sv1za
As filed with the Securities and Exchange Commission on
February 7, 2007
Registration
No. 333-138747
UNITED STATES
SECURITIES AND EXCHANGE
COMMISSION
Washington, D.C.
20549
Amendment No. 5
to
Form S-1
REGISTRATION STATEMENT UNDER
THE SECURITIES ACT OF 1933
TARGA RESOURCES PARTNERS LP
(Exact name of registrant as
specified in its charter)
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Delaware
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4922
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65-1295427
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(State or other jurisdiction
of
incorporation or organization)
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(Primary Standard Industrial
Classification Code Number)
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(I.R.S. Employer
Identification Number)
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1000 Louisiana, Suite 4300
Houston, Texas 77002
(713) 584-1000
(Address, including zip code and
telephone number, including area code, of registrants
principal executive offices)
Rene R. Joyce
Chief Executive Officer
1000 Louisiana, Suite 4300
Houston, Texas 77002
(713) 584-1000
(Name, address, including zip
code, and telephone number, including area code, of agent for
service)
Copies to:
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David P. Oelman
Christopher S. Collins
Vinson & Elkins LLP
1001 Fannin Street, Suite 2500
Houston, Texas 77002
(713) 758-2222
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Joshua Davidson
Douglass M. Rayburn
Baker Botts L.L.P.
910 Louisiana Street
Houston, Texas 77002
(713) 229-1234
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Approximate date of commencement of proposed sale to the
public: As soon as practicable after this
Registration Statement becomes effective.
If any of the securities being registered on this Form are to be
offered on a delayed or continuous basis pursuant to
Rule 415 under the Securities Act of 1933, check the
following box. o
If this Form is filed to register additional securities for an
offering pursuant to Rule 462(b) under the Securities Act,
check the following box and list the Securities Act registration
statement number of the earlier effective registration statement
for the same offering. o
If this Form is a post-effective amendment filed pursuant to
Rule 462(c) under the Securities Act, please check the
following box and list the Securities Act registration statement
number of the earlier effective registration statement for the
same offering. o
If this Form is a post-effective amendment filed pursuant to
Rule 462(d) under the Securities Act, check the following
box and list the Securities Act registration statement number of
the earlier effective registration statement for the same
offering. o
The Registrant hereby amends this Registration Statement on
such date or dates as may be necessary to delay its effective
date until the registrant shall file a further amendment which
specifically states that this Registration Statement shall
thereafter become effective in accordance with Section 8(a)
of the Securities Act of 1933 or until the Registration
Statement shall become effective on such date as the Securities
and Exchange Commission, acting pursuant to said
Section 8(a), may determine.
The information in this 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.
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Subject to Completion, dated
February 7, 2007
PROSPECTUS
TARGA RESOURCES PARTNERS
LP
16,800,000 Common
Units
Representing Limited Partner
Interests
Targa Resources Partners LP is a limited partnership recently
formed by Targa Resources, Inc. This is the initial public
offering of our common units. All of the common units are being
sold by us. Prior to this offering, there has been no public
market for our common units. We expect the initial public
offering price to be between $19.00 and $21.00 per unit. Our
common units have been approved for listing on The NASDAQ Global
Market under the symbol NGLS.
Investing in our common units
involves risks. Please see Risk Factors beginning on
page 17.
These risks include the following:
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We may not have sufficient cash from operations following the
establishment of cash reserves and payment of fees and expenses,
including cost reimbursements to our general partner, to enable
us to make cash distributions to holders of our common units and
subordinated units at the initial distribution rate under our
cash distribution policy.
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Our cash flow is affected by natural gas and natural gas liquid
prices, and decreases in these prices could adversely affect our
ability to make distributions to holders of our common units and
subordinated units.
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Because of the natural decline in production from existing wells
in our operating regions, our success depends on our ability to
obtain new sources of supplies of natural gas and natural gas
liquids, which depends on certain factors beyond our control.
Any decrease in supplies of natural gas or natural gas liquids
could adversely affect our business and operating results.
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Our hedging activities may not be effective in reducing the
variability of our cash flows and may, in certain circumstances,
increase the variability of our cash flows. In addition, the
significant contribution to our results of operations that we
are currently receiving from our hedge positions will decrease
substantially through 2010.
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We depend on one natural gas producer for a significant portion
of our supply of natural gas. The loss of this customer or
replacement of its contracts on less favorable terms could
result in a decline in our volumes, revenues and cash available
for distribution.
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Targa Resources, Inc. controls our general partner, which has
sole responsibility for conducting our business and managing our
operations. Targa Resources, Inc. has conflicts of interest with
us and may favor its own interests to your detriment.
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Targa Resources, Inc. is not limited in its ability to compete
with us, which could limit our ability to acquire additional
assets or businesses.
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Holders of our common units have limited voting rights and are
not entitled to elect our general partner or its directors.
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You may be required to pay taxes on your share of our income
even if you do not receive any cash distributions from us.
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Per Common Unit
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Total
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Public Offering Price
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$
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$
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Underwriting Discount(1)
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$
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$
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Proceeds to Targa Resources
Partners LP (before expenses)(2)
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$
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$
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(1)
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Excludes an aggregate structuring
fee equal to 0.4% of the gross proceeds of this offering, or
approximately $1.3 million, payable to Citigroup Global
Markets Inc., Goldman, Sachs & Co., UBS Securities LLC
and Merrill Lynch & Co.
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(2)
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We will pay approximately
$307.1 million of the proceeds we receive from this
offering to Targa Resources, Inc. to retire a portion of our
affiliate indebtedness.
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We have granted the underwriters a
30-day
option to purchase up to an additional 2,520,000 common units
from us on the same terms and conditions as set forth above if
the underwriters sell more than 16,800,000 common units in this
offering.
Neither the Securities and Exchange Commission nor any state
securities commission has approved or disapproved of these
securities or passed upon the adequacy or accuracy of this
prospectus. Any representation to the contrary is a criminal
offense.
The underwriters expect to deliver the common units through the
facilities of The Depository Trust Company on or
about ,
2007.
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Citigroup |
Goldman,
Sachs &
Co. |
UBS
Investment
Bank |
Merrill
Lynch & Co. |
,
2007
TABLE OF
CONTENTS
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1
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1
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4
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4
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4
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5
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6
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7
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8
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8
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9
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13
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15
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17
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17
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27
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33
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36
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37
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38
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40
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40
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41
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43
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46
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49
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54
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54
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55
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56
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57
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57
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58
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58
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59
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61
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62
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62
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65
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129
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129
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134
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137
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137
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137
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137
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139
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139
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139
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139
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139
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140
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140
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141
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142
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143
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145
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145
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146
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146
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147
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147
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148
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148
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148
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149
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149
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149
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150
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150
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150
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151
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151
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152
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153
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153
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154
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155
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160
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161
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163
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163
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164
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166
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iii
You should rely only on the information contained in this
prospectus. We have not, and the underwriters have not,
authorized anyone to provide you with different information. If
anyone provides you with different or inconsistent information,
you should not rely on it. We are not, and the underwriters are
not, making an offer to sell these securities in any
jurisdiction where an offer or sale is not permitted. You should
assume that the information appearing in this prospectus is
accurate as of the date on the front cover of this prospectus.
Our business, financial condition, results of operations and
prospects may have changed since that date.
Until ,
2007 (25 days after the date of this prospectus), all
dealers that buy, sell or trade our common units, whether or not
participating in this offering, may be required to deliver a
prospectus. This is in addition to the dealers obligation
to deliver a prospectus when acting as underwriters and with
respect to their unsold allotments or subscriptions.
iv
SUMMARY
This summary provides a brief overview of information
contained elsewhere in this prospectus. Because it is
abbreviated, this summary may not contain all of the information
that you should consider before investing in the common units.
You should read the entire prospectus carefully, including the
historical and pro forma financial statements and the notes to
those financial statements. Unless indicated otherwise, the
information presented in this prospectus assumes (1) an
initial public offering price of $20.00 per unit and
(2) that the underwriters do not exercise their option to
purchase additional units. You should read Risk
Factors beginning on page 17 for more information
about important risks that you should consider carefully before
buying our common units. We include a glossary of some of the
terms used in this prospectus as Appendix B. As used in
this prospectus, unless we indicate otherwise:
(1) our, we, us and
similar terms refer to Targa Resources Partners LP, together
with our subsidiaries, after giving effect to the Formation
Transactions described on page 5 of this prospectus,
(2) Targa refers to Targa Resources, Inc.
and its subsidiaries and affiliates (other than us) and
(3) references to our pro forma financial information refer
to the historical financial information of the Predecessor
Business described on page 13 of this prospectus as adjusted to
give effect to the Formation Transactions.
Targa
Resources Partners LP
We are a growth-oriented Delaware limited partnership recently
formed by Targa, a leading provider of midstream natural gas and
NGL services in the United States, to own, operate, acquire and
develop a diversified portfolio of complementary midstream
energy assets. We currently operate in the Fort Worth Basin
in north Texas and are engaged in the business of gathering,
compressing, treating, processing and selling natural gas and
fractionating and selling natural gas liquids, or NGLs, and NGL
products. Fractionating means separating a mixed stream of NGLs
into its constituent products. We intend to leverage our
relationship with Targa to acquire and construct additional
midstream energy assets and to utilize the significant
experience of Targas management team to execute our growth
strategy. At September 30, 2006, Targa had total assets of
$3.4 billion, with the North Texas System to be contributed
to us in connection with this offering representing
$1.1 billion of this amount. Targa intends, but is not
obligated, to offer us the opportunity to purchase substantially
all of its remaining businesses.
Our operations consist of an extensive network of approximately
3,950 miles of integrated gathering pipelines that gather
and compress natural gas received from approximately 2,650
receipt points in the Fort Worth Basin, two natural gas
processing plants that compress, treat and process the natural
gas and a fractionator that fractionates a portion of our raw
NGLs produced in our processing operations into NGL products.
These assets, together with the business conducted thereby, are
collectively referred to as the North Texas System.
We serve a fourteen-county natural gas producing region in the
Fort Worth Basin that includes production from the Barnett
Shale formation and other shallower formations, which are
subsurface rock formations containing hydrocarbons, including
the Bend Conglomerate, Caddo, Atoka, Marble Falls, and other
Pennsylvanian and upper Mississippian formations, which we refer
to as the other Fort Worth Basin formations.
For more information on the North Texas System, please see
Business Our Partnership.
For the year ended December 31, 2005 and the nine months
ended September 30, 2006, we generated pro forma net income
(loss) of approximately $(6.8) million and $0.4 million,
respectively, pro forma operating margin of $81.2 million
and $67.8 million, respectively, and had 162.5 million
cubic feet of natural gas per day, or MMcf/d, and
168.2 MMcf/d of gathering throughput, respectively. For the
year ended December 31, 2005 and the nine months ended
September 30, 2006, we generated approximately
$72.8 million and $62.7 million of pro forma income
before interest, income taxes, depreciation and amortization, or
EBITDA, respectively.
1
Non-GAAP
Financial Measures
EBITDA. We define EBITDA as net income before
interest, income taxes, depreciation and amortization. EBITDA is
used as a supplemental financial measure by our management and
by external users of our financial statements such as investors,
commercial banks and others, to assess:
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the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis;
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our operating performance and return on capital as compared to
other companies in the midstream energy sector, without regard
to financing or capital structure; and
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the viability of acquisitions and capital expenditure projects
and the overall rates of return on alternative investment
opportunities.
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The economic substance behind managements use of EBITDA is
to measure the ability of our assets to generate cash sufficient
to pay interest costs, support our indebtedness, and make
distributions to our investors.
The GAAP measures most directly comparable to EBITDA are net
cash provided by operating activities and net income. Our
non-GAAP financial measure of EBITDA should not be considered as
an alternative to GAAP net cash provided by operating activities
and GAAP net income. EBITDA is not a presentation made in
accordance with GAAP and has important limitations as an
analytical tool. You should not consider EBITDA in isolation or
as a substitute for analysis of our results as reported under
GAAP. Because EBITDA excludes some, but not all, items that
affect net income and net cash provided by operating activities
and is defined differently by different companies in our
industry, our definition of EBITDA may not be comparable to
similarly titled measures of other companies.
Management compensates for the limitations of EBITDA as an
analytical tool by reviewing the comparable GAAP measures,
understanding the differences between the measures and
incorporating these learnings into managements
decision-making processes.
Operating Margin. We define operating margin
as total operating revenues, which consist of natural gas and
NGL sales plus service fee revenues, less product purchases,
which consist primarily of producer payments and other natural
gas purchases, and operating expense. Management reviews
operating margin monthly for consistency and trend analysis.
Based on this monthly analysis, management takes appropriate
action to maintain positive trends or to reverse negative
trends. Management uses operating margin as an important
performance measure of the core profitability of our operations.
The GAAP measure most directly comparable to operating margin is
net income. Our non-GAAP financial measure of operating margin
should not be considered as an alternative to GAAP net income.
Operating margin is not a presentation made in accordance with
GAAP and has important limitations as an analytical tool. You
should not consider operating margin in isolation or as a
substitute for analysis of our results as reported under GAAP.
Because operating margin excludes some, but not all, items that
affect net income and is defined differently by different
companies in our industry, our definition of operating margin
may not be comparable to similarly titled measures of other
companies, thereby diminishing its utility.
Management compensates for the limitations of operating margin
as an analytical tool by reviewing the comparable GAAP measures,
understanding the differences between the measures and
incorporating these learnings into managements
decision-making processes.
We believe that investors benefit from having access to the same
financial measures that our management uses in evaluating our
operating results. Operating margin provides useful information
to investors because it is used as a supplemental financial
measure by our management and by external users of our financial
statements, including such investors, commercial banks and
others, to assess:
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the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis;
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our operating performance and return on capital as compared to
other companies in the midstream energy sector, without regard
to financing or capital structure;
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the viability of acquisitions and capital expenditure projects
and the overall rates of return on alternative investment
opportunities.
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Predecessor Business
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Targa Resources Partners LP
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Dynegy
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Targa
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Pro Forma
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Nine Months
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Ten Months
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Two Months
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Nine Months
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Nine Months
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Years Ended
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Ended
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Ended
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Ended
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Ended
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Year Ended
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Ended
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December 31,
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September 30,
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October 31,
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December 31,
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September 30,
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December 31,
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September 30,
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2003
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2004
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2005
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2005
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2005
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2006
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2005
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2006
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(Audited)
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(Audited)
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(Unaudited)
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(Audited)
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(Audited)
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(Unaudited)
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(Unaudited)
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(Unaudited)
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(in millions of dollars)
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Reconciliation of
EBITDA to net cash provided by (used in) operating
activities:
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Net cash provided by (used in)
operating activities
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$
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31.3
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$
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58.0
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$
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59.2
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72.7
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(1.5
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$
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11.1
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Allocated interest expense from
parent(1)
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10.7
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50.5
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Changes in operating working
capital which provided (used) cash:
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Accounts receivable
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0.7
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(0.7
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0.5
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0.3
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0.1
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(0.4
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Accounts payable
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(1.0
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(2.7
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1.1
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1.3
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0.8
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Other, including changes in
noncurrent assets and liabilities
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(4.9
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(3.8
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(12.6
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(17.1
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5.5
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1.5
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EBITDA
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$
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26.1
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$
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50.8
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$
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48.2
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$
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57.2
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$
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15.6
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$
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62.7
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of
EBITDA to net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
14.1
|
|
|
$
|
38.6
|
|
|
$
|
38.1
|
|
|
$
|
45.9
|
|
|
|
$
|
(5.1
|
)
|
|
$
|
(35.4
|
)
|
|
$
|
(6.8
|
)
|
|
$
|
0.4
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11.5
|
|
|
|
54.4
|
|
|
|
24.8
|
|
|
|
18.6
|
|
Deferred tax expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.0
|
|
|
|
|
|
|
|
2.0
|
|
Depreciation and amortization
expense
|
|
|
12.0
|
|
|
|
12.2
|
|
|
|
10.1
|
|
|
|
11.3
|
|
|
|
|
9.2
|
|
|
|
41.7
|
|
|
|
54.8
|
|
|
|
41.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA
|
|
$
|
26.1
|
|
|
$
|
50.8
|
|
|
$
|
48.2
|
|
|
$
|
57.2
|
|
|
|
$
|
15.6
|
|
|
$
|
62.7
|
|
|
$
|
72.8
|
|
|
$
|
62.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of
operating margin to net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
14.1
|
|
|
$
|
38.6
|
|
|
$
|
38.1
|
|
|
$
|
45.9
|
|
|
|
$
|
(5.1
|
)
|
|
$
|
(35.4
|
)
|
|
$
|
(6.8
|
)
|
|
$
|
0.4
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
expense
|
|
|
12.0
|
|
|
|
12.2
|
|
|
|
10.1
|
|
|
|
11.3
|
|
|
|
|
9.2
|
|
|
|
41.7
|
|
|
|
54.8
|
|
|
|
41.7
|
|
Deferred income tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.0
|
|
|
|
|
|
|
|
2.0
|
|
Other, net
|
|
|
0.6
|
|
|
|
0.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11.5
|
|
|
|
54.4
|
|
|
|
24.8
|
|
|
|
18.6
|
|
General and administrative expense
|
|
|
7.7
|
|
|
|
7.2
|
|
|
|
6.7
|
|
|
|
7.3
|
|
|
|
|
1.1
|
|
|
|
5.1
|
|
|
|
8.4
|
|
|
|
5.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating margin
|
|
$
|
34.4
|
|
|
$
|
58.3
|
|
|
$
|
54.9
|
|
|
$
|
64.5
|
|
|
|
$
|
16.7
|
|
|
$
|
67.8
|
|
|
$
|
81.2
|
|
|
$
|
67.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Excludes non-cash amortization of debt issue costs of $0.8
million for the two months ended December 31, 2005 and
$3.9 million for the nine months ended September 30, 2006.
|
Please see Business Strategies and
Business Competitive Strengths for a
discussion of our strategies and competitive strengths.
3
Our
Relationship with Targa Resources, Inc.
One of our principal strengths is our relationship with Targa, a
leading provider of midstream natural gas and NGL services in
the United States. Targa has indicated that it intends to use us
as a growth vehicle to pursue the acquisition and expansion of
midstream natural gas, NGL and other complementary energy
businesses and assets. We expect to have the opportunity to make
acquisitions directly from Targa in the future. Targa intends to
offer us the opportunity to purchase substantially all of its
remaining businesses, although it is not obligated to do so.
While Targa believes it will be in its best interest to
contribute additional assets to us given its significant
ownership of limited and general partner interests in us, Targa
constantly evaluates acquisitions and dispositions and may elect
to acquire, construct or dispose of midstream assets in the
future without offering us the opportunity to purchase or
construct those assets. Targa has retained such flexibility
because it believes it is in the best interests of its
shareholders to do so. We cannot say with any certainty which,
if any, opportunities to acquire assets from Targa may be made
available to us or if we will choose to pursue any such
opportunity. Moreover, Targa is not prohibited from competing
with us and constantly evaluates acquisitions and dispositions
that do not involve us. In addition, through our relationship
with Targa, we will have access to a significant pool of
management talent, strong commercial relationships throughout
the energy industry and access to Targas broad
operational, commercial, technical, risk management and
administrative infrastructure.
Following this offering, Targa will continue to own interests in
or operate approximately 6,680 miles of natural gas
pipelines and approximately 720 miles of NGL pipelines,
with natural gas gathering systems covering approximately
11,900 square miles and 20 natural gas processing plants
with access to natural gas supplies in the Permian basin,
onshore Louisiana and the Gulf of Mexico. Additionally, Targa
has a significant, integrated NGL logistics and marketing
business, with 13 storage, marine and transport terminals with
an NGL storage capacity of 730 MBbls, net NGL fractionation
capacity of approximately 287 thousand barrels per day, or
MBbls/d, and 43 operated storage wells with a capacity of
103 MMBbls. These asset locations provide Targa access to
relatively stable natural gas supplies and proximity to end-use
markets and market hubs while positioning Targa to capitalize on
growth opportunities from the continued development of onshore
as well as deepwater and deep shelf Gulf of Mexico natural gas
reserves and the increasing importation of liquified natural
gas, or LNG, to the Gulf Coast.
Our
Relationship with Warburg Pincus LLC
Warburg Pincus LLC, or Warburg Pincus, controls us through its
ownership of securities in Targa Resources Investments Inc., the
indirect parent of Targa, and a stockholders agreement among
Targa Resources Investments Inc. and its owners. Warburg Pincus
is a private equity firm and over four decades has invested more
than $20 billion in 525 companies in
30 countries, representing a variety of industries
including energy, information and communication technology,
financial services, healthcare, media and business services and
real estate.
Summary
of Risk Factors
An investment in our common units involves risks associated with
our business, regulatory and legal matters, our limited
partnership structure and the tax characteristics of our common
units. The following list of risk factors is not exhaustive.
Please see these and other risks described under Risk
Factors.
Risks
Related to Our Business
|
|
|
|
|
We may not have sufficient cash from operations following the
establishment of cash reserves and payment of fees and expenses,
including cost reimbursements to our general partner, to enable
us to make cash distributions to holders of our common units and
subordinated units at the initial distribution rate under our
cash distribution policy.
|
|
|
|
On a pro forma basis we would not have had sufficient cash
available for distribution to pay the full minimum quarterly
distribution on all units for the year ended December 31,
2005 or for the twelve months ended September 30, 2006.
|
4
|
|
|
|
|
Our cash flow is affected by natural gas and NGL prices, and
decreases in these prices could adversely affect our ability to
make distributions to holders of our common units and
subordinated units.
|
|
|
|
Because of the natural decline in production from existing wells
in our operating regions, our success depends on our ability to
obtain new sources of supplies of natural gas and NGLs, which
depends on certain factors beyond our control. Any decrease in
supplies of natural gas or NGLs could adversely affect our
business and operating results.
|
|
|
|
Our hedging activities may not be effective in reducing the
variability of our cash flows and may, in certain circumstances,
increase the variability of our cash flows. In addition, the
significant contribution to our results of operations that we
are currently receiving from our hedge positions will decrease
substantially through 2010.
|
Risks
Inherent in an Investment in Us
|
|
|
|
|
Targa controls our general partner, which has sole
responsibility for conducting our business and managing our
operations. Targa has conflicts of interest with us and may
favor its own interests to your detriment.
|
|
|
|
The credit and business risk profile of our general partner and
its owners could adversely affect our credit ratings and profile.
|
|
|
|
|
|
Our partnership agreement limits our general partners
fiduciary duties to holders of our units and restricts the
remedies available to unitholders for actions taken by our
general partner that might otherwise constitute breaches of
fiduciary duty.
|
|
|
|
|
|
Targa is not limited in its ability to compete with us, which
could limit our ability to acquire additional assets or
businesses.
|
Tax
Risks to Common Unitholders
|
|
|
|
|
Our tax treatment depends on our status as a partnership for
federal income tax purposes, as well as our not being subject to
a material amount of entity-level taxation by individual states.
If the Internal Revenue Service, or IRS, were to treat us as a
corporation or if we were to become subject to a material amount
of entity-level taxation for state tax purposes, then our cash
available for distribution to you would be substantially reduced.
|
|
|
|
If the IRS contests the federal income tax positions we take,
the market for our common units may be adversely affected, and
the cost of any contest will reduce our cash available for
distribution to you.
|
|
|
|
You may be required to pay taxes on your share of our income
even if you do not receive any cash distributions from us.
|
Formation
Transactions and Partnership Structure
General
At the closing of this offering, we anticipate that the
following transactions, which we refer to as the Formation
Transactions, will occur:
|
|
|
|
|
Targa will contribute the North Texas System to us;
|
|
|
|
we will issue to Targa 11,528,231 subordinated units,
representing a 39.9% limited partner interest in us;
|
|
|
|
we will issue to our general partner, Targa Resources GP LLC,
578,127 general partner units representing its initial 2%
general partner interest in us, and all of our incentive
distribution rights,
|
5
|
|
|
|
|
which incentive distribution rights will entitle our general
partner to increasing percentages of the cash we distribute in
excess of $0.3881 per unit per quarter;
|
|
|
|
|
|
we will issue 16,800,000 common units to the public in this
offering, representing a 58.1% limited partner interest in us,
and will use the proceeds to pay expenses associated with this
offering, the Formation Transactions and our new credit facility
and to pay approximately $307.1 million to Targa to retire
a portion of our affiliate indebtedness;
|
|
|
|
|
|
we will borrow approximately $342.5 million under our new
$500 million credit facility, the proceeds of which will be
paid to Targa to retire an additional portion of our affiliate
indebtedness;
|
|
|
|
the remaining affiliate indebtedness will be retired and treated
as a capital contribution to us;
|
|
|
|
we will enter into an omnibus agreement with Targa and our
general partner, which will address, among other things, the
provision of and the reimbursement for general and
administrative and operating services;
|
|
|
|
we will enter into a natural gas purchase agreement, pursuant to
which we will sell all of our residue natural gas to Targa at
market-based prices for a term of 15 years; and
|
|
|
|
we will enter into NGL and condensate purchase agreements,
pursuant to which we will sell all of our NGLs and high-pressure
condensate to Targa at market-based prices for a term of
15 years.
|
Our affiliate indebtedness consists of borrowings incurred by
Targa and allocated to us for financial reporting purposes as
well as intercompany indebtedness to be contributed to us
together with the North Texas System.
We will use any net proceeds from the exercise of the
underwriters option to reduce outstanding borrowings under
our new credit facility. If the underwriters exercise in full
their option to purchase additional common units, the ownership
interest of the public unitholders will increase to 19,320,000
common units, representing an aggregate 61.4% limited partner
interest in us, the ownership interest of our general partner
will increase to 629,555 general partner units, representing a
2% general partner interest in us, and the ownership interest of
Targa will remain at 11,528,231 subordinated units, representing
a 36.6% limited partner interest in us.
Management
of Targa Resources Partners LP
Targa Resources GP LLC, our general partner, will manage our
business and operations, and its board of directors and officers
will make decisions on our behalf. All of the executive officers
and some of the directors of Targa also serve as executive
officers or directors of our general partner.
Unlike shareholders in a publicly traded corporation, our
unitholders will not be entitled to elect our general partner or
its directors. Targa will elect all five members to the board of
directors of our general partner and we will have three
directors that are independent as defined under the independence
standards established by The NASDAQ Global Market. For more
information about these individuals, please see
Management Directors and Executive
Officers.
The diagram on the following page depicts our organization and
ownership after giving effect to the offering and the related
Formation Transactions.
6
Simplified
Organizational Structure and Ownership of Targa Resources
Partners LP
after the Formation Transactions
|
|
|
|
|
Public Common Units
|
|
|
58.1
|
%
|
Targa Subordinated Units
|
|
|
39.9
|
%
|
General Partner Units
|
|
|
2.0
|
%
|
|
|
|
|
|
Total
|
|
|
100.0
|
%
|
|
|
|
(1)
|
|
Ownership percentages are presented
on a fully-diluted basis.
|
|
(2)
|
|
Targa Resources, Inc. is an
indirect wholly-owned subsidiary of Targa Resources Investments
Inc. Warburg Pincus LLC controls us through its ownership of
securities in Targa Resources Investments Inc. and a
stockholders agreement among Targa Resources Investments Inc.
and its owners.
|
7
Principal
Executive Offices and Internet Address
Our principal executive offices are located at 1000 Louisiana,
Suite 4300, Houston, Texas 77002 and our telephone number
is
(713) 584-1000.
Our website is located at www.targaresources.com. We expect to
make our periodic reports and other information filed with or
furnished to the Securities and Exchange Commission, or the SEC,
available, free of charge, through our website, as soon as
reasonably practicable after those reports and other information
are electronically filed with or furnished to the SEC.
Information on our website or any other website is not
incorporated by reference into this prospectus and does not
constitute a part of this prospectus.
Summary
of Conflicts of Interest and Fiduciary Duties
Targa Resources GP LLC, our general partner, has a legal duty to
manage us in a manner beneficial to holders of our common units
and subordinated units. This legal duty originates in statutes
and judicial decisions and is commonly referred to as a
fiduciary duty. However, because our general partner
is owned by Targa, the officers and directors of our general
partner also have fiduciary duties to manage our general partner
in a manner beneficial to Targa. As a result of this
relationship, conflicts of interest may arise in the future
between us and holders of our common units and subordinated
units, on the one hand, and our general partner and its
affiliates on the other hand. Our partnership agreement also
provides that Targa is not restricted from competing with us.
For a more detailed description of the conflicts of interest and
fiduciary duties of our general partner, please see
Conflicts of Interest and Fiduciary Duties.
8
The
Offering
|
|
|
Common units offered to the public |
|
16,800,000 common units or 19,320,000 common units if the
underwriters exercise in full their option to purchase
additional common units. |
|
Units outstanding after this offering |
|
16,800,000 common units and 11,528,231 subordinated units,
representing 58.1% and 39.9% limited partner interests in us
(19,320,000 common units and 11,528,231 subordinated units,
representing 61.4% and 36.6% limited partner interests in us if
the underwriters exercise in full their option to purchase
additional common units). The general partner will own 578,127
general partner units, or 629,555 general partner units if the
underwriters exercise in full their option to purchase
additional common units, in each case representing a 2% general
partner interest in us. |
|
Use of proceeds |
|
We intend to use the net proceeds of approximately
$315.3 million from this offering (at an assumed offering
price of $20.00 per common unit), after deducting underwriting
discounts and deducting a structuring fee of approximately
$1.3 million but before paying offering expenses, to: |
|
|
|
|
|
|
pay approximately $4.0 million in expenses
associated with this offering and the Formation Transactions;
|
|
|
|
|
|
pay approximately $4.2 million in fees and
expenses related to our new credit facility; and
|
|
|
|
|
|
use the remaining proceeds to pay approximately
$307.1 million to Targa to retire a portion of our
affiliate indebtedness.
|
|
|
|
|
|
We also expect to borrow approximately $342.5 million under
our new credit facility upon the closing of this offering and to
pay that amount to Targa to retire an additional portion of our
affiliate indebtedness. The remaining balance of our affiliate
indebtedness will be retired and treated as a capital
contribution to us. Please see Certain Relationships and
Related Party Transactions Distributions and
Payments to our General Partner and its Affiliates. |
|
|
|
We will use any net proceeds from the exercise of the
underwriters option to purchase additional common units to
reduce outstanding borrowings under our new credit facility. |
|
Cash distributions |
|
We will make an initial quarterly distribution of $0.3375 per
common unit ($1.35 per common unit on an annualized basis) to
the extent we have sufficient cash from operations after
establishment of cash reserves and payment of fees and expenses.
Our ability to pay cash distributions at this initial
distribution rate is subject to various restrictions and other
factors described in more detail under the caption Our
Cash Distribution Policy and Restrictions on Distributions. |
|
|
|
Our partnership agreement requires us to distribute all of our
cash on hand at the end of each quarter, less reserves
established by our general partner. We refer to this cash as
available cash, and we define its meaning in our
partnership agreement. Our |
9
|
|
|
|
|
partnership agreement also requires that we distribute all of
our available cash from operating surplus each quarter during
the subordination period in the following manner: |
|
|
|
first, 98% to the holders of common units and
2% to our general partner, until each common unit has received a
minimum quarterly distribution of $0.3375 plus any arrearages
from prior quarters;
|
|
|
|
second, 98% to the holders of subordinated
units and 2% to our general partner, until each subordinated
unit has received a minimum quarterly distribution of
$0.3375; and |
|
|
|
third, 98% to all unitholders, pro rata, and
2% to our general partner, until each unit has received an
aggregate distribution of $0.3881. |
|
|
|
If cash distributions to our unitholders exceed $0.3881 per
common unit in any quarter, our general partner will receive, in
addition to distributions on its 2% general partner interest,
increasing percentages, up to 48%, of the cash we distribute in
excess of that amount. We refer to these distributions as
incentive distributions. Please see Provisions
of Our Partnership Agreement Relating to Cash
Distributions. |
|
|
|
|
|
We will adjust the quarterly distribution for the period from
the closing of this offering through March 31, 2007 based
on the actual length of the period. We expect to pay this cash
distribution on or about May 15, 2007. |
|
|
|
|
|
The amount of our pro forma available cash generated during the
year ended December 31, 2005 and the twelve months ended
September 30, 2006 would have been sufficient to allow us
to pay the full minimum quarterly distribution on all of our
common units but only approximately 29% and 98%, respectively,
of the minimum quarterly distribution on our subordinated units
during these periods (28% and 97%, respectively, assuming the
underwriters exercise in full their option to purchase
additional common units). For a calculation of our ability to
make distributions to unitholders based on our pro forma results
for 2006, please see Our Cash Distribution Policy and
Restrictions on Distributions. |
|
|
|
We believe that, based on the minimum estimated EBITDA for the
twelve months ending December 31, 2007 included under the
caption Our Cash Distribution Policy and Restrictions on
Distributions, we will have sufficient cash available for
distribution to make cash distributions for the four quarters
ending December 31, 2007 at the initial quarterly
distribution rate of $0.3375 per unit on all common units,
subordinated units and general partner units. |
|
Subordinated units |
|
Targa will initially own all of our subordinated units. The
principal difference between our common units and subordinated
units is that in any quarter during the subordination period,
holders of the subordinated units are entitled to receive the
minimum quarterly distribution of $0.3375 per unit only after
the common units have received the minimum quarterly
distribution plus any |
10
|
|
|
|
|
arrearages in the payment of the minimum quarterly distribution
from prior quarters. Subordinated units will not accrue
arrearages. The subordination period generally will end if we
have earned and paid at least $0.3375 on each outstanding unit
and general partner unit for any three consecutive,
non-overlapping four-quarter periods ending on or after
December 31, 2009. The subordination period will also end
if the unitholders remove our general partner other than for
cause and units held by our general partner and its affiliates
are not voted in favor of such removal. |
|
|
|
When the subordination period ends, all remaining subordinated
units will convert into common units on a
one-for-one
basis, and the common units will no longer be entitled to
arrearages. |
|
Early conversion of subordinated units |
|
If we have earned and paid at least $2.025 (150% of the
annualized minimum quarterly distribution) on each outstanding
common unit, subordinated unit and general partner unit for any
four-quarter
period, the subordination period will terminate automatically
and all of the subordinated units will convert into an equal
number of common units. Please see Provisions of Our
Partnership Agreement Related to Cash Distributions
Subordination Period. |
|
General Partners right to reset the target distribution
levels |
|
Our general partner has the right, at a time when there are no
subordinated units outstanding and it has received incentive
distributions at the highest level to which it is entitled (48%)
for each of the prior four consecutive fiscal quarters, to reset
the initial cash target distribution levels at higher levels
based on the distribution at the time of the exercise of the
reset election. Following a reset election by our general
partner, the minimum quarterly distribution amount will be reset
to an amount equal to the average cash distribution amount per
common unit for the two fiscal quarters immediately preceding
the reset election (such amount is referred to as the
reset minimum quarterly distribution) and the target
distribution levels will be reset to correspondingly higher
levels based on the same percentage increases above the reset
minimum quarterly distribution amount as in our current target
distribution levels. |
|
|
|
In connection with resetting these target distribution levels,
our general partner will be entitled to receive Class B
units. The Class B units will be entitled to the same cash
distributions per unit as our common units and will be
convertible into an equal number of common units. The number of
Class B units to be issued will be equal to that number of
common units whose aggregate quarterly cash distributions
equaled the average of the distributions to our general partner
on the incentive distribution rights in the prior two quarters.
For a more detailed description of our general partners
right to reset the target distribution levels upon which the
incentive distribution payments are based and the concurrent
right of our general partner to receive Class B units in
connection with this reset, please see Provisions of Our |
11
|
|
|
|
|
Partnership Agreement Related to Cash Distributions
General Partners Right to Reset Incentive Distribution
Levels. |
|
Issuance of additional units |
|
We can issue an unlimited number of units without the consent of
our unitholders. Please see Units Eligible for Future
Sale and The Partnership Agreement
Issuance of Additional Securities. |
|
Limited voting rights |
|
Our general partner will manage and operate us. Unlike the
holders of common stock in a corporation, you will have only
limited voting rights on matters affecting our business. You
will have no right to elect our general partner or its directors
on an annual or other continuing basis. Our general partner may
not be removed except by a vote of the holders of at least
662/3%
of the outstanding units, including any units owned by our
general partner and its affiliates, voting together as a single
class. Upon consummation of this offering, our general partner
and its affiliates will own an aggregate of 40.7% of our common
and subordinated units. This will give our general partner the
ability to prevent its involuntary removal. Please see The
Partnership Agreement Voting Rights. |
|
Limited call right |
|
If at any time our general partner and its affiliates own more
than 80% of the outstanding common units, our general partner
has the right, but not the obligation, to purchase all of the
remaining common units at a price not less than the then-current
market price of the common units. |
|
|
|
Estimated ratio of taxable income to distributions |
|
We estimate that if you own the common units you purchase in
this offering through the record date for distributions for the
period ending December 31, 2009, you will be allocated, on
a cumulative basis, an amount of federal taxable income for that
period that will be 20% or less of the cash distributed to you
with respect to that period. For example, if you receive an
annual distribution of $1.35 per unit, we estimate that your
average allocable federal taxable income per year will be no
more than $0.27 per unit. Please see Material Tax
Consequences Tax Consequences of Unit
Ownership Ratio of Taxable Income to
Distributions. |
|
|
|
Material tax consequences |
|
For a discussion of other material federal income tax
consequences that may be relevant to prospective unitholders who
are individual citizens or residents of the United States,
please see Material Tax Consequences. |
|
|
|
Exchange listing |
|
Our common units have been approved for listing on The NASDAQ
Global Market under the symbol NGLS. |
12
Summary
Historical and Pro Forma Financial and Operating Data
The following table shows summary historical financial and
operating data of the North Texas System and pro forma financial
data of Targa Resources Partners LP for the periods and as of
the dates indicated. The historical financial statements
included in this prospectus reflect the results of operations of
the North Texas System to be contributed to us by Targa upon the
closing of this offering. We refer to the results of operations
of the North Texas System as the results of operations of the
Predecessor Business. The summary historical financial data for
the years ended December 31, 2003 and 2004, the ten-month
period ended October 31, 2005 and for the two-month period
ended December 31, 2005 are derived from the audited
financial statements of the Predecessor Business. The summary
historical financial data for the nine months ended
September 30, 2005 and 2006 are derived from the unaudited
financial statements of the Predecessor Business. The
Predecessor Business was acquired by Targa as part of
Targas acquisition of substantially all of Dynegy
Inc.s midstream business on October 31, 2005 (the
DMS Acquisition). The summary pro forma financial
data for the year ended December 31, 2005 and the nine
months ended September 30, 2006 are derived from the
unaudited pro forma financial statements of Targa Resources
Partners LP included in this prospectus. The pro forma
adjustments have been prepared as if certain transactions to be
effected at the closing of this offering had taken place on
September 30, 2006, in the case of the pro forma balance
sheet, or as of January 1, 2005, in the case of the pro
forma statement of operations for the nine months ended
September 30, 2006 and for the year ended December 31,
2005. The transactions reflected in the pro forma adjustments
assume the following actions will occur:
Targa will contribute the North Texas System to us;
|
|
|
|
|
we will issue to Targa 11,528,231 subordinated units,
representing a 39.9% limited partner interest in us;
|
|
|
|
we will issue to our general partner, Targa Resources GP LLC,
578,127 general partner units representing its initial 2%
general partner interest in us, and all of our incentive
distribution rights, which incentive distribution rights will
entitle our general partner to increasing percentages of the
cash we distribute in excess of $0.3881 per unit per quarter;
|
|
|
|
|
|
we will issue 16,800,000 common units to the public in this
offering, representing a 58.1% limited partner interest in us,
and will use the proceeds to pay expenses associated with this
offering, the Formation Transactions and our new credit facility
and to pay approximately $307.1 million to Targa to retire
a portion of our affiliate indebtedness;
|
|
|
|
|
|
we will borrow approximately $342.5 million under our new
$500 million credit facility the proceeds of which will be
paid to Targa to retire an additional portion of our affiliate
indebtedness; and
|
|
|
|
the remaining affiliate indebtedness will be retired and treated
as a capital contribution to us.
|
We derived the information in the following table from, and that
information should be read together with and is qualified in its
entirety by reference to, the historical combined and pro forma
condensed financial statements and the accompanying notes
included elsewhere in this prospectus.
13
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|
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|
|
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|
|
|
|
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|
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|
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Predecessor Business
|
|
|
Targa Resources Partners LP
|
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Dynegy
|
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Targa
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Pro Forma
|
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|
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Nine Months
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Ten Months
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|
|
Two Months
|
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|
Nine Months
|
|
|
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|
|
Nine Months
|
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|
|
Years Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Year Ended
|
|
|
Ended
|
|
|
|
December 31,
|
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September 30,
|
|
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October 31,
|
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|
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December 31,
|
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September 30,
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December 31,
|
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September 30,
|
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|
|
2003
|
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2004
|
|
|
2005
|
|
|
2005
|
|
|
|
2005
|
|
|
2006
|
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|
2005
|
|
|
2006
|
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|
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(Audited)
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|
|
(Audited)
|
|
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(Unaudited)
|
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|
(Audited)
|
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|
|
(Audited)
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
|
(in millions of dollars, except per unit and operating
data)
|
|
Statement of Operations
Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
196.8
|
|
|
$
|
258.6
|
|
|
$
|
249.7
|
|
|
$
|
293.3
|
|
|
|
$
|
75.1
|
|
|
$
|
290.9
|
|
|
$
|
368.4
|
|
|
$
|
290.9
|
|
Product purchases
|
|
|
147.3
|
|
|
|
182.6
|
|
|
|
179.0
|
|
|
|
210.8
|
|
|
|
|
54.9
|
|
|
|
205.2
|
|
|
|
265.7
|
|
|
|
205.2
|
|
Operating expense
|
|
|
15.1
|
|
|
|
17.7
|
|
|
|
15.8
|
|
|
|
18.0
|
|
|
|
|
3.5
|
|
|
|
17.9
|
|
|
|
21.5
|
|
|
|
17.9
|
|
Depreciation and amortization
expense
|
|
|
12.0
|
|
|
|
12.2
|
|
|
|
10.1
|
|
|
|
11.3
|
|
|
|
|
9.2
|
|
|
|
41.7
|
|
|
|
54.8
|
|
|
|
41.7
|
|
General and administrative expense
|
|
|
7.7
|
|
|
|
7.2
|
|
|
|
6.7
|
|
|
|
7.3
|
|
|
|
|
1.1
|
|
|
|
5.1
|
|
|
|
8.4
|
|
|
|
5.1
|
|
Interest expense, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11.5
|
|
|
|
54.4
|
|
|
|
24.8
|
|
|
|
18.6
|
|
Deferred income tax(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.0
|
|
|
|
|
|
|
|
2.0
|
|
Other, net
|
|
|
0.6
|
|
|
|
0.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
14.1
|
|
|
$
|
38.6
|
|
|
$
|
38.1
|
|
|
$
|
45.9
|
|
|
|
$
|
(5.1
|
)
|
|
$
|
(35.4
|
)
|
|
$
|
(6.8
|
)
|
|
$
|
0.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma net income (loss) per
limited partner unit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(0.24
|
)
|
|
$
|
0.01
|
|
Financial and Operating
Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
Financial data:
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating margin(2)
|
|
$
|
34.4
|
|
|
$
|
58.3
|
|
|
$
|
54.9
|
|
|
$
|
64.5
|
|
|
|
$
|
16.7
|
|
|
$
|
67.8
|
|
|
$
|
81.2
|
|
|
$
|
67.8
|
|
EBITDA(3)
|
|
|
26.1
|
|
|
|
50.8
|
|
|
|
48.2
|
|
|
|
57.2
|
|
|
|
|
15.6
|
|
|
|
62.7
|
|
|
|
72.8
|
|
|
|
62.7
|
|
Operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering throughput, MMcf/d(4)
|
|
|
134.3
|
|
|
|
152.0
|
|
|
|
160.4
|
|
|
|
161.2
|
|
|
|
|
168.8
|
|
|
|
168.2
|
|
|
|
|
|
|
|
|
|
Plant natural gas inlet, MMcf/d(5)
|
|
|
128.6
|
|
|
|
145.4
|
|
|
|
155.4
|
|
|
|
156.2
|
|
|
|
|
161.9
|
|
|
|
161.6
|
|
|
|
|
|
|
|
|
|
Gross NGL production, MBbl/d
|
|
|
15.9
|
|
|
|
17.2
|
|
|
|
18.4
|
|
|
|
18.5
|
|
|
|
|
19.8
|
|
|
|
18.8
|
|
|
|
|
|
|
|
|
|
Natural gas sales, BBtu/d
|
|
|
42.0
|
|
|
|
59.2
|
|
|
|
68.4
|
|
|
|
68.9
|
|
|
|
|
72.3
|
|
|
|
75.2
|
|
|
|
|
|
|
|
|
|
NGL sales, MBbl/d
|
|
|
15.3
|
|
|
|
13.2
|
|
|
|
14.2
|
|
|
|
14.3
|
|
|
|
|
15.4
|
|
|
|
15.1
|
|
|
|
|
|
|
|
|
|
Condensate sales, MBbl/d
|
|
|
0.6
|
|
|
|
0.7
|
|
|
|
0.5
|
|
|
|
0.5
|
|
|
|
|
0.5
|
|
|
|
0.5
|
|
|
|
|
|
|
|
|
|
Balance Sheet Data (at period
end):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant, and equipment, net
|
|
$
|
180.4
|
|
|
$
|
191.2
|
|
|
|
195.4
|
|
|
$
|
196.4
|
|
|
|
$
|
1,097.0
|
|
|
$
|
1,073.0
|
|
|
|
|
|
|
$
|
1,073.0
|
|
Total assets
|
|
|
182.9
|
|
|
|
193.5
|
|
|
|
197.6
|
|
|
|
198.5
|
|
|
|
|
1,122.8
|
|
|
|
1,126.3
|
|
|
|
|
|
|
|
1,110.9
|
|
Long-term debt (including current
portion)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
868.9
|
|
|
|
865.2
|
|
|
|
|
|
|
|
342.5
|
|
Partners capital / Net parent
equity
|
|
|
164.8
|
|
|
|
168.8
|
|
|
|
161.9
|
|
|
|
158.5
|
|
|
|
|
219.5
|
|
|
|
227.2
|
|
|
|
|
|
|
|
734.5
|
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
31.3
|
|
|
$
|
58.0
|
|
|
$
|
59.2
|
|
|
$
|
72.7
|
|
|
|
$
|
(1.5
|
)
|
|
$
|
11.1
|
|
|
|
|
|
|
|
|
|
Investing activities
|
|
|
(14.6
|
)
|
|
|
(23.4
|
)
|
|
|
(14.2
|
)
|
|
|
(16.4
|
)
|
|
|
|
(2.1
|
)
|
|
|
(17.7
|
)
|
|
|
|
|
|
|
|
|
Financing activities
|
|
|
(16.7
|
)
|
|
|
(34.6
|
)
|
|
|
(45.0
|
)
|
|
|
(56.3
|
)
|
|
|
|
3.6
|
|
|
|
6.6
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
In May 2006, Texas adopted a margin tax consisting of a 1% tax
on the amount by which total revenue exceeds cost of goods sold.
The amount presented represents our estimated liability for this
tax.
|
|
(2)
|
Operating margin is total operating revenues less product
purchases and operating expense. Please see
Non-GAAP Financial Measures.
|
|
(3)
|
EBITDA is net income before interest, income taxes, depreciation
and amortization. Please see Non-GAAP Financial
Measures.
|
|
(4)
|
Gathering throughput represents the volume of natural gas
gathered and passed through natural gas gathering pipelines from
connections to producing wells and central delivery points.
|
|
(5)
|
Plant natural gas inlet represents the volume of natural gas
passing through the meter located at the inlet point of a
natural gas processing plant.
|
14
Non-GAAP Financial
Measures
EBITDA. We define EBITDA as net income before
interest, income taxes, depreciation and amortization. EBITDA is
used as a supplemental financial measure by our management and
by external users of our financial statements such as investors,
commercial banks and others, to assess:
|
|
|
|
|
the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis;
|
|
|
|
|
|
our operating performance and return on capital as compared to
other companies in the midstream energy sector, without regard
to financing or capital structure; and
|
|
|
|
|
|
the viability of acquisitions and capital expenditure projects
and the overall rates of return on alternative investment
opportunities.
|
The economic substance behind managements use of EBITDA is
to measure the ability of our assets to generate cash sufficient
to pay interest costs, support our indebtedness, and make
distributions to our investors.
The GAAP measures most directly comparable to EBITDA are net
cash provided by operating activities and net income. Our
non-GAAP financial measure of EBITDA should not be considered as
an alternative to GAAP net cash provided by operating activities
and GAAP net income. EBITDA is not a presentation made in
accordance with GAAP and has important limitations as an
analytical tool. You should not consider EBITDA in isolation or
as a substitute for analysis of our results as reported under
GAAP. Because EBITDA excludes some, but not all, items that
affect net income and net cash provided by operating activities
and is defined differently by different companies in our
industry, our definition of EBITDA may not be comparable to
similarly titled measures of other companies.
Management compensates for the limitations of EBITDA as an
analytical tool by reviewing the comparable GAAP measures,
understanding the differences between the measures and
incorporating these learnings into managements
decision-making processes.
Operating Margin. We define operating margin
as total operating revenues, which consist of natural gas and
NGL sales plus service fee revenues, less product purchases,
which consist primarily of producer payments and other natural
gas purchases, and operating expense. Management reviews
operating margin monthly for consistency and trend analysis.
Based on this monthly analysis, management takes appropriate
action to maintain positive trends or to reverse negative
trends. Management uses operating margin as an important
performance measure of the core profitability of our operations.
The GAAP measure most directly comparable to operating margin is
net income. Our non-GAAP financial measure of operating margin
should not be considered as an alternative to GAAP net income.
Operating margin is not a presentation made in accordance with
GAAP and has important limitations as an analytical tool. You
should not consider operating margin in isolation or as a
substitute for analysis of our results as reported under GAAP.
Because operating margin excludes some, but not all, items that
affect net income and is defined differently by different
companies in our industry, our definition of operating margin
may not be comparable to similarly titled measures of other
companies, thereby diminishing its utility.
Management compensates for the limitations of operating margin
as an analytical tool by reviewing the comparable GAAP measures,
understanding the differences between the measures and
incorporating these learnings into managements
decision-making processes.
We believe that investors benefit from having access to the same
financial measures that our management uses in evaluating our
operating results. Operating margin provides useful information
to investors because it is used as a supplemental financial
measure by our management and by external users of our financial
statements, including such investors, commercial banks and
others, to assess:
|
|
|
|
|
the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis;
|
15
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|
|
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|
our operating performance and return on capital as compared to
other companies in the midstream energy sector, without regard
to financing or capital structure;
|
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the viability of acquisitions and capital expenditure projects
and the overall rates of return on alternative investment
opportunities.
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|
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|
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|
Predecessor Business
|
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|
Targa Resources Partners LP
|
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Dynegy
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|
Targa
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Pro Forma
|
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Nine Months
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Ten Months
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Two Months
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Nine Months
|
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|
Nine Months
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Years Ended
|
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Ended
|
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|
Ended
|
|
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|
Ended
|
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|
Ended
|
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Year Ended
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Ended
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December 31,
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September 30,
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October 31,
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December 31,
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September 30,
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December 31,
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September 30,
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2003
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2004
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2005
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2005
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2005
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2006
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2005
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2006
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(Audited)
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(Audited)
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(Unaudited)
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(Audited)
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|
(Audited)
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|
(Unaudited)
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|
(Unaudited)
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|
(Unaudited)
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(in millions of dollars)
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Reconciliation of
EBITDA to net cash provided by (used in) operating
activities:
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|
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|
|
|
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Net cash provided by (used in)
operating activities
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$
|
31.3
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$
|
58.0
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$
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59.2
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|
$
|
72.7
|
|
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|
$
|
(1.5
|
)
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|
$
|
11.1
|
|
|
|
|
|
|
|
|
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Allocated interest expense from
parent(1)
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|
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|
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|
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10.7
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|
|
|
50.5
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|
|
|
|
|
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|
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Changes in operating working
capital which provided (used) cash:
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|
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|
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|
|
|
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|
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Accounts receivable
|
|
|
0.7
|
|
|
|
(0.7
|
)
|
|
|
0.5
|
|
|
|
0.3
|
|
|
|
|
0.1
|
|
|
|
(0.4
|
)
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
|
(1.0
|
)
|
|
|
(2.7
|
)
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|
|
1.1
|
|
|
|
1.3
|
|
|
|
|
0.8
|
|
|
|
|
|
|
|
|
|
|
|
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Other, including changes in
noncurrent assets and liabilities
|
|
|
(4.9
|
)
|
|
|
(3.8
|
)
|
|
|
(12.6
|
)
|
|
|
(17.1
|
)
|
|
|
|
5.5
|
|
|
|
1.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA
|
|
$
|
26.1
|
|
|
$
|
50.8
|
|
|
$
|
48.2
|
|
|
$
|
57.2
|
|
|
|
$
|
15.6
|
|
|
$
|
62.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
Reconciliation of
EBITDA to net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
14.1
|
|
|
$
|
38.6
|
|
|
$
|
38.1
|
|
|
$
|
45.9
|
|
|
|
$
|
(5.1
|
)
|
|
$
|
(35.4
|
)
|
|
$
|
(6.8
|
)
|
|
$
|
0.4
|
|
Add:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Interest expense, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11.5
|
|
|
|
54.4
|
|
|
|
24.8
|
|
|
|
18.6
|
|
Deferred tax expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.0
|
|
|
|
|
|
|
|
2.0
|
|
Depreciation and amortization
expense
|
|
|
12.0
|
|
|
|
12.2
|
|
|
|
10.1
|
|
|
|
11.3
|
|
|
|
|
9.2
|
|
|
|
41.7
|
|
|
|
54.8
|
|
|
|
41.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA
|
|
$
|
26.1
|
|
|
$
|
50.8
|
|
|
$
|
48.2
|
|
|
$
|
57.2
|
|
|
|
$
|
15.6
|
|
|
$
|
62.7
|
|
|
$
|
72.8
|
|
|
$
|
62.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of
operating margin to net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
14.1
|
|
|
$
|
38.6
|
|
|
$
|
38.1
|
|
|
$
|
45.9
|
|
|
|
$
|
(5.1
|
)
|
|
$
|
(35.4
|
)
|
|
$
|
(6.8
|
)
|
|
$
|
0.4
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
expense
|
|
|
12.0
|
|
|
|
12.2
|
|
|
|
10.1
|
|
|
|
11.3
|
|
|
|
|
9.2
|
|
|
|
41.7
|
|
|
|
54.8
|
|
|
|
41.7
|
|
Deferred income tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.0
|
|
|
|
|
|
|
|
2.0
|
|
Other, net
|
|
|
0.6
|
|
|
|
0.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11.5
|
|
|
|
54.4
|
|
|
|
24.8
|
|
|
|
18.6
|
|
General and administrative expense
|
|
|
7.7
|
|
|
|
7.2
|
|
|
|
6.7
|
|
|
|
7.3
|
|
|
|
|
1.1
|
|
|
|
5.1
|
|
|
|
8.4
|
|
|
|
5.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating margin
|
|
$
|
34.4
|
|
|
$
|
58.3
|
|
|
$
|
54.9
|
|
|
$
|
64.5
|
|
|
|
$
|
16.7
|
|
|
$
|
67.8
|
|
|
$
|
81.2
|
|
|
$
|
67.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Excludes non-cash amortization of debt issue costs of $0.8
million for the two months ended December 31, 2005 and
$3.9 million for the nine months ended September 30, 2006.
|
16
RISK
FACTORS
Limited partner interests are inherently different from
capital stock of a corporation, although many of the business
risks to which we are subject are similar to those that would be
faced by a corporation engaged in similar businesses. You should
consider carefully the following risk factors together with all
of the other information included in this prospectus in
evaluating an investment in our common units.
If any of the following risks were actually to occur, then
our business, financial condition or results of operations could
be materially adversely affected. In that case, we might not be
able to pay the minimum quarterly distribution on our common
units, the trading price of our common units could decline and
you could lose all or part of your investment.
Risks
Related to Our Business
We may
not have sufficient cash from operations following the
establishment of cash reserves and payment of fees and expenses,
including cost reimbursements to our general partner, to enable
us to make cash distributions to holders of our common units and
subordinated units at the initial distribution rate under our
cash distribution policy.
In order to make our cash distributions at our initial
distribution rate of $0.3375 per common unit and
subordinated unit per complete quarter, or $1.35 per unit per
year, we will require available cash of approximately
$9.8 million per quarter, or $39.0 million per year,
based on the common units and subordinated units outstanding
immediately after completion of this offering
($10.6 million or $42.5 million, respectively, if the
underwriters exercise in full their option to purchase
additional common units). We may not have sufficient available
cash from operating surplus each quarter to enable us to make
cash distributions at the initial distribution rate under our
cash distribution policy. The amount of cash we can distribute
on our units principally depends upon the amount of cash we
generate from our operations, which will fluctuate from quarter
to quarter based on, among other things:
|
|
|
|
|
the fees we charge and the margins we realize for our services;
|
|
|
|
the prices of, levels of production of, and demand for, natural
gas and natural gas liquids, or NGLs;
|
|
|
|
the volume of natural gas we gather, treat, compress, process,
transport and sell, and the volume of NGLs we process or
fractionate and sell;
|
|
|
|
the relationship between natural gas and NGL prices;
|
|
|
|
cash settlements of hedging positions;
|
|
|
|
the level of competition from other midstream energy companies;
|
|
|
|
the level of our operating and maintenance and general and
administrative costs; and
|
|
|
|
prevailing economic conditions.
|
In addition, the actual amount of cash we will have available
for distribution will depend on other factors, some of which are
beyond our control, including:
|
|
|
|
|
the level of capital expenditures we make;
|
|
|
|
our ability to make borrowings under our credit facility to pay
distributions;
|
|
|
|
the cost of acquisitions;
|
|
|
|
our debt service requirements and other liabilities;
|
|
|
|
fluctuations in our working capital needs;
|
|
|
|
general and administrative expenses, including expenses we will
incur as a result of being a public company;
|
17
|
|
|
|
|
restrictions on distributions contained in our debt
agreements; and
|
|
|
|
the amount of cash reserves established by our general partner
for the proper conduct of our business.
|
For a description of additional restrictions and factors that
may affect our ability to make cash distributions, please see
Our Cash Distribution Policy and Restrictions on
Distributions.
On a
pro forma basis we would not have had sufficient cash available
for distribution to pay the full minimum quarterly distribution
on all units for the year ended December 31, 2005 or for
the twelve months ended September 30, 2006.
The amount of available cash we need to pay the minimum
quarterly distribution for four quarters on all of our units to
be outstanding immediately after this offering is approximately
$39.0 million. The amount of our pro forma available cash
generated during the year ended December 31, 2005 and the
twelve months ended September 30, 2006 would have been
sufficient to allow us to pay the full minimum quarterly
distribution on all of our common units but only approximately
29% and 98%, respectively, of the minimum quarterly distribution
on our subordinated units during these periods (28% and 97%
respectively, assuming the underwriters exercise in full their
option to purchase additional common units). For a calculation
of our ability to make distributions to unitholders based on our
pro forma results for 2006, please see Our Cash
Distribution Policy and Restrictions on Distributions.
Our
cash flow is affected by natural gas and NGL prices, and
decreases in these prices could adversely affect our ability to
make distributions to holders of our common units and
subordinated units.
Our operations can be affected by the level of natural gas and
NGL prices and the relationship between these prices. The prices
of natural gas and NGLs have been volatile and we expect this
volatility to continue. The NYMEX daily settlement price for
natural gas for the forward month contract in 2005 ranged from a
high of $15.38 per MMBtu to a low of $5.79 per MMBtu.
In the first nine months of 2006, NYMEX pricing ranged from a
high of $10.63 per MMBtu to a low of $4.20 per MMBtu.
Natural gas prices reached relatively high levels in 2005 and
early 2006 but have declined substantially through the first
three quarters of 2006, with the forward month gas futures
contracts closing at a four-year low in September of 2006. NGL
prices exhibit similar volatility. Based on monthly index
prices, the average price for our NGL composition ranged from a
high of $1.12 per gallon to a low $0.73 per gallon in 2005, and
from a high of $1.14 per gallon to a low of $0.88 per
gallon for the first nine months of 2006.
Our future cash flow will be materially adversely affected if we
experience significant, prolonged pricing deterioration below
general price levels experienced over the past few years in our
industry.
The markets and prices for natural gas and NGLs depend upon
factors beyond our control. These factors include demand for
these commodities, which fluctuate with changes in market and
economic conditions and other factors, including:
|
|
|
|
|
the impact of seasonality and weather;
|
|
|
|
general economic conditions;
|
|
|
|
the level of domestic crude oil and natural gas production and
consumption;
|
|
|
|
the availability of imported natural gas, NGLs and crude oil;
|
|
|
|
actions taken by foreign oil and gas producing nations;
|
|
|
|
the availability of local, intrastate and interstate
transportation systems;
|
|
|
|
the availability and marketing of competitive fuels;
|
|
|
|
the impact of energy conservation efforts; and
|
|
|
|
the extent of governmental regulation and taxation.
|
Our primary natural gas gathering and processing arrangements
that expose us to commodity price risk are our
percent-of-proceeds
arrangements. For the nine month period ended September 30,
2006, our
percent-of-proceeds
arrangements accounted for approximately 96% of our gathered
natural gas volume.
18
Under
percent-of-proceeds
arrangements, we generally process natural gas from producers
for an agreed percentage of the proceeds from the sale of
residue gas and NGLs resulting from our processing activities,
selling the resulting residue gas and NGLs at market prices.
Under these types of arrangements, our revenues and our cash
flows increase or decrease, whichever is applicable, as the
price of natural gas, NGLs and crude oil fluctuates. For
additional information regarding our hedging activities, please
see Managements Discussion and Analysis of Financial
Condition and Results of Operation Quantitative and
Qualitative Disclosures about Market Risk Commodity
Price Risk.
Because
of the natural decline in production from existing wells in our
operating regions, our success depends on our ability to obtain
new sources of supplies of natural gas and NGLs, which depends
on certain factors beyond our control. Any decrease in supplies
of natural gas or NGLs could adversely affect our business and
operating results.
Our gathering systems are connected to natural gas wells, from
which the production will naturally decline over time, which
means that our cash flows associated with these wells will also
decline over time. To maintain or increase throughput levels on
our gathering systems and the utilization rate at our processing
plants and our treating and fractionation facilities, we must
continually obtain new natural gas supplies. Our ability to
obtain additional sources of natural gas depends in part on the
level of successful drilling activity near our gathering systems.
We have no control over the level of drilling activity in the
areas of our operations, the amount of reserves associated with
the wells or the rate at which production from a well will
decline. In addition, we have no control over producers or their
drilling or production decisions, which are affected by, among
other things, prevailing and projected energy prices, demand for
hydrocarbons, the level of reserves, geological considerations,
governmental regulations, availability of drilling rigs and
other production and development costs and the availability and
cost of capital. We believe that rig availability in the
Fort Worth Basin has been and will continue to be a
limiting factor on the number of wells drilled in that area.
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 generally
decreases as oil and natural gas prices decrease. Natural gas
prices reached relatively high levels in 2005 and early 2006 but
have declined substantially through the first
three quarters of 2006, with gas futures contracts closing
at a four-year low in September of 2006. These recent declines
in natural gas prices are beginning to have a negative impact on
exploration, development and production activity, and if
sustained, could lead to a material decrease in such activity.
Reductions in exploration or production activity or shut-ins by
producers in the areas in which we operate as a result of a
sustained decline in natural gas prices would lead to reduced
utilization of our gathering and processing assets.
Because of these factors, even if new natural gas reserves are
discovered in areas served by our assets, producers may choose
not to develop those reserves. If, due to reductions in drilling
activity or competition, we are not able to obtain new supplies
of natural gas to replace the natural decline in volumes from
existing wells, throughput on our pipelines and the utilization
rates of our treating, processing and fractionation facilities
would decline, which could reduce our revenue and impair our
ability to make distributions to our unitholders.
Our
hedging activities may not be effective in reducing the
variability of our cash flows and may, in certain circumstances,
increase the variability of our cash flows. In addition, the
significant contribution to our results of operations that we
are currently receiving from our hedge positions will decrease
substantially through 2010.
We have entered into derivative transactions related to only a
portion of our equity volumes. As a result, we will continue to
have direct commodity price risk to the unhedged portion. Our
actual future volumes may be significantly higher or lower than
we estimated at the time we entered into the derivative
transactions for that period. If the actual amount is higher
than we estimated, we will have greater commodity price risk
than we intended. If the actual amount is lower than the amount
that is subject to our derivative financial instruments, we
might be forced to satisfy all or a portion of our derivative
transactions without the benefit of the cash flow from our sale
of the underlying physical commodity, resulting in a
19
reduction of our liquidity. The derivative instruments we
utilize for these hedges are based on posted market prices,
which may be lower than the actual natural gas, NGL and
condensate prices that we realize in our operations. As a result
of these factors, our hedging activities may not be as effective
as we intend in reducing the variability of our cash flows, and
in certain circumstances may actually increase the variability
of our cash flows. To the extent we hedge our commodity price
risk, we may forego the benefits we would otherwise experience
if commodity prices were to change in our favor.
Our results of operations are currently realizing a significant
benefit from hedge positions entered into in April and May of
2006. We estimate that our hedges will generate approximately
$15 million in operating income for the twelve months
ending December 31, 2007. If future prices remain
comparable to current prices, we expect that this benefit will
decline materially over the life of the hedges, which cover
decreasing volumes at declining prices through 2010. For
additional information regarding our hedging activities, please
see Managements Discussion and Analysis of Financial
Condition and Results of Operation Quantitative and
Qualitative Disclosures about Market Risk.
The
assumptions underlying the minimum estimated EBITDA we include
in Our Cash Distribution Policy and Restrictions on
Distributions are inherently uncertain and are subject to
significant business, economic, financial, regulatory and
competitive risks and uncertainties that could cause actual
results to differ materially from those
forecasted.
The minimum estimated EBITDA set forth in Our Cash
Distribution Policy and Restrictions on Distributions
presents our ability to make the minimum quarterly distribution
for the twelve months ending December 31, 2007. Our minimum
estimated EBITDA and related assumptions have been prepared by,
and are the responsibility of, management and our independent
auditor has neither compiled nor examined our minimum estimated
EBITDA and provides no assurance nor any report on it. The
assumptions underlying our minimum estimated EBITDA are
inherently uncertain and are subject to significant business,
economic, financial, regulatory and competitive risks and
uncertainties that could cause actual results to differ
materially from those forecasted. If we do not achieve our
anticipated results, we may not be able to pay the full minimum
quarterly distribution or any amount on our common units or
subordinated units, in which event the market price of our
common units may decline materially.
We
depend on one natural gas producer for a significant portion of
our supply of natural gas. The loss of this customer or
replacement of its contracts on less favorable terms could
result in a decline in our volumes, revenues and cash available
for distribution.
Our largest natural gas supplier for the year ended
December 31, 2005 and the nine months ended
September 30, 2006 was ConocoPhillips, who accounted for
approximately 36% and 34%, respectively, of our supply. The loss
of all or even a portion of the natural gas volumes supplied by
this customer or the extension or replacement of these contracts
on less favorable terms, if at all, as a result of competition
or otherwise, could reduce our revenue or increase our cost for
product purchases, impairing our ability to make distributions
to our unitholders.
If
third-party pipelines and other facilities interconnected to our
natural gas pipelines and facilities become partially or fully
unavailable to transport natural gas and NGLs, our revenues and
cash available for distribution could be adversely
affected.
We depend upon third party pipelines and other facilities that
provide delivery options to and from our pipelines and
facilities. Since we do not own or operate these pipelines or
other facilities, their continuing operation is not within our
control. If any of these third-party pipelines and other
facilities become partially or fully unavailable to transport
natural gas and NGLs, our revenues and cash available for
distribution could be adversely affected.
We
depend on our Chico system for a substantial majority of our
revenues and if those revenues were reduced, there would be a
material adverse effect on our results of operations and ability
to make distributions to unitholders.
Any significant curtailment of gathering, compressing, treating,
processing or fractionation of natural gas on our Chico system
could result in our realizing materially lower levels of
revenues and cash flow for
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the duration of such curtailment. For the nine months ended
September 30, 2006, our Chico plant inlet volume accounted
for over 90% of our revenues. Operations at our Chico system
could be partially curtailed or completely shut down,
temporarily or permanently, as a result of:
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competition from other systems that may be able to meet producer
needs or supply end-user markets on a more cost-effective basis;
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operational problems such as catastrophic events at the Chico
processing plant or gathering lines, labor difficulties or
environmental proceedings or other litigation that compel
cessation of all or a portion of the operations on our Chico
system;
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an inability to obtain sufficient quantities of natural gas for
the Chico system at competitive terms; or
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reductions in exploration or production activity, or shut-ins by
producers in the areas in which we operate.
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The magnitude of the effect on us of any curtailment of
operations will depend on the length of the curtailment and the
extent of the operations affected by such curtailment. We have
no control over many of the factors that may lead to a
curtailment of operations.
In addition, our business interruption insurance is subject to
limitations and deductions. If a significant accident or event
occurs at our Chico system that is not fully insured, it could
adversely affect our operations and financial condition.
We are
exposed to the credit risk of Targa and any material
nonperformance by Targa could reduce our ability to make
distributions to our unitholders.
At the closing of this offering, we will enter into purchase
agreements with Targa pursuant to which Targa will purchase all
of our natural gas, NGLs and high-pressure condensate for a term
of 15 years. We will also enter into an omnibus agreement
with Targa which will address, among other things, the provision
of general and administrative and operating services to us. As
of January 31, 2007, Moodys and Standard &
Poors assigned Targa corporate credit ratings of B1 and
B+, respectively, which are speculative ratings. These
speculative ratings signify a higher risk that Targa will
default on its obligations, including its obligations to us,
than does an investment grade credit rating. Any material
nonperformance under the omnibus and purchase agreements by
Targa could materially and adversely impact our ability to
operate and make distributions to our unitholders.
Our
general partner is an obligor under, and subject to a pledge
related to, Targas credit facility; in the event Targa is
unable to meet its obligations under that facility, or is
declared bankrupt, Targas lenders may gain control of our
general partner or, in the case of bankruptcy, our partnership
may be dissolved.
Our general partner is an obligor under, and all of its assets
and Targas ownership interest in it are subject to a lien
related to, Targas credit facility. In the event Targa is
unable to satisfy its obligations under the credit facility and
the lenders foreclose on their collateral, the lenders will own
our general partner and all of its assets, which include the
general partner interest in us and our incentive distribution
rights. In such event, the lenders would control our management
and operation. Moreover, in the event Targa becomes insolvent or
is declared bankrupt, our general partner may be deemed
insolvent or declared bankrupt as well. Under the terms of our
partnership agreement, the bankruptcy or insolvency of our
general partner will cause a dissolution of our partnership.
Our
industry is highly competitive, and increased competitive
pressure could adversely affect our business and operating
results.
We compete with similar enterprises in our respective areas of
operation. Some of our competitors are large oil, natural gas
and petrochemical companies that have greater financial
resources and access to supplies of natural gas and NGLs than we
do. Some of these competitors may expand or construct gathering,
processing and transportation systems that would create
additional competition for the services we provide to our
customers. In addition, our customers who are significant
producers of natural gas may develop their own gathering,
processing and transportation systems in lieu of using ours. Our
ability to renew or replace existing contracts with our
customers at rates sufficient to maintain current revenues and
21
cash flows could be adversely affected by the activities of our
competitors and our customers. All of these competitive
pressures could have a material adverse effect on our business,
results of operations, financial condition and ability to make
cash distributions to you.
Our
business involves many hazards and operational risks, some of
which may not be fully covered by insurance. If a significant
accident or event occurs that is not fully insured, our
operations and financial results could be adversely
affected.
Our operations are subject to many hazards inherent in the
gathering, compressing, treating, processing and transporting of
natural gas and NGLs, including:
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damage to pipelines and plants, related equipment and
surrounding properties caused by hurricanes, tornadoes, floods,
fires and other natural disasters, explosions and acts of
terrorism;
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inadvertent damage from third parties, including from
construction, farm and utility equipment;
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leaks of natural gas, NGLs and other hydrocarbons or losses of
natural gas or NGLs as a result of the malfunction of equipment
or facilities; and
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other hazards that could also result in personal injury and loss
of life, pollution and suspension of operations.
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These risks could result in substantial losses due to personal
injury
and/or loss
of life, severe damage to and destruction of property and
equipment and pollution or other environmental damage and may
result in curtailment or suspension of our related operations. A
natural disaster or other hazard affecting the areas in which we
operate could have a material adverse effect on our operations.
Our insurance is provided under Targas insurance programs.
We are not fully insured against all risks inherent to our
business. We are not insured against all environmental accidents
that might occur which may include toxic tort claims, other than
those considered to be sudden and accidental. If a significant
accident or event occurs that is not fully insured, it could
adversely affect our operations and financial condition. In
addition, Targa may not be able to maintain or obtain insurance
of the type and amount we desire at reasonable rates. Moreover,
significant claims by Targa may limit or eliminate the amount of
insurance proceeds available to us. As a result of market
conditions, premiums and deductibles for certain of our
insurance policies have increased substantially, and could
escalate further. In some instances, certain insurance could
become unavailable or available only for reduced amounts of
coverage.
Our
debt levels may limit our flexibility in obtaining additional
financing and in pursuing other business
opportunities.
At the closing of this offering, we will borrow approximately
$342.5 million under our new credit facility. Our level of
debt could have important consequences for us, including the
following:
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our ability to obtain additional financing, if necessary, for
working capital, capital expenditures, acquisitions or other
purposes may be impaired or such financing may not be available
on favorable terms;
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we will need a portion of our cash flow to make interest
payments on our debt, reducing the funds that would otherwise be
available for operations, future business opportunities and
distributions to unitholders;
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our debt level will make us more vulnerable to competitive
pressures or a downturn in our business or the economy
generally; and
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our debt level may limit our flexibility in responding to
changing business and economic conditions.
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Our ability to service our debt will depend upon, among other
things, our future financial and operating performance, which
will be affected by prevailing economic conditions and
financial, business, regulatory and other factors, some of which
are beyond our control. If our operating results are not
sufficient to service our current or future indebtedness, we
will be forced to take actions such as reducing distributions,
reducing or delaying our business activities, acquisitions,
investments or capital expenditures, selling assets,
restructuring or refinancing our debt, or seeking additional
equity capital. We may not be able to effect any of
22
these actions on satisfactory terms, or at all. Please see
Managements Discussion and Analysis of Financial
Condition and Results of Operations Liquidity and
Capital Resources Capital Requirements.
Increases
in interest rates could adversely affect our
business.
In addition to our exposure to commodity prices, we will have
significant exposure to increases in interest rates. After this
offering, we expect to have approximately $342.5 million of
debt on a pro forma basis at variable interest rates. An
increase of 1 percentage point in the interest rates will
result in an increase in annual interest expense of
$3.4 million. As a result, our results of operations, cash
flows and financial condition could be materially adversely
affected by significant increases in interest rates.
Restrictions
in our credit facility may interrupt distributions to us from
our subsidiaries, which may limit our ability to make
distributions to you, satisfy our obligations and capitalize on
business opportunities.
We are a holding company with no business operations. As such,
we depend upon the earnings and cash flow of our subsidiaries
and the distribution of that cash to us in order to meet our
obligations and to allow us to make distributions to our
unitholders. In connection with this offering, we expect to
enter into a new credit facility which will contain covenants
limiting our ability to make distributions, incur indebtedness,
grant liens, and engage in transactions with affiliates.
Furthermore, our credit facility will contain covenants
requiring us to maintain a ratio of consolidated indebtedness to
consolidated EBITDA initially of not more than 5.75 to 1.00 and
a ratio of consolidated EBITDA to consolidated interest expense
of not less than 2.25 to 1.00. If we fail to meet these tests or
otherwise breach the terms of our credit facility our operating
subsidiary will be prohibited from making any distribution to us
and, ultimately, to you. Any interruption of distributions to us
from our subsidiaries may limit our ability to satisfy our
obligations and to make distributions to you.
We may
incur significant costs and liabilities in the future resulting
from a failure to comply with new or existing environmental
regulations or an accidental release of hazardous substances or
hydrocarbons into the environment.
Our operations are subject to stringent and complex federal,
state and local environmental laws and regulations. These
include, for example, (1) the federal Clean Air Act and
comparable state laws and regulations that impose obligations
related to air emissions, (2) the federal Resource
Conservation and Recovery Act, or RCRA, and comparable state
laws that impose requirements for the handling, storage,
treatment or discharge of waste from our facilities and
(3) the federal Comprehensive Environmental Response,
Compensation, and Liability Act of 1980, or CERCLA, also known
as Superfund, and comparable state laws that
regulate the cleanup of hazardous substances that may have been
released at properties currently or previously owned or operated
by us or locations to which we have sent waste for disposal.
Failure to comply with these laws and regulations or newly
adopted laws or regulations may trigger a variety of
administrative, civil and criminal enforcement measures,
including the assessment of monetary penalties, the imposition
of remedial requirements, and the issuance of orders enjoining
future operations or imposing additional compliance requirements
on such operations. Certain environmental regulations, including
CERCLA and analogous state laws and regulations, impose strict,
joint and several liability for costs required to clean up and
restore sites where hazardous substances or hydrocarbons have
been disposed or otherwise released. Moreover, it is not
uncommon for neighboring landowners and other third parties to
file claims for personal injury and property damage allegedly
caused by the release of hazardous substances, hydrocarbons or
other waste products into the environment.
There is inherent risk of the incurrence of environmental costs
and liabilities in our business due to our handling of natural
gas and other petroleum products, air emissions related to our
operations, and historical industry operations and waste
disposal practices. For example, an accidental release from one
of our facilities could subject us to substantial liabilities
arising from environmental cleanup and restoration costs, claims
made by neighboring landowners and other third parties for
personal injury and property damage and fines or penalties for
related violations of environmental laws or regulations.
Moreover, the possibility exists that stricter laws, regulations
or enforcement policies could significantly increase our
operational or compliance costs and the cost of any remediation
that may become necessary. In particular, we may incur
expenditures in order to maintain compliance with legal
requirements governing emissions of air pollutants
23
from our facilities. We may not be able to recover these costs
from insurance. Please see
Business Environmental Matters.
We
typically do not obtain independent evaluations of natural gas
reserves dedicated to our gathering pipeline systems; therefore,
volumes of natural gas on our systems in the future could be
less than we anticipate.
We typically do not obtain independent evaluations of natural
gas reserves connected to our gathering systems due to the
unwillingness of producers to provide reserve information as
well as the cost of such evaluations. Accordingly, we do not
have independent estimates of total reserves dedicated to our
gathering systems or the anticipated life of such reserves. If
the total reserves or estimated life of the reserves connected
to our gathering systems is less than we anticipate and we are
unable to secure additional sources of natural gas, then the
volumes of natural gas on our gathering systems in the future
could be less than we anticipate. A decline in the volumes of
natural gas on our systems could have a material adverse effect
on our business, results of operations, financial condition and
our ability to make cash distributions to you.
A
change in the jurisdictional characterization of some of our
assets by federal, state or local regulatory agencies or a
change in policy by those agencies may result in increased
regulation of our assets, which may cause our revenues to
decline and operating expenses to increase.
Our natural gas gathering operations are generally exempt from
Federal Energy Regulatory Commission, or FERC, regulation under
the Natural Gas Act of 1938, or NGA, but FERC regulation still
affects these businesses and the markets for products derived
from these businesses. FERCs policies and practices across
the range of its natural gas regulatory activities, including,
for example, its policies on open access transportation,
ratemaking, capacity release and market center promotion,
indirectly affect intrastate markets. In recent years, FERC has
pursued pro-competitive policies in its regulation of interstate
natural gas pipelines. However, we cannot assure you that FERC
will continue this approach as it considers matters such as
pipeline rates and rules and policies that may affect rights of
access to natural gas transportation capacity. In addition, the
distinction between FERC-regulated transmission services and
federally unregulated gathering services has been the subject of
regular litigation; accordingly, the classification and
regulation of some of our intrastate pipelines may be subject to
change based on future determinations by FERC, the courts or
Congress.
State regulation of natural gas gathering facilities generally
includes various safety, environmental and, in some
circumstances, nondiscriminatory take requirements, and
complaint-based rate regulation. Natural gas gathering may
receive greater regulatory scrutiny at both the state and
federal levels now that FERC has taken a more light-handed
approach to regulation of the gathering activities of interstate
pipeline transmission companies and as a number of such
companies have transferred gathering facilities to unregulated
affiliates. The Railroad Commission of Texas, or TRRC, has
adopted regulations that generally allow natural gas producers
and shippers to file complaints with the TRRC in an effort to
resolve grievances relating to intrastate pipeline access and
rate discrimination. Our natural gas gathering operations could
be adversely affected in the future should they become subject
to the application of state or federal regulation of rates and
services. Our gathering operations also may be or become subject
to safety and operational regulations relating to the design,
installation, testing, construction, operation, replacement and
management of gathering facilities. Additional rules and
legislation pertaining to these matters are considered or
adopted from time to time. We cannot predict what effect, if
any, such changes might have on our operations, but the industry
could be required to incur additional capital expenditures and
increased costs depending on future legislative and regulatory
changes. Other state and local regulations also may affect our
business. See Business Regulation of
Operations.
Our
costs may increase because our credit obligations under hedging
and other contractual arrangements will not be guaranteed by
Targa.
Prior to the completion of this offering, Targa maintains credit
support for our obligations related to derivative financial
instruments, such as commodity price hedging contracts.
Beginning with the closing of this offering, Targa will no
longer provide credit support for our obligations under
derivative financial instruments and other commercial contracts
governing our business or operations. Consequently, we will need
to provide our own credit support arrangements for commercial
contracts, which may increase our
24
costs. For example, it could be more costly for us to manage our
commodity price risk through certain types of financial hedging
arrangements unless we are able to achieve creditworthiness
similar to the current creditworthiness of Targa.
All of
our operations are based in the Fort Worth Basin and we are
dependent on drilling activities and our ability to attract and
maintain customers in such region.
All of our operations are located in the Fort Worth Basin
in north Texas. Due to our lack of diversification in industry
type and location, an adverse development in the oil and gas
production from this area would have a significantly greater
impact on our financial condition and results of operations than
if we maintained more diverse assets and operating areas.
Under
the terms of our gas sales agreement, Targa will manage the
sales of our natural gas and will pay us the amount it realizes
for gas sales less certain costs; however, unexpected volume
changes due to production variability or to gathering, plant, or
pipeline system disruptions may increase our exposure to
commodity price movements.
Targa will sell our processed natural gas to third parties and
other Targa affiliates at our plant tailgate or at interstate
pipeline pooling points. Sales made to natural gas marketers and
end-users may be interrupted by disruptions to volumes anywhere
along the system. Targa will attempt to balance sales with
volumes supplied from our processing operations, but unexpected
volume variations due to production variability or to gathering,
plant, or pipeline system disruptions may expose us to volume
imbalances which, in conjunction with movements in commodity
prices, could materially impact our income from operations, and
cash flow.
We may
incur significant costs and liabilities resulting from pipeline
integrity programs and related repairs.
Pursuant to the Pipeline Safety Improvement Act of 2002, the
United States Department of Transportation, or DOT, has adopted
regulations requiring pipeline operators to develop integrity
management programs for pipelines located where a leak or
rupture could do the most harm in high consequence
areas. The regulations require operators to:
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perform ongoing assessments of pipeline integrity;
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identify and characterize applicable threats to pipeline
segments that could impact a high consequence area;
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improve data collection, integration and analysis;
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repair and remediate the pipeline as necessary; and
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implement preventive and mitigating actions.
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We currently estimate that we will incur an aggregate cost of
approximately $1 million between 2006 and 2010 to implement
pipeline integrity management program testing along certain
segments of our natural gas and NGL pipelines. This does not
include the costs, if any, of any repair, remediation,
preventative or mitigating actions that may be determined to be
necessary as a result of the testing program, which costs could
be substantial.
Our
construction of new assets may not result in revenue increases
and is subject to regulatory, environmental, political, legal
and economic risks, which could adversely affect our results of
operations and financial condition.
One of the ways we intend to grow our business is through the
construction of new midstream assets. The construction of
additions or modifications to our existing systems, and the
construction of new midstream assets, involves numerous
regulatory, environmental, political and legal uncertainties
beyond our control and may require the expenditure of
significant amounts of capital. If we undertake these projects,
they may not be completed on schedule or at the budgeted cost,
or at all. Moreover, our revenues may not increase immediately
upon the expenditure of funds on a particular project. For
instance, if we expand a new pipeline, the construction may
occur over an extended period of time, and we will not receive
any material increases in revenues until the project is
completed. Moreover, we may construct facilities to
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capture anticipated future growth in production in a region in
which such growth does not materialize. Since we are not engaged
in the exploration for and development of natural gas and oil
reserves, we do not possess reserve expertise and we often do
not have access to third-party estimates of potential reserves
in an area prior to constructing facilities in such area. To the
extent we rely on estimates of future production in our decision
to construct additions to our systems, such estimates may prove
to be inaccurate because there are numerous uncertainties
inherent in estimating quantities of future production. As a
result, new facilities may not be able to attract enough
throughput to achieve our expected investment return, which
could adversely affect our results of operations and financial
condition. In addition, the construction of additions to our
existing gathering and transportation assets may require us to
obtain new
rights-of-way
prior to constructing new pipelines. We may be unable to obtain
such
rights-of-way
to connect new natural gas supplies to our existing gathering
lines or capitalize on other attractive expansion opportunities.
Additionally, it may become more expensive for us to obtain new
rights-of-way
or to renew existing
rights-of-way.
If the cost of renewing or obtaining new
rights-of-way
increases, our cash flows could be adversely affected.
If we
do not make acquisitions on economically acceptable terms, or
efficiently and effectively integrate the acquired assets with
our asset base, our future growth will be limited.
Our ability to grow depends, in part, on our ability to make
acquisitions that result in an increase in the cash generated
from operations per unit. If we are unable to make these
accretive acquisitions either because we are (1) unable to
identify attractive acquisition candidates or negotiate
acceptable purchase contracts with them, (2) unable to
obtain financing for these acquisitions on economically
acceptable terms, or (3) outbid by competitors, then our
future growth and ability to increase distributions will be
limited.
Any acquisition involves potential risks, including, among other
things:
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mistaken assumptions about volumes, revenues and costs,
including synergies;
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an inability to integrate successfully the businesses we acquire;
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the assumption of unknown liabilities;
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limitations on rights to indemnity from the seller;
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mistaken assumptions about the overall costs of equity or debt;
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the diversion of managements and employees attention
from other business concerns;
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unforeseen difficulties operating in new product areas or new
geographic areas; and
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customer or key employee losses at the acquired businesses.
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If these risks materialize, the acquired assets may inhibit our
growth or fail to deliver expected benefits.
Our acquisition strategy is based, in part, on our expectation
of ongoing divestitures of energy assets by industry
participants. A material decrease in such divestitures would
limit our opportunities for future acquisitions and could
adversely affect our operations and cash flows available for
distribution to our unitholders.
We do
not own all of the land on which our pipelines and facilities
are located, which could disrupt our operations.
We do not own most of the land on which our pipelines and
facilities are located, and we are therefore subject to the
possibility of more onerous terms
and/or
increased costs to retain necessary land use if we do not have
valid rights of way or leases or if such rights of way or leases
lapse or terminate. We sometimes obtain the rights to land owned
by third parties and governmental agencies for a specific period
of time. Our loss of these rights, through our inability to
renew
right-of-way
contracts, leases or otherwise, could cause us to cease
operations on the affected land, increase costs related to
continuing operations elsewhere, reduce our revenue and impair
our ability to make distributions to our unitholders.
We do
not have any officers or employees and rely solely on officers
of our general partner and employees of Targa.
None of the officers of our general partner are employees of our
general partner. We intend to enter into an omnibus agreement
with Targa, pursuant to which Targa will operate our assets and
perform other
26
administrative services for us such as accounting, legal,
regulatory, corporate development, finance, land and
engineering. Affiliates of Targa conduct businesses and
activities of their own in which we have no economic interest,
including businesses and activities relating to Targa. As a
result, there could be material competition for the time and
effort of the officers and employees who provide services to our
general partner and Targa. If the officers of our general
partner and the employees of Targa do not devote sufficient
attention to the management and operation of our business, our
financial results may suffer and our ability to make
distributions to our unitholders may be reduced.
If our
general partner fails to develop or maintain an effective system
of internal controls, then we may not be able to accurately
report our financial results or prevent fraud. As a result,
current and potential unitholders could lose confidence in our
financial reporting, which would harm our business and the
trading price of our common units.
Targa Resources GP LLC, our general partner, has sole
responsibility for conducting our business and for managing our
operations. Effective internal controls are necessary for our
general partner, on our behalf, to provide reliable financial
reports, prevent fraud and operate us successfully as a public
company. If our general partners efforts to develop and
maintain its internal controls are not successful, it is unable
to maintain adequate controls over our financial processes and
reporting in the future or it is unable to assist us in
complying with our obligations under Section 404 of the
Sarbanes-Oxley Act of 2002, our operating results could be
harmed or we may fail to meet our reporting obligations.
Ineffective internal controls also could cause investors to lose
confidence in our reported financial information, which would
likely have a negative effect on the trading price of our common
units.
The
amount of cash we have available for distribution to holders of
our common units and subordinated units depends primarily on our
cash flow and not solely on profitability. Consequently, even if
we are profitable, we may not be able to make cash distributions
to holders of our common units and subordinated
units.
You should be aware that the amount of cash we have available
for distribution depends primarily upon our cash flow and not
solely on profitability, which will be affected by non-cash
items. As a result, we may make cash distributions during
periods when we record losses for financial accounting purposes
and may not make cash distributions during periods when we
record net earnings for financial accounting purposes.
Terrorist
attacks, and the threat of terrorist attacks, have resulted in
increased costs to our business. Continued hostilities in the
Middle East or other sustained military campaigns may adversely
impact our results of operations.
The long-term impact of terrorist attacks, such as the attacks
that occurred on September 11, 2001, and the threat of
future terrorist attacks on our industry in general, and on us
in particular, is not known at this time. Increased security
measures taken by us as a precaution against possible terrorist
attacks have resulted in increased costs to our business.
Uncertainty surrounding continued hostilities in the Middle East
or other sustained military campaigns may affect our operations
in unpredictable ways, including disruptions of crude oil
supplies and markets for our products, and the possibility that
infrastructure facilities could be direct targets of, or
indirect casualties of, an act of terror.
Changes in the insurance markets attributable to terrorist
attacks may make certain types of insurance more difficult for
us to obtain. Moreover, the insurance that may be available to
us may be significantly more expensive than our existing
insurance coverage. Instability in the financial markets as a
result of terrorism or war could also affect our ability to
raise capital.
Risks
Inherent in an Investment in Us
Targa
controls our general partner, which has sole responsibility for
conducting our business and managing our operations. Targa has
conflicts of interest with us and may favor its own interests to
your detriment.
Following this offering, Targa will own and control our general
partner. Some of our general partners directors, and some
of its executive officers, are directors or officers of Targa.
Therefore, conflicts of interest
27
may arise between Targa, including our general partner, on the
one hand, and us and our unitholders, on the other hand. In
resolving these conflicts of interest, our general partner may
favor its own interests and the interests of its affiliates over
the interests of our unitholders. These conflicts include, among
others, the following situations:
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neither our partnership agreement nor any other agreement
requires Targa to pursue a business strategy that favors us.
Targas directors and officers have a fiduciary duty to
make decisions in the best interests of the owners of Targa,
which may be contrary to our interests;
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our general partner is allowed to take into account the
interests of parties other than us, such as Targa, or its
owners, including Warburg Pincus, in resolving conflicts of
interest; and
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Targa is not limited in its ability to compete with us and is
under no obligation to offer assets to us; please see
Targa is not limited in its ability to compete
with us, which could limit our ability to acquire additional
assets or businesses below.
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Please see Conflicts of Interest and Fiduciary
Duties.
The
credit and business risk profile of our general partner and its
owners could adversely affect our credit ratings and
profile.
The credit and business risk profiles of the general partner and
its owners may be factors in credit evaluations of a master
limited partnership. This is because the general partner can
exercise significant influence over the business activities of
the partnership, including its cash distribution and acquisition
strategy and business risk profile. Another factor that may be
considered is the financial condition of the general partner and
its owners, including the degree of their financial leverage and
their dependence on cash flow from the partnership to service
their indebtedness.
Targa, the owner of our general partner, has significant
indebtedness outstanding and is partially dependent on the cash
distributions from their indirect general partner and limited
partner equity interests in us to service such indebtedness. Any
distributions by us to such entities will be made only after
satisfying our then current obligations to our creditors. Our
credit ratings and business risk profile could be adversely
affected if the ratings and risk profiles of the entities that
control our general partner were viewed as substantially lower
or more risky than ours.
Our
partnership agreement limits our general partners
fiduciary duties to holders of our units and restricts the
remedies available to unitholders for actions taken by our
general partner that might otherwise constitute breaches of
fiduciary duty.
The directors and officers of our general partner have a
fiduciary duty to manage our general partner in a manner
beneficial to its owner, Targa. Our partnership agreement
contains provisions that reduce the standards to which our
general partner would otherwise be held by state fiduciary duty
laws. For example, our partnership agreement:
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permits our general partner to make a number of decisions in its
individual capacity, as opposed to in its capacity as our
general partner. This entitles our general partner to consider
only the interests and factors that it desires, and it has no
duty or obligation to give any consideration to any interest of,
or factors affecting, us, our affiliates or any limited partner;
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provides that our general partner will not have any liability to
us or our unitholders for decisions made in its capacity as a
general partner so long as it acted in good faith, meaning it
believed the decision was in the best interests of our
partnership;
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generally provides that affiliated transactions and resolutions
of conflicts of interest not approved by the conflicts committee
of the board of directors of our general partner acting in good
faith and not involving a vote of unitholders must be on terms
no less favorable to us than those generally being provided to
or available from unrelated third parties or must be fair
and reasonable to us, as determined by our general partner
in good faith and that, in determining whether a transaction or
resolution is fair and reasonable, our general
partner may consider the totality of the relationships
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between the parties involved, including other transactions that
may be particularly advantageous or beneficial to us;
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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 any acts or omissions unless there has
been a final and non-appealable judgment entered by a court of
competent jurisdiction determining that the general partner or
those other persons acted in bad faith or engaged in fraud or
willful misconduct or, in the case of a criminal matter, acted
with knowledge that the conduct was criminal; and
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provides that in resolving conflicts of interest, it will be
presumed that in making its decision the general partner acted
in good faith, and in any proceeding brought by or on behalf of
any limited partner or us, the person bringing or prosecuting
such proceeding will have the burden of overcoming such
presumption.
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If you purchase any common units, you will agree to become bound
by the provisions in the partnership agreement, including the
provisions discussed above. Please see Conflicts of
Interests and Fiduciary Duties Fiduciary
Duties.
Targa
is not limited in its ability to compete with us, which could
limit our ability to acquire additional assets or
businesses.
Neither our partnership agreement nor the omnibus agreement
between us and Targa will prohibit Targa from owning assets or
engaging in businesses that compete directly or indirectly with
us. In addition, Targa may acquire, construct or dispose of
additional midstream or other assets in the future, without any
obligation to offer us the opportunity to purchase or construct
any of those assets. Targa is a large, established participant
in the midstream energy business, and has significantly greater
resources and experience than we have, which factors may make it
more difficult for us to compete with Targa with respect to
commercial activities as well as for acquisition candidates. As
a result, competition from Targa could adversely impact our
results of operations and cash available for distribution.
Please see Conflicts of Interest and Fiduciary
Duties.
Cost
reimbursements due our general partner and its affiliates for
services provided, which will be determined by our general
partner, will be substantial and will reduce our cash available
for distribution to you.
Pursuant to an omnibus agreement we will enter into with Targa
Resources GP LLC, our general partner and others upon the
closing of this offering, Targa will receive reimbursement for
the payment of operating expenses related to our operations and
for the provision of various general and administrative services
for our benefit. Payments for these services will be substantial
and will reduce the amount of cash available for distribution to
unitholders. Please see Certain Relationships and Related
Party Transactions Omnibus Agreement. In
addition, under Delaware partnership law, our general partner
has unlimited liability for our obligations, such as our debts
and environmental liabilities, except for our contractual
obligations that are expressly made without recourse to our
general partner. To the extent our general partner incurs
obligations on our behalf, we are obligated to reimburse or
indemnify our general partner. If we are unable or unwilling to
reimburse or indemnify our general partner, our general partner
may take actions to cause us to make payments of these
obligations and liabilities. Any such payments could reduce the
amount of cash otherwise available for distribution to our
unitholders.
Holders
of our common units have limited voting rights and are not
entitled to elect our general partner or its
directors.
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
will not elect our general partner or our general partners
board of directors, and will have no right to elect our general
partner or our general partners board of directors on an
annual or other continuing basis. The board of directors of our
general partner will be chosen by Targa. Furthermore, if the
unitholders were dissatisfied with the performance of our
general partner, they will have little ability
29
to remove our general partner. As a result of these limitations,
the price at which the common units will trade could be
diminished because of the absence or reduction of a takeover
premium in the trading price.
Even
if holders of our common units are dissatisfied, they cannot
initially remove our general partner without its
consent.
The unitholders will be unable initially to remove our general
partner without its consent because our general partner and its
affiliates will own sufficient units upon completion of this
offering to be able to prevent its removal. The vote of the
holders of at least
662/3%
of all outstanding units voting together as a single class is
required to remove the general partner. Following the closing of
this offering, our general partner and its affiliates will own
40.7% of our aggregate outstanding common and subordinated
units. Also, if our general partner is removed without cause
during the subordination period and units held by our general
partner and its affiliates are not voted in favor of that
removal, all remaining subordinated units will automatically
convert into common units and any existing arrearages on our
common units will be extinguished. A removal of our general
partner under these circumstances would adversely affect our
common units by prematurely eliminating their distribution and
liquidation preference over our subordinated units, which would
otherwise have continued until we had met certain distribution
and performance tests. 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 or willful or wanton misconduct in its capacity as
our general partner. Cause does not include most cases of
charges of poor management of the business, so the removal of
the general partner because of the unitholders
dissatisfaction with our general partners performance in
managing our partnership will most likely result in the
termination of the subordination period and conversion of all
subordinated units to common units.
We may
issue additional units without your approval, which would dilute
your existing ownership interests.
Our partnership agreement does not limit the number of
additional limited partner interests that we may issue at any
time without the approval of our unitholders. The issuance by us
of additional common units or other equity securities of equal
or senior rank will have the following effects:
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our unitholders proportionate ownership interest in us
will decrease;
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the amount of cash available for distribution on each unit may
decrease;
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because a lower percentage of total outstanding units will be
subordinated units, the risk that a shortfall in the payment of
the minimum quarterly distribution will be borne by our common
unitholders will increase;
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the ratio of taxable income to distributions may increase;
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the relative voting strength of each previously outstanding unit
may be diminished; and
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the market price of the common units may decline.
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Affiliates
of our general partner may sell common units in the public
markets, which sales could have an adverse impact on the trading
price of the common units.
After the sale of the common units offered hereby, management of
our general partner and Targa will hold no common units and
11,528,231 subordinated units. All of the subordinated units
will convert into common units at the end of the subordination
period and may convert earlier. The sale of these units in the
public markets could have an adverse impact on the price of the
common units or on any trading market that may develop.
Our
general partner may elect to cause us to issue Class B
units to it in connection with a resetting of the target
distribution levels related to our general partners
incentive distribution rights without the approval of the
conflicts committee of our general partner or holders of our
common units. This ability may result in lower distributions to
holders of our common units in certain situations.
Our general partner has the right, at a time when there are no
subordinated units outstanding and it has received incentive
distributions at the highest level to which it is entitled (48%)
for each of the prior
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four consecutive fiscal quarters, to reset the initial cash
target distribution levels at higher levels based on the
distribution at the time of the exercise of the reset election.
Following a reset election by our general partner, the minimum
quarterly distribution amount will be reset to an amount equal
to the average cash distribution amount per common unit for the
two fiscal quarters immediately preceding the reset
election (such amount is referred to as the reset
minimum quarterly distribution) and the target
distribution levels will be reset to correspondingly higher
levels based on percentage increases above the reset minimum
quarterly distribution amount.
In connection with resetting these target distribution levels,
our general partner will be entitled to receive Class B
units. The Class B units will be entitled to the same cash
distributions per unit as our common units and will be
convertible into an equal number of common units. The number of
Class B units to be issued will be equal to that number of
common units whose aggregate quarterly cash distributions
equaled the average of the distributions to our general partner
on the incentive distribution rights in the prior two quarters.
We anticipate that our general partner would exercise this reset
right in order to facilitate acquisitions or internal growth
projects that would not be sufficiently accretive to cash
distributions per common unit without such conversion; however,
it is possible that our general partner could exercise this
reset election at a time when it is experiencing, or may be
expected to experience, declines in the cash distributions it
receives related to its incentive distribution rights and may
therefore desire to be issued our Class B units, which are
entitled to receive cash distributions from us on the same
priority as our common units, rather than retain the right to
receive incentive distributions based on the initial target
distribution levels. As a result, a reset election may cause our
common unitholders to experience dilution in the amount of cash
distributions that they would have otherwise received had we not
issued new Class B units to our general partner in
connection with resetting the target distribution levels related
to our general partners incentive distribution rights.
Please see Provisions of Our Partnership Agreement Related
to Cash Distributions General Partner Interest and
Incentive Distribution Rights.
Increases
in interest rates could adversely impact our unit price and our
ability to issue additional equity to make acquisitions, for
expansion capital expenditures or for other
purposes.
As with other yield-oriented securities, our unit price is
impacted by the level of our cash distributions and implied
distribution yield. The distribution yield is often used by
investors to compare and rank related yield-oriented securities
for investment decision-making purposes. Therefore, changes in
interest rates, either positive or negative, may affect the
yield requirements of investors who invest in our units, and a
rising interest rate environment could have an adverse impact on
our unit price and our ability to issue additional equity to
make acquisitions, for expansion capital expenditures or for
other purposes.
We
will incur increased costs as a result of being a
publicly-traded company.
We have no history operating as a publicly-traded company. As a
publicly-traded company, we will incur significant legal,
accounting and other expenses that we would not incur as a
private company. In addition, the Sarbanes-Oxley Act of 2002, as
well as new rules subsequently implemented by the SEC and The
NASDAQ Global Market, have required changes in corporate
governance practices of publicly-traded companies. We expect
these new rules and regulations to increase our legal and
financial compliance costs and to make activities more
time-consuming and costly. For example, as a result of becoming
a publicly-traded company, we are required to have at least
three independent directors, create additional board committees
and adopt policies regarding internal controls and disclosure
controls and procedures, including the preparation of reports on
internal controls over financial reporting. In addition, we will
incur additional costs associated with our publicly-traded
company reporting requirements. We also expect these new rules
and regulations to make it more difficult and more expensive for
our general partner to obtain director and officer liability
insurance and it may be required to accept reduced policy limits
and coverage or incur substantially higher costs to obtain the
same or similar coverage. As a result, it may be more difficult
for our general partner to attract and retain qualified persons
to serve on its board of directors or as executive officers. We
have included $2.5 million of estimated incremental costs
per year associated with being a publicly-traded company for
purposes of our financial forecast included elsewhere in this
prospectus; however, it is possible that our actual incremental
costs of being a publicly-traded company will be higher than we
currently estimate.
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Our
partnership agreement restricts the voting rights of unitholders
owning 20% or more of our common units.
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 our general partner, its affiliates,
their transferees and persons who acquired such units with the
prior approval of the board of directors of our general partner,
cannot vote on any matter. Our partnership agreement also
contains provisions limiting the ability of unitholders to call
meetings or to acquire information about our operations, as well
as other provisions limiting the unitholders ability to
influence the manner or direction of management.
Control
of our general partner may be transferred to a third party
without unitholder consent.
Our general partner may transfer its general partner interest to
a third party in a merger or in a sale of all or substantially
all of its assets without the consent of the unitholders.
Furthermore, our partnership agreement does not restrict the
ability of the owners of our general partner from transferring
all or a portion of their respective ownership interest in our
general partner to a third party. The new owners of our general
partner would then be in a position to replace the board of
directors and officers of our general partner with its own
choices and thereby influence the decisions taken by the board
of directors and officers.
Our
general partner has a limited call right that may require you to
sell your units at an undesirable time or price.
If at any time our general partner and its affiliates own more
than 80% of the common units, our general partner will have the
right, but not the obligation, which it may assign to any of its
affiliates or to us, to acquire all, but not less than all, of
the common units held by unaffiliated persons at a price not
less than their then-current market price. As a result, you may
be required to sell your common units at an undesirable time or
price and may not receive any return on your investment. You may
also incur a tax liability upon a sale of your units. At the end
of the subordination period, assuming no additional issuances of
common units, our general partner and its affiliates will own
approximately 40.7% of our aggregate outstanding common units.
For additional information about this right, please see
The Partnership Agreement Limited Call
Right.
Your
liability may not be limited if a court finds that unitholder
action constitutes control of our business.
A general partner of a partnership generally has unlimited
liability for the obligations of the partnership, except for
those contractual obligations of the partnership that are
expressly made without recourse to the general partner. Our
partnership is organized under Delaware law and we conduct
business in Texas. The limitations on the liability of holders
of limited partner interests for the obligations of a limited
partnership have not been clearly established in some of the
other states in which we do business. You could be liable for
any and all of our obligations as if you were a general partner
if:
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a court or government agency determined that we were conducting
business in a state but had not complied with that particular
states partnership statute; or
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your right to act with other unitholders to remove or replace
the general partner, to approve some amendments to our
partnership agreement or to take other actions under our
partnership agreement constitute control of our
business.
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For a discussion of the implications of the limitations of
liability on a unitholder, please see The Partnership
Agreement Limited Liability.
Unitholders
may have liability to repay distributions that were wrongfully
distributed to them.
Under certain circumstances, unitholders may have to repay
amounts wrongfully returned or distributed to them. Under
Section 17-607
of the Delaware Revised Uniform Limited Partnership Act, we may
not make a distribution to you if the distribution would cause
our liabilities to exceed the fair value of our assets. Delaware
law provides that for a period of three years from the date of
the impermissible distribution, limited partners who received
the distribution and who knew at the time of the distribution
32
that it violated Delaware law will be liable to the limited
partnership for the distribution amount. Substituted limited
partners are liable for the obligations of the assignor to make
contributions to the partnership that are known to the
substituted limited partner at the time it became a limited
partner and for unknown obligations if the liabilities could be
determined from the partnership agreement. Liabilities to
partners on account of their partnership interest and
liabilities that are non-recourse to the partnership are not
counted for purposes of determining whether a distribution is
permitted.
Tax Risks
to Common Unitholders
In addition to reading the following risk factors, you should
read Material Tax Consequences for a more complete
discussion of the expected material federal income tax
consequences of owning and disposing of common units.
Our
tax treatment depends on our status as a partnership for federal
income tax purposes, as well as our not being subject to a
material amount of entity-level taxation by individual states.
If the Internal Revenue Service, or IRS, were to treat us as a
corporation or if we were to become subject to a material amount
of entity-level taxation for state tax purposes, then our cash
available for distribution to you would be substantially
reduced.
The anticipated after-tax economic benefit of an investment in
the common units depends largely on our being treated as a
partnership for federal income tax purposes. We have not
requested, and do not plan to request, a ruling from the IRS on
this or any other tax matter affecting us.
If we were treated as a corporation for federal income tax
purposes, we would pay federal income tax on our taxable income
at the corporate tax rate, which is currently a maximum of 35%
and would likely pay state income tax at varying rates.
Distributions to you would generally be taxed again as corporate
distributions, and no income, gains, losses or deductions would
flow through to you. Because a tax would be imposed upon us as a
corporation, our cash available for distribution to you would be
substantially reduced. 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 so as to cause us to be treated as a
corporation for federal income tax purposes or otherwise subject
us to entity-level taxation. In addition, because of widespread
state budget deficits and other reasons, several states are
evaluating ways to subject partnerships to entity-level taxation
through the imposition of state income, margin, franchise and
other forms of taxation. For example, beginning in 2008, we will
be subject to a new entity level tax (imposed at a maximum
effective rate of 0.7%) on the portion of our income that is
generated in Texas. Imposition of such a tax on us by Texas, or
any other state, will reduce the cash available for distribution
to you. The partnership agreement provides that if a law is
enacted or existing law is modified or interpreted in a manner
that subjects us to taxation as a corporation or otherwise
subjects us to entity-level taxation for federal, state or local
income tax purposes, the minimum quarterly distribution amount
and the target distribution amounts will be adjusted to reflect
the impact of that law on us.
If the
IRS contests the federal income tax positions we take, the
market for our common units may be adversely affected, and the
cost of any contest will reduce our cash available for
distribution to you.
We have not requested a ruling from the IRS with respect to our
treatment as a partnership for federal income tax purposes or
any other matter affecting us. The IRS may adopt positions that
differ from the conclusions of our counsel expressed in this
prospectus or from the positions we take. It may be necessary to
resort to administrative or court proceedings to sustain some or
all of our counsels conclusions or the positions we take.
A court may not agree with some or all of our counsels
conclusions or positions we take. Any contest with the IRS may
materially and adversely impact the market for our common units
and the price at which they trade. In addition, our costs of any
contest with the IRS will be borne indirectly by our unitholders
and our general partner because the costs will reduce our cash
available for distribution.
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You
may be required to pay taxes on your share of our income even if
you 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, you 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 you receive no
cash distributions from us. You may not receive cash
distributions from us equal to your share of our taxable income
or even equal to the actual tax liability that results from that
income.
Tax
gain or loss on disposition of our common units could be more or
less than expected.
If you sell your common units, you will recognize a gain or loss
equal to the difference between the amount realized and your tax
basis in those common units. Prior distributions to you in
excess of the total net taxable income you were allocated for a
common unit, which decreased your tax basis in that common unit,
will, in effect, become taxable income to you if the common unit
is sold at a price greater than your tax basis in that common
unit, even if the price you receive is less than your original
cost. A substantial portion of the amount realized, whether or
not representing gain, may be ordinary income. In addition, if
you sell your units, you may incur a tax liability in excess of
the amount of cash you receive from the sale.
Tax-exempt
entities and foreign persons face unique tax issues from owning
our common units that may result in adverse tax consequences to
them.
Investment in common units by tax-exempt entities, such as
individual retirement accounts (known as IRAs), other retirement
plans and
non-U.S. persons
raises issues unique to them. For example, virtually all of our
income allocated to organizations that are exempt from federal
income tax, including IRAs and other retirement plans, will be
unrelated business taxable income and will be taxable to them.
Distributions to
non-U.S. persons
will be reduced by withholding taxes at the highest applicable
effective tax rate, and
non-U.S. persons
will be required to file United States federal tax returns and
pay tax on their share of our taxable income. If you are a
tax-exempt entity or a foreign person, you should consult your
tax advisor before investing in our common units.
We
will treat each purchaser of our common units as having the same
tax benefits without regard to the actual common units
purchased. The IRS may challenge this treatment, which could
adversely affect the value of the common units.
Because we cannot match transferors and transferees of common
units and because of other reasons, we will adopt depreciation
and amortization positions that may not conform to all aspects
of existing Treasury Regulations. A successful IRS challenge to
those positions could adversely affect the amount of tax
benefits available to you. It also could affect the timing of
these tax benefits or the amount of gain from the sale of common
units and could have a negative impact on the value of our
common units or result in audit adjustments to your tax returns.
For a further discussion of the effect of the depreciation and
amortization positions we will adopt, please see Material
Tax Consequences Tax Consequences of Unit
Ownership Section 754 Election.
The
sale or exchange of 50% or more of our capital and profits
interests during any twelve-month period will result in the
termination of our partnership for federal income tax
purposes.
We will be considered to have terminated our partnership for
federal income tax purposes if there is a sale or exchange of
50% or more of the total interests in our capital and profits
within a twelve-month period. Our termination would, among other
things, result in the closing of our taxable year for all
unitholders and could result in a deferral of depreciation
deductions allowable in computing our taxable income. Please see
Material Tax Consequences Disposition of
Common Units Constructive Termination for a
discussion of the consequences of our termination for federal
income tax purposes.
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You
may 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, you might be subject to
return filing requirements and other taxes, including foreign,
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 you do not live in any of those
jurisdictions. Further, you may be subject to penalties for
failure to comply with those requirements. We will initially own
assets and conduct business in the State of Texas. Currently,
Texas does not impose a personal income tax on individuals. As
we make acquisitions or expand our business, we may own assets
or do business in states that impose a personal income tax. It
is your responsibility to file all United States federal, state
and local tax returns. Our counsel has not rendered an opinion
on the foreign, state or local tax consequences of an investment
in our common units.
35
USE OF
PROCEEDS
We expect to receive net proceeds from this offering of
approximately $315.3 million, after deducting underwriting
discounts and deducting a structuring fee of approximately
$1.3 million but before paying offering expenses. We base
this amount on an assumed initial public offering price of
$20.00 per common unit. We anticipate using the aggregate
net proceeds of this offering to:
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|
|
|
|
pay approximately $4.0 million in expenses associated with
this offering and the Formation Transactions;
|
|
|
|
pay approximately $4.2 million in fees and expenses related
to our new credit facility; and
|
|
|
|
use the remaining proceeds to pay approximately
$307.1 million to Targa to retire a portion of our
affiliate indebtedness.
|
The structuring fee will be paid to Citigroup Global Markets
Inc., Goldman, Sachs & Co., UBS Securities LLC and Merrill
Lynch & Co. for evaluation, analysis and structuring of
our partnership. We also expect to borrow approximately
$342.5 million under our new credit facility upon the
closing of this offering and to pay that amount to Targa to
retire an additional portion of our affiliate indebtedness. The
remaining balance of our affiliate indebtedness will be retired
and treated as a capital contribution to us. Please see
Certain Relationships and Related Party
Transactions Distributions and Payments to our
General Partner and its Affiliates. The affiliate
indebtedness to be repaid with proceeds of this offering and
borrowings under our new credit facility will be contributed to
us in connection with the Formation Transactions, is due
December 31, 2007 and bears interest at a rate of
10% per annum.
We will use any net proceeds from the exercise of the
underwriters option to purchase additional common units to
reduce outstanding borrowings under our new credit facility. If
the underwriters exercise in full their option to purchase
additional common units, the ownership interest of the public
unitholders will increase to 19,320,000 common units
representing an aggregate 61.4% limited partner interest in us
and the ownership interest of our general partner will increase
to 629,555 general partner units representing a 2% general
partner interest in us.
An increase or decrease in the assumed public offering price of
$1.00 per common unit would cause the net proceeds from the
offering, after deducting underwriting discounts and commissions
and offering expenses payable by us, to increase or decrease by
approximately $15.8 million.
36
CAPITALIZATION
The following table shows:
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|
|
the cash and capitalization of the Predecessor Business as of
September 30, 2006; and
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|
|
|
our pro forma cash and capitalization as of September 30,
2006, as adjusted to reflect this offering, the other
transactions described under Summary Formation
Transactions and Partnership Structure General
and the application of the net proceeds from this offering as
described under Use of Proceeds.
|
We derived this table from, and it should be read in conjunction
with and is qualified in its entirety by reference to, the
historical and pro forma financial statements and the
accompanying notes included elsewhere in this prospectus. You
should also read this table in conjunction with
Managements Discussion and Analysis of Financial
Condition and Results of Operations. For a description of
the pro forma adjustments, please see our Unaudited Pro Forma
Condensed Balance Sheet.
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|
|
|
|
|
|
|
As of September 30,
|
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|
|
2006
|
|
|
|
Historical
|
|
|
Pro Forma
|
|
|
|
(in millions of dollars)
|
|
|
Cash
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
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|
Long-term debt:
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|
|
|
|
|
|
Credit facility
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|
|
|
|
|
|
342.5
|
|
Affiliate debt (including current
portion)(1)
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|
865.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
|
865.2
|
|
|
|
342.5
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|
|
|
|
|
|
|
|
|
|
Partners capital(2)(3):
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|
Predecessor Business
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194.8
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|
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|
Common units public
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|
|
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|
311.3
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Subordinated units
sponsor
|
|
|
|
|
|
|
372.8
|
|
General partner interest
|
|
|
|
|
|
|
18.7
|
|
|
|
|
|
|
|
|
|
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Total partners capital
|
|
|
194.8
|
|
|
|
702.8
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
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$
|
1,060.0
|
|
|
$
|
1,045.3
|
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|
|
|
|
|
|
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|
|
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|
(1) |
|
Affiliate debt presented above represents indebtedness incurred
by Targa in connection with the DMS Acquisition that has been
allocated to the North Texas System. In connection with this
offering, a portion of the affiliate indebtedness will be repaid
and the remainder will be retired and treated as a capital
contribution to us. Please see Use of Proceeds. |
|
(2) |
|
Assumes a public offering price of our common units of
$20.00 per unit and reflects partner capital of common
unitholders from the net proceeds of this offering of
approximately $311.3 million, including approximately
$24.7 million of underwriters discounts, fees and
other offering expenses payable by us and the application of the
proceeds as described in Use of Proceeds. A $1.00
increase (decrease) in the assumed public offering price per
common unit would increase (decrease) the net proceeds by
$15.8 million, and would result in a corresponding increase
(decrease) in net proceeds to be used to retire indebtedness,
and therefore would not change our total partners capital,
assuming the number of common units offered by us, as set forth
on the cover page of this prospectus, remains the same. The pro
forma information discussed above is illustrative only and
following completion of this offering will be adjusted based on
the actual public offering price and other terms of this
offering determined at pricing. |
|
(3) |
|
Partners capital as presented above excludes accumulated
other comprehensive income. |
This table does not reflect the issuance of up to 2,520,000
common units that may be sold to the underwriters upon exercise
of their option to purchase additional units.
37
DILUTION
Dilution or accretion is the difference between the offering
price paid by the purchasers of common units sold in this
offering and the pro forma net tangible book value per unit
after the offering. Assuming an initial public offering price of
$20.00, which is the midpoint of the estimated initial public
offering price range per common unit in this offering, on a pro
forma basis as of September 30, 2006, after giving effect
to the offering of common units and the application of the
related net proceeds, and assuming the underwriters option
to purchase additional common units is not exercised, our net
tangible book value would be $730.3 million, or
$25.26 per common unit. Net tangible book value excludes
$4.2 million of net intangible assets. Purchasers of common
units in this offering will experience an immediate accretion in
net tangible book value per common unit for financial accounting
purposes, as illustrated in the following table:
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|
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Assumed initial public offering
price per common unit
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|
$
|
20.00
|
|
Net tangible book value per unit
before the offering(1)
|
|
$
|
17.21
|
|
|
|
|
|
Increase in net tangible book
value per common unit attributable to purchasers in the offering
|
|
|
8.05
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma net tangible book value
per common unit after the offering(2)
|
|
|
|
|
|
|
25.26
|
|
|
|
|
|
|
|
|
|
|
Immediate dilution (accretion) in
tangible net book value per common unit to new investors(3)
|
|
|
|
|
|
$
|
(5.26
|
)
|
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|
|
|
|
|
|
|
|
|
|
(1)
|
Determined by dividing the number of units (11,528,231
subordinated units and 578,127 general partner units) to be
issued to Targa for its contribution of the North Texas System
into the net tangible book value of the North Texas System
before the offering.
|
|
(2)
|
Determined by dividing the total number of limited partner units
and general partner units to be outstanding after the offering
(16,800,000 common units, 11,528,231 subordinated units and
578,127 general partner units) into our pro forma net tangible
book value, after giving effect to the application of the
expected net proceeds of the offering.
|
|
(3)
|
If the initial public offering price were to increase or
decrease by $1.00 per common unit, immediate dilution
(accretion) in tangible net book value per common unit would not
change after giving effect to the corresponding change in our
pro forma use of proceeds.
|
The following table sets forth the number of units that we will
issue and the total consideration contributed to us by Targa and
by the purchasers of common units in this offering upon
consummation of the transactions contemplated by this prospectus:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Units Acquired
|
|
|
Total Consideration
|
|
|
|
Number
|
|
|
Percent
|
|
|
Amount
|
|
|
Percent
|
|
|
Equity contribution by Targa(1)(2)
|
|
|
12,106,358
|
|
|
|
41.9
|
%
|
|
$
|
391,500,000
|
|
|
|
53.8
|
%
|
New investors cash contribution
|
|
|
16,800,000
|
|
|
|
58.1
|
%
|
|
|
336,000,000
|
|
|
|
46.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
28,906,358
|
|
|
|
100.0
|
%
|
|
$
|
727,500,000
|
|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
The units acquired by Targa and its affiliates consist of
11,528,231 subordinated units and 578,127 general partner units.
|
|
(2)
|
The North Texas System contributed by Targa is reflected at
Targas historical net carrying value subsequent to
recording the step up in property, plant and equipment at fair
value in connection with the DMS Acquisition. Related
acquisition indebtedness of Targa was also recognized and is
reflected in partners capital. See the historical
financial statements and related notes of the Predecessor
Business for a discussion of the DMS Acquisition.
|
38
The table below shows the net investment of Targa in us after
giving effect to this offering and the Formation Transactions.
Please see our Unaudited Pro Forma Balance Sheet on
page F-3
for a more complete presentation of the adjustments associated
with this offering and the Formation Transactions.
|
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|
|
|
|
|
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|
|
(in millions
|
|
|
|
of dollars)
|
|
|
Total partners capital
excluding accumulated other comprehensive income as of
September 30, 2006
|
|
|
|
|
|
$
|
194.8
|
|
Affiliate debt including current
portion, net of deferred issuance costs
|
|
$
|
846.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Application of net offering
proceeds, after expenses associated with this offering and the
Formation Transactions, to reduce affiliate debt
|
|
|
307.1
|
|
|
|
|
|
Application of borrowings under
our new credit facility to reduce affiliate debt
|
|
|
342.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total reduction in affiliate debt
|
|
|
649.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Elimination of remaining affiliate
debt (net of unamortized debt issue cost), treated as a capital
contribution to us
|
|
|
|
|
|
|
196.7
|
|
|
|
|
|
|
|
|
|
|
Equity contribution by Targa
|
|
|
|
|
|
$
|
391.5
|
|
|
|
|
|
|
|
|
|
|
39
OUR CASH
DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS
You should read the following discussion of our cash
distribution policy in conjunction with specific assumptions
included in this section. For more detailed information
regarding the factors and assumptions upon which our cash
distribution policy is based, please see Assumptions and
Considerations. In addition, you should read
Forward-Looking Statements and Risk
Factors for information regarding statements that do not
relate strictly to historical or current facts and certain risks
inherent in our business.
For additional information regarding our historical and pro
forma operating results, you should refer to our historical and
pro forma financial statements included elsewhere in this
prospectus.
General
Rationale for Our Cash Distribution
Policy. Our partnership agreement requires us
to distribute all of our available cash quarterly. Our available
cash is our cash on hand, including cash from borrowings, at the
end of a quarter after the payment of our expenses and the
establishment of reserves for future capital expenditures and
operational needs. We intend to fund a portion of our capital
expenditures with additional borrowings, or issuances of
additional units. We may also borrow to make distributions to
unitholders, for example, in circumstances where we believe that
the distribution level is sustainable over the long term, but
short-term factors have caused available cash from operations to
be insufficient to pay the distribution at the current level.
Our cash distribution policy reflects a basic judgment that our
unitholders will be better served by our distributing rather
than retaining our available cash.
Limitations on Cash Distributions and Our Ability to
Change Our Cash Distribution Policy. There is
no guarantee that unitholders will receive quarterly
distributions from us. Our distribution policy is subject to
certain restrictions and may be changed at any time, including:
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|
Our cash distribution policy is subject to restrictions on
distributions under our new credit facility. Specifically, the
agreement related to our credit facility will contain material
financial tests and covenants that we must satisfy. These
financial tests and covenants are described in this prospectus
under the caption Managements Discussion and
Analysis of Financial Condition and Results of
Operations Liquidity and Capital
Reserves Description of Credit Agreement.
Should we be unable to satisfy these restrictions under our
credit facility or if we are otherwise in default under our
credit facility, we would be prohibited from making cash
distributions to you notwithstanding our stated cash
distribution policy.
|
|
|
|
|
|
Our board of directors will have the authority to establish
reserves for the prudent conduct of our business and for future
cash distributions to our unitholders, and the establishment of
those reserves could result in a reduction in cash distributions
to you from levels we currently anticipate pursuant to our
stated distribution policy.
|
|
|
|
|
|
While our partnership agreement requires us to distribute all of
our available cash, our partnership agreement, including
provisions requiring us to make cash distributions contained
therein, may be amended. Although during the subordination
period, with certain exceptions, our partnership agreement may
not be amended without the approval of the public common
unitholders, our partnership agreement can be amended with the
consent of our general partner and the approval of a majority of
the outstanding common units and any Class B units issued
upon the reset of incentive distribution rights, if any, voting
as a class (including common units held by Targa) after the
subordination period has ended. At the closing of this offering,
Targa will own our general partner and approximately 40.7% of
our outstanding common units and subordinated units.
|
|
|
|
|
|
Even if our cash distribution policy is not modified or revoked,
the amount of distributions we pay under our cash distribution
policy and the decision to make any distribution is determined
by our general partner, taking into consideration the terms of
our partnership agreement.
|
40
|
|
|
|
|
Under
Section 17-607
of the Delaware Revised Uniform Limited Partnership Act, we may
not make a distribution to you if the distribution would cause
our liabilities to exceed the fair value of our assets.
|
|
|
|
We may lack sufficient cash to pay distributions to our
unitholders due to increases in our operating or general and
administrative expense, principal and interest payments on our
outstanding debt, tax expenses, working capital requirements and
anticipated cash needs.
|
Our Ability to Grow is Dependent on Our Ability to Access
External Expansion Capital. We will
distribute all of our available cash to our unitholders. As a
result, we expect that we will rely primarily upon external
financing sources, including commercial bank borrowings and the
issuance of debt and equity securities, to fund our acquisitions
and expansion capital expenditures. As a result, to the extent
we are unable to finance growth externally, our cash
distribution policy will significantly impair our ability to
grow. In addition, because we distribute all of our available
cash, our growth may not be as fast as businesses that reinvest
their available cash to expand ongoing operations. To the extent
we issue additional units in connection with any acquisitions or
expansion capital expenditures, the payment of distributions on
those additional units may increase the risk that we will be
unable to maintain or increase our per unit distribution level,
which in turn may impact the available cash that we have to
distribute on each unit. There are no limitations in our
partnership agreement or our credit facility on our ability to
issue additional units, including units ranking senior to the
common units. The incurrence of additional commercial borrowings
or other debt to finance our growth strategy would result in
increased interest expense, which in turn may impact the
available cash that we have to distribute to our unitholders.
Our
Initial Distribution Rate
Upon completion of this offering, the board of directors of our
general partner will adopt a policy pursuant to which we will
declare an initial quarterly distribution of $0.3375 per
unit per complete quarter, or $1.35 per unit per year, to
be paid no later than 45 days after the end of each fiscal
quarter through the quarter ending December 31, 2007. This
equates to an aggregate cash distribution of $9.8 million
per quarter or $39.0 million per year, in each case based
on the number of common units, subordinated units and general
partner units outstanding immediately after completion of this
offering. If the underwriters exercise in full their option to
purchase additional common units, the ownership interest of the
public unitholders will increase to 19,320,000 common units
representing an aggregate 61.4% limited partner interest in us
and our aggregate cash distribution per quarter would be $10.6
million or $42.5 million per year. Our ability to make cash
distributions at the initial distribution rate pursuant to this
policy will be subject to the factors described above under the
caption Limitations on Cash Distributions and
Our Ability to Change Our Cash Distribution Policy.
As of the date of this offering, our general partner will be
entitled to 2% of all distributions that we make prior to our
liquidation. In the future, the general partners initial
2% interest in these distributions may be reduced if we issue
additional units in the future and our general partner does not
contribute a proportionate amount of capital to us to maintain
its initial 2% general partner interest. However, if the
underwriters option is exercised in the transaction, and
additional common units are issued, our general partner will
maintain its initial 2% interest and will not be required to
make a capital contribution to us. Our general partner is not
obligated to contribute a proportionate amount of capital to us
to maintain its current general partner interest.
41
The table below sets forth the assumed number of outstanding
common units (assuming no exercise and full exercise of the
underwriters option to purchase additional common units),
subordinated units and general partner units upon the closing of
this offering and the aggregate distribution amounts payable on
such units during the year following the closing of this
offering at our initial distribution rate of $0.3375 per
common unit per quarter ($1.35 per common unit on an
annualized basis).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
No Exercise of the Underwriters
|
|
|
Full Exercise of the Underwriters
|
|
|
|
Option to Purchase Additional Units
|
|
|
Option to Purchase Additional Units
|
|
|
|
Number of
|
|
|
Distributions
|
|
|
Number of
|
|
|
Distributions
|
|
|
|
Units
|
|
|
One Quarter
|
|
|
Annualized
|
|
|
Units
|
|
|
One Quarter
|
|
|
Annualized
|
|
|
Publicly held common units
|
|
|
16,800,000
|
|
|
$
|
5,670,000
|
|
|
$
|
22,680,000
|
|
|
|
19,320,000
|
|
|
$
|
6,520,500
|
|
|
$
|
26,082,000
|
|
Subordinated units held by Targa
|
|
|
11,528,231
|
|
|
|
3,890,778
|
|
|
|
15,563,112
|
|
|
|
11,528,231
|
|
|
|
3,890,778
|
|
|
|
15,563,112
|
|
General partner units held by Targa
|
|
|
578,127
|
|
|
|
195,118
|
|
|
|
780,471
|
|
|
|
629,555
|
|
|
|
212,475
|
|
|
|
849,899
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
28,906,358
|
|
|
$
|
9,755,896
|
|
|
$
|
39,023,583
|
|
|
|
31,477,786
|
|
|
$
|
10,623,753
|
|
|
$
|
42,495,011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The subordination period generally will end if we have earned
and paid at least $1.35 on each outstanding unit and general
partner unit for any three consecutive, non-overlapping
four-quarter periods ending on or after December 31, 2009.
If we have earned and paid at least $2.025 (150% of the
annualized minimum quarterly distribution) on each outstanding
common unit, subordinated unit and general partner unit for any
four-quarter period, the subordination period will terminate
automatically and all of the subordinated units will convert
into an equal number of common units. Please see the
Provisions of Our Partnership Agreement Relating to Cash
Distributions Subordination Period.
We do not have a legal obligation to pay distributions at our
initial distribution rate or at any other rate except as
provided in our partnership agreement. Our partnership agreement
requires that we distribute all of our available cash quarterly.
Under our partnership agreement, available cash is defined to
generally mean, for each fiscal quarter, cash generated from our
business in excess of expenses and the amount of reserves our
general partner determines is necessary or appropriate to
provide for the conduct of our business, comply with applicable
law, to comply with any of our debt instruments or other
agreements or provide for future distributions to our
unitholders for any one or more of the upcoming four quarters.
Please see Provisions of Our Partnership Agreement
Relating to Cash Distributions.
If distributions on our common units are not paid with respect
to any fiscal quarter at the initial distribution rate, our
unitholders will not be entitled to receive such payments in the
future except that, during the subordination period to the
extent we have available cash in any future quarter in excess of
the amount necessary to make cash distributions to holders of
our common units at the initial distribution rate, we will use
this excess available cash to pay these deficiencies related to
prior quarters before any cash distribution is made to holders
of subordinated units. Please see Provisions of Our
Partnership Agreement Relating to Cash Distributions
Subordination Period.
Our partnership agreement provides that any determination made
by our general partner in its capacity as our general partner
must be made in good faith and that any such determination will
not be subject to any other standard imposed by our partnership
agreement, the Delaware limited partnership statute or any other
law, rule or regulation or imposed at equity. Holders of our
common units may pursue judicial action to enforce provisions of
our partnership agreement, including those related to
requirements to make cash distributions as described above;
however, our partnership agreement provides that our general
partner is entitled to make the determinations described above
without regard to any standard other than the requirements to
act in good faith. Our partnership agreement provides that, in
order for a determination by our general partner to be made in
good faith, our general partner must believe that
the determination is in our best interests.
Our cash distribution policy, as expressed in our partnership
agreement, may not be modified or repealed without amending our
partnership agreement. The actual amount of our cash
distributions for any quarter is subject to fluctuations based
on the amount of cash we generate from our business and the
amount of reserves our general partner establishes in accordance
with our partnership agreement as described above.
42
We will pay our distributions on or about the 15th of each of
February, May, August and November to holders of record on or
about the 1st of each such month. If the distribution date
does not fall on a business day, we will make the distribution
on the business day immediately preceding the indicated
distribution date. We will adjust the quarterly distribution for
the period from the closing of this offering through
March 31, 2007 based on the actual length of the period.
In the sections that follow, we present in detail the basis for
our belief that we will be able to fully fund our initial
distribution rate of $0.3375 per unit each quarter through
the quarter ending December 31, 2007. In those sections, we
present two tables, consisting of:
|
|
|
|
|
Unaudited Pro Forma Available Cash, in which we
present the amount of cash we would have had available for
distribution for our fiscal year ended December 31, 2005
and the twelve months ended September 30, 2006, derived
from our unaudited pro forma financial statements that are
included in this prospectus, which unaudited pro forma financial
statements are based on the combined results of operations of
the Predecessor Business reflected in the Pre-Acquisition
Financial Statements and the Post-Acquisition Financial
Statements and on the results of operations reflected in the
unaudited historical financial statements of the Predecessor
Business for the nine months ended September 30, 2006, each
as adjusted to give pro forma effect to the offering and the
Formation Transactions; and
|
|
|
|
Statement of Minimum Estimated EBITDA for the Twelve
Months Ending December 31, 2007, in which we
demonstrate our ability to generate the minimum estimated EBITDA
necessary for us to pay distributions at the initial
distribution rate on all units for the twelve months ending
December 31, 2007.
|
Unaudited
Pro Forma Available Cash for Year Ended December 31, 2005
and the Twelve Months Ended September 30, 2006
If we had completed the transactions contemplated in this
prospectus on January 1, 2005, pro forma available cash
generated during the year ended December 31, 2005 would
have been approximately $31.0 million. Assuming the
underwriters exercise in full their option to purchase
additional common units, this amount would have been sufficient
to make a cash distribution for 2005 at the initial rate of
$0.3375 per unit per quarter ($1.35 per unit on an
annualized basis) on all of the common units and a cash
distribution of $0.0932 per unit per quarter ($0.3728 on an
annualized basis) or 28% of the minimum quarterly distribution
on all of the subordinated units. Assuming the underwriters do
not exercise their option to purchase additional common units,
this amount would have been sufficient to make the full minimum
quarterly distribution on all of the common units and a cash
distribution of $0.0968 per unit per quarter ($0.3874 on an
annualized basis) or 29% of the minimum quarterly distribution
on all of the subordinated units.
If we had completed the transactions contemplated in this
prospectus on October 1, 2005, our pro forma available cash
generated for the twelve months ended September 30, 2006
would have been approximately $42.0 million. Assuming the
underwriters exercise in full their option to purchase
additional common units, this amount would have been sufficient
to make a cash distribution for the twelve months ended
September 30, 2006 at the initial distribution rate of
$0.3375 per unit per quarter ($1.35 per unit on an
annualized basis) on all of the common units and a cash
distribution of $0.3270 per unit per quarter ($1.3079 on an
annualized basis) or 97% of the minimum quarterly distribution
on all of the subordinated units. Assuming the underwriters do
not exercise their option to purchase additional common units,
this amount would have been sufficient to make the full minimum
quarterly distribution on all of the common units and a cash
distribution of $0.3306 per unit per quarter ($1.3225 on an
annualized basis) or 98% of the minimum quarterly distribution
on all of the subordinated units. We had no hedges in place
during the year ended December 31, 2005. Pro forma
available cash for the twelve months ended September 30,
2006 includes $0.3 million in net benefit for hedge
settlements during the second and third quarters of 2006.
Unaudited pro forma available cash from operating surplus
includes direct, incremental general and administrative expenses
that will result from operating as a separate publicly held
limited partnership. These
43
direct, incremental general and administrative expenses are
expected to be approximately $2.5 million annually, are not
subject to the cap contained in the omnibus agreement and
include costs associated with annual and quarterly reports to
unitholders, tax return and
Schedule K-1
preparation and distribution, incremental independent auditor
fees, registrar and transfer agent fees and independent director
compensation. These direct, incremental general and
administrative expenditure are not reflected in the historical
financial statements of the Predecessor Business or our pro
forma financial statements.
We based the pro forma adjustments upon currently available
information and specific estimates and assumptions. The pro
forma amounts below do not purport to present our results of
operations had the transactions contemplated in this prospectus
actually been completed as of the dates indicated. In addition,
cash available to pay distributions is primarily a cash
accounting concept, while our pro forma financial statements
have been prepared on an accrual basis. As a result, you should
view the amount of pro forma available cash only as a general
indication of the amount of cash available to pay distributions
that we might have generated had we been formed in earlier
periods.
The following table illustrates, on a pro forma basis, for the
year ended December 31, 2005 and for the twelve months
ended September 30, 2006, the amount of available cash that
would have been available for distributions to our unitholders,
assuming in each case that this offering had been consummated at
the beginning of such period and that the underwriters exercised
in full their option to purchase additional common units. Each
of the pro forma adjustments presented below is explained in the
footnotes to such adjustments.
Targa
Resources Partners LP
Unaudited
Pro Forma Available Cash
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve Months
|
|
|
|
Year Ended
|
|
|
Ended
|
|
|
|
December 31,
|
|
|
September 30,
|
|
|
|
2005
|
|
|
2006
|
|
|
|
(in millions of dollars,
|
|
|
|
except per unit data)
|
|
|
Net income
(loss)(1)
|
|
$
|
40.8
|
|
|
$
|
(32.7
|
)
|
Interest expense (including debt
issuance amortization)(2)
|
|
|
11.5
|
|
|
|
65.9
|
|
Depreciation and amortization(2)
|
|
|
20.5
|
|
|
|
52.1
|
|
Income taxes(2)
|
|
|
0.0
|
|
|
|
2.0
|
|
|
|
|
|
|
|
|
|
|
EBITDA(3)
|
|
|
72.8
|
|
|
|
87.3
|
|
Incremental general and
administrative expense of being a public company(4)
|
|
|
2.5
|
|
|
|
2.5
|
|
Pro forma net cash interest
expense(5)
|
|
|
20.7
|
|
|
|
20.7
|
|
Maintenance capital expenditures(6)
|
|
|
12.9
|
|
|
|
12.3
|
|
Expansion capital expenditures(6)
|
|
|
5.7
|
|
|
|
9.8
|
|
|
|
|
|
|
|
|
|
|
Pro forma available
cash
|
|
$
|
31.0
|
|
|
$
|
42.0
|
|
|
|
|
|
|
|
|
|
|
Distributions per
unit(7)
|
|
$
|
1.35
|
|
|
$
|
1.35
|
|
Pro forma cash
distributions:
|
|
|
|
|
|
|
|
|
Distributions to public common
unitholders(7)
|
|
|
26.1
|
|
|
|
26.1
|
|
Distributions to Targa(7)
|
|
|
16.4
|
|
|
|
16.4
|
|
|
|
|
|
|
|
|
|
|
Total distributions(7)
|
|
$
|
42.5
|
|
|
$
|
42.5
|
|
|
|
|
|
|
|
|
|
|
Excess (shortfall)
|
|
$
|
(11.5
|
)
|
|
$
|
(0.5
|
)
|
|
|
|
|
|
|
|
|
|
Ratio of consolidated indebtedness
to consolidated EBITDA(8)
|
|
|
4.1
|
x
|
|
|
3.4
|
x
|
Ratio of consolidated EBITDA to
consolidated interest expense(8)
|
|
|
3.5
|
x
|
|
|
4.2
|
x
|
44
|
|
|
(1) |
|
Reflects actual net income of the Predecessor Business derived
from its financial statements for the periods indicated without
giving pro forma effect to the offering and the related
transactions. |
|
|
|
(2) |
|
Reflects adjustments to reconcile net income to EBITDA. |
|
(3) |
|
EBITDA. We define EBITDA as net income before
interest, income taxes, depreciation and amortization. EBITDA is
used as a supplemental financial measure by our management and
by external users of our financial statements such as investors,
commercial banks and others, to assess: |
|
|
|
|
|
the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis;
|
|
|
|
our operating performance and return on capital as compared to
other companies in the midstream energy sector, without regard
to financing or capital structure; and
|
|
|
|
the viability of acquisitions and capital expenditure projects
and the overall rates of return on alternative investment
opportunities.
|
|
|
|
|
|
The economic substance behind managements use of EBITDA is
to measure the ability of our assets to generate cash sufficient
to pay interest costs, support our indebtedness, and make
distributions to our investors. |
|
|
|
The GAAP measures most directly comparable to EBITDA are net
cash provided by operating activities and net income. Our
non-GAAP financial measure of EBITDA should not be considered as
an alternative to GAAP net cash provided by operating activities
and GAAP net income. EBITDA is not a presentation made in
accordance with GAAP and has important limitations as an
analytical tool. You should not consider EBITDA in isolation or
as a substitute for analysis of our results as reported under
GAAP. Because EBITDA excludes some, but not all, items that
affect net income and net cash provided by operating activities
and is defined differently by different companies in our
industry, our definition of EBITDA may not be comparable to
similarly titled measures of other companies. |
|
|
|
Management compensates for the limitations of EBITDA as an
analytical tool by reviewing the comparable GAAP measures,
understanding the differences between the measures and
incorporating these learnings into managements
decision-making processes. |
|
(4) |
|
Reflects an adjustment to our EBITDA for an estimated
incremental cash expense associated with being a publicly traded
limited partnership, including costs associated with annual and
quarterly reports to unitholders, tax return and
Schedule K-1
preparation and distribution, independent auditor fees, investor
relations activities, registrar and transfer agent fees,
incremental director and officer liability insurance costs and
director compensation. |
|
(5) |
|
Reflects the interest expense related to $295.2 million in
borrowings under our new credit facility at an assumed annual
interest rate of 7.0%. This balance reflects the reduction to
our expected initial borrowings of approximately
$342.5 million through the application of the net proceeds
from the assumed exercise in full of the underwriters
option to purchase additional common units. If the interest rate
used to calculate this interest were 1% higher or lower,
our annual cash interest cost would increase or decrease,
respectively, by $3.0 million. |
|
(6) |
|
Maintenance capital expenditures are capital expenditures made
to replace partially or fully depreciated assets, to maintain
the existing operating capacity of our assets and to extend
their useful lives, or other capital expenditures that are
incurred in maintaining existing system volumes and related cash
flows. Expansion capital expenditures are made to acquire
additional assets to grow our business, to expand and upgrade
our systems and facilities and to construct or acquire similar
systems or facilities. |
|
(7) |
|
The table below assumes full exercise of the underwriters
option to purchase additional common units and sets forth the
assumed number of outstanding common units, subordinated units
and general partner units upon the closing of this offering and
the estimated per unit and aggregate distribution amounts
payable on our common units, subordinated units and general
partner units for four quarters at our initial distribution rate
of $0.3375 per common unit per quarter ($1.35 per
common unit on an annualized basis). |
45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Full Exercise of the Underwriters Option to Purchase
Additional Units
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Units
|
|
|
One Quarter
|
|
|
Annualized
|
|
|
|
|
|
|
|
|
|
|
|
Publicly held common units
|
|
|
19,320,000
|
|
|
$
|
6,520,500
|
|
|
$
|
26,082,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subordinated units held
by Targa
|
|
|
11,528,231
|
|
|
|
3,890,778
|
|
|
|
15,563,112
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner units held
by Targa
|
|
|
629,555
|
|
|
|
212,475
|
|
|
|
849,899
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
31,477,786
|
|
|
$
|
10,623,753
|
|
|
$
|
42,495,011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8) |
|
In connection with this offering, we expect to enter into a new
credit facility which will contain covenants limiting our
ability to make distributions, incur indebtedness, grant liens,
and engage in transactions with affiliates. Furthermore, our
credit facility will contain covenants requiring us to maintain
a ratio of consolidated indebtedness to consolidated EBITDA
initially of not more than 5.75 to 1.00 and a ratio of
consolidated EBITDA to consolidated interest expense of not less
than 2.25 to 1.00. Any subsequent replacement of our credit
facility or any new indebtedness could have similar or greater
restrictions. |
Minimum
Estimated EBITDA for the Twelve Months Ending December 31,
2007
Set forth below is a Statement of Minimum Estimated EBITDA that
reflects our ability to generate sufficient cash flows to make
the minimum quarterly distribution on all of our outstanding
units for the twelve months ending December 31, 2007, based
on assumptions we believe to be reasonable. EBITDA is defined as
net income before interest, income taxes, depreciation and
amortization. Our minimum estimated EBITDA is prepared on a
basis consistent with the accounting principles used in the
historical financial statements of the Predecessor Business.
Our minimum estimated EBITDA assumes the underwriters exercise
in full their option to purchase additional common units. The
underwriters may or may not elect to exercise this option. We
have presented our ability to make distributions assuming the
issuance of an additional 2,520,000 common units and 51,428
general partner units as a result of this option. Because we
will use the proceeds from the exercise of this option to reduce
outstanding indebtedness, our cash available for distribution
will increase by $3.3 million as a result of reduced
interest expense. This increase is offset by $3.5 million
of cash required to make distributions on the additional common
and general partner units. If the option to purchase additional
units is not exercised, our interest expense will increase and
cash available for distribution will decrease by
$3.3 million. Our pro forma financial statements and other
information presented in this prospectus does not assume any
exercise of the underwriters option to purchase additional
common units.
Our minimum estimated EBITDA reflects our judgment as of the
date of this prospectus of conditions we expect to exist and the
course of action we expect to take in order to make the minimum
quarterly distribution on all our outstanding units for the
twelve months ending December 31, 2007. The assumptions
disclosed below under Assumptions and
Considerations are those that we believe are significant
to our ability to generate our minimum estimated EBITDA. We
believe our actual results of operations and cash flows will be
sufficient to generate the minimum estimated EBITDA; however, we
can give you no assurance that our minimum estimated EBITDA will
be achieved. There will likely be differences between our
minimum estimated EBITDA and our actual results and those
differences could be material. If we fail to generate the
minimum estimated EBITDA, we may not be able to pay cash
distributions on our common units at the initial distribution
rate stated in our cash distribution policy. Assuming the
underwriters exercise in full their option to purchase
additional common units, in order to fund distributions to all
of our common and subordinated unitholders at our initial rate
of $1.35 per unit for the twelve months ending December 31,
2007, our minimum estimated EBITDA for the twelve months ending
December 31, 2007 must be at least $78.3 million.
Assuming the underwriters do not exercise their option to
purchase additional common units, in order to fund distributions
to all of our common and subordinated unitholders at our initial
rate of $1.35 per unit for the twelve months ending
December 31, 2007, our minimum estimated EBITDA for the
twelve months ending December 31, 2007 must be at least
$78.1 million. The amount of our minimum estimated EBITDA
is lower if the underwriters do not exercise their option to
purchase additional units because we
46
would have fewer units outstanding and lower aggregate
distributions, offset by higher interest expense associated with
the higher level of indebtedness. As set forth in the table
below, our minimum estimated EBITDA for this period will be
approximately $78.3 million.
We do not as a matter of course make public projections as to
future operations, earnings, or other results. However,
management has prepared the minimum estimated EBITDA and related
assumptions set forth below to substantiate our belief that we
will have sufficient cash to make the minimum quarterly
distribution to all our unitholders for the twelve months ending
December 31, 2007. The accompanying prospective financial
information was not prepared with a view toward complying with
the guidelines established by the American Institute of
Certified Public Accountants with respect to prospective
financial information but, in the view of our management, the
prospective financial information has been prepared on a
reasonable basis, reflects the best currently available
estimates and judgments, and presents, to the best of
managements knowledge and belief, the assumptions on which
we base our belief that we can generate the minimum estimated
EBITDA necessary for us to have sufficient cash available for
distributions to pay the minimum quarterly distribution to all
our unitholders. However, this information is not fact and
should not be relied upon as being necessarily indicative of
future results, and readers of this prospectus are cautioned not
to place undue reliance on the prospective financial information.
The prospective financial information included in this
prospectus has been prepared by, and is the responsibility of,
our management. PricewaterhouseCoopers LLP has neither examined
nor compiled the accompanying prospective financial information
and accordingly, PricewaterhouseCoopers LLP does not express an
opinion or any other form of assurance with respect thereto. The
PricewaterhouseCoopers LLP report included in this prospectus
relates to our historical information. It does not extend to the
prospective financial information and should not be read to do
so.
When considering our minimum estimated EBITDA, you should keep
in mind the risk factors and other cautionary statements under
Risk Factors. Any of the risks discussed in this
prospectus could cause our actual results of operations to vary
significantly from those supporting our minimum estimated EBITDA.
We are providing our minimum estimated EBITDA and related
assumptions to supplement our pro forma and historical financial
statements in support of our belief that we will have sufficient
available cash to allow us to pay cash distributions on all of
our outstanding common and subordinated units for each quarter
in the four-quarter period ending December 31, 2007 at our
stated initial distribution rate. Please see below under
Assumptions and Considerations for
further information as to the assumptions we have made for the
financial forecast.
We do not undertake any obligation to release publicly the
results of any future revisions we may make to the assumptions
used in generating minimum estimated EBITDA or to update those
assumptions to reflect events or circumstances after the date of
this prospectus. Therefore, you are cautioned not to place undue
reliance on this information.
47
Targa
Resources Partners LP
Statement
of Minimum Estimated EBITDA
|
|
|
|
|
|
|
Twelve Months Ending
|
|
|
|
December 31, 2007
|
|
|
|
(in millions of dollars,
|
|
|
|
except for per unit data)
|
|
|
Operating revenues
|
|
$
|
358.5
|
|
Hedging gain (loss)
|
|
|
15.0
|
|
|
|
|
|
|
Total operating
revenues
|
|
|
373.5
|
|
Product purchases
|
|
|
256.4
|
|
Operating expense
|
|
|
23.7
|
|
General and administrative expense
|
|
|
7.5
|
|
Depreciation and amortization
expense
|
|
|
55.2
|
|
Interest expense, net
|
|
|
21.6
|
|
|
|
|
|
|
Net income
|
|
$
|
9.1
|
|
Adjustments to reconcile net income
to minimum estimated EBITDA:
|
|
|
|
|
Add:
|
|
|
|
|
Depreciation and amortization
expense
|
|
|
55.2
|
|
Interest expense, net
|
|
|
21.6
|
|
Less:
|
|
|
|
|
Cash reserves(1)
|
|
|
7.6
|
|
|
|
|
|
|
Minimum estimated
EBITDA(2)
|
|
|
78.3
|
|
Adjustments to reconcile minimum
estimated EBITDA to estimated cash available for distribution:
|
|
|
|
|
Less:
|
|
|
|
|
Cash interest expense
|
|
|
20.8
|
|
Expansion capital expenditures
|
|
|
1.8
|
|
Maintenance capital expenditures
|
|
|
15.0
|
|
Add:
|
|
|
|
|
Borrowing to fund expansion capital
expenditures
|
|
|
1.8
|
|
|
|
|
|
|
Estimated cash available for
distribution
|
|
$
|
42.5
|
|
|
|
|
|
|
Per unit minimum annual distribution
|
|
$
|
1.35
|
|
Annual distributions to:
|
|
|
|
|
Public common unitholders
|
|
$
|
26.1
|
|
Targa
|
|
|
16.4
|
|
|
|
|
|
|
Total minimum annual cash
distributions
|
|
|
42.5
|
|
|
|
|
|
|
Ratio of consolidated indebtedness
to consolidated EBITDA(3)
|
|
|
3.5
|
x
|
Ratio of consolidated EBITDA to
consolidated interest expense(3)
|
|
|
4.1
|
x
|
|
|
|
(1) |
|
Represents a discretionary reserve to be used for reinvestment
and other general partnership purposes. |
|
(2) |
|
EBITDA. We define EBITDA as net income before
interest, income taxes, depreciation and amortization. EBITDA is
used as a supplemental financial measure by our management and
by external users of our financial statements such as investors,
commercial banks and others, to assess: |
|
|
|
|
|
the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis;
|
|
|
|
our operating performance and return on capital as compared to
other companies in the midstream energy sector, without regard
to financing or capital structure; and
|
|
|
|
the viability of acquisitions and capital expenditure projects
and the overall rates of return on alternative investment
opportunities.
|
|
|
|
|
|
The economic substance behind managements use of EBITDA is
to measure the ability of our assets to generate cash sufficient
to pay interest costs, support our indebtedness, and make
distributions to our investors. |
48
|
|
|
|
|
The GAAP measures most directly comparable to EBITDA are net
cash provided by operating activities and net income. Our
non-GAAP financial measure of EBITDA should not be considered as
an alternative to GAAP net cash provided by operating activities
and GAAP net income. EBITDA is not a presentation made in
accordance with GAAP and has important limitations as an
analytical tool. You should not consider EBITDA in isolation or
as a substitute for analysis of our results as reported under
GAAP. Because EBITDA excludes some, but not all, items that
affect net income and net cash provided by operating activities
and is defined differently by different companies in our
industry, our definition of EBITDA may not be comparable to
similarly titled measures of other companies. |
|
|
|
Management compensates for the limitations of EBITDA as an
analytical tool by reviewing the comparable GAAP measures,
understanding the differences between the measures and
incorporating these learnings into managements
decision-making processes. |
|
(3) |
|
In connection with this offering, we expect to enter into a new
credit facility which will contain covenants limiting our
ability to make distributions, incur indebtedness, grant liens,
and engage in transactions with affiliates. Furthermore, our
credit facility will contain covenants requiring us to maintain
a ratio of consolidated indebtedness to consolidated EBITDA of
not more than 5.75 to 1.00 and a ratio of consolidated EBITDA to
consolidated interest expense of not less than 2.25 to 1.00. Any
subsequent replacement of our credit facility or any new
indebtedness could have similar or greater restrictions. |
Please see accompanying summary of the assumptions used to
support our minimum estimated EBITDA.
Assumptions
and Considerations
We believe the assumptions and estimates we have made to support
our ability to generate minimum estimated EBITDA, which are set
forth below, are reasonable.
General/Commodity
Price and Risk Considerations
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Our minimum estimated EBITDA includes the effect of our
commodity price hedging program under which we have hedged a
portion of the commodity price risk related to our expected
natural gas, NGL and condensate sales. Our hedging program for
the twelve months ending December 31, 2007 covers
approximately 90% of our expected natural gas, 62% of our
expected NGL and 93% of our expected condensate equity volumes.
We have the following hedging arrangements in place for 2007:
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Natural Gas
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NGL
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Condensate
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Hedged volume swaps
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13,612 MMBtu/d
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2,416 Bbls/d
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439 Bbls/d
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Weighted average price
swaps
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$8.63 per MMBtu
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$0.99 per gallon
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$72.82 per Bbl
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Hedged volume floors
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870 MMBtu/d
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25 Bbls/d
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Weighted average price
floors
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$6.55 per MMBtu
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$58.60 per Bbl
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As of January 30, 2007, the NYMEX 2007 forward prices for
natural gas and crude oil were
$7.82/MMbtu
and $58.35/Bbl, respectively. These prices are 6% above and 13%
below the forecasted prices of $7.40/MMbtu and $67.00/Bbl for
natural gas and crude oil (based on forward prices as of
September 29, 2006) used to calculate 2007 minimum
estimated EBITDA.
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Total
Operating Revenues
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Inlet Volumes. We estimate that we will
have average inlet volumes of 162.1 MMcf/d of natural gas
for the twelve months ending December 31, 2007, as compared
to 161.8 MMcf/d for the twelve months ended
September 30, 2006, 157.2 MMcf/d for the year ended
December 31, 2005, and 145.4 MMcf/d for the year ended
December 31, 2004.
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Residue Gas Sales (Volumes and
Prices). We estimate that we will sell an
average of 73.5 BBtu/d of residue gas for the twelve months
ending December 31, 2007 at an average realized price of
$6.96/MMBtu, as compared to 74.6 BBtu/d at an average price
of $6.83/MMBtu for the twelve months
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ended September 30, 2006, 69.5 BBtu/d at an average price
of $7.11/MMBtu for the year ended December 31, 2005, and
59.2 BBtu/d at an average price of $5.43/MMBtu for the year
ended December 31, 2004. These assumptions take into
account the effect of our natural gas hedges under which we have
hedged through a combination of swaps and purchased puts (or
floors) natural gas commodity price exposure related to
approximately 90% of our expected natural gas equity volumes.
Please see Managements Discussion and Analysis of
Financial Condition and Results of Operations
Quantitative and Qualitative Disclosures about Market
Risk Commodity Price Risk for additional
detail related to the terms of these natural gas hedges. For our
unhedged natural gas volumes, our forecasted realized price is
$6.58/MMBtu compared to average realized prices of $6.09/MMBtu
for the nine months ended September 30, 2006.
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Based on these assumptions, residue gas sales for the:
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twelve months ending December 31, 2007 compared to twelve
months ending September 30, 2006 increase approximately
$0.6 million consisting of higher revenues of
$3.3 million attributable to higher natural gas prices
offset by $2.7 million due to decreased volumes;
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twelve months ending December 31, 2007 compared to twelve
months ending December 31, 2005 increase approximately
$6.5 million consisting of higher revenues of
$10.6 million attributable to increased volumes offset by
$4.1 million due to lower natural gas prices; and
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twelve months ending December 31, 2007 compared to twelve
months ending December 31, 2004 increase approximately
$69.0 million consisting of higher revenues of
$41.0 million attributable to higher natural gas prices and
$28.0 million due to increased volumes.
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NGL Sales (Volumes and Prices). We
estimate that we will sell an average of 14.2 MBbls/d of
NGLs for the twelve months ending December 31, 2007 at an
average price of $33.34/Bbl, as compared to 15.2 MBbls/d at
an average price of $38.20/Bbl for the twelve months ended
September 30, 2006, 14.5 MBbls/d at an average price
of $33.56/Bbl for the calendar year ended December 31,
2005, and 13.2 MBbls/d at an average price of $26.71/Bbl
for the calendar year ended December 31, 2004. These
assumptions take into account the effect of our NGL hedges under
which we have hedged the NGL commodity price exposure related to
approximately 62% of our expected NGL equity volumes. Please see
Managements Discussion and Analysis of Financial
Condition and Results of Operations Quantitative and
Qualitative Disclosures about Market Risk Commodity
Price Risk for additional detail related to the terms of
these NGL hedges. For our unhedged NGL volumes, our estimated
realized price is $32.59/Bbl compared to average realized prices
of $37.80/Bbl for the nine months ended September 30, 2006.
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Based on these assumptions, NGL sales for the:
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twelve months ending December 31, 2007 compared to
twelve months ending September 30, 2006 decrease
approximately $37.4 million consisting of lower revenues of
$23.8 million attributable to lower NGL prices and
$13.6 million due to decreased volumes;
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twelve months ending December 31, 2007 compared to twelve
months ending December 31, 2005 decrease approximately
$4.1 million consisting of lower revenues of
$2.9 million attributable to decreased volumes and $1.2
million due to lower NGL prices; and
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twelve months ending December 31, 2007 compared to twelve
months ending December 31, 2004 increase approximately
$43.9 million consisting of higher revenues of
$34.4 million attributable to higher NGL prices and
$9.5 million due to increased volumes.
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Condensate Sales (Volumes and
Prices). We estimate that we will sell an
average of 0.5 MBbls/d of condensate for the twelve months
ending December 31, 2007 at an average price of $71.12/Bbl,
as compared to 0.5 MBbls/d at an average price of
$61.55/Bbl for the twelve months ended September 30, 2006,
0.5 MBbls/d at an average price of $54.03/Bbl for the
calendar year ended December 31, 2005, and 0.7 MBbls/d
at an average price of $40.56/Bbl for the calendar year ended
December 31, 2004. These assumptions take into account the
effect of the crude oil hedges under
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which we have hedged through a combination of swaps and
purchased puts (or floors) commodity price exposure related to
approximately 93% of our expected condensate equity volumes.
Please see Managements Discussion and Analysis of
Financial Condition and Results of Operations
Quantitative and Qualitative Disclosures about Market
Risk Commodity Price Risk for additional
detail related to the terms of these crude oil hedges. For our
unhedged condensate volumes, our estimated realized price is
$66.00/Bbl compared to average realized prices of $62.66/Bbl for
the nine months ended September 30, 2006.
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Based on these assumptions, condensate sales for the:
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twelve months ending December 31, 2007 compared to twelve
months ending September 30, 2006 increase approximately
$1.8 million due to higher condensate prices;
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twelve months ending December 31, 2007 compared to twelve
months ending December 31, 2005 increase approximately
$2.6 million consisting of higher revenues of
$3.1 million attributable to higher condensate prices
offset by $0.5 million due to decreased volumes; and
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twelve months ending December 31, 2007 compared to twelve
months ending December 31, 2004 increase approximately
$2.7 million consisting of higher revenues of
$5.5 million attributable to higher condensate prices
offset by $2.8 million due to decreased volumes.
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Impact of Volume Declines. If all other
assumptions are held constant, a 5% decline in inlet volumes
below forecasted levels would result in a $5.1 million
decline in cash available for distribution. A decline in
estimated cash flows greater than $7.6 million would result
in our generating less than the minimum cash necessary to pay
distributions. For the twelve months ended December 31,
2004, the twelve months ended December 31, 2005 and the
twelve months ended September 30, 2006, a 5% decline in
inlet volumes would have resulted in a $3.8 million,
$5.1 million and $5.4 million, respectively, decline
in cash available for distribution.
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Impact of Price Declines. A difference
in realized versus estimated commodity prices would affect our
cash flows. For the twelve months ending December 31, 2007,
approximately 10%, 38% and 7% of our forecasted natural gas, NGL
and condensate equity volumes are unhedged. If all other
assumptions are held constant, a 10% decrease in realized
natural gas, NGL and crude oil prices versus our estimated
prices for the unhedged portions of our estimated volumes of
natural gas, NGLs and condensate would result in a
$2.8 million decline in cash available for distribution. A
20% decline in these prices would result in an $5.6 million
decline in cash available for distribution.
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Hedging Gain / (Loss). We estimate hedge gains
will be $15.0 million for the twelve months ending
December 31, 2007. In 2006, we entered into certain hedges
for 2007 at prices that are materially higher than the prices
underlying our Estimated EBITDA for the year ending
December 31, 2007. For a description of our hedges, please
see Managements Discussion and Analysis of Financial
Condition and Results of Operations Quantitative and
Qualitative Disclosures about Market Risk Summary of
Our Hedges.
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Costs
and Expenses
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Product Purchases. We estimate that our
product purchases for the twelve months ending December 31,
2007 will be $256.4 million, as compared to
$291.9 million for the twelve months ended
September 30, 2006, $265.7 million for the twelve
months ended December 31, 2005, and $182.6 million for
the twelve months ended December 31, 2004.
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Based on this estimate, the product purchases for the:
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twelve months ending December 31, 2007 compared to twelve
months ending September 30, 2006 decrease approximately
$35.5 million consisting of lower costs of
$82.9 million attributable to lower commodity prices offset
by $47.4 million due to increased volumes;
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twelve months ending December 31, 2007 compared to twelve
months ending December 31, 2005 decrease approximately
$9.5 million consisting of lower costs of
$65.6 million attributable to lower commodity prices offset
by $56.1 million due to increased volumes; and
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twelve months ending December 31, 2007 compared to twelve
months ending December 31, 2004 increase approximately
$73.9 million consisting of higher costs of
$10.9 million attributable to higher commodity prices and
$63.0 million due to increased volumes.
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Operating Expense. We estimate that we
will incur operating expense of $23.7 million for the
twelve months ending December 31, 2007, as compared to
$23.6 million for the twelve months ended
September 30, 2006, $21.5 million for the twelve
months ended December 31, 2005, and $17.7 million for
the twelve months ended December 31, 2004. The expected
increase in operating expense is driven by higher costs for
labor, supplies and equipment and the expansion of our gathering
system.
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General and Administrative Expense. Our
estimated general and administrative expense will be
$7.5 million for the twelve months ending December 31,
2007 and will consist of up to a maximum of $5.0 million,
subject to adjustment, of general and administrative expense
allocated from Targa pursuant to the omnibus agreement, and
$2.5 million of estimated general and administrative
expense that relates to operating as a publicly held limited
partnership. General and administrative expense was
$6.8 million, $8.4 million and $7.2 million for
the twelve months ended September 30, 2006, the twelve
months ended December 31, 2005 and the twelve months ended
December 31, 2004, respectively. Please see Certain
Relationships and Related Party Transactions Omnibus
Agreement for additional details related to our omnibus
agreement.
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Depreciation and Amortization
Expense. Estimated depreciation and
amortization expense for the twelve months ending
December 31, 2007 is $55.2 million as compared to
$52.1 million for the twelve months ending
September 30, 2006, $20.5 million for the twelve
months ended December 31, 2005 and $12.2 million for
the twelve months ended December 31, 2004. Estimated
depreciation and amortization expense reflects managements
estimates, which are based on consistent average depreciable
asset lives and depreciation methodologies. The majority of the
increase in depreciation and amortization is attributable to the
step-up in
basis associated with the DMS Acquisition.
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Capital Expenditures. Estimated capital
expenditures for the twelve months ending December 31, 2007
are based on the following assumptions:
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Maintenance Capital Expenditures. Our
estimated maintenance capital expenditures are
$15.0 million for the twelve months ending
December 31, 2007 as compared to $12.3 million for the
twelve months ending September 30, 2006, $12.9 million
for the twelve months ended December 31, 2005 and
$10.2 million for the twelve months ended December 31,
2004. The expected increase in maintenance capital expenditures
is attributable to capital spending for additional well
connections in 2007 and the increased size of our gathering
systems compared to prior periods.
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Expansion Capital Expenditures. Our
estimated expansion capital expenditures are $1.8 million
for the twelve months ending December 31, 2007 as compared
to $9.8 million for the twelve months ending
September 30, 2006, $5.7 million for the twelve months
ended December 31, 2005 and $13.5 million for the
twelve months ended December 31, 2004. We expect to finance
our $1.8 million in expansion capital expenditures from
borrowings under our credit facility. The expected decrease in
expansion capital expenditures is primarily due to the
completion of the refurbishment of the Chico processing plant in
2006 offset by remaining expenditures for projects expected to
be completed in the year ending December 31, 2007.
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Financing. Our estimate for the twelve
months ending December 31, 2007 is based on the following
significant financing assumptions:
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Indebtedness. Our expected initial
borrowings of approximately $342.5 million under our new
credit facility will be reduced by $47.3 million through
the application of the net proceeds from the exercise in full of
the underwriters option to purchase additional units, and
increased by $1.8 million in order to fund our expansion
capital requirement.
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Interest Expense. The borrowings under
our credit facility will bear an average variable interest rate
of 7.0% through December 31, 2007. An increase or decrease
of 1% in the interest rate will result in increased or
decreased, respectively, annual interest expense of
$3.0 million.
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Covenant Compliance. We will remain in
compliance with the financial and other covenants in our new
credit facility.
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Regulatory, Industry and Economic
Factors. Our estimate for the twelve months
ending December 31, 2007 is based on the following
significant assumptions related to regulatory, industry and
economic factors:
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There will not be any new federal, state or local regulation of
portions of the energy industry in which we operate, or an
interpretation of existing regulation, that will be materially
adverse to our business.
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There will not be any major adverse change in the portions of
the energy industry or in general economic conditions.
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Market, insurance and overall economic conditions will not
change substantially.
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53
PROVISIONS
OF OUR PARTNERSHIP AGREEMENT
RELATING TO CASH DISTRIBUTIONS
Targa Resources, Inc. and certain of its affiliates hold all
of the membership interests in our general partner, and
consequently are indirectly entitled to all of the distributions
that we make to Targa Resources GP LLC, subject to the terms of
the limited liability company agreement of Targa Resources GP
LLC and relevant legal restrictions.
Set forth below is a summary of the significant provisions of
our partnership agreement that relate to cash distributions.
Distributions
of Available Cash
General. Our partnership agreement
requires that, within 45 days after the end of each
quarter, beginning with the quarter ending March 31, 2007,
we distribute all of our available cash to unitholders of record
on the applicable record date.
Definition of Available Cash. The term
available cash, for any quarter, means all cash and
cash equivalents on hand on the date of determination of
available cash for that quarter:
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less the amount of cash reserves established by our general
partner to:
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provide for the proper conduct of our business;
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comply with applicable law, any of our debt instruments or other
agreements; or
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provide funds for distributions to our unitholders and to our
general partner for any one or more of the next four quarters.
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Minimum Quarterly Distribution. We will
distribute to the holders of common units and subordinated units
on a quarterly basis at least the minimum quarterly distribution
of $0.3375 per unit, or $1.35 per year, to the extent we
have sufficient cash from our operations after establishment of
cash reserves and payment of fees and expenses, including
payments to our general partner. However, there is no guarantee
that we will pay the minimum quarterly distribution on the units
in any quarter. Even if our cash distribution policy is not
modified or revoked, the amount of distributions paid under our
policy and the decision to make any distribution is determined
by our general partner, taking into consideration the terms of
our partnership agreement. We will be prohibited from making any
distributions to unitholders if it would cause an event of
default, or an event of default is existing, under our credit
agreement. Please see Managements Discussion and
Analysis of Financial Condition and Results of
Operations Capital Requirements
Description of Credit Agreement for a discussion of the
restrictions to be included in our credit agreement that may
restrict our ability to make distributions.
General Partner Interest and Incentive Distribution
Rights. Initially, our general partner will
be entitled to 2% of all quarterly distributions since inception
that we make prior to our liquidation. This general partner
interest will be represented by 578,127 general partner units
(or 629,555 general partner units if the underwriters exercise
their option to purchase additional common units in full). Our
general partner has the right, but not the obligation, to
contribute a proportionate amount of capital to us to maintain
its current general partner interest. The general partners
initial 2% interest in these distributions may be reduced if we
issue additional units in the future and our general partner
does not contribute a proportionate amount of capital to us to
maintain its 2% general partner interest.
Our general partner also currently holds incentive distribution
rights that entitle it to receive increasing percentages, up to
a maximum of 50%, of the cash we distribute from operating
surplus (as defined below) in excess of $0.3881 per unit
per quarter. The maximum distribution of 50% includes
distributions paid to our general partner on its 2% general
partner interest and assumes that our general partner maintains
its general partner interest at 2%. The maximum distribution of
50% does not include any distributions that our general partner
may receive on subordinated units that it owns. Please see
General Partner Interest and Incentive
Distribution Rights for additional information.
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Operating
Surplus and Capital Surplus
General. All cash distributed to
unitholders will be characterized as either operating
surplus or capital surplus. Our partnership
agreement requires that we distribute available cash from
operating surplus differently than available cash from capital
surplus.
Operating
Surplus. Operating
surplus consists of:
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an amount equal to four times the amount needed for any one
quarter for us to pay a distribution on all of our units
(including the general partner units) and the incentive
distribution rights at the same per-unit amount as was
distributed in the immediately preceding quarter; plus
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all of our cash receipts after the closing of this offering,
excluding cash from borrowings, sales of equity and debt
securities, sales or other dispositions of assets outside the
ordinary course of business, capital contributions or corporate
reorganizations or restructurings (provided that cash receipts
from the termination of a commodity hedge or interest rate swap
prior to its specified termination date shall be included in
operating surplus in equal quarterly installments over the
scheduled life of such commodity hedge or interest rate swap);
less
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all of our operating expenditures after the closing of this
offering, but excluding the repayment of borrowings, and
including maintenance capital expenditures; less
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the amount of cash reserves established by our general partner
to provide funds for future operating expenditures.
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Maintenance capital expenditures represent capital expenditures
made to replace partially or fully depreciated assets, to
maintain the existing operating capacity of our assets and to
extend their useful lives, or other capital expenditures that
are incurred in maintaining existing system volumes and related
cash flows. Expansion capital expenditures represent capital
expenditures made to expand or to increase the efficiency of the
existing operating capacity of our assets or to expand the
operating capacity or revenues of existing or new assets,
whether through construction or acquisition. Costs for repairs
and minor renewals to maintain facilities in operating condition
and that do not extend the useful life of existing assets will
be treated as operating expenses as we incur them. Our
partnership agreement provides that our general partner
determines how to allocate a capital expenditure for the
acquisition or expansion of our assets between maintenance
capital expenditures and expansion capital expenditures.
Capital
Surplus. Capital
surplus generally consists of:
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sales of our equity and debt securities;
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sales or other dispositions 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 retirement
or replacement of assets;
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capital contributions received; and
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corporate restructurings.
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Characterization of Cash
Distributions. Our partnership agreement
requires that we treat all available cash distributed as coming
from operating surplus until the sum of all available cash
distributed since the closing of this offering equals the
operating surplus as of the most recent date of determination of
available cash. Our partnership agreement requires that we treat
any amount distributed in excess of operating surplus,
regardless of its source, as capital surplus. As reflected
above, operating surplus includes an amount equal to four times
the amount needed for any one quarter for us to pay a
distribution on all of our units (including the general partner
units) and the incentive distribution rights at the same
per-unit amount as was distributed in the immediately preceding
quarter. This amount, which initially equals approximately
$39.0 million, does not reflect actual cash on hand that is
available for distribution to our unitholders.
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Rather, it is a provision that will enable us, if we choose, to
distribute as operating surplus up to this amount of cash we
receive in the future from non-operating sources, such as asset
sales, issuances of securities, and borrowings, that would
otherwise be distributed as capital surplus. We do not
anticipate that we will make any distributions from capital
surplus.
Subordination
Period
General. Our partnership agreement
provides that, during the subordination period (which we define
below and in Appendix B), the common units will have the
right to receive distributions of available cash from operating
surplus each quarter in an amount equal to $0.3375 per
common unit, which amount is defined in our partnership
agreement as the minimum quarterly distribution, plus any
arrearages in the payment of the minimum quarterly distribution
on the common units from prior quarters, before any
distributions of available cash from operating surplus may be
made on the subordinated units. These units are deemed
subordinated because for a period of time, referred
to as the subordination period, the subordinated units will not
be entitled to receive any distributions until the common units
have received the minimum quarterly distribution plus any
arrearages from prior quarters. Furthermore, no arrearages will
be paid on the subordinated units. The practical effect of the
subordinated units is to increase the likelihood that during the
subordination period there will be available cash to be
distributed on the common units.
Subordination Period. The subordination
period will extend until the first day of any quarter beginning
after December 31, 2009 that each of the following tests
are met:
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distributions of available cash from operating surplus on each
of the outstanding common units, subordinated units and general
partner units equaled or exceeded the minimum quarterly
distribution for each of the three consecutive, non-overlapping
four-quarter periods immediately preceding that date;
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the adjusted operating surplus (as defined below)
generated during each of the three consecutive, non-overlapping
four-quarter periods immediately preceding that date equaled or
exceeded the sum of the minimum quarterly distributions on all
of the outstanding common and subordinated units and general
partner units during those periods on a fully diluted basis
during those periods; and
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there are no arrearages in payment of the minimum quarterly
distribution on the common units.
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Expiration of the Subordination
Period. When the subordination period
expires, each outstanding subordinated unit will convert into
one common unit and will then participate pro rata with the
other common units in distributions of available cash. In
addition, if the unitholders remove our general partner other
than for cause and units held by the general partner and its
affiliates are not voted in favor of such removal:
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the subordination period will end and each subordinated unit
will immediately convert into one common unit;
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any existing arrearages in payment of the minimum quarterly
distribution on the common units will be extinguished; and
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the general partner will have the right to convert its general
partner units and its incentive distribution rights into common
units or to receive cash in exchange for those interests.
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Early Conversion of Subordinated
Units. The subordination period will
automatically terminate and all of the subordinated units will
convert into common units on a
one-for-one
basis if each of the following occurs:
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distributions of available cash from operating surplus on each
outstanding common unit and subordinated unit equaled or
exceeded $2.025 (150% of the annualized minimum quarterly
distribution) for any four-quarter period immediately preceding
that date;
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the adjusted operating surplus (as defined below)
generated during any four-quarter period immediately preceding
that date equaled or exceeded the sum of a distribution of
$2.025 (150% of the annualized minimum quarterly distribution)
on all of the outstanding common units and subordinated units
and general partner units on a fully diluted basis; and
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there are no arrearages in payment of the minimum quarterly
distribution on the common units.
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Adjusted Operating Surplus. Adjusted
operating surplus is intended to reflect the cash generated from
operations during a particular period and therefore excludes net
drawdowns of reserves of cash generated in prior periods.
Adjusted operating surplus consists of:
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operating surplus generated with respect to that period
(excluding any amounts attributable to the items described in
the first bullet point under Operating Surplus
and Capital Surplus Operating Surplus above);
plus
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any net decrease made in subsequent periods in cash reserves for
operating expenditures initially established with respect to
that period to the extent such decrease results in a reduction
in adjusted operating surplus in subsequent periods pursuant to
the following bullet point; less
|
|
|
|
any net decrease in cash reserves for operating expenditures
with respect to that period not relating to an operating
expenditure made with respect to that period; plus
|
|
|
|
any net increase in cash reserves for operating expenditures
with respect to that period required by any debt instrument for
the repayment of principal, interest or premium.
|
Distributions
of Available Cash from Operating Surplus during the
Subordination Period
Our partnership agreement requires that we make distributions of
available cash from operating surplus for any quarter during the
subordination period in the following manner:
|
|
|
|
|
first, 98% to the common unitholders, pro rata, and 2% to
the general partner, until we distribute for each outstanding
common unit an amount equal to the minimum quarterly
distribution for that quarter;
|
|
|
|
second, 98% to the common unitholders, pro rata, and 2%
to the general partner, until we distribute for each outstanding
common unit an amount equal to any arrearages in payment of the
minimum quarterly distribution on the common units for any prior
quarters during the subordination period;
|
|
|
|
third, 98% to the subordinated unitholders, pro rata, and
2% to the general partner, until we distribute for each
subordinated unit an amount equal to the minimum quarterly
distribution for that quarter; and
|
|
|
|
thereafter, in the manner described in
General Partner Interest and Incentive
Distribution Rights below.
|
The preceding discussion is based on the assumptions that our
general partner maintains its 2% general partner interest and
that we do not issue additional classes of equity securities.
Distributions
of Available Cash from Operating Surplus after the Subordination
Period
Our partnership agreement requires that we make distributions of
available cash from operating surplus for any quarter after the
subordination period in the following manner:
|
|
|
|
|
first, 98% to all unitholders, pro rata, and 2% to the
general partner, until we distribute for each outstanding unit
an amount equal to the minimum quarterly distribution for that
quarter; and
|
|
|
|
thereafter, in the manner described in
General Partner Interest and Incentive
Distribution Rights below.
|
The preceding discussion is based on the assumptions that our
general partner maintains its 2% general partner interest and
that we do not issue additional classes of equity securities.
57
General
Partner Interest and Incentive Distribution Rights
Our partnership agreement provides that our general partner
initially will be entitled to 2% of all distributions that we
make prior to our liquidation. Our general partner has the
right, but not the obligation, to contribute a proportionate
amount of capital to us to maintain its 2% general partner
interest if we issue additional units. Our general
partners 2% interest, and the percentage of our cash
distributions to which it is entitled, will be proportionately
reduced if we issue additional units in the future and our
general partner does not contribute a proportionate amount of
capital to us in order to maintain its 2% general partner
interest. Our general partner will be entitled to make a capital
contribution in order to maintain its 2% general partner
interest in the form of the contribution to us of common units
that it may hold based on the current market value of the
contributed common units.
Incentive distribution rights represent the right to receive an
increasing percentage (13%, 23% and 48%) of quarterly
distributions of available cash from operating surplus after the
minimum quarterly distribution and the target distribution
levels have been achieved. Our general partner currently holds
the incentive distribution rights, but may transfer these rights
separately from its general partner interest, subject to
restrictions in the partnership agreement.
The following discussion assumes that the general partner
maintains its 2% general partner interest and continues to own
the incentive distribution rights.
If for any quarter:
|
|
|
|
|
we have distributed available cash from operating surplus to the
common and subordinated unitholders in an amount equal to the
minimum quarterly distribution; and
|
|
|
|
we have distributed available cash from operating surplus on
outstanding common units in an amount necessary to eliminate any
cumulative arrearages in payment of the minimum quarterly
distribution;
|
then, our partnership agreement requires that we distribute any
additional available cash from operating surplus for that
quarter among the unitholders and the general partner in the
following manner:
|
|
|
|
|
first, 98% to all unitholders, pro rata, and 2% to the
general partner, until each unitholder receives a total of
$0.3881 per unit for that quarter (the first target
distribution);
|
|
|
|
second, 85% to all unitholders, pro rata, and 15% to the
general partner, until each unitholder receives a total of
$0.4219 per unit for that quarter (the second target
distribution);
|
|
|
|
|
|
third, 75% to all unitholders, pro rata, and 25% to the
general partner, until each unitholder receives a total of
$0.50625 per unit for that quarter (the third target
distribution); and
|
|
|
|
|
|
thereafter, 50% to all unitholders, pro rata, and 50% to
the general partner.
|
Percentage
Allocations of Available Cash from Operating Surplus
The following table illustrates the percentage allocations of
available cash from operating surplus between the unitholders
and our general partner based on the specified target
distribution levels. The amounts set forth under Marginal
Percentage Interest in Distributions are the percentage
interests of our general partner and the unitholders in any
available cash from operating surplus we distribute up to and
including the corresponding amount in the column Total
Quarterly Distribution Per Unit, until available cash from
operating surplus we distribute reaches the next target
distribution level, if any. The percentage interests shown for
the unitholders and the general partner for the minimum
quarterly distribution are also applicable to quarterly
distribution amounts that are less than the minimum quarterly
distribution. The percentage interests set forth below for our
general partner include its 2% general partner interest and
58
assume our general partner has contributed any additional
capital to maintain its 2% general partner interest and has not
transferred its incentive distribution rights.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Quarterly
|
|
|
Marginal Percentage
|
|
|
|
Distribution
|
|
|
Interest in
|
|
|
|
per Unit
|
|
|
Distributions
|
|
|
|
|
|
|
|
|
|
General
|
|
|
|
Target Amount
|
|
|
Unitholders
|
|
|
Partner
|
|
|
Minimum Quarterly Distribution
|
|
|
$0.3375
|
|
|
|
98
|
%
|
|
|
2
|
%
|
First Target Distribution
|
|
|
up to $0.3881
|
|
|
|
98
|
%
|
|
|
2
|
%
|
Second Target Distribution
|
|
|
above $0.3881 up to $0.4219
|
|
|
|
85
|
%
|
|
|
15
|
%
|
Third Target Distribution
|
|
|
above $0.4219 up to $0.50625
|
|
|
|
75
|
%
|
|
|
25
|
%
|
Thereafter
|
|
|
above $0.50625
|
|
|
|
50
|
%
|
|
|
50
|
%
|
General
Partners Right to Reset Incentive Distribution
Levels
Our general partner, as the holder of our incentive distribution
rights, has the right under our partnership agreement to elect
to relinquish the right to receive incentive distribution
payments based on the initial cash target distribution levels
and to reset, at higher levels, the minimum quarterly
distribution amount and cash target distribution levels upon
which the incentive distribution payments to our general partner
would be set. Our general partners right to reset the
minimum quarterly distribution amount and the target
distribution levels upon which the incentive distributions
payable to our general partner are based may be exercised,
without approval of our unitholders or the conflicts committee
of our general partner, at any time when there are no
subordinated units outstanding and we have made cash
distributions to the holders of the incentive distribution
rights at the highest level of incentive distribution for each
of the prior four consecutive fiscal quarters. The reset minimum
quarterly distribution amount and target distribution levels
will be higher than the minimum quarterly distribution amount
and the target distribution levels prior to the reset such that
our general partner will not receive any incentive distributions
under the reset target distribution levels until cash
distributions per unit following this event increase as
described below. We anticipate that our general partner would
exercise this reset right in order to facilitate acquisitions or
internal growth projects that would otherwise not be
sufficiently accretive to cash distributions per common unit,
taking into account the existing levels of incentive
distribution payments being made to our general partner.
In connection with the resetting of the minimum quarterly
distribution amount and the target distribution levels and the
corresponding relinquishment by our general partner of incentive
distribution payments based on the target cash distributions
prior to the reset, our general partner will be entitled to
receive a number of newly issued Class B units based on a
predetermined formula described below that takes into account
the cash parity value of the average cash
distributions related to the incentive distribution rights
received by our general partner for the two quarters prior to
the reset event as compared to the average cash distributions
per common unit during this period.
The number of Class B units that our general partner would
be entitled to receive from us in connection with a resetting of
the minimum quarterly distribution amount and the target
distribution levels then in effect would be equal to
(x) the average amount of cash distributions received by
our general partner in respect of its incentive distribution
rights during the two consecutive fiscal quarters ended
immediately prior to the date of such reset election divided by
(y) the average of the amount of cash distributed per
common unit during each of these two quarters. Each Class B
unit will be convertible into one common unit at the election of
the holder of the Class B unit at any time following the
first anniversary of the issuance of these Class B units.
Following a reset election by our general partner, the minimum
quarterly distribution amount will be reset to an amount equal
to the average cash distribution amount per common unit for the
two fiscal quarters immediately preceding the reset
election (such amount is referred to as the reset
minimum
59
quarterly distribution) and the target distribution levels
will be reset to be correspondingly higher such that we would
distribute all of our available cash from operating surplus for
each quarter thereafter as follows:
|
|
|
|
|
first, 98% to all unitholders, pro rata, and 2% to the
general partner, until each unitholder receives an amount equal
to 115% of the reset minimum quarter distribution for that
quarter;
|
|
|
|
second, 85% to all unitholders, pro rata, and 15% to the
general partner, until each unitholder receives an amount per
unit equal to 125% of the reset minimum quarterly distribution
for that quarter;
|
|
|
|
third, 75% to all unitholders, pro rata, and 25% to the
general partner, until each unitholder receives an amount per
unit equal to 150% of the reset minimum quarterly distribution
for that quarter; and
|
|
|
|
thereafter, 50% to all unitholders, pro rata, and 50% to
the general partner.
|
The following table illustrates the percentage allocation of
available cash from operating surplus between the unitholders
and our general partner at various levels of cash distribution
levels pursuant to the cash distribution provision of our
partnership agreement in effect at the closing of this offering
as well as following a hypothetical reset of the minimum
quarterly distribution and target distribution levels based on
the assumption that the average quarterly cash distribution
amount per common unit during the two fiscal quarters
immediately preceding the reset election was $0.60.
|
|
|
|
|
|
|
|
|
|
|
|
|
Marginal Percentage
|
|
|
|
|
|
|
Interest in Distributions
|
|
|
|
|
Quarterly Distribution
|
|
|
|
General
|
|
Quarterly Distribution per Unit
|
|
|
per Unit Prior to Reset
|
|
Unitholders
|
|
Partner
|
|
Following Hypothetical Reset
|
|
Minimum Quarterly Distribution
|
|
$0.3375
|
|
98%
|
|
2%
|
|
$0.6000
|
First Target Distribution
|
|
up to $0.3881
|
|
98%
|
|
2%
|
|
up to $0.6900(1)
|
Second Target Distribution
|
|
above $0.3881 up to $0.4219
|
|
85%
|
|
15%
|
|
above $0.6900(1) up to $0.7500(2)
|
Third Target Distribution
|
|
above $0.4219 up to $0.50625
|
|
75%
|
|
25%
|
|
above $0.7500(2) up to $0.9000(3)
|
Thereafter
|
|
above $0.50625
|
|
50%
|
|
50%
|
|
above $0.9000(3)
|
|
|
|
(1) |
|
This amount is 115% of the hypothetical reset minimum quarterly
distribution. |
|
(2) |
|
This amount is 125% of the hypothetical reset minimum quarterly
distribution. |
|
(3) |
|
This amount is 150% of the hypothetical reset minimum quarterly
distribution. |
The following table illustrates the total amount of available
cash from operating surplus that would be distributed to the
unitholders and the general partner, including in respect of
incentive distribution rights, based on an average of the
amounts distributed per quarter for the two quarters immediately
prior to the reset. The table assumes that there are 30,848,231
common units and 629,555 general partner units outstanding and
that the average distribution to each common unit is
$0.60 for the two quarters prior to the reset. The assumed
number of outstanding units assumes the underwriters exercise in
full their option to purchase additional common units, the
conversion of all subordinated units into common units and no
additional unit issuances.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarterly
|
|
Common
|
|
|
General Partner Cash Distributions Prior to Reset
|
|
|
|
|
|
|
Distribution
|
|
Unitholders Cash
|
|
|
|
|
|
2% General
|
|
|
Incentive
|
|
|
|
|
|
|
|
|
|
per Unit
|
|
Distributions
|
|
|
Class B
|
|
|
Partner
|
|
|
Distribution
|
|
|
|
|
|
Total
|
|
|
|
Prior to Reset
|
|
Prior to Reset
|
|
|
Units
|
|
|
Interest
|
|
|
Rights
|
|
|
Total
|
|
|
Distributions
|
|
|
Minimum Quarterly Distribution
|
|
$0.3375
|
|
$
|
10,411,278
|
|
|
$
|
|
|
|
$
|
212,475
|
|
|
$
|
|
|
|
$
|
212,475
|
|
|
$
|
10,623,753
|
|
First Target Distribution
|
|
up to $0.3881
|
|
|
1,560,920
|
|
|
|
|
|
|
|
31,856
|
|
|
|
|
|
|
|
31,856
|
|
|
|
1,592,776
|
|
Second Target Distribution
|
|
above $0.3881 up to $0.4219
|
|
|
1,042,670
|
|
|
|
|
|
|
|
24,533
|
|
|
|
159,467
|
|
|
|
184,001
|
|
|
|
1,226,671
|
|
Third Target Distribution
|
|
above $0.4219 up to $0.50625
|
|
|
2,603,591
|
|
|
|
|
|
|
|
69,429
|
|
|
|
798,434
|
|
|
|
867,864
|
|
|
|
3,471,454
|
|
Thereafter
|
|
above $0.50625
|
|
|
2,890,479
|
|
|
|
|
|
|
|
115,619
|
|
|
|
2,774,860
|
|
|
|
2,890,479
|
|
|
|
5,780,958
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
18,508,939
|
|
|
$
|
|
|
|
$
|
453,912
|
|
|
$
|
3,732,762
|
|
|
$
|
4,186,674
|
|
|
$
|
22,695,613
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
60
The following table illustrates the total amount of available
cash from operating surplus that would be distributed to the
unitholders and the general partner with respect to the quarter
in which the reset occurs. The table reflects that as a result
of the reset there are 30,848,231 common units, 6,221,270
Class B units and 756,520 general partner units
outstanding, and that the average distribution to each common
unit is $0.60. The number of Class B units was calculated
by dividing (x) the $3,732,762 received by the general
partner in respect of its incentive distribution rights per
quarter for the two quarters prior to the reset as shown in the
table above by (y) the $0.60 of available cash from
operating surplus distributed to each common unit per quarter
for the two quarters prior to the reset.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarterly
|
|
Common
|
|
|
General Partner Cash Distributions After Reset
|
|
|
|
|
|
|
Distribution
|
|
Unitholders Cash
|
|
|
|
|
|
2% General
|
|
|
Incentive
|
|
|
|
|
|
|
|
|
|
per Unit
|
|
Distributions
|
|
|
Class B
|
|
|
Partner
|
|
|
Distribution
|
|
|
|
|
|
Total
|
|
|
|
After Reset
|
|
After Reset
|
|
|
Units
|
|
|
Interest
|
|
|
Rights
|
|
|
Total
|
|
|
Distributions
|
|
|
Minimum Quarterly Distribution
|
|
$0.6000
|
|
$
|
18,508,939
|
|
|
$
|
3,732,762
|
|
|
$
|
453,912
|
|
|
$
|
|
|
|
$
|
4,186,674
|
|
|
$
|
22,695,613
|
|
First Target Distribution(1)
|
|
up to 0.6900
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Target Distribution(2)
|
|
above $0.6900 up to $0.7500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Third Target Distribution(3)
|
|
above $0.7500 up to $0.9000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Thereafter
|
|
above $0.9000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
18,508,939
|
|
|
$
|
3,732,762
|
|
|
$
|
453,912
|
|
|
$
|
|
|
|
$
|
4,186,674
|
|
|
$
|
22,695,613
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
This amount is 115% of the hypothetical reset minimum quarterly
distribution. |
|
(2) |
|
This amount is 125% of the hypothetical reset minimum quarterly
distribution. |
|
(3) |
|
This amount is 150% of the hypothetical reset minimum quarterly
distribution. |
Our general partner will be entitled to cause the minimum
quarterly distribution amount and the target distribution levels
to be reset on more than one occasion, provided that it may not
make a reset election except at a time when it has received
incentive distributions for the prior four consecutive fiscal
quarters based on the highest level of incentive distributions
that it is entitled to receive under our partnership agreement.
Distributions
from Capital Surplus
How Distributions from Capital Surplus Will Be
Made. Our partnership agreement requires that
we 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 that
was issued in this offering, an amount of available cash from
capital surplus equal to the initial public offering price;
|
|
|
|
second, 98% to the common 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
any unpaid arrearages in payment of the minimum quarterly
distribution on the common units; and
|
|
|
|
thereafter, we will make all distributions of available
cash from capital surplus as if they were from operating surplus.
|
Effect of a Distribution from Capital
Surplus. Our partnership agreement treats a
distribution of capital surplus as the repayment of the initial
unit price from this initial public offering, which is a return
of capital. The initial public offering price less any
distributions of capital surplus per unit is referred to as the
unrecovered initial unit price. Each time a
distribution of capital surplus is made, the minimum quarterly
distribution and the target distribution levels will be reduced
in the same proportion as the corresponding
61
reduction in the unrecovered initial unit price. Because
distributions of capital surplus will reduce the minimum
quarterly distribution, after any of these distributions are
made, it may be easier for the general partner to receive
incentive distributions and for the subordinated units to
convert into common units. However, any distribution of capital
surplus before the unrecovered initial unit price is reduced to
zero cannot be applied to the payment of the minimum quarterly
distribution or any arrearages.
Once we distribute capital surplus on a unit issued in this
offering in an amount equal to the initial unit price, our
partnership agreement specifies that the minimum quarterly
distribution and the target distribution levels will be reduced
to zero. Our partnership agreement specifies that we then make
all future distributions from operating surplus, with 50% being
paid to the holders of units and 50% to the general partner. The
percentage interests shown for our general partner include its
2% general partner interest and assume the general partner has
not transferred the incentive distribution rights.
Adjustment
to the Minimum Quarterly Distribution and Target Distribution
Levels
In addition to adjusting the minimum quarterly distribution and
target distribution levels to reflect a distribution of capital
surplus, if we combine our units into fewer units or subdivide
our units into a greater number of units, our partnership
agreement specifies that the following items will be
proportionately adjusted:
|
|
|
|
|
the minimum quarterly distribution;
|
|
|
|
target distribution levels;
|
|
|
|
the unrecovered initial unit price; and
|
|
|
|
the number of common units into which a subordinated unit is
convertible.
|
For example, if a
two-for-one
split of the common units should occur, the minimum quarterly
distribution, the target distribution levels and the unrecovered
initial unit price would each be reduced to 50% of its initial
level, and each subordinated unit would be convertible into two
common units. Our partnership agreement provides that we not
make any adjustment by reason of the issuance of additional
units for cash or property.
In addition, if legislation is enacted or if existing law is
modified or interpreted by a governmental taxing authority, so
that we become taxable as a corporation or otherwise subject to
taxation as an entity for federal, state or local income tax
purposes, our partnership agreement specifies that general
partner may reduce the minimum quarterly distribution and the
target distribution levels for each quarter by multiplying each
distribution level by a fraction, the numerator of which is
available cash for that quarter and the denominator of which is
the sum of available cash for that quarter plus the general
partners estimate of our aggregate liability for the
quarter for such income taxes payable by reason of such
legislation or interpretation. To the extent that the actual tax
liability differs from the estimated tax liability for any
quarter, the difference will be accounted for in subsequent
quarters.
Distributions
of Cash Upon Liquidation
General. If we dissolve in accordance
with the 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.
The allocations of gain and loss upon liquidation are intended,
to the extent possible, to entitle the holders of outstanding
common units to a preference over the holders of outstanding
subordinated units upon our liquidation, to the extent required
to permit common unitholders to receive their unrecovered
initial unit price plus the minimum quarterly distribution for
the quarter during which liquidation occurs plus any unpaid
arrearages in payment of the minimum quarterly distribution on
the common units. However, there may not be sufficient gain upon
our liquidation to enable the holders of common units to
62
fully recover all of these amounts, even though there may be
cash available for distribution to the holders of subordinated
units. 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 the
partnership agreement. If our liquidation occurs before the end
of the subordination period, we will allocate any gain to the
partners 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: (1) the unrecovered
initial unit price; (2) the amount of the minimum quarterly
distribution for the quarter during which our liquidation
occurs; and (3) any unpaid arrearages in payment of the
minimum quarterly distribution;
|
|
|
|
third, 98% to the subordinated unitholders, pro rata, and
2% to the general partner until the capital account for each
subordinated unit is equal to the sum of: (1) the
unrecovered initial unit price; and (2) the amount of the
minimum quarterly distribution for the quarter during which our
liquidation occurs;
|
|
|
|
fourth, 98% to all unitholders, pro rata, and 2% to the
general partner, until we allocate under this paragraph an
amount per unit equal to: (1) 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
(2) 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;
|
|
|
|
fifth, 85% to all unitholders, pro rata, and 15% to the
general partner, until we allocate under this paragraph an
amount per unit equal to: (1) 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
(2) 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, and 15% to the general partner for each
quarter of our existence;
|
|
|
|
sixth, 75% to all unitholders, pro rata, and 25% to the
general partner, until we allocate under this paragraph an
amount per unit equal to: (1) 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
(2) 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, and 25% to the general partner for each
quarter of our existence; and
|
|
|
|
thereafter, 50% to all unitholders, pro rata, and 50% to
the general partner.
|
The percentage interests set forth above for our general partner
include its 2% general partner interest and assume the general
partner has not transferred the incentive distribution rights.
If the liquidation occurs after the end of the subordination
period, the distinction between common units and subordinated
units will disappear, so that clause (3) of the second
bullet point above and all of the third bullet point above will
no longer be applicable.
Manner of Adjustments for Losses. If
our liquidation occurs before the end of the subordination
period, we will generally allocate any loss to the general
partner and the unitholders in the following manner:
|
|
|
|
|
first, 98% to holders of subordinated units in proportion
to the positive balances in their capital accounts and 2% to the
general partner, until the capital accounts of the subordinated
unitholders have been reduced to zero;
|
63
|
|
|
|
|
second, 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
|
|
|
|
thereafter, 100% to the general partner.
|
If the liquidation occurs after the end of the subordination
period, the distinction between common units and subordinated
units will disappear, so that all of the first bullet point
above will no longer be applicable.
Adjustments to Capital Accounts. Our
partnership agreement requires that we make adjustments to
capital accounts upon the issuance of additional units. In this
regard, our partnership agreement specifies that we 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,
our partnership agreement requires that we 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.
64
SELECTED
HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA
The following table shows selected historical financial and
operating data of the North Texas System and pro forma financial
data of Targa Resources Partners LP for the periods and as of
the dates indicated. The historical financial statements
included in this prospectus reflect the results of operations of
the North Texas System to be contributed to us by Targa upon the
closing of this offering. We refer to the results of operations
of the North Texas System as the results of operations of the
Predecessor Business. The selected historical financial data for
the years ended December 31, 2001 and 2002 are derived from
the books and records of the Predecessor Business. The selected
historical financial data for the years ended December 31,
2003 and 2004, the ten-month period ended October 31, 2005
and the two-month period ended December 31, 2005 are
derived from the audited financial statements of the Predecessor
Business. The selected historical financial data for the nine
months ended September 30, 2005 and 2006 are derived from
the unaudited financial statements of the Predecessor Business.
The Predecessor Business was acquired by Targa as part of the
DMS Acquisition. The selected pro forma financial data for the
year ended December 31, 2005 and the nine months ended
September 30, 2006 are derived from the unaudited pro forma
financial statements of Targa Resources Partners LP included in
this prospectus. The pro forma adjustments have been prepared as
if certain transactions to be effected at the closing of this
offering had taken place on September 30, 2006, in the case
of the pro forma balance sheet, or as of January 1, 2005,
in the case of the pro forma statement of operations for the
nine months ended September 30, 2006 and for the year ended
December 31, 2005. The transactions reflected in the pro
forma adjustments assume the following actions will occur:
|
|
|
|
|
Targa will contribute the North Texas System to us;
|
|
|
|
we will issue to Targa 11,528,231 subordinated units,
representing a 39.9% limited partner interest in us;
|
|
|
|
we will issue to our general partner, Targa Resources GP
LLC, 578,127 general partner units representing its initial 2%
general partner interest in us, and all of our incentive
distribution rights, which incentive distribution rights will
entitle our general partner to increasing percentages of the
cash we distribute in excess of $0.3881 per unit per quarter;
|
|
|
|
|
|
we will issue 16,800,000 common units to the public in this
offering, representing a 58.1% limited partner interest in us,
and will use the proceeds to pay expenses associated with this
offering, the Formation Transactions and our new credit facility
and to pay approximately $307.1 million to Targa to retire
a portion of our affiliate indebtedness;
|
|
|
|
|
|
we will borrow approximately $342.5 million under our new
$500 million credit facility the proceeds of which will be
paid to Targa to retire an additional portion of our affiliate
indebtedness; and
|
|
|
|
the remaining affiliate indebtedness will be retired and treated
as a capital contribution to us.
|
We derived the information in the following table from, and that
information should be read together with and is qualified in its
entirety by reference to, the historical combined and pro forma
condensed financial statements and the accompanying notes
included elsewhere in this prospectus.
65
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor Business
|
|
|
Targa Resources Partners LP
|
|
|
|
Dynegy
|
|
|
|
Targa
|
|
|
Pro Forma
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
|
|
|
Ten
|
|
|
|
Two
|
|
|
Nine
|
|
|
|
|
|
Nine
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Months
|
|
|
Months
|
|
|
|
Months
|
|
|
Months
|
|
|
Year
|
|
|
Months
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
Years Ended December 31,
|
|
|
September 30,
|
|
|
October 31,
|
|
|
|
December 31,
|
|
|
September 30,
|
|
|
December 31,
|
|
|
September 30,
|
|
|
|
2001
|
|
|
2002
|
|
|
2003
|
|
|
2004
|
|
|
2005
|
|
|
2005
|
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
(Audited)
|
|
|
(Audited)
|
|
|
(Unaudited)
|
|
|
(Audited)
|
|
|
|
(Audited)
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
|
(in millions of dollars, except per unit, operating and price
data)
|
|
Statement of Operations
Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
122.9
|
|
|
$
|
112.5
|
|
|
$
|
196.8
|
|
|
$
|
258.6
|
|
|
$
|
249.7
|
|
|
$
|
293.3
|
|
|
|
$
|
75.1
|
|
|
$
|
290.9
|
|
|
$
|
368.4
|
|
|
$
|
290.9
|
|
Product purchases
|
|
|
94.0
|
|
|
|
82.7
|
|
|
|
147.3
|
|
|
|
182.6
|
|
|
|
179.0
|
|
|
|
210.8
|
|
|
|
|
54.9
|
|
|
|
205.2
|
|
|
|
265.7
|
|
|
|
205.2
|
|
Operating expense
|
|
|
15.8
|
|
|
|
14.9
|
|
|
|
15.1
|
|
|
|
17.7
|
|
|
|
15.8
|
|
|
|
18.0
|
|
|
|
|
3.5
|
|
|
|
17.9
|
|
|
|
21.5
|
|
|
|
17.9
|
|
Depreciation and amortization
expense
|
|
|
9.7
|
|
|
|
11.8
|
|
|
|
12.0
|
|
|
|
12.2
|
|
|
|
10.1
|
|
|
|
11.3
|
|
|
|
|
9.2
|
|
|
|
41.7
|
|
|
|
54.8
|
|
|
|
41.7
|
|
General and administrative expense
|
|
|
7.2
|
|
|
|
7.7
|
|
|
|
7.7
|
|
|
|
7.2
|
|
|
|
6.7
|
|
|
|
7.3
|
|
|
|
|
1.1
|
|
|
|
5.1
|
|
|
|
8.4
|
|
|
|
5.1
|
|
Interest expense, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11.5
|
|
|
|
54.4
|
|
|
|
24.8
|
|
|
|
18.6
|
|
Deferred income taxes(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.0
|
|
|
|
|
|
|
|
2.0
|
|
Other, net
|
|
|
|
|
|
|
(0.3
|
)
|
|
|
0.6
|
|
|
|
0.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(3.8
|
)
|
|
$
|
(4.3
|
)
|
|
$
|
14.1
|
|
|
$
|
38.6
|
|
|
$
|
38.1
|
|
|
$
|
45.9
|
|
|
|
$
|
(5.1
|
)
|
|
$
|
(35.4
|
)
|
|
$
|
(6.8
|
)
|
|
$
|
0.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma net income (loss) per
limited partner unit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(0.24
|
)
|
|
$
|
0.01
|
|
Financial and Operating
Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating margin(2)
|
|
$
|
13.1
|
|
|
$
|
14.9
|
|
|
$
|
34.4
|
|
|
$
|
58.3
|
|
|
$
|
54.9
|
|
|
$
|
64.5
|
|
|
|
$
|
16.7
|
|
|
$
|
67.8
|
|
|
$
|
81.2
|
|
|
$
|
67.8
|
|
EBITDA(2)
|
|
|
5.9
|
|
|
|
7.5
|
|
|
|
26.1
|
|
|
|
50.8
|
|
|
|
48.2
|
|
|
|
57.2
|
|
|
|
|
15.6
|
|
|
|
62.7
|
|
|
|
72.8
|
|
|
|
62.7
|
|
Operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering throughput, MMcf/d(3)
|
|
|
95.9
|
|
|
|
106.6
|
|
|
|
134.3
|
|
|
|
152.0
|
|
|
|
160.4
|
|
|
|
161.2
|
|
|
|
|
168.8
|
|
|
|
168.2
|
|
|
|
|
|
|
|
|
|
Plant natural gas inlet, MMcf/d(4)
|
|
|
85.6
|
|
|
|
104.0
|
|
|
|
128.6
|
|
|
|
145.4
|
|
|
|
155.4
|
|
|
|
156.2
|
|
|
|
|
161.9
|
|
|
|
161.6
|
|
|
|
|
|
|
|
|
|
Gross NGL production, MBbl/d
|
|
|
11.3
|
|
|
|
12.5
|
|
|
|
15.9
|
|
|
|
17.2
|
|
|
|
18.4
|
|
|
|
18.5
|
|
|
|
|
19.8
|
|
|
|
18.8
|
|
|
|
|
|
|
|
|
|
Natural gas sales, BBtu/d
|
|
|
31.5
|
|
|
|
38.2
|
|
|
|
42.0
|
|
|
|
59.2
|
|
|
|
68.4
|
|
|
|
68.9
|
|
|
|
|
72.3
|
|
|
|
75.2
|
|
|
|
|
|
|
|
|
|
NGL sales, MBbl/d
|
|
|
11.3
|
|
|
|
12.3
|
|
|
|
15.3
|
|
|
|
13.2
|
|
|
|
14.2
|
|
|
|
14.3
|
|
|
|
|
15.4
|
|
|
|
15.1
|
|
|
|
|
|
|
|
|
|
Condensate sales, MBbl/d
|
|
|
0.6
|
|
|
|
0.6
|
|
|
|
0.6
|
|
|
|
0.7
|
|
|
|
0.5
|
|
|
|
0.5
|
|
|
|
|
0.5
|
|
|
|
0.5
|
|
|
|
|
|
|
|
|
|
Average Realized
Prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, $/MMBtu
|
|
|
4.00
|
|
|
|
2.84
|
|
|
|
4.97
|
|
|
|
5.43
|
|
|
|
6.39
|
|
|
|
6.79
|
|
|
|
|
8.61
|
|
|
|
6.09
|
|
|
|
|
|
|
|
|
|
NGL, $/gal
|
|
|
0.41
|
|
|
|
0.35
|
|
|
|
0.47
|
|
|
|
0.64
|
|
|
|
0.75
|
|
|
|
0.78
|
|
|
|
|
0.90
|
|
|
|
0.90
|
|
|
|
|
|
|
|
|
|
Condensate, $/Bbl
|
|
|
21.34
|
|
|
|
23.24
|
|
|
|
29.86
|
|
|
|
40.56
|
|
|
|
52.61
|
|
|
|
53.42
|
|
|
|
|
57.54
|
|
|
|
62.66
|
|
|
|
|
|
|
|
|
|
Balance Sheet Data (at period
end):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
$
|
159.0
|
|
|
$
|
178.2
|
|
|
$
|
180.4
|
|
|
$
|
191.2
|
|
|
|
195.4
|
|
|
$
|
196.4
|
|
|
|
$
|
1,097.0
|
|
|
$
|
1,073.0
|
|
|
|
|
|
|
$
|
1,073.0
|
|
Total assets
|
|
|
160.1
|
|
|
|
179.7
|
|
|
|
182.9
|
|
|
|
193.5
|
|
|
|
197.6
|
|
|
|
198.5
|
|
|
|
|
1,122.8
|
|
|
|
1,126.3
|
|
|
|
|
|
|
|
1,110.9
|
|
Long-term debt (including current
portion)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
868.9
|
|
|
|
865.2
|
|
|
|
|
|
|
|
342.5
|
|
Partners capital / Net parent
equity
|
|
|
151.2
|
|
|
|
167.3
|
|
|
|
164.8
|
|
|
|
168.8
|
|
|
|
161.9
|
|
|
|
158.5
|
|
|
|
|
219.5
|
|
|
|
227.2
|
|
|
|
|
|
|
|
734.5
|
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
2.6
|
|
|
$
|
10.2
|
|
|
$
|
31.3
|
|
|
$
|
58.0
|
|
|
$
|
59.2
|
|
|
$
|
72.7
|
|
|
|
$
|
(1.5
|
)
|
|
$
|
11.1
|
|
|
|
|
|
|
|
|
|
Investing activities
|
|
|
(41.2
|
)
|
|
|
(30.6
|
)
|
|
|
(14.6
|
)
|
|
|
(23.4
|
)
|
|
|
(14.2
|
)
|
|
|
(16.4
|
)
|
|
|
|
(2.1
|
)
|
|
|
(17.7
|
)
|
|
|
|
|
|
|
|
|
Financing activities
|
|
|
38.6
|
|
|
|
20.4
|
|
|
|
(16.7
|
)
|
|
|
(34.6
|
)
|
|
|
(45.0
|
)
|
|
|
(56.3
|
)
|
|
|
|
3.6
|
|
|
|
6.6
|
|
|
|
|
|
|
|
|
|
_
_
|
|
(1) |
In May 2006, Texas adopted a margin tax consisting of a 1% tax
on the amount by which total revenue exceeds cost of goods. The
amount presented represents our estimated liability for this tax.
|
66
|
|
(2) |
EBITDA. We define EBITDA as net income before
interest, income taxes, depreciation and amortization. EBITDA is
used as a supplemental financial measure by our management and
by external users of our financial statements such as investors,
commercial banks and others, to assess:
|
|
|
|
|
|
the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis;
|
|
|
|
our operating performance and return on capital as compared to
other companies in the midstream energy sector, without regard
to financing or capital structure; and
|
|
|
|
the viability of acquisitions and capital expenditure projects
and the overall rates of return on alternative investment
opportunities.
|
The economic substance behind managements use of EBITDA is
to measure the ability of our assets to generate cash sufficient
to pay interest costs, support our indebtedness, and make
distributions to our investors.
The GAAP measures most directly comparable to EBITDA are net
cash provided by operating activities and net income. Our
non-GAAP financial measure of EBITDA should not be considered as
an alternative to GAAP net cash provided by operating activities
and GAAP net income. EBITDA is not a presentation made in
accordance with GAAP and has important limitations as an
analytical tool. You should not consider EBITDA in isolation or
as a substitute for analysis of our results as reported under
GAAP. Because EBITDA excludes some, but not all, items that
affect net income and net cash provided by operating activities
and is defined differently by different companies in our
industry, our definition of EBITDA may not be comparable to
similarly titled measures of other companies.
Management compensates for the limitations of EBITDA as an
analytical tool by reviewing the comparable GAAP measures,
understanding the differences between the measures and
incorporating these learnings into managements
decision-making processes.
Operating Margin. We define operating margin
as total operating revenues, which consist of natural gas and
NGL sales plus service fee revenues, less product purchases,
which consist primarily of producer payments and other natural
gas purchases, and operating expense. Management reviews
operating margin monthly for consistency and trend analysis.
Based on this monthly analysis, management takes appropriate
action to maintain positive trends or to reverse negative
trends. Management uses operating margin as an important
performance measure of the core profitability of our operations.
The GAAP measure most directly comparable to operating margin is
net income. Our non-GAAP financial measure of operating margin
should not be considered as an alternative to GAAP net income.
Operating margin is not a presentation made in accordance with
GAAP and has important limitations as an analytical tool. You
should not consider operating margin in isolation or as a
substitute for analysis of our results as reported under GAAP.
Because operating margin excludes some, but not all, items that
affect net income and is defined differently by different
companies in our industry, our definition of operating margin
may not be comparable to similarly titled measures of other
companies, thereby diminishing its utility.
Management compensates for the limitations of operating margin
as an analytical tool by reviewing the comparable GAAP measures,
understanding the differences between the measures and
incorporating these learnings into managements
decision-making processes.
We believe that investors benefit from having access to the same
financial measures that our management uses in evaluating our
operating results. Operating margin provides useful information
to investors because it is used as a supplemental financial
measure by our management and by external users of our financial
statements, including such investors, commercial banks and
others, to assess:
|
|
|
|
|
the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis;
|
|
|
|
our operating performance and return on capital as compared to
other companies in the midstream energy sector, without regard
to financing or capital structure;
|
|
|
|
the viability of acquisitions and capital expenditure projects
and the overall rates of return on alternative investment
opportunities.
|
67
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor Business
|
|
|
Targa Resources Partners LP
|
|
|
|
Dynegy
|
|
|
|
Targa
|
|
|
Pro Forma
|
|
|
|
|
|
|
|
|
|
Nine Months
|
|
|
Ten Months
|
|
|
|
Two Months
|
|
|
Nine Months
|
|
|
|
|
|
Nine Months
|
|
|
|
Years Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Year Ended
|
|
|
Ended
|
|
|
|
December 31,
|
|
|
September 30,
|
|
|
October 31,
|
|
|
|
December 31,
|
|
|
September 30,
|
|
|
December 31,
|
|
|
September 30,
|
|
|
|
2003
|
|
|
2004
|
|
|
2005
|
|
|
2005
|
|
|
|
2005
|
|
|
2006
|
|
|
2005
|
|
|
2006
|
|
|
|
(Audited)
|
|
|
(Audited)
|
|
|
(Unaudited)
|
|
|
(Audited)
|
|
|
|
(Audited)
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
|
(in millions of dollars)
|
|
Reconciliation of
EBITDA to net cash provided by (used in) operating
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in)
operating activities
|
|
$
|
31.3
|
|
|
$
|
58.0
|
|
|
$
|
59.2
|
|
|
$
|
72.7
|
|
|
|
$
|
(1.5
|
)
|
|
$
|
11.1
|
|
|
|
|
|
|
|
|
|
Allocated interest expense from
parent(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7
|
|
|
|
50.5
|
|
|
|
|
|
|
|
|
|
Changes in operating working
capital which provided (used) cash:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
0.7
|
|
|
|
(0.7
|
)
|
|
|
0.5
|
|
|
|
0.3
|
|
|
|
|
0.1
|
|
|
|
(0.4
|
)
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
|
(1.0
|
)
|
|
|
(2.7
|
)
|
|
|
1.1
|
|
|
|
1.3
|
|
|
|
|
0.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other, including changes in
noncurrent assets and liabilities
|
|
|
(4.9
|
)
|
|
|
(3.8
|
)
|
|
|
(12.6
|
)
|
|
|
(17.1
|
)
|
|
|
|
5.5
|
|
|
|
1.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA
|
|
$
|
26.1
|
|
|
$
|
50.8
|
|
|
$
|
48.2
|
|
|
$
|
57.2
|
|
|
|
$
|
15.6
|
|
|
$
|
62.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of
EBITDA to net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
14.1
|
|
|
$
|
38.6
|
|
|
$
|
38.1
|
|
|
$
|
45.9
|
|
|
|
$
|
(5.1
|
)
|
|
$
|
(35.4
|
)
|
|
$
|
(6.8
|
)
|
|
$
|
0.4
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11.5
|
|
|
|
54.4
|
|
|
|
24.8
|
|
|
|
18.6
|
|
Deferred tax expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.0
|
|
|
|
|
|
|
|
2.0
|
|
Depreciation and amortization
expense
|
|
|
12.0
|
|
|
|
12.2
|
|
|
|
10.1
|
|
|
|
11.3
|
|
|
|
|
9.2
|
|
|
|
41.7
|
|
|
|
54.8
|
|
|
|
41.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA
|
|
$
|
26.1
|
|
|
$
|
50.8
|
|
|
$
|
48.2
|
|
|
$
|
57.2
|
|
|
|
$
|
15.6
|
|
|
$
|
62.7
|
|
|
$
|
72.8
|
|
|
$
|
62.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of
operating margin to net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
14.1
|
|
|
$
|
38.6
|
|
|
$
|
38.1
|
|
|
$
|
45.9
|
|
|
|
$
|
(5.1
|
)
|
|
$
|
(35.4
|
)
|
|
$
|
(6.8
|
)
|
|
$
|
0.4
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
expense
|
|
|
12.0
|
|
|
|
12.2
|
|
|
|
10.1
|
|
|
|
11.3
|
|
|
|
|
9.2
|
|
|
|
41.7
|
|
|
|
54.8
|
|
|
|
41.7
|
|
Deferred income tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.0
|
|
|
|
|
|
|
|
2.0
|
|
Other, net
|
|
|
0.6
|
|
|
|
0.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11.5
|
|
|
|
|