limited to the tax basis in his
units and, in the case of an individual unitholder estate,
trust, or a corporate unitholder (if more than 50% of the value
of the corporate unitholders stock is owned directly or
indirectly by or for five or fewer individuals or some
tax-exempt organizations) to the amount for which the unitholder
is considered to be at risk with respect to our
activities, if that is less than his tax basis. A common
unitholder subject to these allowances must recapture losses
deducted in previous years to the extent that distributions
cause his at risk amount to be less than zero at the end of any
taxable year. Losses disallowed to a unitholder or recaptured as
a result of these limitations will carry forward and will be
allowable as a deduction to the extent that his at-risk amount
is subsequently increased, provided such losses do not exceed
such common unitholders tax basis in his common units.
Upon the taxable disposition of a unit, any gain recognized by a
unitholder can be offset by losses that were previously
suspended by the at risk limitation but may not be offset by
losses suspended by the basis limitation. Any loss previously
suspended by the at-risk limitation in excess of that gain would
no longer be utilizable. In general, a unitholder will be at
risk to the extent of the tax basis of his units, excluding any
portion of that basis attributable to his share of our
nonrecourse liabilities, reduced by (i) any portion of that
basis representing amounts otherwise protected against loss
because of a guarantee, stop loss agreement or other similar
arrangement and (ii) any amount of money he borrows to
acquire or hold his units, if the lender of those borrowed funds
owns an interest in us, is related to the unitholder or can look
only to the units for repayment. A unitholders at risk
amount will increase or decrease as the tax basis of the
unitholders units increases or decreases, other than tax
basis increases or decreases attributable to increases or
decreases in his share of our nonrecourse liabilities.
In addition to the basis and at-risk limitations on the
deductibility of losses, the passive loss limitations generally
provide that individuals, estates, trusts and some closely-held
corporations and personal service corporations can deduct losses
from passive activities, which are generally trade or business
activities in which the taxpayer does not materially
participate, only to the extent of the taxpayers income
from those passive activities. The passive loss limitations are
applied separately with respect to each publicly traded
partnership. Consequently, any passive losses we generate will
only be available to offset our passive income generated in the
future and will not be available to offset income from other
passive activities or investments, including our investments or
investments in other publicly traded partnerships, or salary or
active business income. Passive losses that are not deductible
because they exceed a unitholders share of income we
generate may be deducted in full when he disposes of his entire
investment in us in a fully taxable transaction with an
unrelated party. The passive loss limitations are applied after
other applicable limitations on deductions, including the at
risk rules and the basis limitation.
A unitholders share of our net income may be offset by any
of our suspended passive losses, but it may not be offset by any
other current or carryover losses from other passive activities,
including those attributable to other publicly traded
partnerships.
47
Limitations on Interest Deductions. The
deductibility of a non-corporate taxpayers
investment interest expense is generally limited to
the amount of that taxpayers net investment
income. Investment interest expense includes:
|
|
|
|
|
interest on indebtedness properly allocable to property held for
investment;
|
|
|
|
our interest expense attributed to portfolio income; and
|
|
|
|
the portion of interest expense incurred to purchase or carry an
interest in a passive activity to the extent attributable to
portfolio income.
|
The computation of a unitholders investment interest
expense will take into account interest on any margin account
borrowing or other loan incurred to purchase or carry a unit.
Net investment income includes gross income from property held
for investment and amounts treated as portfolio income under the
passive loss rules, less deductible expenses, other than
interest, directly connected with the production of investment
income, but generally does not include gains attributable to the
disposition of property held for investment or qualified
dividend income. The IRS has indicated that the net passive
income earned by a publicly traded partnership will be treated
as investment income to its unitholders. In addition, the
unitholders share of our portfolio income will be treated
as investment income.
Entity-Level Collections. If we
are required or elect under applicable law to pay any federal,
state, local or foreign income tax on behalf of any unitholder
or our general partner or any former unitholder, we are
authorized to pay those taxes from our funds. That payment, if
made, will be treated as a distribution of cash to the
unitholder on whose behalf the payment was made. If the payment
is made on behalf of a person whose identity cannot be
determined, we are authorized to treat the payment as a
distribution to all current unitholders. We are authorized to
amend our partnership agreement in the manner necessary to
maintain uniformity of intrinsic tax characteristics of units
and to adjust later distributions, so that after giving effect
to these distributions, the priority and characterization of
distributions otherwise applicable under our partnership
agreement is maintained as nearly as is practicable. Payments by
us as described above could give rise to an overpayment of tax
on behalf of an individual unitholder in which event the
unitholder would be required to file a claim in order to obtain
a credit or refund.
Allocation of Income, Gain, Loss and
Deduction. In general, if we have a net
profit, our items of income, gain, loss and deduction will be
allocated among our general partner and the unitholders in
accordance with their percentage interests in us. At any time
that distributions are made to the common units in excess of
distributions to the subordinated units, or incentive
distributions are made to our general partner, gross income will
be allocated to the recipients to the extent of these
distributions. If we have a net loss, that loss will be
allocated first to our general partner and the unitholders in
accordance with their percentage interests in us to the extent
of their positive capital accounts and, second, to our general
partner. Specified items of our income, gain, loss and deduction
will be allocated to account for the difference between the tax
basis and fair market value of our assets at the time of an
offering, referred to in this discussion as Contributed
Property. The effect of these allocations, referred to as
Section 704(c) Allocations, to a unitholder purchasing
common units from us in an offering will be essentially the same
as if the tax bases of our assets were equal to their fair
market value at the time of this offering. In the event we issue
additional common units or engage in certain other transactions
in the future reverse Section 704(c)
Allocations, similar to the Section 704(c)
Allocations described above, will be made to all holders of
partnership interests immediately prior to such other
transactions, including purchasers of common units in this
offering, to account for the difference between the
book basis for purposes of maintaining capital
accounts and the fair market value of all property held by us at
the time of the future transaction. In addition, items of
recapture income will be allocated to the extent possible to the
unitholder who was allocated the deduction giving rise to the
treatment of that gain as recapture income in order to minimize
the recognition of ordinary income by some unitholders. Finally,
although we do not expect that our operations will result in the
creation of negative capital accounts, if negative capital
accounts nevertheless result, items of our income and gain will
be allocated in an amount and manner to eliminate the negative
balance as quickly as possible. An allocation of items of our
income, gain, loss or deduction, other than an allocation
required by the Internal Revenue Code to eliminate the
difference between a partners book capital
account, credited with the fair market value of Contributed
Property, and tax
48
capital account, credited with the tax basis of Contributed
Property, referred to in this discussion as the Book-Tax
Disparity, will generally be given effect for federal
income tax purposes in determining a partners share of an
item of income, gain, loss or deduction only if the allocation
has substantial economic effect. In any other case, a
partners share of an item will be determined on the basis
of his interest in us, which will be determined by taking into
account all the facts and circumstances, including:
|
|
|
|
|
his relative contributions to us;
|
|
|
|
the interests of all the partners in profits and losses;
|
|
|
|
the interest of all the partners in cash flow; and
|
|
|
|
the rights of all the partners to distributions of capital upon
liquidation.
|
Vinson & Elkins L.L.P. is of the opinion that, with
the exception of the issues described in
Section 754 Election and
Disposition of Common Units
Allocations Between Transferors and Transferees,
allocations under our partnership agreement will be given effect
for federal income tax purposes in determining a partners
share of an item of income, gain, loss or deduction.
Treatment of Short Sales. A unitholder
whose units are loaned to a short seller to cover a
short sale of units may be considered as having disposed of
those units. If so, he would no longer be treated for tax
purposes as a partner with respect to those units during the
period of the loan and may recognize gain or loss from the
disposition. As a result, during this period:
|
|
|
|
|
any of our income, gain, loss or deduction with respect to those
units would not be reportable by the unitholder;
|
|
|
|
any cash distributions received by the unitholder as to those
units would be fully taxable; and
|
|
|
|
all of these distributions would appear to be ordinary income.
|
Vinson & Elkins L.L.P. has not rendered an opinion
regarding the treatment of a unitholder where common units are
loaned to a short seller to cover a short sale of common units;
therefore, unitholders desiring to assure their status as
partners and avoid the risk of gain recognition from a loan to a
short seller are urged to modify any applicable brokerage
account agreements to prohibit their brokers from loaning their
units. The IRS has announced that it is actively studying issues
relating to the tax treatment of short sales of partnership
interests. Please also read Disposition of
Common Units Recognition of Gain or Loss.
Alternative Minimum Tax. Each
unitholder will be required to take into account his
distributive share of any items of our income, gain, loss or
deduction for purposes of the alternative minimum tax. The
current minimum tax rate for noncorporate taxpayers is 26% on
the first $175,000 of alternative minimum taxable income in
excess of the exemption amount and 28% on any additional
alternative minimum taxable income. Prospective unitholders are
urged to consult with their tax advisors as to the impact of an
investment in units on their liability for the alternative
minimum tax.
Tax Rates. Under current law, the
highest marginal U.S. federal income tax rate applicable to
ordinary income of individuals is 35% and the highest marginal
U.S. federal income tax rate applicable to long-term
capital gains (generally, capital gains on certain assets held
for more than 12 months) of individuals is 15%. However,
absent new legislation extending the current rates, beginning
January 1, 2011, the highest marginal U.S. federal
income tax rate applicable to ordinary income and long-term
capital gains of individuals will increase to 39.6% and 20%,
respectively. Moreover, these rates are subject to change by new
legislation at any time.
Section 754 Election. We have made
the election permitted by Section 754 of the Internal
Revenue Code. That election is irrevocable without the consent
of the IRS. The election will generally permit us to adjust a
common unit purchasers tax basis in our assets
(inside basis) under Section 743(b) of the
Internal Revenue Code to reflect his purchase price. This
election does not apply to a person who purchases common units
directly from us. The Section 743(b) adjustment belongs to
the purchaser and not to other unitholders. For purposes of this
discussion, a unitholders inside basis in our assets will
be considered to have two
49
components: (1) his share of our tax basis in our assets
(common basis) and (2) his Section 743(b)
adjustment to that basis.
Where the remedial allocation method is adopted (which we have
historically adopted as to all property other than certain
goodwill properties and which we will generally adopt as to all
properties going forward), the Treasury Regulations under
Section 743 of the Internal Revenue Code require a portion
of the Section 743(b) adjustment that is attributable to
recovery property under Section 168 of the Internal Revenue
Code whose book basis is in excess of its tax basis to be
depreciated over the remaining cost recovery period for the
propertys unamortized Book-Tax Disparity. Under Treasury
Regulation Section 1.167(c)-1(a)(6),
a Section 743(b) adjustment attributable to property
subject to depreciation under Section 167 of the Internal
Revenue Code, rather than cost recovery deductions under
Section 168, is generally required to be depreciated using
either the straightline method or the 150% declining balance
method. If we elect a method other than the remedial method, the
depreciation and amortization methods and useful lives
associated with the Section 743(b) adjustment, therefore,
may differ from the methods and useful lives generally used to
depreciate the inside basis in such properties. Under our
partnership agreement, our general partner is authorized to take
a position to preserve the uniformity of units even if that
position is not consistent with these and any other Treasury
Regulations. If we elect a method other than the remedial method
with respect to a goodwill property, the common basis of such
property is not amortizable. Please read
Uniformity of Units.
Although Vinson & Elkins L.L.P. is unable to opine as
to the validity of this approach because there is no direct or
indirect controlling authority on this issue, we intend to
depreciate the portion of a Section 743(b) adjustment
attributable to unrealized appreciation in the value of
Contributed Property, to the extent of any unamortized Book-Tax
Disparity, using a rate of depreciation or amortization derived
from the depreciation or amortization method and useful life
applied to the propertys unamortized Book-Tax Disparity,
or treat that portion as
non-amortizable
to the extent attributable to property which is not amortizable.
This method is consistent with the methods employed by other
publicly traded partnerships but is arguably inconsistent with
Treasury
Regulation Section 1.167(c)-1(a)(6),
which is not expected to directly apply to a material portion of
our assets, and Treasury
Regulation Section 1.197-2(g)(3).
To the extent this Section 743(b) adjustment is
attributable to appreciation in value in excess of the
unamortized Book-Tax Disparity, we will apply the rules
described in the Treasury Regulations and legislative history.
If we determine that this position cannot reasonably be taken,
we may take a depreciation or amortization position under which
all purchasers acquiring units in the same month would receive
depreciation or amortization, whether attributable to common
basis or a Section 743(b) adjustment, based upon the same
applicable rate as if they had purchased a direct interest in
our assets. This kind of aggregate approach may result in lower
annual depreciation or amortization deductions than would
otherwise be allowable to some unitholders. Please read
Uniformity of Units. A unitholders
tax basis for his common units is reduced by his share of our
deductions (whether or not such deductions were claimed on an
individuals income tax return) so that any position we
take that understates deductions will overstate the common
unitholders basis in his common units, which may cause the
unitholder to understate gain or overstate loss on any sale of
such units. Please read Disposition of Common
Units Recognition of Gain or Loss. The IRS may
challenge our position with respect to depreciating or
amortizing the Section 743(b) adjustment we take to
preserve the uniformity of the units. If such a challenge were
sustained, the gain from the sale of units might be increased
without the benefit of additional deductions.
A Section 754 election is advantageous if the
transferees tax basis in his units is higher than the
units share of the aggregate tax basis of our assets
immediately prior to the transfer. In that case, as a result of
the election, the transferee would have, among other items, a
greater amount of depreciation deductions and his share of any
gain or loss on a sale of our assets would be less. Conversely,
a Section 754 election is disadvantageous if the
transferees tax basis in his units is lower than those
units share of the aggregate tax basis of our assets
immediately prior to the transfer. Thus, the fair market value
of the units may be affected either favorably or unfavorably by
the election. A basis adjustment is required regardless of
whether a Section 754 election is made in the case of a
transfer of an interest in us if we have a substantial built-in
loss immediately after the transfer, or if we distribute
property and have a substantial basis reduction. Generally a
built-in loss or a basis reduction is substantial if it exceeds
$250,000.
50
The calculations involved in the Section 754 election are
complex and will be made on the basis of assumptions as to the
value of our assets and other matters. For example, the
allocation of the Section 743(b) adjustment among our
assets must be made in accordance with the Internal Revenue
Code. The IRS could seek to reallocate some or all of any
Section 743(b) adjustment allocated by us to our tangible
assets to goodwill instead. Goodwill, as an intangible asset, is
generally nonamortizable or amortizable over a longer period of
time or under a less accelerated method than our tangible
assets. We cannot assure you that the determinations we make
will not be successfully challenged by the IRS and that the
deductions resulting from them will not be reduced or disallowed
altogether. Should the IRS require a different basis adjustment
to be made, and should, in our opinion, the expense of
compliance exceed the benefit of the election, we may seek
permission from the IRS to revoke our Section 754 election.
If permission is granted, a subsequent purchaser of units may be
allocated more income than he would have been allocated had the
election not been revoked.
Tax
Treatment of Operations
Accounting Method and Taxable Year. We
use the year ending December 31 as our taxable year and the
accrual method of accounting for federal income tax purposes.
Each unitholder will be required to include in income his share
of our income, gain, loss and deduction for our taxable year
ending within or with his taxable year. In addition, a
unitholder who has a taxable year ending on a date other than
December 31 and who disposes of all of his units following the
close of our taxable year but before the close of his taxable
year must include his share of our income, gain, loss and
deduction in income for his taxable year, with the result that
he will be required to include in income for his taxable year
his share of more than one year of our income, gain, loss and
deduction. Please read Disposition of Common
Units Allocations Between Transferors and
Transferees.
Initial Tax Basis, Depreciation and
Amortization. The tax basis of our assets
will be used for purposes of computing depreciation and cost
recovery deductions and, ultimately, gain or loss on the
disposition of these assets. The federal income tax burden
associated with the difference between the fair market value of
our assets and their tax basis immediately prior to an offering
will be borne by our partners holding interest in us prior to
such offering. Please read Tax Consequences of Unit
Ownership Allocation of Income, Gain, Loss and
Deduction.
To the extent allowable, we may elect to use the depreciation
and cost recovery methods that will result in the largest
deductions being taken in the early years after assets subject
to these allowances are placed in service. Because our general
partner may determine not to adopt the remedial method of
allocation with respect to any difference between the tax basis
and the fair market value of goodwill immediately prior to this
or any future offering, we may not be entitled to any
amortization deductions with respect to any goodwill properties
conveyed to us on formation or held by us at the time of any
future offering. Please read Uniformity of
Units. Property we subsequently acquire or construct may
be depreciated using accelerated methods permitted by the
Internal Revenue Code.
If we dispose of depreciable property by sale, foreclosure or
otherwise, all or a portion of any gain, determined by reference
to the amount of depreciation previously deducted and the nature
of the property, may be subject to the recapture rules and taxed
as ordinary income rather than capital gain. Similarly, a
unitholder who has taken cost recovery or depreciation
deductions with respect to property we own will likely be
required to recapture some or all of those deductions as
ordinary income upon a sale of his interest in us. Please read
Tax Consequences of Unit Ownership
Allocation of Income, Gain, Loss and Deduction and
Disposition of Common Units
Recognition of Gain or Loss.
The costs incurred in selling our units (called
syndication expenses) must be capitalized and cannot
be deducted currently, ratably or upon our termination. There
are uncertainties regarding the classification of costs as
organization expenses, which may be amortized by us, and as
syndication expenses, which may not be amortized by us. The
underwriting discounts and commissions we incur will be treated
as syndication expenses.
Valuation and Tax Basis of Our
Properties. The federal income tax
consequences of the ownership and disposition of units will
depend in part on our estimates of the relative fair market
values, and the initial tax
51
bases, of our assets. Although we may from time to time consult
with professional appraisers regarding valuation matters, we
will make many of the relative fair market value estimates
ourselves. These estimates and determinations of basis are
subject to challenge and will not be binding on the IRS or the
courts. If the estimates of fair market value or basis are later
found to be incorrect, the character and amount of items of
income, gain, loss or deductions previously reported by
unitholders might change, and unitholders might be required to
adjust their tax liability for prior years and incur interest
and penalties with respect to those adjustments.
Disposition
of Common Units
Recognition of Gain or Loss. Gain or
loss will be recognized on a sale of units equal to the
difference between the amount realized and the unitholders
tax basis for the units sold. A unitholders amount
realized will be measured by the sum of the cash or the fair
market value of other property received by him plus his share of
our nonrecourse liabilities. Because the amount realized
includes a unitholders share of our nonrecourse
liabilities, the gain recognized on the sale of units could
result in a tax liability in excess of any cash received from
the sale.
Prior distributions from us in excess of cumulative net taxable
income for a common unit that decreased a unitholders tax
basis in that common unit will, in effect, become taxable income
if the common unit is sold at a price greater than the
unitholders tax basis in that common unit, even if the
price received is less than his original cost.
Except as noted below, gain or loss recognized by a unitholder,
other than a dealer in units, on the sale or
exchange of a unit will generally be taxable as capital gain or
loss. Capital gain recognized by an individual on the sale of
units held for more than twelve months will generally be taxed
at a maximum U.S. federal income tax rate of 15% through
December 31, 2010 and 20% thereafter (absent new
legislation extending or adjusting the current rate). However, a
portion of this gain or loss, which will likely be substantial,
will be separately computed and taxed as ordinary income or loss
under Section 751 of the Internal Revenue Code to the
extent attributable to assets giving rise to depreciation
recapture or other unrealized receivables or to
inventory items we own. The term unrealized
receivables includes potential recapture items, including
depreciation recapture. Ordinary income attributable to
unrealized receivables, inventory items and depreciation
recapture may exceed net taxable gain realized upon the sale of
a unit and may be recognized even if there is a net taxable loss
realized on the sale of a unit. Thus, a unitholder may recognize
both ordinary income and a capital loss upon a sale of units.
Net capital losses may offset capital gains and no more than
$3,000 of ordinary income, in the case of individuals, and may
only be used to offset capital gains in the case of corporations.
The IRS has ruled that a partner who acquires interests in a
partnership in separate transactions must combine those
interests and maintain a single adjusted tax basis for all those
interests. Upon a sale or other disposition of less than all of
those interests, a portion of that tax basis must be allocated
to the interests sold using an equitable
apportionment method, which generally means that the tax
basis allocated to the interest sold equals an amount that bears
the same relation to the partners tax basis in his entire
interest in the partnership as the value of the interest sold
bears to the value of the partners entire interest in the
partnership. Treasury Regulations under Section 1223 of the
Internal Revenue Code allow a selling unitholder who can
identify common units transferred with an ascertainable holding
period to elect to use the actual holding period of the common
units transferred. Thus, according to the ruling, a common
unitholder will be unable to select high or low basis common
units to sell as would be the case with corporate stock, but,
according to the Treasury Regulations, may designate specific
common units sold for purposes of determining the holding period
of units transferred. A unitholder electing to use the actual
holding period of common units transferred must consistently use
that identification method for all subsequent sales or exchanges
of common units. A unitholder considering the purchase of
additional units or a sale of common units purchased in separate
transactions is urged to consult his tax advisor as to the
possible consequences of this ruling and application of the
Treasury Regulations.
52
Specific provisions of the Internal Revenue Code affect the
taxation of some financial products and securities, including
partnership interests, by treating a taxpayer as having sold an
appreciated partnership interest, one in which gain
would be recognized if it were sold, assigned or terminated at
its fair market value, if the taxpayer or related persons
enter(s) into:
|
|
|
|
|
a short sale;
|
|
|
|
an offsetting notional principal contract; or
|
|
|
|
a futures or forward contract with respect to the partnership
interest or substantially identical property.
|
Moreover, if a taxpayer has previously entered into a short
sale, an offsetting notional principal contract or a futures or
forward contract with respect to the partnership interest, the
taxpayer will be treated as having sold that position if the
taxpayer or a related person then acquires the partnership
interest or substantially identical property. The Secretary of
the Treasury is also authorized to issue regulations that treat
a taxpayer that enters into transactions or positions that have
substantially the same effect as the preceding transactions as
having constructively sold the financial position.
Allocations Between Transferors and
Transferees. In general, our taxable income
and losses will be determined annually, will be prorated on a
monthly basis and will be subsequently apportioned among the
unitholders in proportion to the number of units owned by each
of them as of the opening of the applicable exchange on the
first business day of the month, which we refer to in this
prospectus as the Allocation Date. However, gain or
loss realized on a sale or other disposition of our assets other
than in the ordinary course of business will be allocated among
the unitholders on the Allocation Date in the month in which
that gain or loss is recognized. As a result, a unitholder
transferring units may be allocated income, gain, loss and
deduction realized after the date of transfer.
Although simplifying conventions are contemplated by the
Internal Revenue Code and most publicly traded partnerships use
similar simplifying conventions, the use of this method may not
be permitted under existing Treasury Regulations. Accordingly,
Vinson & Elkins L.L.P. is unable to opine on the
validity of this method of allocating income and deductions
between transferor and transferee unitholders. If this method is
not allowed under the Treasury Regulations, or only applies to
transfers of less than all of the unitholders interest,
our taxable income or losses might be reallocated among the
unitholders. We are authorized to revise our method of
allocation between transferor and transferee unitholders, as
well as unitholders whose interests vary during a taxable year,
to conform to a method permitted under future Treasury
Regulations. A unitholder who owns units at any time during a
quarter and who disposes of them prior to the record date set
for a cash distribution for that quarter will be allocated items
of our income, gain, loss and deductions attributable to that
quarter but will not be entitled to receive that cash
distribution.
Notification Requirements. A unitholder
who sells any of his units is generally required to notify us in
writing of that sale within 30 days after the sale (or, if
earlier, January 15 of the year following the sale). A purchaser
of units who purchases units from another unitholder is also
generally required to notify us in writing of that purchase
within 30 days after the purchase. Upon receiving such
notifications, we are required to notify the IRS of that
transaction and to furnish specified information to the
transferor and transferee. Failure to notify us of a purchase
may, in some cases, lead to the imposition of penalties.
However, these reporting requirements do not apply to a sale by
an individual who is a citizen of the United States and who
effects the sale or exchange through a broker who will satisfy
such requirements.
Constructive Termination. We will be
considered to have been terminated for tax purposes if there are
sales or exchanges which, in the aggregate, constitute 50% or
more of the total interests in our capital and profits within a
twelve-month period. For purposes of measuring whether the 50%
threshold is reached, multiple sales of the same interest are
counted only once. A constructive termination results in the
closing of our taxable year for all unitholders. In the case of
a unitholder reporting on a taxable year other than a fiscal
year ending December 31, the closing of our taxable year
may result in more than twelve months of our taxable income or
loss being includable in his taxable income for the year of
termination. A constructive termination occurring on a date
other than December 31 will result in us filing two tax returns
(and unitholders receiving two Schedules K-1) for one fiscal
year and the cost of the preparation of these returns will be
borne
53
by all common unitholders. We would be required to make new tax
elections after a termination, including a new election under
Section 754 of the Internal Revenue Code, and a termination
would result in a deferral of our deductions for depreciation. A
termination could also result in penalties if we were unable to
determine that the termination had occurred. Moreover, a
termination might either accelerate the application of, or
subject us to, any tax legislation enacted before the
termination.
Uniformity
of Units
Because we cannot match transferors and transferees of units, we
must maintain uniformity of the economic and tax characteristics
of the units to a purchaser of these units. In the absence of
uniformity, we may be unable to completely comply with a number
of federal income tax requirements, both statutory and
regulatory. A lack of uniformity can result from a literal
application of Treasury
Regulation Section 1.167(c)-1(a)(6)
and Treasury
Regulation Section 1.197-2(g)(3).
Any non-uniformity could have a negative impact on the value of
the units. Please read Tax Consequences of
Unit Ownership Section 754 Election.
We intend to depreciate the portion of a Section 743(b)
adjustment attributable to unrealized appreciation in the value
of Contributed Property, to the extent of any unamortized
Book-Tax Disparity, using a rate of depreciation or amortization
derived from the depreciation or amortization method and useful
life applied to the propertys unamortized Book-Tax
Disparity, or treat that portion as nonamortizable, to the
extent attributable to property the common basis of which is not
amortizable, consistent with the Treasury Regulations under
Section 743 of the Internal Revenue Code, even though that
position may be inconsistent with Treasury
Regulation Section 1.167(c)-1(a)(6),
which is not expected to directly apply to a material portion of
our assets, and Treasury
Regulation Section 1.197-2(g)(3).
Please read Tax Consequences of Unit
Ownership Section 754 Election. To the
extent that the Section 743(b) adjustment is attributable
to appreciation in value in excess of the unamortized Book-Tax
Disparity, we will apply the rules described in the Treasury
Regulations and legislative history. If we determine that this
position cannot reasonably be taken, we may adopt a depreciation
and amortization position under which all purchasers acquiring
units in the same month would receive depreciation and
amortization deductions, whether attributable to a common basis
or Section 743(b) adjustment, based upon the same
applicable rate as if they had purchased a direct interest in
our property. If this position is adopted, it may result in
lower annual depreciation and amortization deductions than would
otherwise be allowable to some unitholders and risk the loss of
depreciation and amortization deductions not taken in the year
that these deductions are otherwise allowable. This position
will not be adopted if we determine that the loss of
depreciation and amortization deductions will have a material
adverse effect on the unitholders. If we choose not to utilize
this aggregate method, we may use any other reasonable
depreciation and amortization method to preserve the uniformity
of the intrinsic tax characteristics of any units that would not
have a material adverse effect on the unitholders. The IRS may
challenge any method of depreciating the Section 743(b)
adjustment described in this paragraph. If this challenge were
sustained, the uniformity of units might be affected, and the
gain from the sale of units might be increased without the
benefit of additional deductions. Please read
Disposition of Common Units
Recognition of Gain or Loss.
Tax-Exempt
Organizations and Other Investors
Ownership of units by employee benefit plans, other tax-exempt
organizations, non-resident aliens, foreign corporations and
other foreign persons raises issues unique to those investors
and, as described below, may have substantially adverse tax
consequences to them. 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.
Employee benefit plans and most other organizations exempt from
federal income tax, including individual retirement accounts and
other retirement plans, are subject to federal income tax on
unrelated business taxable income. Virtually all of our income
allocated to a unitholder that is a tax-exempt organization will
be unrelated business taxable income and will be taxable to them.
54
Non-resident aliens and foreign corporations, trusts or estates
that own units will be considered to be engaged in business in
the United States because of the ownership of units. As a
consequence, they will be required to file federal tax returns
to report their share of our income, gain, loss or deduction and
pay federal income tax at regular rates on their share of our
net income or gain. Moreover, under rules applicable to publicly
traded partnerships, we will withhold at the highest applicable
effective tax rate from cash distributions made quarterly to
foreign unitholders. Each foreign unitholder must obtain a
taxpayer identification number from the IRS and submit that
number to our transfer agent on a
Form W-8BEN
or applicable substitute form in order to obtain credit for
these withholding taxes. A change in applicable law may require
us to change these procedures.
In addition, because a foreign corporation that owns units will
be treated as engaged in a United States trade or business, that
corporation may be subject to the United States branch profits
tax at a rate of 30%, in addition to regular federal income tax,
on its share of our income and gain, as adjusted for changes in
the foreign corporations U.S. net equity,
which is effectively connected with the conduct of a United
States trade or business. That tax may be reduced or eliminated
by an income tax treaty between the United States and the
country in which the foreign corporate unitholder is a
qualified resident. In addition, this type of
unitholder is subject to special information reporting
requirements under Section 6038C of the Internal Revenue
Code.
A foreign unitholder who sells or otherwise disposes of a common
unit will be subject to U.S. federal income tax on gain
realized from the sale or disposition of that unit to the extent
the gain is effectively connected with a U.S. trade or
business of the foreign unitholder. Under a ruling published by
the IRS, interpreting the scope of effectively connected
income, a foreign unitholder would be considered to be
engaged in a trade or business in the U.S. by virtue of the
U.S. activities of the partnership, and part or all of that
unitholders gain would be effectively connected with that
unitholders indirect U.S. trade or business.
Moreover, under the Foreign Investment in Real Property Tax Act,
a foreign common unitholder generally will be subject to
U.S. federal income tax upon the sale or disposition of a
common unit if (i) he owned (directly or constructively
applying certain attribution rules) more than 5% of our common
units at any time during the five-year period ending on the date
of such disposition and (ii) 50% or more of the fair market
value of all of our assets consisted of U.S. real property
interests at any time during the shorter of the period during
which such unitholder held the common units or the
5-year
period ending on the date of disposition. Currently, more than
50% of our assets consist of U.S. real property interests
and we do not expect that to change in the foreseeable future.
Therefore, foreign unitholders may be subject to federal income
tax on gain from the sale or disposition of their units.
Administrative
Matters
Information Returns and Audit
Procedures. We intend to furnish to each
unitholder, within 90 days after the close of each calendar
year, specific tax information, including a
Schedule K-1,
which describes his share of our income, gain, loss and
deduction for our preceding taxable year. In preparing this
information, which will not be reviewed by counsel, we will take
various accounting and reporting positions, some of which have
been mentioned earlier, to determine each unitholders
share of income, gain, loss and deduction. We cannot assure you
that those positions will yield a result that conforms to the
requirements of the Internal Revenue Code, Treasury Regulations
or administrative interpretations of the IRS. Neither we nor
Vinson & Elkins L.L.P. can assure prospective
unitholders that the IRS will not successfully contend in court
that those positions are impermissible. Any challenge by the IRS
could negatively affect the value of the units. The IRS may
audit our federal income tax information returns. Adjustments
resulting from an IRS audit may require each unitholder to
adjust a prior years tax liability, and possibly may
result in an audit of his return. Any audit of a
unitholders return could result in adjustments not related
to our returns as well as those related to our returns.
Partnerships generally are treated as separate entities for
purposes of federal tax audits, judicial review of
administrative adjustments by the IRS and tax settlement
proceedings. The tax treatment of partnership items of income,
gain, loss and deduction are determined in a partnership
proceeding rather than in separate proceedings with the
partners. The Internal Revenue Code requires that one partner be
designated as the Tax
55
Matters Partner for these purposes. Our partnership
agreement names our general partner as our Tax Matters Partner.
The Tax Matters Partner will make some elections on our behalf
and on behalf of unitholders. In addition, the Tax Matters
Partner can extend the statute of limitations for assessment of
tax deficiencies against unitholders for items in our returns.
The Tax Matters Partner may bind a unitholder with less than a
1% profits interest in us to a settlement with the IRS unless
that unitholder elects, by filing a statement with the IRS, not
to give that authority to the Tax Matters Partner. The Tax
Matters Partner may seek judicial review, by which all the
unitholders are bound, of a final partnership administrative
adjustment and, if the Tax Matters Partner fails to seek
judicial review, judicial review may be sought by any unitholder
having at least a 1% interest in profits or by any group of
unitholders having in the aggregate at least a 5% interest in
profits. However, only one action for judicial review will go
forward, and each unitholder with an interest in the outcome may
participate.
A unitholder must file a statement with the IRS identifying the
treatment of any item on his federal income tax return that is
not consistent with the treatment of the item on our return.
Intentional or negligent disregard of this consistency
requirement may subject a unitholder to substantial penalties.
Nominee Reporting. Persons who hold an
interest in us as a nominee for another person are required to
furnish to us:
(a) the name, address and taxpayer identification number of
the beneficial owner and the nominee;
(b) whether the beneficial owner is:
1. a person that is not a United States person;
2. a foreign government, an international organization or
any wholly owned agency or instrumentality of either of the
foregoing; or
3. a tax-exempt entity;
(c) the amount and description of units held, acquired or
transferred for the beneficial owner; and
(d) specific information including the dates of
acquisitions and transfers, means of acquisitions and transfers,
and acquisition cost for purchases, as well as the amount of net
proceeds from sales. Brokers and financial institutions are
required to furnish additional information, including whether
they are United States persons and specific information on units
they acquire, hold or transfer for their own account. A penalty
of $50 per failure, up to a maximum of $100,000 per calendar
year, is imposed by the Internal Revenue Code for failure to
report that information to us. The nominee is required to supply
the beneficial owner of the units with the information furnished
to us.
Accuracy-Related Penalties. An
additional tax equal to 20% of the amount of any portion of an
underpayment of tax that is attributable to one or more
specified causes, including negligence or disregard of rules or
regulations, substantial understatements of income tax and
substantial valuation misstatements, is imposed by the Internal
Revenue Code. No penalty will be imposed, however, for any
portion of an underpayment if it is shown that there was a
reasonable cause for that portion and that the taxpayer acted in
good faith regarding that portion.
For individuals, a substantial understatement of income tax in
any taxable year exists if the amount of the understatement
exceeds the greater of 10% of the tax required to be shown on
the return for the taxable year or $5,000. The amount of any
understatement subject to penalty generally is reduced if any
portion is attributable to a position adopted on the return:
(1) for which there is, or was, substantial
authority; or
(2) as to which there is a reasonable basis and the
pertinent facts of that position are disclosed on the return.
56
If any item of income, gain, loss or deduction included in the
distributive shares of unitholders might result in that kind of
an understatement of income for which no
substantial authority exists, we must disclose the
pertinent facts on our return. In addition, we will make a
reasonable effort to furnish sufficient information for
unitholders to make adequate disclosure on their returns and to
take other actions as may be appropriate to permit unitholders
to avoid liability for this penalty. More stringent rules apply
to tax shelters, which we do not believe includes
us, or any of our investments, plans or arrangements.
A substantial valuation misstatement exists if (a) the
value of any property, or the tax basis of any property, claimed
on a tax return is 150% or more of the amount determined to be
the correct amount of the valuation or tax basis, (b) the
price for any property or services (or for the use of property)
claimed on any such return with respect to any transaction
between persons described in Internal Revenue Code
Section 482 is 200% or more (or 50% or less) of the amount
determined under Section 482 to be the correct amount of
such price, or (c) the net Internal Revenue Code
Section 482 transfer price adjustment for the taxable year
exceeds the lesser of $5 million or 10% of the
taxpayers gross receipts. No penalty is imposed unless the
portion of the underpayment attributable to a substantial
valuation misstatement exceeds $5,000 ($10,000 for a corporation
other than an S Corporation or a personal holding company).
The penalty is increased to 40% in the event of a gross
valuation misstatement. We do not anticipate making any
valuation misstatements.
Reportable Transactions. If we were to
engage in a reportable transaction, we (and possibly
you and others) would be required to make a detailed disclosure
of the transaction to the IRS. A transaction may be a reportable
transaction based upon any of several factors, including the
fact that it is a type of tax avoidance transaction publicly
identified by the IRS as a listed transaction or
that it produces certain kinds of losses for partnerships,
individuals, S corporations, and trusts in excess of
$2 million in any single year, or $4 million in any
combination of 6 successive tax years. Our participation in a
reportable transaction could increase the likelihood that our
federal income tax information return (and possibly your tax
return) would be audited by the IRS. Please read
Information Returns and Audit Procedures.
Moreover, if we were to participate in a reportable transaction
with a significant purpose to avoid or evade tax, or in any
listed transaction, you may be subject to the following
provisions of the American Jobs Creation Act of 2004:
|
|
|
|
|
accuracy-related penalties with a broader scope, significantly
narrower exceptions, and potentially greater amounts than
described above at Accuracy-Related
Penalties,
|
|
|
|
for those persons otherwise entitled to deduct interest on
federal tax deficiencies, nondeductibility of interest on any
resulting tax liability and
|
|
|
|
in the case of a listed transaction, an extended statute of
limitations.
|
We do not expect to engage in any reportable
transactions.
State,
Local, Foreign and Other Tax Considerations
In addition to federal income taxes, you likely will be subject
to other taxes, such as state, local and foreign income taxes,
unincorporated business taxes, and estate, inheritance or
intangible taxes that may be imposed by the various
jurisdictions in which we conduct business or own property or in
which you are a resident. Although an analysis of those various
taxes is not presented here, each prospective unitholder should
consider their potential impact on his investment in us. We will
currently own property or conduct business in more than
40 states. Most of these states impose an income tax on
individuals, corporations and other entities. We may also own
property or do business in other jurisdictions in the future.
Although you may not be required to file a return and pay taxes
in some jurisdictions because your income from that jurisdiction
falls below the filing and payment requirement, you will be
required to file income tax returns and to pay income taxes in
many of these jurisdictions in which we do business or own
property and may be subject to penalties for failure to comply
with those requirements. In some jurisdictions, tax losses may
not produce a tax benefit in the year incurred and may not be
available to offset income in subsequent taxable years. Some of
the jurisdictions may require us, or we may elect, to withhold a
percentage of income from amounts to be distributed to a
unitholder who is not a resident of the jurisdiction.
Withholding, the amount of which may be
57
greater or less than a particular unitholders income tax
liability to the jurisdiction, generally does not relieve a
nonresident unitholder from the obligation to file an income tax
return. Amounts withheld will be treated as if distributed to
unitholders for purposes of determining the amounts distributed
by us. Please read Tax Consequences of Unit
Ownership Entity-Level Collections. Based
on current law and our estimate of our future operations, our
general partner anticipates that any amounts required to be
withheld will not be material.
It is the responsibility of each unitholder to investigate the
legal and tax consequences, under the laws of pertinent
jurisdictions, of his investment in us. Accordingly, each
prospective unitholder is urged to consult, and depend upon, his
tax counsel or other advisor with regard to those matters.
Further, it is the responsibility of each unitholder to file all
state, local and foreign, as well as United States federal tax
returns, that may be required of him. Vinson & Elkins
L.L.P. has not rendered an opinion on the state, local or
foreign tax consequences of an investment in us.
58
SELLING
UNITHOLDER
This prospectus covers the offering for resale of up to
12,000,000 of our common units by the selling unitholder
identified below. No offer or sale may occur unless this
prospectus has been declared effective by the SEC, and remains
effective at the time such selling unitholder offers or sells
such common units. We are required to update this prospectus to
reflect material developments in our business, financial
position and results of operations.
The following table sets forth certain information regarding the
selling unitholders beneficial ownership of our common
stock as of June 16, 2009. The information presented below
is based solely on our review of information provided by the
selling unitholder.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Percentage of
|
|
|
Number of
|
|
|
Number of Common
|
|
|
|
Common Units
|
|
|
Common Units
|
|
|
Common Units
|
|
|
Units Beneficially
|
|
|
|
Beneficially
|
|
|
Beneficially
|
|
|
That May be
|
|
|
Owned After
|
|
Name of Selling Unitholder
|
|
Owned
|
|
|
Owned
|
|
|
Sold(1)
|
|
|
Offering
|
|
|
Energy Transfer Equity, L.P.(2)
|
|
|
62,500,797
|
|
|
|
37
|
%
|
|
|
12,000,000
|
|
|
|
50,500,797
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Because the selling unitholder may sell all or a portion of the
common units registered hereby, we cannot estimate the number or
percentage of common units that the selling unitholder will hold
upon completion of the offering. Accordingly, the information
presented in this table assumes that the selling unitholder will
sell all of its common units registered pursuant hereto. |
|
(2) |
|
Energy Transfer Equity, L.P. (ETE) is a publicly
traded limited partnership and its common units are publicly
traded on the New York Stock Exchange under the ticker symbol
ETE. Its only cash generating assets are its direct
and indirect investments in limited partner and general partner
interests in us. Its direct and indirect ownership in us
consists of 62,500,797 common units, a 2% general partner
interest in us (through its sole ownership of Energy Transfer
Partners GP, L.P., our general partner) and 100% of our
incentive distribution rights. ETEs principal executive
offices are located at 3738 Oak Lawn Avenue, Dallas, Texas 75219. |
Any prospectus supplement reflecting a sale of common units
hereunder will set forth, with respect to the selling unitholder:
|
|
|
|
|
the name of the selling unitholder;
|
|
|
|
the nature of the position, office or other material
relationship which the selling unitholder will have had within
the prior three years with us or any of our affiliates;
|
|
|
|
the number of common units owned by the selling unitholder prior
to the offering;
|
|
|
|
the amount or number of common units to be offered for the
selling unitholders account; and
|
|
|
|
the amount and (if one percent or more) the percentage of common
units to be owned by the selling unitholder after the completion
of the offering.
|
All expenses incurred with the registration of the common units
owned by the selling unitholder will be borne by us.
59
INVESTMENTS
IN US BY EMPLOYEE BENEFIT PLANS
An investment in our units or debt securities by an employee
benefit plan is subject to certain additional considerations
because the investments of such plans are subject to the
fiduciary responsibility and prohibited transaction provisions
of the Employee Retirement Income Security Act of 1974, as
amended, or ERISA, and restrictions imposed by Section 4975
of the Internal Revenue Code of 1986, as amended, or the Code,
and provisions under any federal, state, local,
non-U.S. or
other laws or regulations that are similar to such provisions of
the Internal Revenue Code or ERISA, which we refer to
collectively as Similar Laws. As used herein, the term
employee benefit plan includes, but is not limited
to, qualified pension, profit-sharing and stock bonus plans,
Keogh plans, simplified employee pension plans and tax deferred
annuities or individual retirement accounts or other
arrangements established or maintained by an employer or
employee organization, and entities whose underlying assets are
considered to include plan assets of such plans,
accounts and arrangements.
General
Fiduciary Matters
ERISA and the Code impose certain duties on persons who are
fiduciaries of an employee benefit plan that is subject to
Title I of ERISA or Section 4975 of the Code, which we
refer to as an ERISA Plan, and prohibit certain transactions
involving the assets of an ERISA Plan and its fiduciaries or
other interested parties. Under ERISA and the Code, any person
who exercises any discretionary authority or control over the
administration of such an ERISA Plan or the management or
disposition of the assets of such an ERISA Plan, or who renders
investment advice for a fee or other compensation to such an
ERISA Plan, is generally considered to be a fiduciary of the
ERISA Plan. In considering an investment in our units or debt
securities, among other things, consideration should be given to
(a) whether such investment is prudent under
Section 404(a)(1)(B) of ERISA and any other applicable
Similar Laws; (b) whether in making such investment, such
plan will satisfy the diversification requirement of
Section 404(a)(1)(C) of ERISA and any other applicable
Similar Laws; (c) whether making such an investment will
comply with the delegation of control and prohibited transaction
provisions of ERISA, the Code and any other applicable Similar
Laws. and (d) whether such investment will result in
recognition of unrelated business taxable income by such plan
and, if so, the potential after-tax investment return. Please
read Material Income Tax Considerations. The person
with investment discretion with respect to the assets of an
employee benefit plan, which we refer to as a fiduciary, should
determine whether an investment in our units or debt securities
is authorized by the appropriate governing instrument and is a
proper investment for such plan.
Prohibited
Transaction Issues
Section 406 of ERISA and Section 4975 of the Code
(which also applies to IRAs that are not considered part of an
employee benefit plan) prohibit an employee benefit plan from
engaging in certain transactions involving plan
assets with parties that are parties in
interest under ERISA or disqualified persons
under the Code with respect to the plan, unless an exemption is
available. A party in interest or disqualified person who
engages in a non-exempt prohibited transaction may be subject to
excise taxes and other penalties and liabilities under ERISA and
the Code. In addition, the fiduciary of the ERISA Plan that
engaged in such a non-exempt prohibited transaction may be
subject to penalties and liabilities under ERISA and the Code.
The acquisition
and/or
holding of the debt securities by an ERISA Plan with respect to
which we or the initial purchasers are considered a party in
interest or a disqualified person, may constitute or result in a
direct or indirect prohibited transaction under Section 406
of ERISA
and/or
Section 4975 of the Code, unless the debt securities are
acquired and held in accordance with an applicable statutory,
class or individual prohibited transaction exemption. In this
regard, the U.S. Department of Labor has issued prohibited
transaction class exemptions, or PTCEs, that may apply to the
acquisition, holding and, if applicable, conversion of the debt
securities. These class exemptions include, without limitation,
PTCE 84-14
respecting transactions determined by independent qualified
professional asset managers,
PTCE 90-1
respecting insurance company pooled separate accounts,
PTCE 91-38
respecting bank collective investment funds,
PTCE 95-60
respecting life insurance company general accounts and
PTCE 96-23
respecting transactions determined by in-house asset managers.
There can be no assurance that all of the conditions of any such
exemptions will be satisfied.
60
Because of the foregoing, the debt securities should not be
purchased or held (or converted to equity securities, in the
case of any convertible debt) by any person investing plan
assets of any employee benefit plan, unless such purchase
and holding (or conversion, if any) will not constitute a
non-exempt prohibited transaction under ERISA and the Code or
similar violation of any applicable Similar Laws.
Representation
Accordingly, by acceptance of the debt securities, each
purchaser and subsequent transferee of the debt securities will
be deemed to have represented and warranted that either
(i) no portion of the assets used by such purchaser or
transferee to acquire and hold the notes constitutes assets of
any employee benefit plan or (ii) the purchase and holding
(and any conversion, if applicable) of the notes by such
purchaser or transferee will not constitute a non-exempt
prohibited transaction under Section 406 of ERISA or
Section 4975 of the Code or similar violation under any
applicable Similar Laws.
Plan
Asset Issues
In addition to considering whether the purchase of our limited
partnership units or debt securities is a prohibited
transaction, a fiduciary of an employee benefit plan should
consider whether such plan will, by investing in our units or
debt securities, be deemed to own an undivided interest in our
assets, with the result that our general partner also would be a
fiduciary of such plan and our operations would be subject to
the regulatory restrictions of ERISA, including its prohibited
transaction rules, as well as the prohibited transaction rules
of the Code and any other applicable Similar Laws.
The Department of Labor regulations provide guidance with
respect to whether the assets of an entity in which employee
benefit plans acquire equity interests would be deemed
plan assets under certain circumstances. Pursuant to
these regulations, an entitys assets would not be
considered to be plan assets if, among other things,
(a) the equity interest acquired by employee benefit plans
are publicly offered securities i.e., the equity
interests are widely held by 100 or more investors independent
of the issuer and each other, freely transferable and registered
pursuant to certain provisions of the federal securities laws,
(b) the entity is an operating
company i.e., it is primarily engaged in the
production or sale of a product or service other than the
investment of capital either directly or through a majority
owned subsidiary or subsidiaries, or (c) there is no
significant investment by benefit plan investors, which is
defined to mean that less than 25% of the value of each class of
equity interest (disregarding certain interests held by our
general partner, its affiliates and certain other persons) is
held by the employee benefit plans that are subject to
part 4 of Title I of ERISA (which excludes
governmental plans and non-electing church plans) and/or
Section 4975 of the Code, IRAs and certain other employee
benefit plans not subject to ERISA (such as electing church
plans). With respect to an investment in our units, our assets
should not be considered plan assets under these
regulations because it is expected that the investment will
satisfy the requirements in (a) and (b) above and may
also satisfy the requirements in (c) above (although we do
not monitor the level of benefit plan investors as required for
compliance with (c)). With respect to an investment in our debt
securities, our assets should not be considered plan
assets under these regulations because such securities are
not equity securities or, even if they are issued with a feature
that allows their conversion to equity securities, the
securities into which they will be convertible will satisfy the
requirements in (a) and (b) above.
The foregoing discussion of issues arising for employee benefit
plan investments under ERISA, the Code and Similar Laws should
not be construed as legal advice. Plan fiduciaries contemplating
a purchase of our limited partnership units or debt securities
should consult with their own counsel regarding the consequences
under ERISA, the Code and other Similar Laws in light of the
serious penalties imposed on persons who engage in prohibited
transactions or other violations.
61
PLAN OF
DISTRIBUTION
As of the date of this prospectus, we have not been advised by
the selling unitholder as to any plan of distribution.
Distributions of the common units by the selling unitholder, or
by its partners, pledgees, donees (including charitable
organizations), transferees or other successors in interest, may
from time to time be offered for sale either directly by such
individual, or through underwriters, dealers or agents or on any
exchange on which the units may from time to time be traded, in
the over-the-counter market, or in independently negotiated
transactions or otherwise. The methods by which the common units
may be sold include:
|
|
|
|
|
a block trade (which may involve crosses) in which the broker or
dealer so engaged will attempt to sell the securities as agent
but may position and resell a portion of the block as principal
to facilitate the transaction;
|
|
|
|
purchases by a broker or dealer as principal and resale by such
broker or dealer for its own account pursuant to this prospectus;
|
|
|
|
exchange distributions
and/or
secondary distributions;
|
|
|
|
sales in the over-the-counter market;
|
|
|
|
underwritten transactions;
|
|
|
|
short sales;
|
|
|
|
broker-dealers may agree with the selling unitholder to sell a
specified number of such common units at a stipulated price per
unit;
|
|
|
|
ordinary brokerage transactions and transactions in which the
broker solicits purchasers;
|
|
|
|
privately negotiated transactions;
|
|
|
|
a combination of any such methods of sale; and
|
|
|
|
any other method permitted pursuant to applicable law.
|
Such transactions may be effected by the selling unitholder at
market prices prevailing at the time of sale or at negotiated
prices. The selling unitholder may effect such transactions by
selling the common units to underwriters or to or through
broker-dealers, and such underwriters or broker-dealers may
receive compensation in the form of discounts or commissions
from the selling unitholder and may receive commissions from the
purchasers of the common units for whom they may act as agent.
The selling unitholder may agree to indemnify any underwriter,
broker-dealer or agent that participates in transactions
involving sales of the units against certain liabilities,
including liabilities arising under the Securities Act. We have
agreed to register the units for sale under the Securities Act
and to indemnify the selling unitholder and each person who
participates as an underwriter in the offering of the units
against certain civil liabilities, including certain liabilities
under the Securities Act.
In connection with sales of the common units under this
prospectus, the selling unitholder may enter into hedging
transactions with broker-dealers, who may in turn engage in
short sales of the common units in the course of hedging the
positions they assume. The selling unitholder also may sell
common units short and deliver them to close out the short
positions, or loan or pledge the common units to broker-dealers
that in turn may sell them.
The selling unitholder and any underwriters, broker-dealers or
agents who participate in the distribution of the common units
may be deemed to be underwriters within the meaning
of the Securities Act. To the extent the selling unitholder is a
broker-dealer, it is, according to SEC interpretation, an
underwriter within the meaning of the Securities
Act. Underwriters are subject to the prospectus delivery
requirements under the Securities Act. If the selling unitholder
is deemed to be an underwriter, the selling unitholder may be
subject to certain statutory liabilities under the Securities
Act and the Securities Exchange Act of 1934.
There can be no assurances that the selling unitholder will sell
any or all of the common units offered under this prospectus.
62
LEGAL
MATTERS
The validity of the securities offered in this prospectus will
be passed upon for us by Vinson & Elkins L.L.P.,
Houston, Texas. Vinson & Elkins L.L.P. will also
render an opinion on the material federal income tax
considerations regarding the securities. If certain legal
matters in connection with an offering of the securities made by
this prospectus and a related prospectus supplement are passed
on by counsel for the underwriters of such offering, that
counsel will be named in the applicable prospectus supplement
related to that offering.
EXPERTS
The consolidated financial statements and managements
assessment of the effectiveness of internal control over
financial reporting of Energy Transfer Partners, L.P. and the
consolidated balance sheets of Energy Transfer Partners GP, L.P.
and Energy Transfer Partners, L.L.C., all incorporated by
reference in this prospectus, have been so incorporated by
reference in reliance upon the reports of Grant Thornton LLP,
independent registered public accountants, upon the authority of
said firm as experts in giving said reports.
WHERE YOU
CAN FIND MORE INFORMATION
We have filed a registration statement with the SEC under the
Securities Act of 1933 that registers the securities offered by
this prospectus. The registration statement, including the
attached exhibits, contains additional relevant information
about us. The rules and regulations of the SEC allow us to omit
some information included in the registration statement from
this prospectus.
In addition, we file annual, quarterly and other reports and
other information with the SEC. You may read and copy any
document we file at the SECs public reference room at
100 F Street, N.E., Washington, D.C. 20549.
Please call the SEC at
1-800-732-0330
for further information on the operation of the SECs
public reference room. Our SEC filings are available on the
SECs web site at
http://www.sec.gov.
We also make available free of charge on our website, at
http://www.energytransfer.com,
all materials that we file electronically with the SEC,
including our annual report on
Form 10-K,
quarterly reports on
Form 10-Q,
current reports on
Form 8-K,
Section 16 reports and amendments to these reports as soon
as reasonably practicable after such materials are
electronically filed with, or furnished to, the SEC.
Additionally, you can obtain information about us through the
New York Stock Exchange, 20 Broad Street, New York, New
York 10005, on which our common units are listed.
The SEC allows us to incorporate by reference the
information we have filed with the SEC. This means that we can
disclose important information to you without actually including
the specific information in this prospectus by referring you to
other documents filed separately with the SEC. These other
documents contain important information about us, our financial
condition and results of operations. The information
incorporated by reference is an important part of this
prospectus. Information that we file later with the SEC will
automatically update and may replace information in this
prospectus and information previously filed with the SEC.
We incorporate by reference in this prospectus the documents
listed below:
|
|
|
|
|
our annual report on
Form 10-K
for the year ended December 31, 2008;
|
|
|
|
our quarterly report on
Form 10-Q
for the quarter ended March 31, 2009;
|
|
|
|
our current reports on
Form 8-K
filed January 21, 2009, January 26, 2009 (two
reports), January 27, 2009, February 17, 2009,
March 17, 2009, April 2, 2009, April 7, 2009,
April 9, 2009 and April 17, 2009 (excluding any
information furnished pursuant to Item 2.02 or
Item 7.01 of any such current report on
Form 8-K);
|
|
|
|
the description of our common units in our registration
statement on
Form 8-A
(File
No. 1-11727)
filed pursuant to the Securities Exchange Act of 1934 on
May 16, 1996; and
|
63
|
|
|
|
|
all documents filed by us under Sections 13(a), 13(c), 14
or 15(d) of the Securities Exchange Act of 1934 between the date
of this prospectus and the termination of the registration
statement (excluding any information furnished pursuant to
Item 2.02 or Item 7.01 of any current report on
Form 8-K).
|
You may obtain any of the documents incorporated by reference in
this prospectus from the SEC through the SECs website at
the address provided above. You also may request a copy of any
document incorporated by reference in this prospectus (including
exhibits to those documents specifically incorporated by
reference in this document), at no cost, by visiting our
internet website at www.energytransfer.com, or by writing or
calling us at the following address:
Energy
Transfer Partners, L.P.
3738 Oak Lawn Avenue
Dallas, TX 75219
Attention: Thomas P. Mason
Telephone:
(214) 981-0700
64
PART II
INFORMATION
NOT REQUIRED IN PROSPECTUS
|
|
Item 14.
|
Other
Expenses of Issuance and Distribution
|
Set forth below are the expenses (other than underwriting
discounts and commissions) expected to be incurred in connection
with the issuance and distribution of the securities registered
hereby. With the exception of the Securities and Exchange
Commission registration fee, the amounts set forth below are
estimates:
|
|
|
|
|
Securities and Exchange Commission registration fee
|
|
$
|
0
|
|
Legal fees and expenses
|
|
|
100,000
|
|
Accounting fees and expenses
|
|
|
50,000
|
|
Printing and engraving expenses
|
|
|
50,000
|
|
Miscellaneous
|
|
|
0
|
|
|
|
|
|
|
Total
|
|
$
|
200,000
|
|
|
|
|
|
|
|
|
Item 15.
|
Indemnification
of Directors and Officers
|
Energy Transfer Partners, L.P. is a partnership organized under
the laws of the State of Delaware. The partnership agreement of
Energy Transfer Partners, L.P. provides that the partnership
will indemnify (i) its general partner, any departing
partner (as defined therein), any person who is or was an
affiliate of its general partner or any departing partner,
(ii) any person who is or was a director, officer,
employee, agent or trustee of the partnership, (iii) any
person who is or was an officer, director, employee, agent or
trustee of its general partner or any departing partner or any
affiliate of its general partner or any departing partner, or
(iv) any person who is or was serving at the request of its
general partner or any departing partner or any affiliate of its
general partner or any departing partner as an officer,
director, employee, partner, agent, fiduciary or trustee of
another person (each, an Indemnitee), to the fullest
extent permitted by law, from and against any and all losses,
claims, damages, liabilities (joint and several), expenses
(including, without limitation, legal fees and expenses),
judgments, fines, penalties, interest, settlements and other
amounts arising from any and all claims, demands, actions, suits
or proceedings, whether civil, criminal, administrative or
investigative, in which any Indemnitee may be involved, or is
threatened to be involved, as a party or otherwise, by reason of
its status as any of the foregoing; provided that in each case
the Indemnitee acted in good faith and in a manner that such
Indemnitee reasonably believed to be in or not opposed to the
best interests of the partnership and, with respect to any
criminal proceeding, had no reasonable cause to believe its
conduct was unlawful. Any indemnification under these provisions
will be only out of the assets of the partnership, and the
general partner shall not be personally liable for, or have any
obligation to contribute or loan funds or assets to each
applicable partnership to enable it to effectuate, such
indemnification. Energy Transfer Partners, L.P. is authorized to
purchase (or to reimburse the general partner or its affiliates
for the cost of) insurance against liabilities asserted against
and expenses incurred by such persons in connection with each of
the partnerships activities, regardless of whether each of the
applicable partnerships would have the power to indemnify such
person against such liabilities under the provisions described
above.
Insofar as indemnification for liabilities arising under the
Securities Act of 1933 may be permitted to directors,
officers or persons controlling the registrant pursuant to the
foregoing provisions, the registrant has been informed that in
the opinion of the Securities and Exchange Commission such
indemnification is against public policy as expressed in the Act
and is therefore unenforceable.
II-1
|
|
Item 16.
|
Exhibits
and Financial Statement Schedules
|
(a) Exhibits
The following documents are filed as exhibits to this
registration:
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
1
|
.1
|
|
Form of Underwriting Agreement. (**)
|
|
4
|
.1
|
|
Registration Rights Agreement for Limited Partner Interests of
Heritage Propane Partners, L.P.(1)
|
|
4
|
.2
|
|
Unitholder Rights Agreement dated January 20, 2004 among
Heritage Propane Partners, L.P., Heritage Holdings, Inc., TAAP
LP and La Grange Energy, L.P.(2)
|
|
4
|
.3
|
|
Indenture dated January 18, 2005 among Energy Transfer
Partners, L.P., the subsidiary guarantors named therein and
Wachovia Bank, National Association, as trustee.(3)
|
|
4
|
.4
|
|
First Supplemental Indenture dated January 18, 2005, among
Energy Transfer Partners, L.P., the subsidiary guarantors names
therein and Wachovia Bank, National Association, as trustee.(4)
|
|
4
|
.5
|
|
Second Supplemental Indenture dated as of February 24, 2005
to Indenture dated as of January 18, 2005, among Energy
Transfer Partners, L.P., the subsidiary guarantors named therein
and Wachovia Bank, National Association, as trustee.(5)
|
|
4
|
.6
|
|
Third Supplemental Indenture dated as of July 29, 2005 to
Indenture dated January 18, 2005, among Energy Transfer
Partners, L.P., the subsidiary guarantors named therein and
Wachovia Bank, National Association, as trustee.(6)
|
|
4
|
.7
|
|
Fourth Supplemental Indenture dated as of June 29, 2006 to
Indenture dated January 18, 2005, among Energy Transfer
Partners, L.P., the subsidiary guarantors named therein and
Wachovia Bank, National Association, as trustee.(7)
|
|
4
|
.8
|
|
Fifth Supplemental Indenture dated as of October 23, 2006
to Indenture dated January 18, 2005, among Energy Transfer
Partners, L.P., the subsidiary guarantors named therein and
Wachovia Bank, National Association, as trustee.(13)
|
|
4
|
.9
|
|
Sixth Supplemental Indenture dated as of March 28, 2008 to
Indenture dated January 18, 2005, among Energy Transfer
Partners, L.P., the subsidiary guarantors named therein and
Wachovia Bank, National Association, as trustee.(8)
|
|
4
|
.10
|
|
Seventh Supplemental Indenture dated as of December 23, 2008 to
Indenture dated January 18, 2005, among Energy Transfer
Partners, L.P., the subsidiary guarantors named therein and
Wachovia Bank, National Association, as trustee.(9)
|
|
4
|
.11
|
|
Eighth Supplemental Indenture dated as of April 7, 2009 to
Indenture dated January 18, 2005, among Energy Transfer
Partners, L.P., the subsidiary guarantors named therein and
Wachovia Bank, National Association, as trustee.(10)
|
|
4
|
.12
|
|
Form of Senior Indenture of Energy Transfer Partners, L.P.(11)
|
|
4
|
.13
|
|
Form of Subordinated Indenture of Energy Transfer Partners,
L.P.(12)
|
|
4
|
.14
|
|
Registration Rights Agreement, dated November 1, 2006,
between Energy Transfer Partners, L.P., and Energy Transfer
Equity, L.P.(14)
|
|
5
|
.1
|
|
Opinion of Vinson & Elkins L.L.P. as to the legality
of the securities registered hereby.(*)
|
|
8
|
.1
|
|
Opinion of Vinson & Elkins L.L.P. as to tax matters.(*)
|
|
12
|
.1
|
|
Statement Regarding Computation of Ratios.(*)
|
|
23
|
.1
|
|
Consent of Grant Thornton LLP.(*)
|
|
24
|
.1
|
|
Powers of Attorney (included on the signature pages of this
registration statement).(*)
|
|
25
|
.1
|
|
Form T-1
Statement of Eligibility and Qualification under the
Trust Indenture Act of 1939 of the Trustee under the Senior
Indenture.(*)
|
|
|
|
* |
|
Filed herewith. |
|
** |
|
To be filed by
8-K. |
|
(1) |
|
Incorporated by reference to the same numbered Exhibit to the
Registrants
Form 8-K
dated February 4, 2002. |
|
(2) |
|
Incorporated by reference as the same numbered exhibit to the
Registrants
Form 10-Q
for the quarter ended February 29, 2004. |
|
(3) |
|
Incorporated by reference to Exhibit 4.1 to the
Registrants
Form 8-K
filed January 19, 2005. |
|
(4) |
|
Incorporated by reference to Exhibit 4.2 to the
Registrants
Form 8-K
filed January 19, 2005. |
II-2
|
|
|
(5) |
|
Incorporated by reference to Exhibit 10.45 to the
Registrants Form
10-Q for the
quarter ended February 28, 2005. |
|
(6) |
|
Incorporated by reference to Exhibit 4.1 to the
Registrants
Form 8-K
filed August 2, 2005. |
|
(7) |
|
Incorporated by reference to Exhibit 4.13 to
Registrants Registration Statement of
Form S-3,
File
No. 333-133174,
filed with the Commission on August 9, 2006. |
|
(8) |
|
Incorporated by reference to Exhibit 4.2 to the
Registrants Form 8-K filed on March 31, 2008. |
|
(9) |
|
Incorporated by reference to Exhibit 4.2 to the
Registrants Form 8-K filed on December 21, 2008. |
|
(10) |
|
Incorporated by reference to Exhibit 4.2 to the
Registrants Form 8-K filed on April 7, 2009. |
|
(11) |
|
Incorporated by reference to Exhibit 4.11 to the
Registrants Form S-3 filed on August 9, 2006. |
|
(12) |
|
Incorporated by reference to Exhibit 4.12 to the
Registrants Form S-3 filed on August 9, 2006. |
|
(13) |
|
Incorporated by reference to Exhibit 4.1 to the
Registrants
Form 8-K
filed October 25, 2006. |
|
(14) |
|
Incorporated by reference to Exhibit 3.1.10 to the
Registrants Form
8-K filed
November 3, 2006. |
The undersigned registrant hereby undertakes:
1. To file, during any period in which offers or sales are
being made, a post-effective amendment to this registration
statement:
(i) To include any prospectus required by
Section 10(a)(3) of the Securities Act of 1933;
(ii) To reflect in the prospectus any facts or events
arising after the effective date of the registration statement
(or the most recent post-effective amendment thereof) which,
individually or in the aggregate, represent a fundamental change
in the information set forth in the registration statement.
Notwithstanding the foregoing, any increase or decrease in
volume of securities offered (if the total dollar value of
securities offered would not exceed that which was registered)
and any deviation from the low or high end of the estimated
maximum offering range may be reflected in the form of
prospectus filed with the Securities and Exchange Commission
pursuant to Rule 424(b) if, in the aggregate, the changes
in volume and price represent no more than a 20% change in the
maximum aggregate offering price set forth in the
Calculation of Registration Fee table in the
effective registration statement; and
(iii) To include any material information with respect to
the plan of distribution not previously disclosed in the
registration statement or any material change to such
information in the registration statement;
provided, however, that paragraphs (a)(1)(i), (a)(1)(ii)
and (a)(1)(iii) above do not apply if the registration statement
is on
Form S-3
and the information required to be included in a post-effective
amendment by those paragraphs is contained in reports filed with
or furnished to the Securities and Exchange Commission by the
registrant pursuant to section 13 or section 15(d) of
the Securities Exchange Act of 1934 that are incorporated by
reference in the registration statement, or is contained in a
form of prospectus filed pursuant to Rule 424(b) that is
part of the registration statement.
2. That, for the purpose of determining any liability under
the Securities Act of 1933, each such post-effective amendment
shall be deemed to be a new registration statement relating to
the securities offered therein, and the offering of such
securities at that time shall be deemed to be the initial bona
fide offering thereof.
3. To remove from registration by means of a post-effective
amendment any of the securities being registered which remain
unsold at the termination of the offering.
4. That, for the purpose of determining liability under the
Securities Act of 1933 to any purchaser:
(i) Each prospectus filed by the registrant pursuant to
Rule 424(b)(3) shall be deemed to be part of the
registration statement as of the date the filed prospectus was
deemed part of and included in the registration
statement; and
II-3
(ii) Each prospectus required to be filed pursuant to
Rule 424(b)(2), (b)(5), or (b)(7) as part of a registration
statement in reliance on Rule 430B relating to an offering
made pursuant to Rule 415(a)(1)(i), (vii), or (x) for
the purpose of providing the information required by
section 10(a) of the Securities Act of 1933 shall be deemed
to be part of and included in the registration statement as of
the earlier of the date such form of prospectus is first used
after effectiveness or the date of the first contract of sale of
securities in the offering described in the prospectus. As
provided in Rule 430B, for liability purposes of the issuer
and any person that is at that date an underwriter, such date
shall be deemed to be a new effective date of the registration
statement relating to the securities in the registration
statement to which that prospectus relates, and the offering of
such securities at that time shall be deemed to be the initial
bona fide offering thereof. Provided, however, that no
statement made in a registration statement or prospectus that is
part of the registration statement or made in a document
incorporated or deemed incorporated by reference into the
registration statement or prospectus that is part of the
registration statement will, as to a purchaser with a time of
contract of sale prior to such effective date, supersede or
modify any statement that was made in the registration statement
or prospectus that was part of the registration statement or
made in any such document immediately prior to such effective
date.
5. That, for the purpose of determining liability of the
registrant under the Securities Act of 1933 to any purchaser in
the initial distribution of the securities, the undersigned
registrant undertakes that in a primary offering of securities
of the undersigned registrant pursuant to this registration
statement, regardless of the underwriting method used to sell
the securities to the purchaser, if the securities are offered
or sold to such purchaser by means of any of the following
communications, the undersigned registrant will be a seller to
the purchaser and will be considered to offer or sell such
securities to such purchaser:
(i) Any preliminary prospectus or prospectus of the
undersigned registrant relating to the offering required to be
filed pursuant to Rule 424;
(ii) Any free writing prospectus relating to the offering
prepared by or on behalf of the undersigned registrant or used
or referred to by the undersigned registrant;
(iii) The portion of any other free writing prospectus
relating to the offering containing material information about
the undersigned registrant or its securities provided by or on
behalf of the undersigned registrant; and
(iv) Any other communication that is an offer in the
offering made by the undersigned registrant to the purchaser.
6. For purposes of determining any liability under the
Securities Act of 1933, each filing of the registrants
annual report pursuant to section 13(a) or
section 15(d) of the Securities Exchange Act of 1934 (and,
where applicable, each filing of an employee benefit plans
annual report pursuant to section 15(d) of the Securities
Exchange Act of 1934) that is incorporated by reference in
the registration statement shall be deemed to be a new
registration statement relating to the securities offered
therein, and the offering of such securities at that time shall
be deemed to be the initial bona fide offering thereof.
7. To supplement the prospectus, after the expiration of
the subscription period, to set forth the results of the
subscription offer, the transactions by the underwriters during
the subscription period, the amount of unsubscribed securities
to be purchased by the underwriters, and the terms of any
subsequent reoffering thereof. If any public offering by the
underwriters is to be made on terms differing from those set
forth on the cover page of the prospectus, a post-effective
amendment will be filed to set forth the terms of such offering.
8. To file an application for the purpose of determining
the eligibility of the trustee under subsection (a) of
Section 310 of the Trust Indenture Act
(Act) in accordance with the rules and regulations
prescribed by the Securities and Exchange Commission under
Section 305(b)(2) of the Act.
II-4
For purposes of determining any liability under the Securities
Act of 1933, the information omitted from the form of prospectus
filed as part of this registration statement in reliance upon
Rule 430A and contained in a form of prospectus filed by
the registrant pursuant to Rule 424(b) (1) or
(4) or 497(h) under the Securities Act shall be deemed to
be part of this registration statement as of the time it was
declared effective.
For the purpose of determining any liability under the
Securities Act of 1933, each post-effective amendment that
contains a form of prospectus shall be deemed to be a new
registration statement relating to the securities offered
therein, and the offering of such securities at that time shall
be deemed to be the initial bona fide offering thereof.
II-5
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as
amended, each of the signatories hereto certifies that it has
reasonable grounds to believe that it meets all of the
requirements for filing this Registration Statement on
Form S-3
and has duly caused this Registration Statement to be signed on
its behalf by the undersigned, thereunto duly authorized, in the
City of Dallas, State of Texas, on June 16, 2009.
ENERGY TRANSFER PARTNERS, L.P.
|
|
|
|
By:
|
Energy Transfer Partners GP, L.P.
Its: General Partner
|
|
|
By:
|
Energy Transfer Partners, L.L.C.
Its: General Partner
|
|
|
By:
|
/s/ Martin
Salinas, Jr.
|
Name: Martin Salinas, Jr.
Title: Chief Financial Officer
KNOW ALL PERSONS BY THESE PRESENTS, that each person whose
signature appears below hereby constitutes and appoints Martin
Salinas, Jr. and Thomas P. Mason, and each of them, his true and
lawful attorney-in-fact and agents, with full power to act
without the other, to sign any and all amendments (including
post-effective amendments) to this registration statement and
any additional registration statement pursuant to
Rule 462(b), and to file the same with all exhibits thereto
and any and all other documents in connection therewith, with
the Securities and Exchange Commission and any national exchange
or self regulatory agency, and to do and perform any and all
acts and things requisite and necessary to be done in connection
with the foregoing as fully as he might or could do in person
hereby ratifying and confirming all that said attorneys-in-fact
and agents, or either of them, may lawfully do or cause to be
done by virtue hereof.
Pursuant to the requirements of the Securities Act of 1933, this
registration statement has been signed by the following persons
in the capacities indicated on the dates indicated:
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
|
/s/ Kelcy
L. Warren
Kelcy
L. Warren
|
|
Chief Executive Officer
(Principal Executive Officer),
Chairman of the Board of Directors
of Energy Transfer Partners, L.L.C.
|
|
June 16, 2009
|
|
|
|
|
|
/s/ Martin
Salinas, Jr.
Martin
Salinas, Jr.
|
|
Chief Financial Officer
(Principal Financial Officer and Principal Accounting Officer)
|
|
June 16, 2009
|
|
|
|
|
|
/s/ Ray
C. Davis
Ray
C. Davis
|
|
Director of
Energy Transfer Partners, L.L.C.
|
|
June 16, 2009
|
|
|
|
|
|
/s/ Bill
W. Byrne
Bill
W. Byrne
|
|
Director of
Energy Transfer Partners, L.L.C.
|
|
June 16, 2009
|
|
|
|
|
|
/s/ David
R. Albin
David
R. Albin
|
|
Director of
Energy Transfer Partners, L.L.C.
|
|
June 16, 2009
|
II-6
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
|
/s/ Kenneth
A. Hersh
Kenneth
A. Hersh
|
|
Director of
Energy Transfer Partners, L.L.C.
|
|
June 16, 2009
|
|
|
|
|
|
/s/ Paul
E. Glaske
Paul
E. Glaske
|
|
Director of
Energy Transfer Partners, L.L.C.
|
|
June 16, 2009
|
|
|
|
|
|
/s/ K.
Rick Turner
K.
Rick Turner
|
|
Director of
Energy Transfer Partners, L.L.C.
|
|
June 16, 2009
|
|
|
|
|
|
/s/ Ted
Collins, Jr.
Ted
Collins, Jr.
|
|
Director of
Energy Transfer Partners, L.L.C.
|
|
June 16, 2009
|
|
|
|
|
|
/s/ John
W. McReynolds
John
W. McReynolds
|
|
Director of
Energy Transfer Partners, L.L.C.
|
|
June 16, 2009
|
|
|
|
|
|
/s/ Michael
K. Grimm
Michael
K. Grimm
|
|
Director of
Energy Transfer Partners, L.L.C.
|
|
June 16, 2009
|
|
|
|
|
|
/s/ John
D. Harkey, Jr.
John
D. Harkey, Jr.
|
|
Director of
Energy Transfer Partners, L.L.C.
|
|
June 16, 2009
|
II-7
INDEX TO
EXHIBITS
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
1
|
.1
|
|
Form of Underwriting Agreement. (**)
|
|
4
|
.1
|
|
Registration Rights Agreement for Limited Partner Interests of
Heritage Propane Partners, L.P.(1)
|
|
4
|
.2
|
|
Unitholder Rights Agreement dated January 20, 2004 among
Heritage Propane Partners, L.P., Heritage Holdings, Inc., TAAP
LP and La Grange Energy, L.P.(2)
|
|
4
|
.3
|
|
Indenture dated January 18, 2005 among Energy Transfer
Partners, L.P., the subsidiary guarantors named therein and
Wachovia Bank, National Association, as trustee.(3)
|
|
4
|
.4
|
|
First Supplemental Indenture dated January 18, 2005, among
Energy Transfer Partners, L.P., the subsidiary guarantors names
therein and Wachovia Bank, National Association, as trustee.(4)
|
|
4
|
.5
|
|
Second Supplemental Indenture dated as of February 24, 2005
to Indenture dated as of January 18, 2005, among Energy
Transfer Partners, L.P., the subsidiary guarantors named therein
and Wachovia Bank, National Association, as trustee.(5)
|
|
4
|
.6
|
|
Third Supplemental Indenture dated as of July 29, 2005 to
Indenture dated January 18, 2005, among Energy Transfer
Partners, L.P., the subsidiary guarantors named therein and
Wachovia Bank, National Association, as trustee.(6)
|
|
4
|
.7
|
|
Fourth Supplemental Indenture dated as of June 29, 2006 to
Indenture dated January 18, 2005, among Energy Transfer
Partners, L.P., the subsidiary guarantors named therein and
Wachovia Bank, National Association, as trustee.(7)
|
|
4
|
.8
|
|
Fifth Supplemental Indenture dated as of October 23, 2006
to Indenture dated January 18, 2005, among Energy Transfer
Partners, L.P., the subsidiary guarantors named therein and
Wachovia Bank, National Association, as trustee.(13)
|
|
4
|
.9
|
|
Sixth Supplemental Indenture dated as of March 28, 2008 to
Indenture dated January 18, 2005, among Energy Transfer
Partners, L.P., the subsidiary guarantors named therein and
Wachovia Bank, National Association, as trustee.(8)
|
|
4
|
.10
|
|
Seventh Supplemental Indenture dated as of December 23, 2008 to
Indenture dated January 18, 2005, among Energy Transfer
Partners, L.P., the subsidiary guarantors named therein and
Wachovia Bank, National Association, as trustee.(9)
|
|
4
|
.11
|
|
Eighth Supplemental Indenture dated as of April 7, 2009 to
Indenture dated January 18, 2005, among Energy Transfer
Partners, L.P., the subsidiary guarantors named therein and
Wachovia Bank, National Association, as trustee.(10)
|
|
4
|
.12
|
|
Form of Senior Indenture of Energy Transfer Partners, L.P.(11)
|
|
4
|
.13
|
|
Form of Subordinated Indenture of Energy Transfer Partners,
L.P.(12)
|
|
4
|
.14
|
|
Registration Rights Agreement, dated November 1, 2006,
between Energy Transfer Partners, L.P., and Energy Transfer
Equity, L.P.(14)
|
|
5
|
.1
|
|
Opinion of Vinson & Elkins L.L.P. as to the legality
of the securities registered hereby.(*)
|
|
8
|
.1
|
|
Opinion of Vinson & Elkins L.L.P. as to tax matters.(*)
|
|
12
|
.1
|
|
Statement Regarding Computation of Ratios.(*)
|
|
23
|
.1
|
|
Consent of Grant Thornton LLP.(*)
|
|
24
|
.1
|
|
Powers of Attorney (included on the signature pages of this
registration statement).(*)
|
|
25
|
.1
|
|
Form T-1
Statement of Eligibility and Qualification under the
Trust Indenture Act of 1939 of the Trustee under the Senior
Indenture.(*)
|
|
|
|
* |
|
Filed herewith. |
|
** |
|
To be filed by
8-K. |
|
(1) |
|
Incorporated by reference to the same numbered Exhibit to the
Registrants
Form 8-K
dated February 4, 2002. |
|
(2) |
|
Incorporated by reference as the same numbered exhibit to the
Registrants
Form 10-Q
for the quarter ended February 29, 2004. |
|
(3) |
|
Incorporated by reference to Exhibit 4.1 to the
Registrants
Form 8-K
filed January 19, 2005. |
|
(4) |
|
Incorporated by reference to Exhibit 4.2 to the
Registrants
Form 8-K
filed January 19, 2005. |
|
(5) |
|
Incorporated by reference to Exhibit 10.45 to the
Registrants Form
10-Q for the
quarter ended February 28, 2005. |
|
(6) |
|
Incorporated by reference to Exhibit 4.1 to the
Registrants
Form 8-K
filed August 2, 2005. |
|
|
|
(7) |
|
Incorporated by reference to Exhibit 4.13 to
Registrants Registration Statement of
Form S-3,
File
No. 333-133174,
filed with the Commission on August 9, 2006. |
|
(8) |
|
Incorporated by reference to Exhibit 4.2 to the
Registrants Form 8-K filed on March 31, 2008. |
|
(9) |
|
Incorporated by reference to Exhibit 4.2 to the
Registrants Form 8-K filed on December 21, 2008. |
|
(10) |
|
Incorporated by reference to Exhibit 4.2 to the
Registrants Form 8-K filed on April 7, 2009. |
|
(11) |
|
Incorporated by reference to Exhibit 4.11 to the
Registrants Form S-3 filed on August 9, 2006. |
|
(12) |
|
Incorporated by reference to Exhibit 4.12 to the
Registrants Form S-3 filed on August 9, 2006. |
|
(13) |
|
Incorporated by reference to Exhibit 4.1 to the
Registrants
Form 8-K
filed October 25, 2006. |
|
(14) |
|
Incorporated by reference to Exhibit 3.1.10 to the
Registrants Form
8-K filed
November 3, 2006. |