sv1za
As filed with the Securities and Exchange Commission on
December 26, 2007
Registration No. 333-146700
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Amendment No. 1
to
Form S-1
REGISTRATION STATEMENT UNDER
THE SECURITIES ACT OF 1933
WESTERN GAS PARTNERS,
LP
(Exact Name of Registrant as
Specified in Its Charter)
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Delaware
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1311
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26-1075808
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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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1201 Lake Robbins
Drive
The Woodlands, Texas
77380-1046
(832) 636-1000
(Address, Including Zip Code,
and Telephone Number, Including Area Code, of
Registrants Principal
Executive Offices)
Robert G. Gwin
1201 Lake Robbins
Drive
The Woodlands, Texas
77380-1046
(832) 636-1000
(Name, Address, Including Zip
Code, and Telephone Number, Including Area
Code, of Agent for
Service)
Copies to:
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David P. Oelman
Vinson & Elkins L.L.P.
1001 Fannin Street, Suite 2500
Houston, Texas 77002
(713) 758-2222
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G. Michael OLeary
Andrews Kurth LLP
600 Travis Street, Suite 4200
Houston, Texas 77002
(713) 220-4200
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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, 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
If
delivery of the prospectus is expected to be made pursuant to
Rule 434, please check the following
box. o
The
Registrant hereby amends this Registration Statement on such
date or dates as may be necessary to delay its effective date
until the Registrant shall file a further amendment which
specifically states that this Registration Statement shall
thereafter become effective in accordance with Section 8(a)
of the Securities Act of 1933 or until the Registration
Statement shall become effective on such date as the Securities
and Exchange Commission, acting pursuant to said
Section 8(a), may determine.
The information in this preliminary prospectus is not complete
and may be changed. We may not sell these securities until the
registration statement filed with the Securities and Exchange
Commission is effective. This preliminary prospectus is not an
offer to sell these securities and we are not soliciting offers
to buy these securities in any jurisdiction where the offer or
sale is not permitted.
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PRELIMINARY PROSPECTUS
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Subject
to Completion
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December 26,
2007
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18,750,000
Common Units
Representing
Limited Partner Interests
This is the initial public offering of our common units. We
currently estimate that the initial public offering price will
be between $ and
$ per common unit. Prior to this
offering, there has been no public market for the common units.
We have applied to list our common units on the New York Stock
Exchange under the symbol WES.
Investing in our common units involves
risks. Please read Risk factors beginning
on page 18.
These risks include the following:
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Ø
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We are dependent on a single
natural gas producer, Anadarko Petroleum Corporation, for almost
all of the natural gas that we gather and transport. A material
reduction in Anadarkos production gathered or transported
by our assets would result in a material decline in our revenues
and cash available for distribution.
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Ø
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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 pay the minimum quarterly
distribution to holders of our common and subordinated units.
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Ø
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Because of the natural decline in
production from existing wells, our success depends on our
ability to obtain new sources of natural gas, which is dependent
on certain factors beyond our control. Any decrease in the
volumes of natural gas that we gather and transport could
adversely affect our business and operating results.
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Anadarko owns and controls our
general partner, which has sole responsibility for conducting
our business and managing our operations. Anadarko and our
general partner have conflicts of interest and may favor
Anadarkos interests to your detriment.
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Cost reimbursements due to Anadarko
and our general partner for services provided to us or on our
behalf will be substantial and will reduce our cash available
for distribution to you. The amount and timing of such
reimbursements will be determined by our general partner.
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You will have limited voting rights
and are not entitled to elect our general partner or its
directors.
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Even if you are dissatisfied, you
cannot initially remove our general partner without its consent.
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Our general partner interest or the
control of our general partner may be transferred to a third
party without your consent.
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Ø |
You will experience immediate and
substantial dilution in pro forma net tangible book value of
$5.09 per common unit.
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Ø |
You will be required to pay taxes
on your share of our income even if you do not receive any cash
distributions from us.
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Per common
unit
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Total
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Public offering price
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$
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$
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Underwriting discounts and
commissions(1)
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$
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$
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Proceeds, before expenses, to Western Gas Partners, LP
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$
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$
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(1) |
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Excludes a structuring fee
payable to UBS Securities LLC that is equal
to % of the gross proceeds of this
offering, or approximately
$ . |
We have granted the underwriters a
30-day
option to purchase up to an additional 2,812,500 common units
from us on the same terms and conditions as set forth above if
the underwriters sell more than 18,750,000 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 on or
about ,
2008.
UBS
Investment Bank
You should rely only on the information contained in this
prospectus and any free writing prospectus prepared by us or on
our behalf. 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.
TABLE OF
CONTENTS
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1
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1
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2
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2
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42
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72
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75
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91
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113
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114
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114
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115
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122
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126
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126
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127
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130
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138
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141
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141
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143
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143
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143
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144
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147
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149
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150
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ii
Through and
including ,
2008 (the
25th
day after the date of this prospectus), federal securities law
may require all dealers that effect transactions in these
securities, whether or not participating in this offering, to
deliver a prospectus. This requirement is in addition to the
dealers obligation to deliver a prospectus when acting as
underwriters and with respect to their unsold allotments or
subscriptions.
iii
This summary provides a brief overview of information
contained elsewhere in this prospectus. Because it is
abbreviated, this summary does not contain all of the
information that you should consider before investing in our
common units. You should read the entire prospectus carefully,
including the historical and pro forma combined financial
statements and the notes to those financial statements. The
information presented in this prospectus assumes (1) an
initial public offering price of $20.00 per common unit and
(2) unless otherwise indicated, that the underwriters
option to purchase additional common units is not exercised. You
should read Risk factors beginning on page 18
for more information about important risks that you should
consider carefully before investing in our common units. We
include a glossary of some of the terms used in this prospectus
as Appendix B.
Unless the context otherwise requires, references in this
prospectus to (i) Western Gas Partners, LP,
we, our, us or like terms,
when used in a historical context, refer to our Predecessor, as
defined in Summary historical and pro forma
financial data, and when used in the present tense or
prospectively, refer to Western Gas Partners, LP and its
subsidiaries; (ii) Anadarko refers to Anadarko
Petroleum Corporation and its subsidiaries and affiliates, other
than Western Gas Partners, LP and Western Gas Holdings, LLC, our
general partner, as of the closing date of this offering;
(iii) Anadarko Petroleum Corporation refers to
Anadarko Petroleum Corporation excluding its subsidiaries and
affiliates; and (iv) MIGC refers to MIGC,
Inc.
We are a growth-oriented Delaware limited partnership recently
formed by Anadarko (NYSE: APC) to own, operate, acquire and
develop midstream energy assets. We currently operate in East
Texas, the Rocky Mountains, the Mid-Continent and West Texas and
are engaged in the business of gathering, compressing, treating
and transporting natural gas for our ultimate parent, Anadarko,
and third-party producers and customers. We principally provide
our midstream services under long-term contracts with fee-based
rates extending for primary terms of up to 20 years. We
generally do not take title to the natural gas that we gather
and, therefore, are able to avoid significant direct commodity
price exposure.
We believe that one of our principal strengths is our
relationship with Anadarko. During each of the year ended
December 31, 2006 and the nine months ended
September 30, 2007, over 90% of our total natural gas
gathering and transportation volumes were comprised of natural
gas production owned or controlled by Anadarko. Anadarko
Petroleum Corporation has dedicated to us all of the natural gas
production it owns or controls from (i) wells that are
currently connected to our gathering systems, and
(ii) additional wells that are drilled within one mile of
connected wells or our gathering systems, as the systems
currently exist and as they are expanded to connect additional
wells in the future. As a result, this dedication will continue
to expand as additional wells are connected to our gathering
systems. Volumes associated with this dedication averaged
approximately 736 MMBtu/d for the year ended
December 31, 2006 and 738 MMBtu/d for the nine months
ended September 30, 2007.
We expect to utilize the significant experience of
Anadarkos management team to execute our growth strategy,
which includes acquiring and constructing additional midstream
assets. For the nine months ended September 30, 2007, as
adjusted for divestitures prior to this offering and including
the assets being contributed to us, Anadarkos total
domestic midstream asset portfolio generated approximately
$250 million of cash flow from operations and consisted of
25 gathering systems and one transportation system with an
aggregate throughput of approximately 3.0 Bcf/d,
approximately 11,200 miles of pipeline and 25 processing
and/or
treating facilities.
1
OUR
ASSETS AND AREAS OF OPERATION
Our assets consist of six gathering systems, five natural gas
treating facilities and one interstate pipeline. Our assets are
located in East Texas, the Rocky Mountains (Utah and Wyoming),
the Mid-Continent (Kansas and Oklahoma) and West Texas. The
following table provides information regarding our assets by
operating area as of or for the nine months ended
September 30, 2007:
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Approximate
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Treating
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Average
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Asset
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Length
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# of receipt
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Gas
compression
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capacity
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throughput
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Area
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Type
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(miles)
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points
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(horsepower)
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(MMcf/d)
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(MMcf/d)
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East Texas
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Gathering and
Treating
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577
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789
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45,633
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510
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304
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(1)
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Rocky Mountains
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Gathering and
Treating
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114
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162
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20,385
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92
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55
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Transportation
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264
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19
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29,696
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137
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Mid-Continent
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Gathering
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1,753
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1,507
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130,720
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123
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West Texas
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Gathering
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87
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50
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185
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Total
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2,795
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2,527
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226,434
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602
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804
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(1) |
To avoid duplicating volumes, 213 MMcf/d that is
gathered on our Dew gathering system and delivered into our
Pinnacle gas treating system is included only once in the
calculation of average throughput.
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Our primary business objective is to increase our cash
distribution per unit over time. We intend to accomplish this
objective by executing the following strategy:
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Pursuing accretive acquisitions. We expect to
pursue accretive acquisition opportunities within the midstream
energy industry from Anadarko and third parties.
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Capitalizing on organic growth
opportunities. We expect to grow organically by
meeting Anadarkos gathering needs, which we expect to
increase as a result of its anticipated drilling activity in our
areas of operation.
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Attracting additional third-party volumes to our
systems. We intend to actively market our
midstream services to and pursue strategic relationships with
third-party producers to attract additional volumes and/or
expansion opportunities.
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Minimizing commodity price exposure. Our
midstream services are provided under fee-based arrangements
which minimize our direct commodity price exposure. We expect to
utilize hedging to manage any significant future commodity price
risk that could result from contracts we may acquire or enter
into in the future.
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We believe that we are well positioned to successfully execute
our strategy and achieve our primary business objective because
of the following competitive strengths:
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Affiliation with Anadarko. We believe
Anadarko, as the owner of our general partner interest, all of
our incentive distribution rights and a 57.3% limited partner
interest in us, is motivated to promote and support the
successful execution of our business plan and to pursue projects
that enhance the value of our business.
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Relatively stable and predictable cash
flow. Our cash flow is largely protected from
fluctuations caused by commodity price volatility due to the
fee-based, long-term nature of our midstream service agreements.
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Well-positioned, well-maintained and efficient assets. We
believe that our established positions in our areas of operation
provide us with opportunities to expand and attract additional
volumes to our
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systems. Moreover, our systems consist of high-quality,
well-maintained assets for which we have implemented modern
treating, measuring and operating technologies.
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Financial flexibility to pursue expansion and acquisition
opportunities. We have up to $100 million of borrowing
capacity available to us under Anadarkos $750 million
credit facility and, concurrently with the closing of this
offering, we expect to obtain a $30 million working capital
facility from Anadarko. In addition, we will have no
indebtedness outstanding at the closing of this offering. We
believe that our borrowing capacity and our ability to
effectively access debt and equity capital markets provide us
with the financial flexibility necessary to achieve our organic
expansion and acquisition strategy.
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Experienced management team. Members of our
general partners management team have extensive experience
in building, acquiring, integrating, financing and managing
midstream assets. In addition, our relationship with Anadarko
provides us with the services of experienced personnel who
successfully managed our assets and operations while they were
owned by Anadarko.
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We believe that we will effectively leverage our competitive
strengths to successfully implement our strategy; however, our
business involves numerous risks and uncertainties which may
prevent us from achieving our primary business objective. For a
more complete description of the risks associated with an
investment in us, please read Risk factors.
OUR
RELATIONSHIP WITH ANADARKO PETROLEUM CORPORATION
One of our principal attributes is our relationship with
Anadarko. It will own our general partner and a significant
interest in us following this offering. Anadarko is one of the
largest independent oil and gas exploration and production
companies in the world. Anadarkos upstream oil and gas
business finds and produces natural gas, crude oil, condensate
and natural gas liquids, or NGLs, and Anadarko annually pursues
one of the most active drilling programs in the industry. At
September 30, 2007, including the assets being contributed
to us but adjusted for divestitures prior to this offering,
Anadarkos total domestic midstream asset portfolio
consisted of 25 gathering systems and one transportation system
with an aggregate throughput of approximately 3.0 Bcf/d,
approximately 11,200 miles of pipeline and 25 processing
and/or treating facilities. Following this offering,
Anadarkos remaining midstream business will consist of 19
gathering systems with an aggregate throughput of approximately
2.2 Bcf/d, 8,400 miles of pipeline and 20 processing
and/or treating facilities. The assets to be retained by
Anadarko generated approximately $191 million of cash flow
from operating activities for the nine months ended
September 30, 2007. Anadarko has invested significant
capital into its domestic midstream business, including the
assets being contributed to us, with investments of
approximately $290 million in 2006 and planned investments
of approximately $600 million in 2007, of which
approximately $475 million had been invested as of
September 30, 2007.
Upon completion of this offering, Anadarko will own a 2.0%
general partner interest in us, all of our incentive
distribution rights and a 57.3% limited partner interest in us.
We will enter into an omnibus agreement with Anadarko and our
general partner that will govern our relationship with them
regarding certain reimbursement and indemnification matters.
Please read Certain relationships and related party
transactionsAgreements governing the
transactionsOmnibus agreement. Although our
relationship with Anadarko provides us with a significant
advantage in the midstream natural gas market, it is also a
source of potential conflicts. For example, Anadarko is not
restricted from competing with us. Please read Conflicts
of interest and fiduciary duties. Given Anadarkos
significant ownership of limited and general partner interests
in us following this offering, we believe it will be in
Anadarkos best interest for it to sell additional assets
to us over time; however, Anadarko continually evaluates
acquisitions and divestitures and may elect to acquire,
construct or dispose of midstream assets in the future without
offering us the opportunity to acquire or construct those
assets. Anadarko is under no contractual obligation to offer
any such opportunities to us, nor are we obligated to
participate in any such opportunities. We cannot state with any
certainty which, if any, opportunities to acquire assets from
Anadarko may be made available to us or if we will elect to
pursue any such opportunities.
3
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. Please read Risk factors for a more thorough
description of these and other risks.
FORMATION
TRANSACTIONS AND PARTNERSHIP STRUCTURE
General
We are a growth-oriented Delaware limited partnership recently
formed by Anadarko to own, operate, acquire and develop
midstream energy assets. At the closing of this offering,
assuming that the underwriters do not exercise their option to
purchase additional common units, the following transactions,
which we refer to as the formation transactions, will occur:
|
|
Ø |
Anadarko will contribute certain midstream assets to us;
|
|
|
Ø |
we will issue to Western Gas Holdings, LLC, our general partner
and a subsidiary of Anadarko, 921,385 general partner units
representing a 2.0% general partner interest in us as well as
all of our incentive distribution rights;
|
|
|
Ø
|
we will issue to Anadarko 3,823,925 common units and 22,573,925
subordinated units, representing an aggregate 57.3% limited
partner interest
in us;(1)
|
|
Ø
|
we will issue 18,750,000 common units to the public,
representing a 40.7% limited partner interest
in us;(1)
|
|
Ø
|
we will receive gross proceeds of $375.0 million from the
issuance and sale of 18,750,000 common units at an assumed
initial offering price of $20.00 per unit;
|
|
Ø
|
we will use the proceeds from this offering to pay underwriting
discounts and a structuring fee totaling approximately
$24.4 million and other estimated offering expenses of
$3.0 million;
|
|
Ø
|
we will use the remaining $347.6 million of aggregate net
proceeds of this offering to (i) make a loan of
$337.6 million to Anadarko in exchange for a
30-year note
bearing interest at a fixed annual rate of 6.00% and
(ii) provide $10.0 million for general partnership
purposes;
|
|
|
Ø |
we will have up to $100 million of long-term borrowing
capacity available to us under Anadarkos $750 million
credit facility;
|
|
|
Ø |
we will enter into a $30 million working capital facility
with Anadarko as the lender;
|
|
|
Ø |
we will enter into an omnibus agreement with Anadarko and our
general partner pursuant to which, among other things,
(i) we will reimburse Anadarko and our general partner for
certain expenses incurred on our behalf, including expenses for
various general and administrative services rendered by Anadarko
and our general partner to us, and (ii) the parties will
agree to certain indemnification obligations;
|
|
|
Ø |
our general partner will enter into a services and secondment
agreement with Anadarko, pursuant to which certain employees of
Anadarko will be under our control and render services to us or
on our behalf; and
|
|
|
Ø |
our general partner will enter into a tax sharing agreement with
Anadarko, pursuant to which we will pay Anadarko for our share
of state and local income and other taxes that are included in
combined or consolidated tax returns filed by Anadarko.
|
|
|
|
(1) |
|
If the underwriters exercise
their option to purchase up to 2,812,500 additional common units
within 30 days of this offering, the number of units
purchased by the underwriters pursuant to such exercise will be
issued to the public instead of Anadarko. |
4
Ownership of
Western Gas Partners, LP
The diagram below illustrates our organization and ownership
after giving effect to the offering and the related formation
transactions and assumes that the underwriters option to
purchase additional common units is not exercised.
|
|
|
|
|
Public Common Units
|
|
|
40.7
|
%
|
Anadarko Common and Subordinated Units
|
|
|
57.3
|
%
|
General Partner Units
|
|
|
2.0
|
%
|
|
|
|
|
|
Total
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|
|
100.0
|
%
|
5
Our general partner has sole responsibility for conducting our
business and for managing our operations and will be controlled
by our ultimate parent, Anadarko. Pursuant to the omnibus
agreement and the services and secondment agreement that we will
enter into concurrently with the closing of this offering,
Anadarko and our general partner will be entitled to
reimbursement for all direct and indirect expenses that they
incur on our behalf. Under the omnibus agreement, our
reimbursement to Anadarko for certain general and administrative
expenses it allocates to us will be capped at $6.0 million
annually through December 31, 2009, subject to adjustments
to reflect changes in the Consumer Price Index and, with the
concurrence of the special committee of our general
partners board of directors, to reflect expansions of our
operations through the acquisition or construction of new assets
or businesses. Thereafter, our general partner will determine
the general and administrative expenses to be reimbursed by us
in accordance with our partnership agreement. The cap contained
in the omnibus agreement does not apply to incremental general
and administrative expenses we expect to incur or to be
allocated to us as a result of becoming a publicly traded
partnership. We currently expect those expenses to be
approximately $2.5 million per year. Please read
Certain relationships and related party
transactionsAgreements governing the
transactionsOmnibus agreement and
Services and secondment agreement.
Neither our general partner nor its board of directors will be
elected by our unitholders. Anadarko is the sole member of our
general partner and will have the right to appoint our general
partners entire board of directors. Certain of our
officers and directors are also officers of Anadarko.
As is common with publicly traded partnerships and in order to
maximize operational flexibility, we will conduct our operations
through subsidiaries. We will initially have one direct
subsidiary, Western Gas Operating, LP, a limited partnership
that will conduct business itself and through its subsidiaries.
PRINCIPAL
EXECUTIVE OFFICES AND INTERNET ADDRESS
Our principal executive offices are located at 1201 Lake Robbins
Drive, The Woodlands, Texas 77380, and our telephone number is
(832) 636-1000.
We expect our website to be located at www.westerngas.com. We
expect to make available our periodic reports and other
information filed with or furnished to the Securities and
Exchange Commission, which we refer to as the SEC, 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 herein and
does not constitute a part of this prospectus.
OUR
GENERAL PARTNERS RIGHT TO RECEIVE DISTRIBUTIONS
2.0% general
partner interest
Our general partner initially will be entitled to receive 2.0%
of our quarterly cash distributions. This 2.0% interest will
initially be represented by 921,385 general partner units.
General partner units are not deemed outstanding units for
purposes of voting rights and such units represent a non-voting
general partner interest. Our general partners initial
2.0% interest in these distributions will be reduced if we issue
additional units in the future and our general partner does not
elect to contribute a proportionate amount of capital to us to
maintain its initial 2.0% general partner interest. If and to
the extent our general partner elects to contribute sufficient
capital to maintain its 2.0% general partner interest, it will
be issued the number of general partner units necessary to
maintain its 2.0% interest. All references in this prospectus to
our general partners 2.0% general partner interest assume
that our general partner will elect to make these additional
capital contributions in order to maintain its right to receive
2.0% of our cash distributions.
Incentive
distributions
In addition to its 2.0% general partner interest, our general
partner holds the incentive distribution rights, which are
non-voting limited partner interests that represent the right to
receive an increasing
6
percentage of quarterly distributions of available cash as
higher target distribution levels of cash are achieved. The
following table shows how our available cash will be distributed
among our unitholders and our general partner as higher target
distribution levels are met:
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Marginal
percentage interest
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Total quarterly
distribution
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in
distributions(1)
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|
per
unit
|
|
Unitholders
|
|
General
partner
|
|
|
|
|
Minimum Quarterly Distribution
|
|
$0.300
|
|
|
98.0%
|
|
|
2.0%
|
First Target Distribution
|
|
up to $0.345
|
|
|
98.0%
|
|
|
2.0%
|
Second Target Distribution
|
|
above $0.345 up to $0.375
|
|
|
85.0%
|
|
|
15.0%
|
Third Target Distribution
|
|
above $0.375 up to $0.450
|
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75.0%
|
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|
25.0%
|
Thereafter
|
|
above $0.450
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50.0%
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|
50.0%
|
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|
(1) |
|
Assumes that there are no
arrearages on common units and that our general partner
maintains its 2.0% general partner interest and continues to own
the incentive distribution rights. |
For a more detailed description of the incentive distribution
rights, please read Provisions of our partnership
agreement relating to cash distributionsGeneral partner
interest and incentive distribution rights.
Our general
partners right to reset the target distribution
levels
Our general partner has the right, at any 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 target distribution levels to higher levels based on
our cash distributions at the time of the exercise of the reset
election. Following a reset election by our general partner, the
minimum quarterly distribution will be reset to an amount equal
to the average cash distribution per common unit for the two
fiscal quarters immediately preceding the reset election (we
refer to such amount 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. As a
result, following a reset, we would distribute all of our
available cash for each quarter thereafter as follows (assuming
our general partner maintains its 2.0% general partner interest
and the ownership of the incentive distribution rights):
|
|
Ø
|
first, 98.0% to all unitholders, pro rata, and 2.0% to
our general partner, until each unitholder receives a total
amount equal to 115% of the reset minimum quarterly distribution
for that quarter;
|
|
Ø
|
second, 85.0% to all unitholders, pro rata, and 15.0% to
our general partner, until each unitholder receives a total
amount per unit equal to 125% of the reset minimum quarterly
distribution for the quarter;
|
|
Ø
|
third, 75.0% to all unitholders, pro rata, and 25.0% to
our general partner, until each unitholder receives a total
amount per unit equal to 150% of the reset minimum quarterly
distribution for the quarter; and
|
|
Ø
|
thereafter, 50.0% to all unitholders, pro rata, and 50.0%
to our general partner.
|
If our general partner elects to reset the target distribution
levels, it will be entitled to receive a number of Class B
units and general partner 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 to our
general partner will be equal to that number of common units
which would have entitled their holder to an average aggregate
quarterly cash distribution in the prior two quarters equal to
the average of the distributions to our general partner on the
incentive distribution rights in the prior two quarters. Our
general partner will be issued the number of general partner
units necessary to maintain our general partners interest
in us immediately prior to the reset election.
7
SUMMARY
OF CONFLICTS OF INTEREST AND FIDUCIARY DUTIES
General
Our general partner has a legal duty to manage us in a manner
beneficial to holders of our common and subordinated units. This
legal duty originates in statutes and judicial decisions and is
commonly referred to as a fiduciary duty. However,
the officers and directors of our general partner also have
fiduciary duties to manage our general partner in a manner
beneficial to its owner, Anadarko. Certain of the officers and
directors of our general partner are also officers of Anadarko.
As a result, conflicts of interest will arise in the future
between us and holders of our common and subordinated units, on
the one hand, and Anadarko and our general partner, on the other
hand. For example, our general partner will be entitled to make
determinations that affect the amount of cash distributions we
make to the holders of common units, which in turn has an effect
on whether our general partner receives incentive cash
distributions as discussed above.
Partnership
agreement modifications to fiduciary duties
Our partnership agreement limits the liability of, and reduces
the fiduciary duties owed by, our general partner to holders of
our common and subordinated units. Our partnership agreement
also restricts the remedies available to holders of our common
and subordinated units for actions that might otherwise
constitute a breach of our general partners fiduciary
duties. By purchasing a common unit, the purchaser agrees to be
bound by the terms of our partnership agreement, and pursuant to
the terms of our partnership agreement, each holder of common
units consents to various actions and potential conflicts of
interest contemplated in the partnership agreement that might
otherwise be considered a breach of fiduciary or other duties
under applicable state law.
Anadarko may
engage in competition with us
Neither our partnership agreement nor the omnibus agreement
between us and Anadarko will prohibit Anadarko from owning
assets or engaging in businesses that compete directly or
indirectly with us. In addition, Anadarko may acquire, construct
or dispose of additional midstream or other assets in the
future, without any obligation to offer us the opportunity to
acquire or construct any of those assets.
For a more detailed description of the conflicts of interest and
the fiduciary duties of our general partner, please read
Conflicts of interest and fiduciary duties.
8
|
|
|
Common units offered to the public |
|
18,750,000 common units |
|
|
|
|
|
21,562,500 common units, if the underwriters exercise in full
their option to purchase additional common units |
|
|
|
Units outstanding after this offering |
|
22,573,925 common
units(1)
and 22,573,925 subordinated units, each representing a
49.0% limited partner interest in us. Our general partner will
own 921,835 general partner units, representing a 2.0% general
partner interest in us. |
|
|
|
Use of proceeds |
|
We expect to receive gross proceeds of $375.0 million from
this offering. We will use the proceeds to (i) make a loan
of $337.6 million to Anadarko in exchange for a
30-year note
bearing interest at a fixed annual rate of 6.00%,
(ii) provide $10.0 million for general partnership
purposes and (iii) pay underwriting discounts and a
structuring fee totaling approximately $24.4 million and
other estimated offering expenses of $3.0 million. |
|
|
|
The net proceeds from any exercise of the underwriters
option to purchase additional common units will be used to
reimburse Anadarko for capital expenditures it incurred with
respect to the assets contributed to us during the two-year
period prior to this offering. |
|
Cash distributions |
|
Our general partner will adopt a cash distribution policy that
will require us to pay a minimum quarterly distribution of $0.30
per unit ($1.20 per 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, including
payments to our general partner and its affiliates. We refer to
this cash as available cash, and it is defined in
our partnership agreement included in this prospectus as
Appendix A and in the glossary included in this prospectus
as Appendix B. Our ability to pay the minimum quarterly
distribution is subject to various restrictions and other
factors described in more detail under the caption Our
cash distribution policy and restrictions on
distributions. We will adjust the minimum quarterly
distribution payable for the period from the completion of this
offering through March 31, 2008, based on the actual length
of that period. |
|
|
|
Our partnership agreement requires that we distribute all of our
available cash each quarter in the following manner: |
|
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|
Ø first,
98.0% to the holders of common units and 2.0% to our general
partner, until each common unit has received the minimum
quarterly distribution of $0.30 plus any arrearages from prior
quarters;
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|
|
|
Ø second,
98.0% to the holders of subordinated units and 2.0% to our
general partner, until each subordinated unit
|
(1) Excludes common units subject to
issuance under our Long-Term Incentive Plan. Please read
Management Long-term incentive plan.
9
|
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|
has received the minimum quarterly distribution of $0.30; and |
|
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|
Ø third,
98.0% to all unitholders, pro rata, and 2.0% to our general
partner, until each unit has received a distribution of $0.345.
|
|
|
|
If cash distributions to our unitholders exceed $0.345 per unit
in any quarter, our general partner will receive, in addition to
distributions on its 2.0% general partner interest, increasing
percentages, up to 48.0%, of the cash we distribute in excess of
that amount. We refer to these distributions as incentive
distributions. Please read Provisions of our
partnership agreement relating to cash distributions. |
|
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|
The amounts of pro forma available cash generated during each of
the year ended December 31, 2006 and twelve months ended
September 30, 2007 would have been sufficient to allow us
to pay the full minimum quarterly distribution ($0.30 per unit
per quarter, or $1.20 on an annualized basis) on all of our
common and subordinated units for such periods. Please read
Our cash distribution policy and restrictions on
distributions. |
|
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|
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|
We believe that, based on the Statement of Estimated Adjusted
EBITDA included under the caption Our cash distribution
policy and restrictions on distributions, we will have
sufficient cash available for distribution to pay the minimum
quarterly distribution of $0.30 per unit on all common and
subordinated units and the corresponding distributions on our
general partners 2.0% interest for the four quarters
ending December 31, 2008. |
|
|
|
Subordinated units |
|
Anadarko will initially indirectly own all of our subordinated
units. The principal difference between our common and
subordinated units is that in any quarter during the
subordination period, holders of the subordinated units are not
entitled to receive any distribution until the common units have
received the minimum quarterly distribution plus any arrearages
in the payment of the minimum quarterly distribution from prior
quarters. Subordinated units will not accrue arrearages. |
|
Conversion of subordinated units |
|
The subordination period will end on the first business day
after we have earned and paid at least (i) $1.20 (the
minimum quarterly distribution on an annualized basis) on each
outstanding unit and the corresponding distribution on our
general partners 2.0% interest for each of three
consecutive, non-overlapping four quarter periods ending on or
after December 31, 2010 or (ii) $0.45 per quarter
(150% of the minimum quarterly distribution, which is $1.80 on
an annualized basis) on each outstanding unit and the
corresponding distributions on our general partners 2.0%
interest for each of four consecutive quarters. |
|
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|
In addition, the subordination period will end upon the removal
of our general partner other than for cause if the units |
10
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|
held by our general partner and its affiliates are not voted in
favor of such removal. |
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|
When the subordination period ends, all subordinated units will
convert into common units on a one-for-one basis, and all common
units thereafter will no longer be entitled to arrearages. |
|
General partners right to reset the target distribution
levels |
|
Our general partner has the right, at any 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 target distribution levels at higher levels based on
our cash distributions at the time of the exercise of the reset
election. Following a reset election by our general partner, the
minimum quarterly distribution will be adjusted to equal 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. |
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|
If our general partner elects to reset the target distribution
levels, it will be entitled to receive Class B units and
general partner 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 to our general partner
will be equal to that number of common units which would have
entitled their holder to an average aggregate quarterly cash
distribution in the prior two quarters equal to the average of
the distributions to our general partner on the incentive
distribution rights in the prior two quarters. Our general
partner will be issued the number of general partner units
necessary to maintain our general partners interest in us
immediately prior to the reset election. Please read
Provisions of our partnership agreement relating to cash
distributionsGeneral 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 read Units eligible for future
sale and The partnership agreementIssuance 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 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 voting together as a single class,
including any units owned by our general partner and its
affiliates, including Anadarko. Upon consummation of this
offering, Anadarko will own an aggregate of 58.5% of our common
and subordinated units. This will give Anadarko the ability to |
11
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prevent the involuntary removal of our general partner. Please
read The partnership agreementVoting 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 that is 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, 2010, you will be allocated, on
a cumulative basis, an amount of federal taxable income for that
period that will be % or less of
the cash distributed to you with respect to that period. For
example, if you receive an annual distribution of $1.20 per
unit, we estimate that your average allocable federal taxable
income per year will be no more than
$
per unit. Please read Material tax consequencesTax
consequences of unit ownershipRatio 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, or
the U.S., please read Material tax consequences. |
|
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Exchange listing |
|
We have applied to list our common units on the New York Stock
Exchange under the symbol WES. |
12
Summary
historical and pro forma financial and operating data
The following table shows (i) the summary combined
historical financial and operating data of our Predecessor,
which is comprised of Anadarko Gathering Company and Pinnacle
Gas Treating, Inc., with MIGC reported as an acquired business
of our Predecessor, and (ii) the summary combined pro forma
as adjusted financial and operating data of Western Gas
Partners, LP (the Partnership), for the periods and
as of the dates indicated. The information in the following
table should be read together with Managements
discussion and analysis of financial condition and results of
operations.
Our Predecessors summary combined historical balance sheet
data as of December 31, 2006 and 2005 and summary combined
historical statement of income and cash flow data for the years
ended December 31, 2006, 2005 and 2004 are derived from the
audited historical combined financial statements of our
Predecessor included elsewhere in this prospectus. Our
Predecessors summary combined historical balance sheet
data as of December 31, 2004 are derived from the unaudited
historical combined financial statements of our Predecessor not
included in this prospectus. Our Predecessors summary
combined historical balance sheet data as of September 30,
2007 and summary combined historical statement of income and
cash flow data for the nine months ended September 30, 2007
and 2006 are derived from the unaudited historical combined
financial statements of our Predecessor included elsewhere in
this prospectus. Our Predecessors summary combined
historical balance sheet data as of September 30, 2006 are
derived from the unaudited historical combined financial
statements of our Predecessor not included in this prospectus.
The Partnerships summary combined pro forma as adjusted
statement of income data for the year ended December 31,
2006 and the nine months ended September 30, 2007 and
summary combined pro forma as adjusted balance sheet data as of
September 30, 2007 are derived from the unaudited pro forma
combined financial statements of the Partnership included
elsewhere in this prospectus.
The pro forma adjustments have been prepared as if the
acquisition of MIGC by our Predecessor occurred on
January 1, 2006 and as if certain transactions to be
effected at the closing of this offering had taken place on
September 30, 2007, in the case of the pro forma balance
sheet, and on January 1, 2006, in the case of the pro forma
statements of operations for the year ended December 31,
2006 and the nine months ended September 30, 2007. These
transactions include:
|
|
Ø |
the receipt by the Partnership of gross proceeds of
$375.0 million from the issuance and sale of 18,750,000
common units at an assumed initial offering price of $20.00 per
unit;
|
|
|
Ø |
the use of the proceeds from this offering to pay underwriting
discounts and a structuring fee totaling approximately
$24.4 million and other estimated offering expenses of
$3.0 million; and
|
|
|
Ø |
the use of the remaining $347.6 million of aggregate net
proceeds of this offering to (i) make a loan of
$337.6 million to Anadarko in exchange for a
30-year note
bearing interest at a fixed annual rate of 6.00% and
(ii) provide $10.0 million for general partnership
purposes.
|
The following table includes our Predecessors historical
and our pro forma Adjusted EBITDA, which have not been prepared
in accordance with generally accepted accounting principles
(GAAP). Adjusted EBITDA is presented because it is
helpful to management, industry analysts, investors, lenders and
rating agencies and may be used to assess the financial
performance and operating results of our fundamental business
activities. For a reconciliation of Adjusted EBITDA to its most
directly comparable financial measures calculated and presented
in accordance with GAAP, please read
Non-GAAP financial
measure below.
13
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Partnership pro
forma
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as
adjusted
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Predecessor
combined
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Nine months
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Nine months
ended
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ended
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Year ended
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Year ended
December 31,
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September 30,
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September 30,
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December 31,
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2006
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2005
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2004
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2007
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2006
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2007
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2006
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(in thousands,
except for operating and per unit data)
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|
Statement of Income Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
81,152
|
|
|
$
|
71,650
|
|
|
$
|
68,049
|
|
|
$
|
85,513
|
|
|
$
|
57,481
|
|
|
$
|
85,513
|
|
|
$
|
93,304
|
|
Costs and expenses
|
|
|
39,960
|
|
|
|
35,720
|
|
|
|
31,301
|
|
|
|
33,184
|
|
|
|
29,057
|
|
|
|
33,184
|
|
|
|
43,857
|
|
Depreciation
|
|
|
18,009
|
|
|
|
15,447
|
|
|
|
14,841
|
|
|
|
17,104
|
|
|
|
12,635
|
|
|
|
17,104
|
|
|
|
19,710
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
57,969
|
|
|
|
51,167
|
|
|
|
46,142
|
|
|
|
50,288
|
|
|
|
41,692
|
|
|
|
50,288
|
|
|
|
63,567
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
23,183
|
|
|
|
20,483
|
|
|
|
21,907
|
|
|
|
35,225
|
|
|
|
15,789
|
|
|
|
35,225
|
|
|
|
29,737
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other (expense) income
|
|
|
26
|
|
|
|
(66
|
)
|
|
|
|
|
|
|
|
|
|
|
25
|
|
|
|
|
|
|
|
377
|
|
Interest expense (income)
|
|
|
9,631
|
|
|
|
8,650
|
|
|
|
7,146
|
|
|
|
6,643
|
|
|
|
7,943
|
|
|
|
(15,022
|
)
|
|
|
(20,030
|
)
|
Income tax expense
|
|
|
3,814
|
|
|
|
4,789
|
|
|
|
5,504
|
|
|
|
10,469
|
|
|
|
1,740
|
|
|
|
160
|
|
|
|
978
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
9,712
|
|
|
$
|
7,110
|
|
|
$
|
9,257
|
|
|
$
|
18,113
|
|
|
$
|
6,081
|
|
|
$
|
50,087
|
|
|
$
|
48,412
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner interest in pro forma net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,315
|
|
|
|
968
|
|
Common unitholders interest in pro forma net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24,386
|
|
|
|
23,722
|
|
Subordinated unitholders interest in pro forma net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24,386
|
|
|
|
23,722
|
|
Net income per common unit (basic and diluted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1.08
|
|
|
$
|
1.05
|
|
Net income per subordinated unit (basic and diluted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1.08
|
|
|
$
|
1.05
|
|
Balance Sheet Data (at period end):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net, property, plant and equipment
|
|
$
|
310,871
|
|
|
$
|
200,451
|
|
|
$
|
196,065
|
|
|
$
|
353,894
|
|
|
$
|
302,057
|
|
|
$
|
353,894
|
|
|
|
|
|
Total assets
|
|
|
332,228
|
|
|
|
206,373
|
|
|
|
199,110
|
|
|
|
360,692
|
|
|
|
324,772
|
|
|
|
708,306
|
|
|
|
|
|
Total parent net equity
|
|
|
238,531
|
|
|
|
160,585
|
|
|
|
162,542
|
|
|
|
273,507
|
|
|
|
234,063
|
|
|
|
691,561
|
|
|
|
|
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
|
27,323
|
|
|
|
30,131
|
|
|
|
31,160
|
|
|
|
41,810
|
|
|
|
12,941
|
|
|
|
|
|
|
|
|
|
Investing activities
|
|
|
(42,713
|
)
|
|
|
(21,076
|
)
|
|
|
(16,548
|
)
|
|
|
(37,247
|
)
|
|
|
(27,952
|
)
|
|
|
|
|
|
|
|
|
Financing activities
|
|
|
15,844
|
|
|
|
(9,067
|
)
|
|
|
(14,596
|
)
|
|
|
(5,021
|
)
|
|
|
15,007
|
|
|
|
|
|
|
|
|
|
Adjusted
EBITDA(1)
|
|
|
41,192
|
|
|
|
35,930
|
|
|
|
36,748
|
|
|
|
52,329
|
|
|
|
28,424
|
|
|
|
52,329
|
|
|
|
49,447
|
|
Capital expenditures, net
|
|
|
42,299
|
|
|
|
20,841
|
|
|
|
16,548
|
|
|
|
37,020
|
|
|
|
27,709
|
|
|
|
|
|
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partnership pro
forma
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
as
adjusted
|
|
|
|
Predecessor
combined
|
|
|
Nine months
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months
ended
|
|
|
ended
|
|
|
Year ended
|
|
|
|
Year ended
December 31,
|
|
|
September 30,
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
(in thousands,
except for operating and per unit data)
|
|
|
Operating Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput, MMBtu/d
|
|
|
820
|
|
|
|
757
|
|
|
|
715
|
|
|
|
904
|
|
|
|
778
|
|
|
|
904
|
|
|
|
878
|
|
Average rate per MMBtu
|
|
$
|
0.22
|
|
|
$
|
0.21
|
|
|
$
|
0.21
|
|
|
$
|
0.28
|
|
|
$
|
0.22
|
|
|
$
|
0.28
|
|
|
$
|
0.23
|
|
Third Party
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput, MMBtu/d
|
|
|
72
|
|
|
|
41
|
|
|
|
31
|
|
|
|
90
|
|
|
|
64
|
|
|
|
90
|
|
|
|
93
|
|
Average rate per MMBtu
|
|
$
|
0.19
|
|
|
$
|
0.16
|
|
|
$
|
0.13
|
|
|
$
|
0.25
|
|
|
$
|
0.21
|
|
|
$
|
0.25
|
|
|
$
|
0.23
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput, MMBtu/d
|
|
|
892
|
|
|
|
798
|
|
|
|
746
|
|
|
|
994
|
|
|
|
842
|
|
|
|
994
|
|
|
|
971
|
|
Average rate per MMBtu
|
|
$
|
0.21
|
|
|
$
|
0.21
|
|
|
$
|
0.21
|
|
|
$
|
0.28
|
|
|
$
|
0.22
|
|
|
$
|
0.28
|
|
|
$
|
0.23
|
|
|
|
|
(1) |
|
Adjusted EBITDA is defined in
Non-GAAP financial measure
below. |
15
NON-GAAP FINANCIAL
MEASURE
We define Adjusted EBITDA as net income (loss), plus interest
expense, income taxes and depreciation, less interest income and
other income (expense). We believe that the presentation of
Adjusted EBITDA provides information useful to investors in
assessing our financial condition and results of operations and
that Adjusted EBITDA is a widely accepted financial indicator of
a companys ability to incur and service debt, fund capital
expenditures and make distributions. Adjusted EBITDA is a
supplemental financial measure that management and external
users of our combined financial statements, such as industry
analysts, investors, lenders and rating agencies, may use to
assess:
|
|
Ø
|
our operating performance as compared to other publicly traded
partnerships in the midstream energy industry, without regard to
financing methods, capital structure or historical cost basis;
|
|
Ø
|
the ability of our assets to generate sufficient cash flow to
make distributions to our unitholders; and
|
|
Ø
|
the viability of acquisitions and capital expenditure projects
and the returns on investment of various investment
opportunities.
|
The GAAP measures most directly comparable to Adjusted EBITDA
are net income and net cash provided by operating activities.
Our non-GAAP financial measure of Adjusted EBITDA should not be
considered as an alternative to GAAP net income or net cash
provided by operating activities. Adjusted EBITDA has important
limitations as an analytical tool because it excludes some but
not all items that affect net income and net cash provided by
operating activities. You should not consider Adjusted EBITDA in
isolation or as a substitute for analysis of our results as
reported under GAAP. Because Adjusted EBITDA may be defined
differently by other companies in our industry, our definition
of Adjusted EBITDA may not be comparable to similarly titled
measures of other companies, thereby diminishing its utility.
Management compensates for the limitations of Adjusted EBITDA as
an analytical tool by reviewing the comparable GAAP measures,
understanding the differences between Adjusted EBITDA and net
income and net cash provided by operating activities, and
incorporating this knowledge into its 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.
The following table presents a reconciliation of the non-GAAP
financial measure of Adjusted EBITDA to the GAAP financial
measures of net income and net cash provided by operating
activities on an historical and pro forma as adjusted basis:
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partnership pro
forma
|
|
|
|
Predecessor
combined
|
|
|
as
adjusted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months
|
|
|
|
|
|
|
Year ended
|
|
|
Nine months
|
|
|
ended
|
|
|
Year ended
|
|
|
|
December 31,
|
|
|
ended
September 30,
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
(in
thousands)
|
|
|
Reconciliation of Adjusted EBITDA to Net Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
9,712
|
|
|
$
|
7,110
|
|
|
$
|
9,257
|
|
|
$
|
18,113
|
|
|
$
|
6,081
|
|
|
$
|
50,087
|
|
|
$
|
48,412
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense (income)
|
|
|
9,631
|
|
|
|
8,650
|
|
|
|
7,146
|
|
|
|
6,643
|
|
|
|
7,943
|
|
|
|
(15,022
|
)
|
|
|
(20,030
|
)
|
Income tax expense
|
|
|
3,814
|
|
|
|
4,789
|
|
|
|
5,504
|
|
|
|
10,469
|
|
|
|
1,740
|
|
|
|
160
|
|
|
|
978
|
|
Depreciation
|
|
|
18,009
|
|
|
|
15,447
|
|
|
|
14,841
|
|
|
|
17,104
|
|
|
|
12,635
|
|
|
|
17,104
|
|
|
|
19,710
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense)
|
|
|
(26
|
)
|
|
|
66
|
|
|
|
|
|
|
|
|
|
|
|
(25
|
)
|
|
|
|
|
|
|
(377
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
41,192
|
|
|
$
|
35,930
|
|
|
$
|
36,748
|
|
|
$
|
52,329
|
|
|
$
|
28,424
|
|
|
$
|
52,329
|
|
|
$
|
49,447
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Adjusted EBITDA to Net Cash Provided by
Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
27,323
|
|
|
$
|
30,131
|
|
|
$
|
31,160
|
|
|
$
|
41,810
|
|
|
$
|
12,941
|
|
|
$
|
66,880
|
|
|
$
|
64,888
|
|
Interest expense (income)
|
|
|
9,631
|
|
|
|
8,650
|
|
|
|
7,146
|
|
|
|
6,643
|
|
|
|
7,943
|
|
|
|
(15,022
|
)
|
|
|
(20,030
|
)
|
Current income tax expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,406
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
Other income (expense)
|
|
|
(26
|
)
|
|
|
66
|
|
|
|
|
|
|
|
|
|
|
|
(25
|
)
|
|
|
|
|
|
|
(377
|
)
|
Changes in operating working capital:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(374
|
)
|
|
|
662
|
|
|
|
(933
|
)
|
|
|
1,062
|
|
|
|
1,410
|
|
|
|
1,062
|
|
|
|
(374
|
)
|
Accounts payable and accrued expenses
|
|
|
4,556
|
|
|
|
(3,373
|
)
|
|
|
551
|
|
|
|
(580
|
)
|
|
|
6,015
|
|
|
|
(580
|
)
|
|
|
4,556
|
|
Other, including changes in non-current assets and liabilities
|
|
|
30
|
|
|
|
(74
|
)
|
|
|
(1,176
|
)
|
|
|
(12
|
)
|
|
|
90
|
|
|
|
(12
|
)
|
|
|
30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
41,192
|
|
|
$
|
35,930
|
|
|
$
|
36,748
|
|
|
$
|
52,329
|
|
|
$
|
28,424
|
|
|
$
|
52,329
|
|
|
$
|
49,447
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Includes impact of change in accounting principle.
|
17
Limited partner units 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. We urge you to
carefully consider the following risk factors together with all
of the other information included in this prospectus in
evaluating an investment in our common units.
If any of the following risks were to occur, our business,
financial condition or results of operations could be materially
adversely affected. In that case, we might not be able to pay
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 in us.
RISKS
RELATED TO OUR BUSINESS
We are dependent
on a single natural gas producer, Anadarko, for almost all of
the natural gas that we gather and transport. A material
reduction in Anadarkos production gathered or transported
by our assets would result in a material decline in our revenues
and cash available for distribution.
We rely on Anadarko for virtually all of the natural gas that we
gather and transport. For the nine months ended
September 30, 2007, Anadarko accounted for over 90% of our
natural gas gathering and transportation volumes. We may be
unable to negotiate on favorable terms, if at all, extensions or
replacements of our contracts to gather, compress, treat and
transport Anadarkos production. Furthermore, Anadarko may
suffer a decrease in production volumes in the areas serviced by
us and is under no contractual obligation to maintain its
production dedicated to us. The loss of a significant portion of
the natural gas volumes supplied by Anadarko would result in a
material decline in our revenues and our cash available for
distribution. In addition, Anadarko may determine in the future
that drilling activity in other areas of operation is
strategically more attractive. A shift in Anadarkos focus
away from our areas of operation could result in reduced
throughput on our system and a material decline in our revenues.
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 pay the
minimum quarterly distribution to holders of our common and
subordinated units.
In order to pay the minimum quarterly distribution of $0.30 per
unit per quarter, or $1.20 per unit per year, we will require
available cash of approximately $13.8 million per quarter,
or $55.3 million per year, based on the number of common
and subordinated units to be outstanding immediately after
completion of this offering. We may not have sufficient
available cash from operating surplus each quarter to enable us
to pay the minimum quarterly distribution. 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:
|
|
Ø
|
the prices of, level of production of and demand for natural gas;
|
|
Ø
|
the volume of natural gas we gather, compress, treat and
transport;
|
|
Ø
|
the volumes and prices of condensate that we retain and sell;
|
|
Ø
|
demand charges and volumetric fees associated with our
transportation services;
|
|
Ø
|
the level of competition from other midstream energy companies;
|
|
Ø
|
the level of our operating and maintenance and general and
administrative costs;
|
18
Risk
factors
|
|
Ø
|
regulatory action affecting the supply of or demand for natural
gas, the rates we can charge, how we contract for services, our
existing contracts, our operating costs or our operating
flexibility; and
|
|
Ø
|
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:
|
|
Ø
|
the level of capital expenditures we make;
|
|
Ø
|
the cost of acquisitions;
|
|
Ø
|
our debt service requirements and other liabilities;
|
|
Ø
|
fluctuations in our working capital needs;
|
|
Ø
|
our ability to borrow funds and access capital markets;
|
|
Ø
|
restrictions contained in debt agreements to which we are a
party; and
|
|
Ø
|
the amount of cash reserves established by our general partner.
|
For a description of additional restrictions and factors that
may affect our ability to make cash distributions, please read
Our cash distribution policy and restrictions on
distributions.
The amount of
cash we have available for distribution to holders of our common
and subordinated units depends primarily on our cash flow rather
than on our profitability, which may prevent us from making
distributions, even during periods in which we record net
income.
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.
The amount of available cash we need to pay the minimum
quarterly distribution on all of our units to be outstanding
immediately after this offering and the corresponding
distribution on our general partners 2.0% interest for
four quarters is approximately $55.3 million. The amounts
of pro forma available cash generated during each of the year
ended December 31, 2006 and twelve months ended
September 30, 2007 would have been sufficient to allow us
to pay the full minimum quarterly distribution on all of our
common and subordinated units for such periods. For a
calculation of our ability to make distributions to unitholders
based on our pro forma results for 2006, please read Our
cash distribution policy and restrictions on distributions.
The assumptions
underlying the forecast of cash available for distribution that
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 forecast of cash available for distribution set forth in
Our cash distribution policy and restrictions on
distributions includes our forecasted results of
operations, Adjusted EBITDA and cash available for distribution
for the twelve months ending December 31, 2008. The
financial forecast has been prepared by management, and we have
not received an opinion or report on it from our or any other
independent auditor. The assumptions underlying the forecast 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 the
forecasted results, we may not be able to pay the full minimum
quarterly distribution or any amount on our common or
subordinated units, in which event the market price of our
common units may decline materially.
19
Risk
factors
Because of the
natural decline in production from existing wells, our success
depends on our ability to obtain new sources of natural gas,
which is dependent on certain factors beyond our control. Any
decrease in the volumes of natural gas that we gather and
transport could adversely affect our business and operating
results.
The volumes that support our business are dependent on the level
of production from natural gas wells connected to our gathering
systems, the production of which will naturally decline over
time. As a result, our cash flows associated with these wells
will also decline over time. In order to maintain or increase
throughput levels on our gathering systems, we must obtain new
sources of natural gas. The primary factors affecting our
ability to obtain non-dedicated sources of natural gas include
(i) the level of successful drilling activity near our
systems and (ii) our ability to compete for volumes from
successful new wells.
While Anadarko has dedicated production from certain of its
properties to us, we have no control over the level of drilling
activity in our areas of operation, the amount of reserves
associated with wells connected to our gathering systems or the
rate at which production from a well declines. In addition, we
have no control over Anadarko or other producers or their
drilling or production decisions, which are affected by, among
other things, the availability and cost of capital, prevailing
and projected energy prices, demand for hydrocarbons, levels of
reserves, geological considerations, governmental regulations,
the availability of drilling rigs and other production and
development costs. Fluctuations in energy prices can also
greatly affect investments by Anadarko and third parties in the
development of new natural gas reserves. Declines in natural gas
prices could have a negative impact on exploration, development
and production activity, and if sustained, could lead to a
material decrease in such activity. Sustained reductions in
exploration or production activity in our areas of operation
would lead to reduced utilization of our gathering and treating
assets.
Because of these factors, even if new natural gas reserves are
known to exist in areas served by our assets, producers may
choose not to develop those reserves. Moreover, Anadarko may not
develop the acreage it has dedicated to us. If competition or
reductions in drilling activity result in our inability to
maintain the current levels of throughput on our systems, it
could reduce our revenue and impair our ability to make cash
distributions to our unitholders.
We typically do
not obtain independent evaluations of natural gas reserves
connected to our gathering and transportation systems;
therefore, in the future, volumes of natural gas on our systems
could be less than we anticipate.
We typically do not obtain independent evaluations of natural
gas reserves connected to our systems. Accordingly, we do not
have independent estimates of total reserves dedicated to our
systems or the anticipated life of such reserves. If the total
reserves or estimated life of the reserves connected to our
gathering systems are less than we anticipate and we are unable
to secure additional sources of natural gas, it could have a
material adverse effect on our business, results of operations,
financial condition and our ability to make cash distributions
to you.
Lower natural gas
and oil prices could adversely affect our business.
Lower natural gas and oil prices could impact natural gas and
oil exploration and production activity levels and result in a
decline in the production of natural gas and condensate,
resulting in reduced throughput on our systems. Any such decline
may cause our current or potential customers to delay drilling
or shut in production. In addition, such a decline would reduce
the amount of condensate we retain and sell. As a result, lower
natural gas prices could have an adverse effect on our business,
results of operations, financial condition and our ability to
make cash distributions to you.
20
Risk
factors
In general terms, the prices of natural gas, oil, condensate,
NGLs and other hydrocarbon products fluctuate in response to
changes in supply and demand, market uncertainty and a variety
of additional factors that are beyond our control. These factors
include:
|
|
Ø
|
worldwide economic conditions;
|
|
Ø
|
weather conditions and seasonal trends;
|
|
Ø
|
the levels of domestic production and consumer demand;
|
|
Ø
|
the availability of imported liquified natural gas, or LNG;
|
|
Ø
|
the availability of transportation systems with adequate
capacity;
|
|
Ø
|
the volatility and uncertainty of regional pricing differentials
such as in the Mid-Continent;
|
|
Ø
|
the price and availability of alternative fuels;
|
|
Ø
|
the effect of energy conservation measures;
|
|
Ø
|
the nature and extent of governmental regulation and taxation;
and
|
|
Ø
|
the anticipated future prices of natural gas, LNG and other
commodities.
|
Our industry is
highly competitive, and increased competitive pressure could
adversely affect our business and operating results.
We compete with similar enterprises in our areas of operation.
Our competitors may expand or construct gathering, compression,
treating or transportation systems that would create additional
competition for the services we provide to our customers. In
addition, our customers, including Anadarko, may develop their
own gathering, compression, treating or 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 cash flow 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 operating
income could be affected by a change in oil prices relative to
the price of natural gas.
Under our gathering agreements, we retain and sell condensate,
which falls out of the natural gas stream during the gathering
process, and compensate shippers with a thermally equivalent
volume of natural gas. Condensate sales comprised approximately
9% of our gathering system revenues for the nine months ended
September 30, 2007. The price we receive for our condensate
is generally tied to the market price of oil. The relationship
between natural gas prices and oil prices therefore affects the
margin on our condensate sales. When natural gas prices are high
relative to oil prices, the profit margin we realize on our
condensate sales is low due to the higher value of natural gas.
Correspondingly, when natural gas prices are low relative to oil
prices, the profit margin is high.
If third-party
pipelines or other facilities interconnected to our gathering or
transportation systems become partially or fully unavailable, or
if the volumes we gather or transport do not meet the natural
gas quality requirements of such pipelines or facilities, our
revenues and cash available for distribution could be adversely
affected.
Our natural gas gathering and transportation systems connect to
other pipelines or facilities, the majority of which are owned
by third parties. The continuing operation of such
third-party
pipelines or facilities is not within our control. If any of
these pipelines or facilities becomes unable to transport
natural gas, or if the volumes we gather or transport do not
meet the natural gas quality requirements of such pipelines or
facilities, our revenues and cash available for distribution
could be adversely affected.
21
Risk
factors
Our interstate
natural gas transportation operations are subject to regulation
by FERC, which could have an adverse impact on our ability to
establish transportation rates that would allow us to earn a
reasonable return on our investment, or even recover the full
cost of operating our pipeline, thereby adversely impacting our
ability to make distributions to you.
MIGC, our interstate natural gas transportation system, is
subject to regulation by the Federal Energy Regulatory
Commission, or FERC, under the Natural Gas Act of 1938, or the
NGA, and the Energy Policy Act of 2005, or the EPAct 2005.
Under the NGA, FERC has the authority to regulate natural gas
companies that provide natural gas pipeline transportation
services in interstate commerce. Federal regulation extends to
such matters as:
|
|
Ø |
rates, services and terms and conditions of service;
|
|
|
Ø
|
the types of services MIGC may offer to its customers;
|
|
Ø
|
the certification and construction of new facilities;
|
|
Ø
|
the acquisition, extension, disposition or abandonment of
facilities;
|
|
Ø
|
the maintenance of accounts and records;
|
|
Ø
|
relationships between affiliated companies involved in certain
aspects of the natural gas business;
|
|
Ø
|
the initiation and discontinuation of services;
|
|
Ø
|
market manipulation in connection with interstate sales,
purchases or transportation of natural gas; and
|
|
Ø
|
participation by interstate pipelines in cash management
arrangements.
|
Natural gas companies are prohibited from charging rates that
have been determined to be not just and reasonable by FERC. In
addition, FERC prohibits natural gas companies from unduly
preferring or unreasonably discriminating against any person
with respect to pipeline rates or terms and conditions of
service.
The rates and terms and conditions for our interstate pipeline
services are set forth in a FERC-approved tariff. Pursuant to
FERCs jurisdiction over rates, existing rates may be
challenged by complaint and proposed rate increases may be
challenged by protest. Any successful complaint or protest
against our rates could have an adverse impact on our revenues
associated with providing transportation service.
Should we fail to comply with all applicable FERC-administered
statutes, rules, regulations and orders, we could be subject to
substantial penalties and fines. Under the EPAct 2005, FERC has
civil penalty authority under the NGA to impose penalties for
current violations of up to $1,000,000 per day for each
violation. FERC also has the power to order disgorgement of
profits from transactions deemed to violate the NGA and EPAct
2005.
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 could result in increased regulation of
our assets, which could cause our revenues to decline and
operating expenses to increase.
Section 1(b) of the NGA exempts natural gas gathering
facilities from the jurisdiction of FERC. We believe that our
natural gas pipelines, other than MIGC, meet the traditional
tests FERC has used to determine if a pipeline is a gathering
pipeline and is, therefore, not subject to FERC jurisdiction.
The distinction between FERC-regulated transmission services and
federally unregulated gathering services is the subject of
substantial ongoing litigation and, over time, FERC policy
concerning where to draw the line between activities it
regulates and activities excluded from its regulation has
changed. The classification and regulation of our gathering
facilities are subject to change based on future determinations
by FERC, the courts or Congress. State regulation of gathering
facilities generally includes various safety, environmental and,
in some circumstances, nondiscriminatory take requirements
22
Risk
factors
and complaint-based rate regulation. In recent years, FERC has
taken a more light-handed approach to regulation of the
gathering activities of interstate pipeline transmission
companies, which has resulted in a number of such companies
transferring gathering facilities to unregulated affiliates. As
a result of these activities, natural gas gathering may begin to
receive greater regulatory scrutiny at both the state and
federal levels.
FERC regulation
of MIGC, including the outcome of certain FERC proceedings on
the appropriate treatment of tax allowances included in
regulated rates and the appropriate return on equity, may reduce
our transportation revenues, affect our ability to include
certain costs in regulated rates and increase our costs of
operations, and thus adversely affect our cash available for
distribution.
FERC has pending certain proceedings concerning the appropriate
allowance for income taxes that may be included in cost-based
rates for FERC regulated pipelines owned by publicly traded
partnerships that do not directly pay federal income tax. FERC
issued a policy permitting such tax allowances in 2005.
FERCs policy and its initial application in a specific
case were upheld on appeal by the D.C. Circuit in May of 2007
and the D.C. Circuits decision is final. In December 2006,
FERC issued another order addressing the income tax allowance in
rates, in which it reaffirmed prior statements regarding its
income tax allowance policy, but raised a new issue regarding
the implication of the policy statement for publicly traded
partnerships. FERC noted that the tax deferral features of a
publicly traded partnership may cause some investors to receive,
for some indeterminate duration, cash distributions in excess of
their taxable income, creating an opportunity for those
investors to earn an additional return, funded by ratepayers.
Responding to this concern, FERC adjusted the equity rate of
return of the pipeline at issue downward based on the percentage
by which the publicly traded partnerships cash flow
exceeded taxable income. Rehearing is currently pending before
FERC.
FERC also has pending a proceeding on the appropriate
composition of proxy groups for purposes of determining natural
gas and oil pipeline equity returns to be included in
cost-of-service based rates. In a policy statement issued
July 19, 2007, FERC proposed to permit inclusion of
publicly traded partnerships in the proxy group analysis
relating to return on equity determinations in rate proceedings,
provided that the analysis be limited to actual publicly traded
partnership distributions capped at the level of the
pipelines earnings and that evidence be provided in the
form of a multiyear analysis of past earnings demonstrating a
publicly traded partnerships ability to provide stable
earnings over time. In November 2007, the FERC requested
additional comments and announced a technical conference
regarding the method to be used for creating growth forecasts
for publicly traded partnerships.
The ultimate outcome of these proceedings is not certain and may
result in new policies being established at FERC that would
limit the amount of income tax allowance permitted to be
recovered in regulated rates or disallow the full use of
distributions to unitholders by pipeline publicly traded
partnerships in any proxy group comparisons used to determine
return on equity in future rate proceedings. Any such policy
developments may adversely affect the ability of MIGC to achieve
a reasonable level of return or impose limits on its ability to
include a full income tax allowance in cost of service, and
therefore could adversely affect our cash available for
distribution.
We are subject to
stringent environmental laws and regulations that may expose us
to significant costs and liabilities.
Our natural gas gathering, compression, treating and
transportation operations are subject to stringent and complex
federal, state and local environmental laws and regulations that
govern the discharge of materials into the environment or
otherwise relate to environmental protection. Examples of these
laws include:
|
|
Ø |
the federal Clean Air Act and analogous state laws that impose
obligations related to air emissions;
|
23
Risk
factors
|
|
Ø
|
the federal Comprehensive Environmental Response, Compensation
and Liability Act, also known as CERCLA or the Superfund law,
and analogous state laws that regulate the cleanup of hazardous
substances that may be or have been released at properties
currently or previously owned or operated by us or at locations
to which our wastes are or have been transported for disposal;
|
|
Ø
|
the federal Water Pollution Control Act, also known as the Clean
Water Act, and analogous state laws that regulate discharges
from our facilities into state and federal waters, including
wetlands;
|
|
Ø
|
the federal Resource Conservation and Recovery Act, also known
as RCRA, and analogous state laws that impose requirements for
the storage, treatment and disposal of solid and hazardous waste
from our facilities; and
|
|
Ø
|
the Toxic Substances Control Act, also known as TSCA, and
analogous state laws that impose requirements on the use,
storage and disposal of various chemicals and chemical
substances at our facilities.
|
These laws and regulations may impose numerous obligations that
are applicable to our operations, including the acquisition of
permits to conduct regulated activities, the incurrence of
capital expenditures to limit or prevent releases of materials
from our pipelines and facilities, and the imposition of
substantial liabilities for pollution resulting from our
operations. Numerous governmental authorities, such as the
U.S. Environmental Protection Agency, or the EPA, and
analogous state agencies, have the power to enforce compliance
with these laws and regulations and the permits issued under
them, oftentimes requiring difficult and costly corrective
actions. Failure to comply with these laws, regulations and
permits may result in the assessment of administrative, civil
and criminal penalties, the imposition of remedial obligations
and the issuance of injunctions limiting or preventing some or
all of our operations.
There is an inherent risk of incurring significant environmental
costs and liabilities in connection with our operations due to
historical industry operations and waste disposal practices, our
handling of hydrocarbon wastes and potential emissions and
discharges related to our operations. Joint and several, strict
liability may be incurred, without regard to fault, under
certain of these environmental laws and regulations in
connection with discharges or releases of hydrocarbon wastes on,
under or from our properties and facilities, many of which have
been used for midstream activities for a number of years,
oftentimes by third parties not under our control. Private
parties, including the owners of the properties through which
our gathering or transportation systems pass and facilities
where our wastes are taken for reclamation or disposal, may also
have the right to pursue legal actions to enforce compliance as
well as to seek damages for non-compliance with environmental
laws and regulations or for personal injury or property damage.
In addition, changes in environmental laws and regulations occur
frequently, and any such changes that result in more stringent
and costly waste handling, storage, transport, disposal or
remediation requirements could have a material adverse effect on
our operations or financial position. We may not be able to
recover all or any of these costs from insurance. Please read
BusinessEnvironmental matters for more
information.
Our construction
of new assets may not result in revenue increases and will be
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 involve numerous
regulatory, environmental, political and legal uncertainties
that are beyond our control. Such expansion projects may also
require the expenditure of significant amounts of capital, and
financing may not be available on economically acceptable terms
or at all. If we undertake these projects, they may not be
completed on schedule, at the budgeted cost, or at all.
Moreover, our revenues may not increase immediately upon the
expenditure of funds on a particular project. For
24
Risk
factors
instance, if we expand a pipeline, the construction may occur
over an extended period of time, yet we will not receive any
material increases in revenues until the project is completed.
Moreover, we could construct facilities to capture anticipated
future growth in production in a region in which such growth
does not materialize. Since we are not engaged in the
exploration for and development of natural gas and oil reserves,
we often do not have access to third-party estimates of
potential reserves in an area prior to constructing facilities
in that 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 as a result
of the 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. We may be unable to obtain such rights-of-way and
may, therefore, be unable to connect new natural gas volumes to
our systems 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 Anadarko were
to limit divestitures of midstream assets to us or if we were to
be unable to make acquisitions on economically acceptable terms
from Anadarko or third parties, our future growth would be
limited, and the acquisitions we do make may reduce, rather than
increase, our cash generated from operations on a per unit
basis.
Our ability to grow depends, in part, on our ability to make
acquisitions that increase our cash generated from operations on
a per unit basis. The acquisition component of our strategy is
based, in large part, on our expectation of ongoing divestitures
of midstream energy assets by industry participants, including,
most notably, Anadarko. A material decrease in such divestitures
would limit our opportunities for future acquisitions and could
adversely affect our ability to grow our operations and increase
our distributions to our unitholders.
If we are unable to make accretive acquisitions from Anadarko or
third parties, either because we are (i) unable to identify
attractive acquisition candidates or negotiate acceptable
purchase contracts, (ii) unable to obtain financing for
these acquisitions on economically acceptable terms or
(iii) outbid by competitors, then our future growth and
ability to increase distributions will be limited. Furthermore,
even if we do make acquisitions that we believe will be
accretive, these acquisitions may nevertheless result in a
decrease in the cash generated from operations on a per unit
basis.
Any acquisition involves potential risks, including, among other
things:
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mistaken assumptions about volumes, revenues and costs,
including synergies;
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an inability to successfully integrate the assets or 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 geographic areas; and
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customer or key employee losses at the acquired businesses.
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If we consummate any future acquisitions, our capitalization and
results of operations may change significantly, and you will not
have the opportunity to evaluate the economic, financial and
other relevant information that we will consider in determining
the application of these funds and other resources.
25
Risk
factors
We do not own all
of the land on which our pipelines and facilities are located,
which could result in disruptions to our operations.
We do not own all of the land on which our pipelines and
facilities have been constructed, 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 if such rights-of-way lapse or terminate.
We obtain the rights to construct and operate our pipelines on
land owned by third parties and governmental agencies for a
specific period of time. Our loss of these rights, through our
inability to renew right-of-way contracts or otherwise, 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 for which we are not fully insured, our operations
and financial results could be adversely affected.
Our operations are subject to all of the risks and hazards
inherent in the gathering, compressing, treating and
transportation of natural gas, 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 and acts of terrorism;
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inadvertent damage from construction, farm and utility equipment;
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leaks of natural gas and other hydrocarbons or losses of natural
gas as a result of the malfunction of equipment or facilities;
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leaks of natural gas containing hazardous quantities of hydrogen
sulfide from our Pinnacle gathering system or Bethel treating
facility;
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fires and explosions; 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. These
risks may also result in curtailment or suspension of our
operations. A natural disaster or other hazard affecting the
areas in which we operate could have a material adverse effect
on our operations. We are not fully insured against all risks
inherent in our business. For example, we do not have any
property insurance on any of our underground pipeline systems
that would cover damage to the pipelines. In addition, although
we are insured for environmental pollution resulting from
environmental accidents that occur on a sudden and accidental
basis, we may not be insured against all environmental accidents
that might incur, some of which may result in toxic tort claims.
If a significant accident or event occurs for which we are not
fully insured, it could adversely affect our operations and
financial condition. Furthermore, we may not be able to maintain
or obtain insurance of the type and amount we desire at
reasonable rates. As a result of market conditions, premiums and
deductibles for certain of our insurance policies may
substantially increase. In some instances, certain insurance
could become unavailable or available only for reduced amounts
of coverage. Additionally, we may be unable to recover from
prior owners of our assets, pursuant to our indemnification
rights, for potential environmental liabilities.
26
Risk
factors
We are exposed to
the credit risk of Anadarko, and any material non-payment or
non-performance by Anadarko, including with respect to our
gathering and transportation agreements and our
$337.6 million note receivable, could reduce our ability to
make distributions to our unitholders.
We are dependent on Anadarko for the majority of our revenues.
In addition, we anticipate using the proceeds of this offering
to make a loan to Anadarko. Consequently, we are subject to the
risk of non-payment or non-performance by Anadarko, including
with respect to our gathering and transportation agreements and
our $337.6 million note receivable. Any such non-payment or
non-performance could reduce our ability to make distributions
to our unitholders. Furthermore, Anadarko is subject to its own
financial, operating and regulatory risks, which could increase
the risk of default on its obligations to us. We cannot predict
the extent to which Anadarkos business would be impacted
if conditions in the energy industry were to deteriorate nor can
we estimate the impact such conditions would have on
Anadarkos ability to perform under our gathering and
transportation agreements or note receivable. Further, unless
and until we receive full repayment of the $337.6 million
note from Anadarko, we will be subject to the risk of
non-payment or late payment of the interest payments and
principal of the note. Interest income on the note receivable
from Anadarko will be allocated in accordance with the general
profit and loss allocation provisions included in our
partnership agreement. Accordingly, any material non-payment or
non-performance by Anadarko could reduce our ability to make
distributions to our unitholders.
Anadarkos
credit facility and other debt instruments contain financial and
operating restrictions that may limit our access to credit. In
addition, our ability to obtain credit in the future may be
affected by Anadarkos credit rating.
We have the ability to incur up to $100 million of
indebtedness under Anadarkos $750 million credit
facility. However, this $100 million of borrowing capacity
will be available to us only to the extent that sufficient
amounts remain unborrowed by Anadarko. As a result, borrowings
by Anadarko could restrict our access to credit. In addition, if
we or Anadarko were to fail to comply with the terms of
Anadarkos credit facility, we could be unable to make any
borrowings under Anadarkos credit facility, even if
capacity were otherwise available. As a result, the restrictions
in Anadarkos credit facility could adversely affect our
ability to finance our future operations or capital needs or to
engage in, expand or pursue our business activities, and could
also prevent us from engaging in certain transactions that might
otherwise be considered beneficial to us.
Anadarkos and our ability to comply with the terms of
Anadarkos debt instruments may be affected by events
beyond its and our control, including prevailing economic,
financial and industry conditions. If market or other economic
conditions deteriorate, Anadarkos and our ability to
comply with the terms of Anadarkos debt instruments may be
impaired. We and Anadarko are subject to financial covenants and
ratios under Anadarkos credit facility. Should we or
Anadarko fail to comply with such financial covenants and
ratios, we could be unable to make any borrowings under
Anadarkos credit facility. Additionally, a default by
Anadarko under one of Anadarkos debt instruments may cause
a cross-default under Anadarkos other debt instruments,
including the credit facility under which we are a co-borrower.
Accordingly, a breach by Anadarko of certain of the covenants or
ratios in another debt instrument could cause the acceleration
of any indebtedness we have outstanding under the credit
facility. In the event of an acceleration, we might not have, or
be able to obtain, sufficient funds to make the required
repayments of debt, finance our operations and pay distributions
to unitholders. For more information regarding our debt
agreements, please read Managements discussion and
analysis of financial condition and results of
operationsLiquidity and capital resources.
Due to our relationship with Anadarko, our ability to obtain
credit will be affected by Anadarkos credit rating. Even
if we obtain our own credit rating or separate financing
arrangement, any future change in Anadarkos credit rating
would likely also result in a change in our credit rating.
Regardless
27
Risk
factors
of whether we have our own credit rating, a downgrading of
Anadarkos credit rating could limit our ability to obtain
financing in the future upon favorable terms or at all.
Debt we incur in
the future may limit our flexibility to obtain financing and to
pursue other business opportunities.
Our future level of debt could have important consequences to
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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our funds available for operations, future business
opportunities and distributions to unitholders will be reduced
by that portion of our cash flow required to make interest
payments on our debt;
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we may be more vulnerable to competitive pressures or a downturn
in our business or the economy generally; and
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our flexibility in responding to changing business and economic
conditions may be limited.
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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 any 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 or seeking additional
equity capital. We may not be able to effect any of these
actions on satisfactory terms or at all.
Increases in
interest rates could adversely impact our unit price, our
ability to issue equity or incur debt for acquisitions or other
purposes and our ability to make cash distributions at our
intended levels.
Interest rates may increase in the future to counter possible
inflation. As a result, interest rates on future credit
facilities and debt offerings could be higher than current
levels, causing our financing costs to increase accordingly. As
with other yield-oriented securities, our unit price is impacted
by our level of our cash distributions and implied distribution
yield. The distribution yield is often used by investors to
compare and rank 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, our
ability to issue equity or incur debt for acquisitions or other
purposes and our ability to make cash distributions at our
intended levels.
RISKS
INHERENT IN AN INVESTMENT IN US
Anadarko owns and
controls our general partner, which has sole responsibility for
conducting our business and managing our operations. Anadarko
and our general partner have conflicts of interest and may favor
Anadarkos interests to your detriment.
Following this offering, Anadarko will own and control our
general partner, as well as appoint all of the officers and
directors of our general partner, some of whom will also be
officers of Anadarko. Although our general partner has a
fiduciary duty to manage us in a manner that is beneficial to us
and our unitholders, the directors and officers of our general
partner have a fiduciary duty to manage our general partner in a
manner that is beneficial to its owner, Anadarko. Conflicts of
interest may arise between Anadarko and 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
28
Risk
factors
interests of Anadarko over our interests and the interests of
our unitholders. These conflicts include the following
situations, among others:
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Neither our partnership agreement nor any other agreement
requires Anadarko to pursue a business strategy that favors us.
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Anadarko is not limited in its ability to compete with us and
may offer business opportunities or sell midstream assets to
parties other than us.
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Our general partner is allowed to take into account the
interests of parties other than us, such as Anadarko, in
resolving conflicts of interest.
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The officers of our general partner will also devote significant
time to the business of Anadarko and will be compensated by
Anadarko accordingly.
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Our partnership agreement limits the liability of and reduces
the fiduciary duties owed by of our general partner, and also
restricts the remedies available to our unitholders for actions
that, without the limitations, might constitute breaches of
fiduciary duty.
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Except in limited circumstances, our general partner has the
power and authority to conduct our business without unitholder
approval.
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Our general partner determines the amount and timing of asset
purchases and sales, borrowings, issuance of additional
partnership securities and the creation, reduction or increase
of reserves, each of which can affect the amount of cash that is
distributed to our unitholders.
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Our general partner determines the amount and timing of any
capital expenditures and whether a capital expenditure is
classified as a maintenance capital expenditure, which reduces
operating surplus, or an expansion capital expenditure, which
does not reduce operating surplus. This determination can affect
the amount of cash that is distributed to our unitholders and to
our general partner and the ability of the subordinated units to
convert to common units.
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Our general partner determines which costs incurred by it are
reimbursable by us.
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Our general partner may cause us to borrow funds in order to
permit the payment of cash distributions, even if the purpose or
effect of the borrowing is to make a distribution on the
subordinated units, to make incentive distributions or to
accelerate the expiration of the subordination period.
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Our partnership agreement permits us to classify up to
$27.1 million as operating surplus, even if it is generated
from asset sales, non-working capital borrowings or other
sources that would otherwise constitute capital surplus. This
cash may be used to fund distributions on our subordinated units
or to our general partner in respect of the general partner
interest or the incentive distribution rights.
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Our partnership agreement does not restrict our general partner
from causing us to pay it or its affiliates for any services
rendered to us or entering into additional contractual
arrangements with any of these entities on our behalf.
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Our general partner intends to limit its liability regarding our
contractual and other obligations.
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Our general partner may exercise its right to call and purchase
all of the common units not owned by it and its affiliates if
they own more than 80% of the common units.
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Our general partner controls the enforcement of the obligations
that it and its affiliates owe to us.
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Our general partner decides whether to retain separate counsel,
accountants or others to perform services for us.
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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
special committee of the board of directors of our general
partner or our
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29
Risk
factors
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unitholders. This election may result in lower distributions to
our common unitholders in certain situations.
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Please read Conflicts of interest and fiduciary
duties.
Anadarko is not
limited in its ability to compete with us and is not obligated
to offer us the opportunity to acquire additional assets or
businesses, which could limit our ability to grow and could
adversely affect our results of operations and cash available
for distribution to our unitholders.
Anadarko is not prohibited from owning assets or engaging in
businesses that compete directly or indirectly with us. In
addition, in the future, Anadarko may acquire, construct or
dispose of additional midstream or other assets and may be
presented with new business opportunities, without any
obligation to offer us the opportunity to purchase or construct
such assets or to engage in such business opportunities.
Moreover, while Anadarko may offer us the opportunity to buy
additional assets from it, it is under no contractual obligation
to do so and we are unable to predict whether or when such
acquisitions might be completed.
Cost
reimbursements due to Anadarko and our general partner for
services provided to us or on our behalf will be substantial and
will reduce our cash available for distribution to you. The
amount and timing of such reimbursements will be determined by
our general partner.
Prior to making distributions on our common units, we will
reimburse our general partner and its affiliates for all
expenses they incur on our behalf. These expenses will include
all costs incurred by Anadarko and our general partner in
managing and operating us. While our reimbursement of allocated
general and administrative expenses is capped under the omnibus
agreement, we are required to reimburse Anadarko and our general
partner for all direct operating expenses incurred on our
behalf. These direct operating expense reimbursements and the
reimbursement of incremental general and administrative expenses
we will incur as a result of becoming a publicly traded
partnership are not capped. Our partnership agreement provides
that our general partner will determine in good faith the
expenses that are allocable to us. The reimbursements to
Anadarko and our general partner will reduce the amount of cash
otherwise available for distribution to our unitholders.
Our general
partner intends to limit its liability regarding our
obligations.
Our general partner intends to limit its liability under
contractual arrangements so that the counterparties to such
arrangements have recourse only against our assets, and not
against our general partner or its assets. Our general partner
may therefore cause us to incur indebtedness or other
obligations that are nonrecourse to our general partner. Our
partnership agreement provides that any action taken by our
general partner to limit its liability is not a breach of our
general partners fiduciary duties, even if we could have
obtained more favorable terms without the limitation on
liability. In addition, we are obligated to reimburse or
indemnify our general partner to the extent that it incurs
obligations on our behalf. Any such reimbursement or
indemnification payments would reduce the amount of cash
otherwise available for distribution to our unitholders.
Our partnership
agreement requires that we distribute all of our available cash,
which could limit our ability to grow and make
acquisitions.
We expect that we will distribute all of our available cash to
our unitholders and 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.
Furthermore, we anticipate using substantially all of the net
proceeds of this offering to
30
Risk
factors
make a loan to Anadarko, and therefore, the net proceeds of this
offering will not be directly used to grow our business.
In addition, because we distribute all of our available cash,
our growth may not be as fast as that of 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. There are no limitations in our partnership
agreement or in Anadarkos credit facility, under which we
are a co-borrower, 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 partnership
agreement limits our general partners fiduciary duties to
holders of our common and subordinated units.
Our partnership agreement contains provisions that modify and
reduce the fiduciary standards to which our general partner
would otherwise be held by state fiduciary duty law. For
example, our partnership agreement permits our general partner
to make a number of decisions in its individual capacity, as
opposed to in its capacity as our general partner, or otherwise
free of fiduciary duties to us and our unitholders. This
entitles our general partner to consider only the interests and
factors that it desires and relieves it of any duty or
obligation to give any consideration to any interest of, or
factors affecting, us, our affiliates or our limited partners.
Examples of decisions that our general partner may make in its
individual capacity include:
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how to allocate corporate opportunities among us and its
affiliates;
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whether to exercise its limited call right;
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how to exercise its voting rights with respect to the units it
owns;
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whether to exercise its registration rights;
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whether to elect to reset target distribution levels; and
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whether or not to consent to any merger or consolidation of the
partnership or amendment to the partnership agreement.
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By purchasing a common unit, a common unitholder agrees to
become bound by the provisions in the partnership agreement,
including the provisions discussed above. Please read
Conflicts of interest and fiduciary dutiesFiduciary
duties.
Our partnership
agreement restricts the remedies available to holders of our
common and subordinated units for actions taken by our general
partner that might otherwise constitute breaches of fiduciary
duty.
Our partnership agreement contains provisions that restrict the
remedies available to unitholders for actions taken by our
general partner that might otherwise constitute breaches of
fiduciary duty under state fiduciary duty law. For example, our
partnership agreement:
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provides that whenever our general partner makes a determination
or takes, or declines to take, any other action in its capacity
as our general partner, our general partner is required to make
such determination, or take or decline to take such other
action, in good faith, and will not be subject to any other or
different standard imposed by our partnership agreement,
Delaware law, or any other law, rule or regulation, or at equity;
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31
Risk
factors
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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 such decisions are made in good
faith, meaning that it believed that the decision was in the
best interest of our partnership;
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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 their assignees resulting from any act or omission
unless there has been a final and non-appealable judgment
entered by a court of competent jurisdiction determining that
our general partner or its officers and directors, as the case
may be, 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 our general partner will not be in breach of its
obligations under the partnership agreement or its fiduciary
duties to us or our unitholders if a transaction with an
affiliate or the resolution of a conflict of interest is:
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(a)
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approved by the special committee of the board of directors of
our general partner, although our general partner is not
obligated to seek such approval;
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(b)
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approved by the vote of a majority of the outstanding common
units, excluding any common units owned by our general partner
and its affiliates;
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(c)
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on terms no less favorable to us than those generally being
provided to or available from unrelated third parties; or
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(d)
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fair and reasonable to us, taking into account the totality of
the relationships among the parties involved, including other
transactions that may be particularly favorable or advantageous
to us.
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In connection with a situation involving a transaction with an
affiliate or a conflict of interest, any determination by our
general partner must be made in good faith. If an affiliate
transaction or the resolution of a conflict of interest is not
approved by our common unitholders or the special committee and
the board of directors of our general partner determines that
the resolution or course of action taken with respect to the
affiliate transaction or conflict of interest satisfies either
of the standards set forth in subclauses (c) and (d) above, then
it will be presumed that, in making its decision, the board of
directors acted in good faith, and in any proceeding brought by
or on behalf of any limited partner or the partnership, the
person bringing or prosecuting such proceeding will have the
burden of overcoming such presumption.
Our general
partner may elect to cause us to issue Class B and general
partner units to it in connection with a resetting of the target
distribution levels related to its incentive distribution
rights, without the approval of the special committee of its
board of directors or the holders of our common units. This
could result in lower distributions to holders of our common
units.
Our general partner has the right, at any 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 target distribution levels at higher levels based on
our distributions at the time of the exercise of the reset
election. Following a reset election by our general partner, the
minimum quarterly distribution will be adjusted to equal 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.
If our general partner elects to reset the target distribution
levels, it will be entitled to receive a number of Class B
units and general partner 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 to our
general partner will be equal to that number of common units
which would have entitled their holder to an average aggregate
quarterly cash distribution in the prior two quarters equal to
the average of the distributions to our general partner on
32
Risk
factors
the incentive distribution rights in the prior two quarters. Our
general partner will be issued the number of general partner
units necessary to maintain our general partners interest
in us that existed immediately prior to the reset election. 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. It is
possible, however, that our general partner could exercise this
reset election at a time when it is experiencing, or expects to
experience, declines in the cash distributions it receives
related to its incentive distribution rights and may, therefore,
desire to be issued Class B units, which are entitled to
distributions 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 a
reduction in the amount of cash distributions that our common
unitholders would have otherwise received had we not issued new
Class B units and general partner units to our general
partner in connection with resetting the target distribution
levels. Please read Provisions of our partnership
agreement relating to cash distributionsGeneral
partners right to reset target distribution levels.
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 have no right on an annual or ongoing basis to elect our
general partner or its board of directors. The board of
directors of our general partner will be chosen by Anadarko.
Furthermore, if the unitholders are dissatisfied with the
performance of our general partner, they will have little
ability to remove our general partner. As a result of these
limitations, the price at which the common units will trade
could be diminished because of the absence or reduction of a
takeover premium in the trading price. 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.
Even if holders
of our common units are dissatisfied, they cannot initially
remove our general partner without its consent.
The unitholders initially will be unable 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 our general partner. Following the closing of
this offering, Anadarko will own 58.5% of our 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 our general
partner liable for actual fraud, gross negligence 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 our 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.
33
Risk
factors
Our partnership
agreement restricts the voting rights of unitholders owning 20%
or more of our common units.
Unitholders voting rights are further restricted by a
provision of our partnership agreement 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 general
partner interest or the control of our general partner may be
transferred to a third party without unitholder
consent.
Our general partner may transfer its general partner interest to
a third party in a merger or in a sale of all or substantially
all of its assets without the consent of the unitholders.
Furthermore, our partnership agreement does not restrict the
ability of Anadarko to transfer all or a portion of its
ownership interest in our general partner to a third party. The
new owner 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 designees and thereby exert significant
control over the decisions made by the board of directors and
officers.
You will
experience immediate and substantial dilution in pro forma net
tangible book value of $5.09 per common unit.
The estimated initial public offering price of $20.00 per common
unit exceeds our pro forma net tangible book value of $14.91 per
unit. Based on the estimated initial public offering price of
$20.00 per common unit, you will incur immediate and substantial
dilution of $5.09 per common unit. This dilution results
primarily because the assets contributed by our general partner
and its affiliates are recorded in accordance with GAAP at their
historical cost, and not their fair value. Please read
Dilution.
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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|
Ø
|
our existing unitholders proportionate ownership interest
in us will decrease;
|
|
Ø
|
the amount of cash available for distribution on each unit may
decrease;
|
|
Ø
|
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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Ø
|
the ratio of taxable income to distributions may increase;
|
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Ø
|
the relative voting strength of each previously outstanding unit
may be diminished; and
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Ø
|
the market price of the common units may decline.
|
Anadarko may sell
units in the public or private markets, and such sales could
have an adverse impact on the trading price of the common
units.
After the sale of the common units offered by this prospectus,
assuming that the underwriters do not exercise their option to
purchase additional common units, Anadarko will hold an
aggregate of 3,823,925 common units and 22,573,925 subordinated
units. All of the subordinated units will convert into common
units at the end of the subordination period and may convert
earlier under certain
34
Risk
factors
circumstances. The sale of these units in the public or private
markets could have an adverse impact on the price of the common
units or on any trading market that may develop.
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, which it may assign to any of its affiliates or to us,
but not the obligation, to acquire all, but not less than all,
of the common units held by unaffiliated persons at a price that
is 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 completion of this offering, and assuming no exercise of the
underwriters option to purchase additional common units,
Anadarko will own approximately 16.9% of our outstanding common
units. At the end of the subordination period, assuming no
additional issuances of common units (other than upon the
conversion of the subordinated units), Anadarko will own
approximately 58.5% of our outstanding common units. For
additional information about this right, please read The
partnership agreementLimited 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 a number of other states. 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 a court or government agency were to
determine that:
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Ø
|
we were conducting business in a state but had not complied with
that particular states partnership statute; or
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Ø
|
your right to act with other unitholders to remove or replace
our general partner, to approve some amendments to our
partnership agreement or to take other actions under our
partnership agreement constitute control of our
business.
|
For a discussion of the implications of the limitations of
liability on a unitholder, please read The partnership
agreementLimited 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
an impermissible distribution, limited partners who received the
distribution and who knew at the time of the distribution that
it violated Delaware law will be liable to the limited
partnership for the distribution amount. Substituted limited
partners are liable both for the obligations of the assignor to
make contributions to the partnership that were known to the
substituted limited partner at the time it became a limited
partner and for those obligations that were unknown if the
liabilities could have been determined from the partnership
agreement. Neither liabilities to partners on account of their
partnership interest nor liabilities that are non-recourse to
the partnership are counted for purposes of determining whether
a distribution is permitted.
35
Risk
factors
There is no
existing market for our common units, and a trading market that
will provide you with adequate liquidity may not develop. The
price of our common units may fluctuate significantly, and you
could lose all or part of your investment.
Prior to this offering, there has been no public market for our
common units. After this offering, there will be only 18,750,000
publicly traded common units, assuming no exercise of the
underwriters option to purchase additional common units.
In addition, Anadarko will own 3,823,925 common and 22,573,925
subordinated units, representing an aggregate 57.3% ownership
interest in us. We do not know the extent to which investor
interest will lead to the development of a trading market or how
liquid that market might be. You may not be able to resell your
common units at or above the initial public offering price.
Additionally, the lack of liquidity may result in wide bid-ask
spreads, contribute to significant fluctuations in the market
price of the common units and limit the number of investors who
are able to buy the common units.
The initial public offering price for the common units will be
determined by negotiations between us and the representatives of
the underwriters and may not be indicative of the market price
of the common units that will prevail in the trading market. The
market price of our common units may decline below the initial
public offering price. The market price of our common units may
also be influenced by many factors, some of which are beyond our
control, including:
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Ø
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our quarterly distributions;
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Ø
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our quarterly or annual earnings or those of other companies in
our industry;
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Ø
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the loss of a large customer;
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Ø
|
announcements by us or our competitors of significant contracts
or acquisitions;
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Ø
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changes in accounting standards, policies, guidance,
interpretations or principles;
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Ø
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general economic conditions;
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Ø
|
the failure of securities analysts to cover our common units
after this offering or changes in financial estimates by
analysts;
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Ø
|
future sales of our common units; and
|
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Ø
|
other factors described in these Risk factors.
|
We will incur
increased costs as a result of being a publicly traded
partnership.
We have no history operating as a publicly traded partnership.
As a publicly traded partnership, we will incur significant
legal, accounting and other expenses. In addition, the
Sarbanes-Oxley Act of 2002 and related rules subsequently
implemented by the SEC and the New York Stock Exchange, or the
NYSE, have required changes in the corporate governance
practices of publicly traded companies. We expect these 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 partnership,
we are required to have at least three independent directors,
create an audit committee 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 partnership 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
to possibly result in our general partner having to accept
reduced policy limits and 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 partnership in our financial forecast included
elsewhere in this prospectus. However, it is possible that our
actual incremental costs of being a publicly traded partnership
will be higher than we currently estimate. These costs are not
36
Risk
factors
subject to the $6.0 million cap in the omnibus agreement
applicable to general and administrative expenses allocable to
us by Anadarko.
If we are deemed
to be an investment company under the Investment
Company Act of 1940, it would adversely affect the price of our
common units and could have a material adverse effect on our
business.
Our initial assets will consist of our ownership interests in
our operating subsidiaries as well as a $337.6 million note
receivable from Anadarko. If this note receivable together with
a sufficient amount of our other assets are deemed to be
investment securities, within the meaning of the
Investment Company Act of 1940, or the Investment Company Act,
we would either have to register as an investment company under
the Investment Company Act, obtain exemptive relief from the SEC
or modify our organizational structure or contract rights so as
to fall outside of the definition of investment company.
Registering as an investment company could, among other things,
materially limit our ability to engage in transactions with
affiliates, including the purchase and sale of certain
securities or other property from or to our affiliates, restrict
our ability to borrow funds or engage in other transactions
involving leverage and require us to add additional directors
who are independent of us or our affiliates. The occurrence of
some or all of these events would adversely affect the price of
our common units and could have a material adverse effect on our
business.
Moreover, treatment of us as an investment company would prevent
our qualification as a partnership for federal income tax
purposes, in which case we would be treated as a corporation for
federal income tax purposes. As a result, we would pay federal
income tax on our taxable income at the corporate tax rate,
distributions to you would generally be taxed again as corporate
distributions and none of our income, gains, losses or
deductions would flow through to you. If we were taxed as a
corporation, our cash available for distribution to you would be
substantially reduced. Therefore, treatment of us as an
investment company 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. For a discussion of the federal income tax
implications that would result from our treatment as a
corporation in any taxable year, please read Material tax
consequencesPartnership status.
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 IRS were
to treat us as a corporation for federal income tax purposes or
we were to become subject to additional amounts of entity-level
taxation for state tax purposes, then our cash available for
distribution to you could be substantially reduced.
The anticipated after-tax economic benefit of an investment in
our common units depends largely on our being treated as a
partnership for federal income tax purposes. We have not
requested, and do not plan to request, a ruling from the
Internal Revenue Service, or the IRS, on this or any other tax
matter affecting us.
Despite the fact that we are classified as a limited partnership
under Delaware law, it is possible in certain circumstances for
a partnership such as ours to be treated as a corporation for
federal income tax purposes. Although we do not believe, based
upon our current operations, that we will be so treated, a
change in our business (or a change in current law) could cause
us to be treated as a corporation for federal income tax
purposes or otherwise subject us to taxation as an entity.
37
Risk
factors
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, deductions or
credits would flow through to you. Because a tax would be
imposed upon us as a corporation, our cash available for
distribution to you would be substantially reduced. 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, if we are deemed to be
an investment company, as described above, we would be subject
to such taxation. Moreover, at the federal level, legislation
has been proposed that would eliminate partnership tax treatment
for certain publicly traded partnerships. Although such
legislation would not apply to us as currently proposed, it
could be amended prior to enactment such that it would apply to
us. We are unable to predict whether any of these changes, or
other proposals, will ultimately be enacted. Any such changes
could negatively impact the value of an investment in our common
units.
At the state level, were we to be subject to federal income tax,
we would also be subject to the income tax provisions of many
states. Moreover, because of widespread state budget deficits
and other reasons, several states are evaluating ways to
independently subject partnerships to entity-level taxation
through the imposition of state income, franchise and other
forms of taxation. Specifically, beginning in 2008, we will be
required to pay Texas franchise tax at a maximum effective rate
of 0.7% of our gross income apportioned to Texas in the prior
year. Imposition of such a tax on us by Texas and, if
applicable, by any other state will reduce the cash available
for distribution to you.
Our 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 may be adjusted to reflect the
impact of that law on us.
We prorate our
items of income, gain, loss and deduction between transferors
and transferees of our units each month based upon the ownership
of our units on the first day of each month, instead of on the
basis of the date a particular unit is transferred. The IRS may
challenge this treatment, which could change the allocation of
items of income, gain, loss and deduction among our
unitholders.
We prorate our items of income, gain, loss and deduction between
transferors and transferees of our units each month based upon
the ownership of our units on the first day of each month,
instead of on the basis of the date a particular unit is
transferred. The use of this proration method may not be
permitted under existing Treasury regulations, and, accordingly,
our counsel is unable to opine as to the validity of this
method. If the IRS were to challenge this method or new Treasury
regulations were issued, we may be required to change the
allocation of items of income, gain, loss and deduction among
our unitholders. Please read Material tax
consequencesDisposition of common unitsAllocations
between transferors and transferees.
If the IRS
contests the federal income tax positions we take or the pricing
of our related party agreements with Anadarko, the market for
our common units may be adversely impacted and the cost of any
IRS 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, including the pricing of our
related party agreements with Anadarko. The IRS may adopt
positions that differ from the conclusions of our
38
Risk
factors
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. For example, the IRS may reallocate items of income,
deductions, credits or allowances between related parties if the
IRS determines that such reallocation is necessary to prevent
evasion of taxes or clearly to reflect the income of any such
related parties. Any contest with the IRS may materially and
adversely impact the market for our common units and the price
at which they trade. If the IRS were successful in any such
challenge, we may be required to change the allocation of items
of income, gain, loss and deduction among our unitholders and
our general partner. Such a reallocation may require us and our
unitholders to file amended tax returns. 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.
You will 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 whether or not you
receive cash distributions from us. You may not receive cash
distributions from us equal to your share of our taxable income
or even equal to the actual tax liability that results from that
income.
Tax gain or loss
on the 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. Because distributions in excess of
your allocable share of our net taxable income decrease your tax
basis in your common units, the amount, if any, of such prior
excess distributions with respect to the units you sell will, in
effect, become taxable income to you, if you sell such units at
a price greater than your tax basis in those units, even if the
price you receive is less than your original cost. Furthermore,
a substantial portion of the amount realized, whether or not
representing gain, may be taxed as ordinary income due to
potential recapture items, including depreciation recapture. In
addition, because the amount realized includes a
unitholders share of our nonrecourse liabilities, if you
sell your units, you may incur a tax liability in excess of the
amount of cash you receive from the sale. Please read
Material tax consequencesDisposition of common
unitsRecognition of gain or loss for a further
discussion of the foregoing.
Tax-exempt
entities and
non-U.S.
persons face unique tax issues from owning common units that may
result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as
employee benefit plans and individual retirement accounts (known
as IRAs), 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 U.S. federal tax returns and pay tax on
their share of our taxable income. If you are a tax-exempt
entity or a
non-U.S. person,
you should consult your tax advisor before investing in our
common units.
39
Risk
factors
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, we will adopt depreciation and amortization positions
that may not conform to all aspects of existing Treasury
Regulations. Our counsel is unable to opine on the validity of
such filing positions. 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 your sale of common units
and could have a negative impact on the value of our common
units or result in audit adjustments to your tax returns. Please
read Material tax consequencesTax consequences of
unit ownershipSection 754 election for a
further discussion of the effect of the depreciation and
amortization positions we adopt.
We will adopt
certain valuation methodologies that may result in a shift of
income, gain, loss and deduction between our general partner and
the unitholders. The IRS may challenge this treatment, which
could adversely affect the value of the common units.
When we issue additional units or engage in certain other
transactions, we will determine the fair market value of our
assets and allocate any unrealized gain or loss attributable to
our assets to the capital accounts of our unitholders and our
general partner. Our methodology may be viewed as understating
the value of our assets. In that case, there may be a shift of
income, gain, loss and deduction between certain unitholders and
our general partner, which may be unfavorable to such
unitholders. Moreover, under our valuation methods, subsequent
purchasers of common units may have a greater portion of their
Internal Revenue Code Section 743(b) adjustment allocated
to our tangible assets and a lesser portion allocated to our
intangible assets. The IRS may challenge our valuation methods,
or our allocation of the Section 743(b) adjustment
attributable to our tangible and intangible assets, and
allocations of income, gain, loss and deduction between our
general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could
adversely affect the amount of taxable income or loss being
allocated to our unitholders. It also could affect the amount of
gain from our unitholders sale of common units and could
have a negative impact on the value of the common units or
result in audit adjustments to our unitholders tax returns
without the benefit of additional deductions.
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. In the
case of a unitholder reporting on a taxable year other than a
fiscal year ending December 31, the closing of our taxable
year may also result in more than twelve months of our taxable
income or loss being includable in his taxable income for the
year of termination. Our termination currently would not affect
our classification as a partnership for federal income tax
purposes, but instead, we would be treated as a new partnership
for tax purposes. If treated as a new partnership, we must make
new tax elections and could be subject to penalties, if we are
unable to determine that a termination occurred. Please read
Material tax consequencesDisposition of common
unitsConstructive termination for a discussion of
the consequences of our termination for federal income tax
purposes.
40
Risk
factors
You will likely
be subject to state and local taxes and return filing
requirements in states where you do not live as a result of
investing in our common units.
In addition to federal income taxes, you will likely be subject
to 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 conduct business or own property, even if you do not
live in any of those jurisdictions. You will likely be required
to file foreign, state and local income tax returns and pay
state and local income taxes in some or all of these various
jurisdictions. Further, you may be subject to penalties for
failure to comply with those requirements. We will initially own
assets and conduct business in the states of Kansas, Oklahoma,
Texas, Utah and Wyoming. Each of these states, other than Texas
and Wyoming, currently imposes a personal income tax, and all of
theses states also impose income taxes on corporations and other
entities. As we make acquisitions or expand our business, we may
own assets or conduct business in additional states that impose
a personal income tax. It is your responsibility to file all
U.S. federal, foreign, 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.
41
We expect to receive gross proceeds of approximately
$375.0 million from the issuance and sale of 18,750,000
common units offered by this prospectus. We will use these
proceeds to (i) make a loan of $337.6 million to
Anadarko in exchange for a
30-year note
bearing interest at a fixed annual rate of 6.00%,
(ii) provide $10.0 million for general partnership
purposes and (iii) pay underwriting discounts and a
structuring fee totaling approximately $24.4 million and
other estimated offering expenses of $3.0 million.
Our estimates assume an initial public offering price of $20.00
per common unit and no exercise of the underwriters option
to purchase additional common units. An increase or decrease in
the initial public offering price of $1.00 per common unit would
cause the net proceeds from the offering, after deducting
underwriting discounts and the structuring fee, to increase or
decrease by $17.5 million. If the proceeds increase due to
a higher initial public offering price, we will use the
additional proceeds to reimburse Anadarko for capital
expenditures it incurred with respect to the assets contributed
to us during the two-year period prior to this offering. If the
proceeds decrease due to a lower initial public offering price,
our loan to Anadarko will decrease by such amount.
The proceeds from any exercise of the underwriters option
to purchase additional common units will be used to reimburse
Anadarko for capital expenditures it incurred with respect to
the assets contributed to us during the two-year period prior to
this offering.
Anadarko has informed us that it intends to use the
$337.6 million of proceeds that we loan to it, and any
other proceeds that it receives from this offering, to repay a
portion of the amount outstanding under its
354-day
credit facility. Affiliates of UBS Securities LLC are lenders
under this facility and will receive their proportionate shares
of any such repayment. Please read
UnderwritingAffiliations.
42
The following table shows:
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the historical capitalization of our Predecessor as of
September 30, 2007; and
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our pro forma as adjusted capitalization as of
September 30, 2007, reflecting this offering of 18,750,000
common units at an assumed initial public offering price of
$20.00, the other formation transactions described under
Prospectus summaryFormation transactions and
partnership structureGeneral and the application of
the net proceeds from this offering as described under Use
of proceeds.
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We derived this table from, and it should be read in conjunction
with and is qualified in its entirety by reference to, the
historical and pro forma combined financial statements and the
accompanying notes included elsewhere in this prospectus. You
should also read this table in conjunction with
Managements discussion and analysis of financial
condition and results of operations.
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As of
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September 30,
2007
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Pro forma as
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Historical
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adjusted(1)
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(in
millions)
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Debt
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$
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$
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Total partners equity/parent net equity:
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Parent net equity
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273.5
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Common
unitspublic(2)(3)
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347.6
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Common
unitsAnadarko(2)(3)
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48.2
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Subordinated
unitsAnadarko(2)
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284.2
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General partner
units(2)
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11.6
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Total partners equity/parent net equity
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|
273.5
|
|
|
|
691.6
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
$
|
273.5
|
|
|
$
|
691.6
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
On a pro forma as adjusted
basis, as of September 30, 2007, the public and Anadarko
would have held 18,750,000 and 3,823,925 common units,
respectively, Anadarko would have held 22,573,925 subordinated
units and our general partner would have held 921,385 general
partner units representing a 2.0% general partner interest in
us. |
|
|
|
(2) |
|
An increase or decrease in the
initial public offering price of $1.00 per common unit
would cause the public common unitholders capital to
increase or decrease by $17.5 million, and in the case of
an increase, would cause a $17.5 million decrease in the
partners capital of Anadarko. |
|
|
|
(3) |
|
A 1,000,000 unit increase in the
number of common units issued to the public would result in an
$18.7 million increase in the public common
unitholders capital and an $18.7 million decrease in
the partners capital of Anadarko. |
43
Dilution is the amount by which the offering price paid by the
purchasers of common units sold in this offering will exceed the
pro forma net tangible book value per unit after the offering.
On a pro forma basis as of September 30, 2007, 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 was $686.8 million, or
$14.91 per unit. Net tangible book value excludes
$4.8 million of net intangible assets. Purchasers of common
units in this offering will experience substantial and immediate
dilution in net tangible book value per common unit for
financial accounting purposes, as illustrated in the following
table:
|
|
|
|
|
|
|
|
|
Initial public offering price per common unit
|
|
|
|
|
|
$
|
20.00
|
|
Net tangible book value per unit before the
offering(1)
|
|
|
9.84
|
|
|
|
|
|
Increase in net tangible book value per unit attributable to
purchasers in the offering
|
|
|
5.07
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less: Pro forma net tangible book value per unit after the
offering(2)
|
|
|
|
|
|
|
14.91
|
|
|
|
|
|
|
|
|
|
|
Immediate dilution in tangible net book value per common unit to
purchasers in the
offering(3)
|
|
|
|
|
|
$
|
5.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Determined by dividing the
number of units (3,823,925 common units, 22,573,925
subordinated units and 921,385 general partner units) to be
issued to our general partner and its affiliates, including
Anadarko, for the contribution of assets and liabilities to
Western Gas Partners, LP into the net tangible book value of the
contributed assets and liabilities. |
|
|
|
(2) |
|
Determined by dividing the total
number of units to be outstanding after the offering
(22,573,925 common units, 22,573,925 subordinated
units and 921,385 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,
then dilution in net tangible book value per common unit would
equal $6.09 and $4.47, respectively. |
The following table sets forth the number of units that we will
issue and the total consideration contributed to us by our
general partner and its affiliates and by the purchasers of
common units in this offering upon consummation of the
transactions contemplated by this prospectus:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Units
acquired
|
|
|
Total
consideration
|
|
|
|
Number
|
|
|
Percent
|
|
|
Amount
|
|
|
Percent
|
|
|
|
|
|
|
|
|
|
|
|
(in
thousands)
|
|
|
General partner and
affiliates(1)(2)(3)
|
|
|
27,319,235
|
|
|
|
59.3
|
%
|
|
$
|
273,507
|
|
|
|
42.2
|
%
|
Purchasers in the offering
|
|
|
18,750,000
|
|
|
|
40.7
|
%
|
|
|
375,000
|
|
|
|
57.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
46,069,235
|
|
|
|
100.0
|
%
|
|
$
|
648,507
|
|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The units acquired by our
general partner and its affiliates, including Anadarko, consist
of 3,823,925 common units, 22,573,925 subordinated
units and 921,385 general partner units. |
|
|
|
(2) |
|
The assets contributed by our
general partner and its affiliates were recorded at historical
cost in accordance with GAAP. Book value of the consideration
provided by our general partner and its affiliates, as of
September 30, 2007, equals parent net investment, which was
$273.5 million and is not affected by this
offering. |
|
|
|
(3) |
|
Assumes the underwriters
option to purchase additional common units is not
exercised. |
44
Our
cash distribution policy and restrictions on distributions
You should read the following discussion of our cash
distribution policy in conjunction with the factors and
assumptions upon which our cash distribution policy is based,
which are included under the heading Assumptions and
considerations. In addition, please 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 combined financial statements,
and the notes thereto, included elsewhere in this prospectus.
Rationale for our
cash distribution policy
Our partnership agreement requires us to distribute all of our
available cash quarterly. Our cash distribution policy reflects
a basic judgment that our unitholders will be better served by
our distributing rather than retaining our available cash.
Generally, our available cash is our cash on hand at the end of
a quarter after the payment of our expenses and the
establishment of cash reserves and cash on hand resulting from
working capital borrowings made after the end of the quarter.
Limitations on
cash distributions and our ability to change our cash
distribution policy
There is no guarantee that our unitholders will receive
quarterly distributions from us. We do not have a legal
obligation to pay the minimum quarterly distribution or any
other distribution except as provided in our partnership
agreement. Our cash distribution policy may be changed at any
time and is subject to certain restrictions, including the
following:
|
|
Ø
|
Our general partner 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 or
increase of those reserves could result in a reduction in cash
distributions to you from the levels we currently anticipate
pursuant to our stated distribution policy. Any determination to
establish cash reserves made by our general partner in good
faith will be binding on our unitholders. 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.
|
|
Ø
|
While our partnership agreement requires us to distribute all of
our available cash, our partnership agreement, including the
provisions requiring us to make cash distributions contained
therein, may be amended. Our partnership agreement generally may
not be amended during the subordination period without the
approval of our public common unitholders. However, our
partnership agreement can be amended with the consent of our
general partner and the approval of a majority of the
outstanding common units (including common units held by
Anadarko) and the Class B units issued upon the reset of
incentive distribution rights, if any, voting as a single class
after the subordination period has ended. At the closing of this
offering, Anadarko will own our general partner and
approximately 58.5% of our outstanding common and subordinated
units.
|
|
Ø
|
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.
|
|
Ø
|
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.
|
45
Our cash
distribution policy and restrictions on distributions
|
|
Ø |
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
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 that of 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. There are no limitations in our partnership
agreement, Anadarkos credit facility, under which we are a
co-borrower, or our working capital 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
MINIMUM QUARTERLY DISTRIBUTION
Upon completion of this offering, the board of directors of our
general partner will adopt a policy pursuant to which we will
declare a minimum quarterly distribution of $0.30 per unit per
complete quarter, or $1.20 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, 2008. This equates
to an aggregate cash distribution of $13.8 million per
quarter, or $55.3 million per year, based on the number of
common, subordinated and general partner units to be outstanding
immediately after the completion of this offering.
If the underwriters do not exercise their option to purchase
additional common units within the 30-day option period, we will
issue 2,812,500 common units to Anadarko at the expiration of
this period. If and to the extent the underwriters exercise
their option to purchase additional common units, the number of
units purchased by the underwriters pursuant to such exercise
will be issued to the public and the remainder, if any, will be
issued to Anadarko. Accordingly, the exercise of the
underwriters option will not affect the total number of
units outstanding or the amount of cash needed to pay the
minimum quarterly distribution on all units. Please read
Underwriting.
Initially, our general partner will be entitled to 2.0% of all
distributions that we make prior to our liquidation. In the
future, our general partners initial 2.0% interest in
these distributions may be reduced if we issue additional units
and our general partner does not contribute a proportionate
amount of capital to us to maintain its initial 2.0% general
partner interest. The table below sets forth the assumed number
of outstanding common, subordinated and general partner units
upon the closing of this offering, assuming the underwriters do
not exercise their option to purchase additional common units,
and the aggregate distribution amounts payable on such units
during the year following the closing of this offering at our
minimum quarterly distribution rate of $0.30 per unit per
quarter ($1.20 per unit on an annualized basis).
46
Our cash
distribution policy and restrictions on distributions
|
|
|
|
|
|
|
|
|
|
|
|
Minimum quarterly
distributions
|
|
|
Number of
units
|
|
One
quarter
|
|
Annualized
|
|
|
Publicly held common units
|
|
|
18,750,000
|
|
$
|
5,625,000
|
|
$
|
22,500,000
|
Common units held by
Anadarko(1)
|
|
|
3,823,925
|
|
|
1,147,178
|
|
|
4,588,710
|
Subordinated units held by Anadarko
|
|
|
22,573,925
|
|
|
6,772,178
|
|
|
27,088,710
|
General partner units held by our general partner
|
|
|
921,385
|
|
|
276,416
|
|
|
1,105,662
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
46,069,235
|
|
$
|
13,820,772
|
|
$
|
55,283,082
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Assumes the underwriters do not
exercise their option to purchase 2,812,500 common units and
that the 2,812,500 common units will be issued to Anadarko upon
the expiration of the underwriters 30-day option period.
Accordingly, irrespective of whether the underwriters exercise
their option to purchase additional common units, the total
number of common units we have outstanding upon the completion
of this offering and the expiration of the option period will
not be impacted. |
The subordination period generally will end if we have earned
and paid at least $1.20 on each outstanding common and
subordinated unit and the corresponding distribution on our
general partners 2.0% interest for each of three
consecutive, non-overlapping four-quarter periods ending on or
after December 31, 2010. If we have earned and paid at
least $0.45 (150% of the minimum quarterly distribution, which
is $1.80 on an annualized basis) on each outstanding common and
subordinated unit and the corresponding distribution on our
general partners 2.0% interest for each quarter in 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 read the
Provisions of our partnership agreement relating to cash
distributionsSubordination period.
If we do not pay the minimum quarterly distribution on our
common units, our common unitholders will not be entitled to
receive such payments in the future except during the
subordination period. To the extent we have available cash in
any future quarter during the subordination period in excess of
the amount necessary to pay the minimum quarterly distribution
to holders of our common units, we will use this excess
available cash to pay any distribution arrearages related to
prior quarters before any cash distribution is made to holders
of subordinated units. Please read Provisions of our
partnership agreement relating to cash
distributionsSubordination period.
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. 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, 2008
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 minimum
quarterly distribution of $0.30 per unit each quarter through
the quarter ending December 31, 2008. In those sections, we
present two tables, consisting of:
|
|
Ø |
Unaudited Pro Forma Available Cash, in which we
present the amount of cash we would have had available for
distribution on a pro forma basis for our fiscal year ended
December 31, 2006 and the twelve months ended
September 30, 2007, derived from our unaudited pro forma
combined financial statements that are included in this
prospectus, as adjusted to give pro forma effect to the offering
and the formation transactions; and
|
47
Our cash
distribution policy and restrictions on distributions
|
|
Ø |
Statement of Estimated Adjusted EBITDA, in which we
demonstrate our ability to generate the minimum estimated
Adjusted EBITDA necessary for us to pay the minimum quarterly
distribution on all units for each quarter in the twelve months
ending December 31, 2008.
|
UNAUDITED
PRO FORMA AVAILABLE CASH FOR THE YEAR ENDED DECEMBER 31,
2006 AND THE TWELVE MONTHS ENDED SEPTEMBER 30,
2007
If we had completed the transactions contemplated in this
prospectus on January 1, 2006, pro forma available cash
generated for the year ended December 31, 2006 would have
been approximately $63.3 million. This amount would have
been sufficient to pay the minimum quarterly distribution on all
of our common and subordinated units for such period.
If we had completed the transactions contemplated in this
prospectus on October 1, 2006, our pro forma available cash
generated for the twelve months ended September 30, 2007
would have been approximately $59.0 million. This amount
would have been sufficient to pay the minimum quarterly
distribution on all of our common and subordinated units for
such period.
Unaudited pro forma available cash includes incremental revenue
we expect to receive pursuant to the new gas gathering
agreements we have entered into with Anadarko. These new
gathering agreements include fees for gathering and treating
that are higher than those reflected in our historical financial
results.
Unaudited pro forma available cash also includes general and
administrative expenses, which were calculated on a different
basis as compared to historical periods. These general and
administrative expenses are expected to total $8.5 million
annually and consist of $6.0 million of general and
administrative expenses allocated to us by Anadarko as well as
$2.5 million of general and administrative expenses we
expect to incur as a result of becoming a publicly traded
partnership. Under the omnibus agreement, our reimbursement to
Anadarko for certain general and administrative expenses it
allocates to us will be capped at $6.0 million annually
through December 31, 2009, subject to adjustments to
reflect changes in the Consumer Price Index and, with the
concurrence of the special committee of our general
partners board of directors, to reflect expansions of our
operations through the acquisition or construction of new assets
or businesses. Thereafter, our general partner will determine
the general and administrative expenses to be reimbursed by us
in accordance with our partnership agreement. The cap contained
in the omnibus agreement does not apply to incremental general
and administrative expenses we expect to incur or to be
allocated to us as a result of becoming a publicly traded
partnership. We currently expect those expenses to be
approximately $2.5 million per year. Please read
Certain relationships and related party
transactionsAgreements governing the
transactionsOmnibus agreement. General and
administrative expenses related to being a publicly traded
partnership include expenses associated with annual and
quarterly reporting; tax return and
Schedule K-1
preparation and distribution expenses; Sarbanes-Oxley compliance
expenses; expenses associated with listing on the New York Stock
Exchange; independent auditor fees; legal fees; investor
relations expenses; and registrar and transfer agent fees. These
expenses are not reflected in the historical combined financial
statements of our Predecessor or our pro forma combined
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 combined 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.
48
Our cash
distribution policy and restrictions on distributions
The following table illustrates, on a pro forma basis, for the
year ended December 31, 2006 and for the twelve months
ended September 30, 2007, the amount of cash that would
have been available for distribution to our unitholders,
assuming in each case that this offering had been consummated at
the beginning of such period. Each of the pro forma adjustments
presented below is explained in the footnotes to such
adjustments.
PARTNERSHIP
UNAUDITED PRO FORMA AVAILABLE CASH
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve months
|
|
|
|
Year ended
|
|
|
ended
|
|
|
|
December 31,
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2007
|
|
|
|
|
|
(in millions,
except per unit data)
|
|
|
Net
income(1):
|
|
$
|
14.1
|
|
|
$
|
21.7
|
|
Add:
|
|
|
|
|
|
|
|
|
Other income (expense)
|
|
|
0.4
|
|
|
|
|
|
Depreciation(2)
|
|
|
19.7
|
|
|
|
22.5
|
|
Income
taxes(2)
|
|
|
6.2
|
|
|
|
12.5
|
|
Interest
expense(2)
|
|
|
9.1
|
|
|
|
8.3
|
|
|
|
|
|
|
|
|
|
|
Adjusted
EBITDA(3):
|
|
|
49.5
|
|
|
|
65.0
|
|
|
|
|
|
|
|
|
|
|
Add:
|
|
|
|
|
|
|
|
|
Pro forma net cash interest
income(4)
|
|
|
20.3
|
|
|
|
20.3
|
|
Pro forma incremental Anadarko contract
revenue(5)
|
|
|
38.5
|
|
|
|
28.0
|
|
Less:
|
|
|
|
|
|
|
|
|
General and administrative expenses of being a publicly traded
partnership(6)
|
|
|
2.5
|
|
|
|
2.5
|
|
Pro forma net cash interest
expense(7)
|
|
|
0.2
|
|
|
|
0.2
|
|
Capital
expenditures(8)
|
|
|
42.3
|
|
|
|
51.6
|
|
|
|
|
|
|
|
|
|
|
Pro forma available cash
|
|
$
|
63.3
|
|
|
$
|
59.0
|
|
|
|
|
|
|
|
|
|
|
Pro forma cash distributions
|
|
|
|
|
|
|
|
|
Distributions per
unit(9)
|
|
$
|
1.20
|
|
|
$
|
1.20
|
|
Distributions to public common
unitholders(9)
|
|
$
|
22.5
|
|
|
$
|
22.5
|
|
Distributions to Anadarko and our general
partner(9)
|
|
|
32.8
|
|
|
|
32.8
|
|
|
|
|
|
|
|
|
|
|
Total distributions
|
|
$
|
55.3
|
|
|
$
|
55.3
|
|
|
|
|
|
|
|
|
|
|
Excess
|
|
$
|
8.0
|
|
|
$
|
3.7
|
|
|
|
|
|
|
|
|
|
|
Percent of minimum quarterly distributions payable to common
unitholders
|
|
|
100
|
%
|
|
|
100
|
%
|
Percent of minimum quarterly distributions payable to
subordinated unitholders
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
|
(1) |
|
Reflects pro forma net income of
our Predecessor as if the acquisition of MIGC occurred on
(i) January 1, 2006 for the year ended
December 31, 2006 and (ii) October 1, 2006 for
the twelve months ended September 30, 2007, derived from
our Predecessors combined financial statements. |
|
|
|
(2) |
|
Reflects an adjustment to
reconcile net income to Adjusted EBITDA. |
|
|
|
(3) |
|
We define Adjusted EBITDA as net
income (loss), plus interest expense, income taxes and
depreciation, less interest income and other income (expense).
For a reconciliation of Adjusted EBITDA to its most directly
comparable financial measures calculated and presented in
accordance with GAAP, please read Prospectus
SummaryNon-GAAP financial measure. |
49
Our cash
distribution policy and restrictions on distributions
|
|
|
(4) |
|
Represents interest income we
expect to receive annually with respect to the
$337.6 million
30-year note
bearing interest at a fixed annual rate of 6.00% that we will
receive from Anadarko concurrently with the closing of this
offering. |
|
|
|
(5) |
|
Represents incremental revenue
we expect to receive pursuant to the new gas gathering
agreements we have entered into with Anadarko. These new
gathering agreements include fees for gathering and treating
that are higher than the fees reflected in our historical
financial results. If the new gathering agreements had been in
place for the year ended December 31, 2006 and the twelve
months ended September 30, 2007, the average rate received
for our gathering and treating volumes would have increased by
$0.13/Mcf and $0.09/Mcf, respectively. |
|
|
|
(6) |
|
Reflects an adjustment to our
Adjusted EBITDA for estimated cash expenses associated with
being a publicly traded partnership, such as expenses associated
with annual and quarterly reporting; tax return and Schedule K-1
preparation and distribution expenses; Sarbanes-Oxley compliance
expenses; expenses associated with listing on the New York Stock
Exchange; independent auditor fees; legal fees; investor
relations expenses; and registrar and transfer agent fees. We
expect these expenses to total approximately $2.5 million
per year. |
|
|
|
(7) |
|
Represents estimated cash
interest expense related to annual commitment fees of 0.175% on
Anadarkos credit facility, under which we are a
co-borrower, and our working capital facility. |
|
|
|
(8) |
|
For the year ended
December 31, 2006 and for the twelve months ended
September 30, 2007, our capital expenditures were
$42.3 million and $51.6 million, respectively. The
capital expenditures are assumed to have occurred ratably
throughout the year. For these periods, capital expenditures
include both maintenance and expansion capital expenditures
(excluding $18.0 million for compressor lease repurchases
for the twelve months ended September 30, 2007) because we
did not segregate these costs in historic periods. If we were
able to isolate these costs, we would reflect borrowings to
offset expansion capital expenditures and our pro forma
available cash would be reduced by incremental interest expense
on those borrowings as opposed to being reduced by the entire
amount of such expansion capital expenditures in the table
presented above. The $18.0 million for compressor lease
repurchases was excluded because during the twelve months ended
September 30, 2007, Anadarko exercised its early buyout
option contained in three of its compressor leases, under which
compressors were leased from a third party to Anadarko and
subleased by Anadarko to us. Anadarko then transferred the
compressors to us as a contribution to our capital. Absent this
offering, these leases would have been refinanced and no capital
expenditures would have been incurred. |
|
|
|
(9) |
|
The table above is based on the
assumption that the underwriters option has not been
exercised and the 30-day option period for such exercise has
expired. Set forth below is the assumed number of outstanding
common, subordinated and general partner units upon the closing
of this offering and expiration of the underwriters option
period, and the aggregate distribution amounts payable on such
units during the year following the closing of this offering at
our minimum quarterly distribution rate of $0.30 per unit per
quarter ($1.20 per unit on an annualized basis). |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minimum quarterly
distributions
|
|
|
|
Number of
units
|
|
One
quarter
|
|
|
Annualized
|
|
|
|
|
Publicly held common units
|
|
|
18,750,000
|
|
$
|
5,625,000
|
|
|
$
|
22,500,000
|
|
Common units held by
Anadarko(a)
|
|
|
3,823,925
|
|
|
1,147,178
|
|
|
|
4,588,710
|
|
Subordinated units held by Anadarko
|
|
|
22,573,925
|
|
|
6,772,178
|
|
|
|
27,088,710
|
|
General partner units held by our general partner
|
|
|
921,385
|
|
|
276,416
|
|
|
|
1,105,662
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
46,069,235
|
|
$
|
13,820,772
|
|
|
$
|
55,283,082
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The number of common units held
by Anadarko includes 2,812,500 common units subject to the
underwriters option to purchase additional common units.
If and to the extent this option is exercised, the remainder of
these common units, if any, will be issued to Anadarko at the
expiration of the underwriters option period. |
50
Our cash
distribution policy and restrictions on distributions
ESTIMATED
ADJUSTED EBITDA FOR THE TWELVE MONTHS ENDING DECEMBER 31,
2008
Set forth below is a Statement of Estimated Adjusted EBITDA that
reflects our ability to generate sufficient cash flow to pay the
minimum quarterly distribution on all of our outstanding units
for each quarter in the twelve months ending December 31,
2008. The financial forecast presents, to the best of our
knowledge and belief, the expected results of operations,
Adjusted EBITDA and cash available for distribution for the
forecast period. We define Adjusted EBITDA as net income (loss),
plus interest expense, income taxes, and depreciation, less
interest income and other income (expense).
For a reconciliation of Adjusted EBITDA to its most directly
comparable financial measures calculated and presented in
accordance with GAAP, please read Prospectus
summaryNon-GAAP financial measure.
Our minimum estimated Adjusted 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 pay the
minimum quarterly distribution on all of our outstanding units
and the corresponding distributions on our general
partners 2.0% interest for each quarter in the twelve
months ending December 31, 2008. The assumptions discussed
below under Assumptions and considerations are
those that we believe are significant to our ability to generate
our minimum estimated Adjusted EBITDA. We believe our actual
results of operations and cash flows will be sufficient to
generate the minimum estimated Adjusted EBITDA; however, we can
give you no assurance that we will generate the minimum
estimated Adjusted EBITDA. There will likely be differences
between our minimum estimated Adjusted EBITDA and our actual
results and those differences could be material. If we fail to
generate the minimum estimated Adjusted EBITDA, we may not be
able to pay the minimum quarterly distribution on our common
units. In order to fund distributions to our unitholders at our
initial rate of $1.20 per unit for the twelve months ending
December 31, 2008, our minimum estimated Adjusted EBITDA
for the twelve months ending December 31, 2008 must be at
least $63.7 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 Adjusted EBITDA
and related assumptions set forth below to substantiate our
belief that we will have sufficient available cash to pay the
minimum quarterly distribution to all our unitholders for each
quarter in the twelve months ending December 31, 2008. This
forecast is a forward-looking statement and should be read
together with the historical and pro forma combined financial
statements and the accompanying notes included elsewhere in this
prospectus and Managements discussion and analysis
of financial condition and results of operations. 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, was 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 Adjusted EBITDA necessary for us to have
sufficient cash available for distribution to pay the minimum
quarterly distribution to all unitholders for each quarter in
the twelve months ending December 31, 2008. 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.
Neither our independent auditors nor any other independent
accountants have compiled, examined or performed any procedures
with respect to the prospective financial information contained
herein, nor have they expressed any opinion or any other form of
assurance on such information or its achievability, and they
assume no responsibility for, and disclaim any association with,
the prospective financial information.
When considering our financial forecast, you should keep in mind
the risk factors and other cautionary statements under
Risk factors. Any of the risks discussed in this
prospectus, to the extent they are
51
Our cash
distribution policy and restrictions on distributions
realized, could cause our actual results of operations to vary
significantly from those which would enable us to generate the
minimum estimated Adjusted EBITDA.
We are providing the minimum estimated Adjusted EBITDA
calculation to supplement our pro forma and historical combined
financial statements in support of our belief that we will have
sufficient available cash to pay the minimum quarterly
distribution on all of our outstanding common and subordinated
units for each quarter in the twelve months ending
December 31, 2008. Please read 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 financial
forecast or to update this financial forecast to reflect events
or circumstances after the date of this prospectus. Therefore,
you are cautioned not to place undue reliance on this
information.
52
Our cash
distribution policy and restrictions on distributions
PARTNERSHIP
STATEMENT OF ESTIMATED ADJUSTED EBITDA
|
|
|
|
|
|
|
Twelve months
ending
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
|
|
|
(in
millions)
|
|
|
Total operating revenues
|
|
$
|
126.0
|
|
Costs and expenses:
|
|
|
|
|
Operating and maintenance expense
|
|
|
(48.5
|
)
|
General and administrative expense
|
|
|
(8.5
|
)
|
Depreciation and amortization expense
|
|
|
(24.0
|
)
|
|
|
|
|
|
Operating income
|
|
|
45.0
|
|
Interest expense
|
|
|
(0.4
|
)
|
Interest income Anadarko note
|
|
|
20.3
|
|
Texas margin tax
|
|
|
(0.3
|
)
|
|
|
|
|
|
Net income
|
|
$
|
64.6
|
|
Adjustments to reconcile net income to estimated Adjusted EBITDA:
|
|
|
|
|
Add:
|
|
|
|
|
Depreciation and amortization expense
|
|
|
24.0
|
|
Interest expense
|
|
|
0.4
|
|
Texas margin tax
|
|
|
0.3
|
|
Less:
|
|
|
|
|
Interest income Anadarko note
|
|
|
(20.3
|
)
|
|
|
|
|
|
Estimated Adjusted
EBITDA(1)
|
|
$
|
69.0
|
|
Adjustments to reconcile estimated Adjusted EBITDA to estimated
cash available for distribution:
|
|
|
|
|
Less:
|
|
|
|
|
Cash interest expense
|
|
|
(0.4
|
)
|
Estimated expansion capital expenditures
|
|
|
(15.9
|
)
|
Estimated maintenance capital expenditures
|
|
|
(28.0
|
)
|
Texas margin tax
|
|
|
(0.3
|
)
|
Add:
|
|
|
|
|
Cash interest income Anadarko note
|
|
|
20.3
|
|
Cash on hand and borrowings for expansion capital expenditures
|
|
|
15.9
|
|
|
|
|
|
|
Estimated cash available for distribution
|
|
$
|
60.6
|
|
|
|
|
|
|
Aggregate annualized minimum quarterly distributions
|
|
|
55.3
|
|
Excess of cash available for distribution over aggregate
annualized minimum quarterly distributions
|
|
|
5.3
|
|
|
|
|
|
|
Calculation of minimum estimated Adjusted EBITDA necessary to
pay aggregate annualized minimum quarterly distributions:
|
|
|
|
|
Estimated Adjusted EBITDA
|
|
|
69.0
|
|
Excess of cash available for distribution over aggregate
annualized minimum quarterly distributions
|
|
|
(5.3
|
)
|
|
|
|
|
|
Minimum estimated Adjusted EBITDA necessary to pay aggregate
annualized minimum quarterly distributions
|
|
$
|
63.7
|
|
|
|
|
|
|
|
|
|
(1) |
|
We define Adjusted EBITDA as net
income (loss), plus interest expense, income taxes and
depreciation, less interest income and other income (expenses).
For a reconciliation of Adjusted EBITDA to its most directly
comparable financial measures calculated and presented in
accordance with GAAP, please read Prospectus
summaryNon-GAAP financial measure. |
53
Our cash
distribution policy and restrictions on distributions
ASSUMPTIONS
AND CONSIDERATIONS
We believe the assumptions and estimates we have made to
demonstrate our ability to generate the minimum estimated
Adjusted EBITDA, which are set forth below, are reasonable. We
define Adjusted EBITDA as net income (loss), plus interest
expense, income taxes and depreciation, less interest income and
other income (expenses). For a reconciliation of Adjusted EBITDA
to its most directly comparable financial measures calculated
and presented in accordance with GAAP, please read
Prospectus summaryNon-GAAP financial measure.
General
considerations
|
|
Ø |
Revenues and operating expenses are net of intercompany
transactions.
|
|
|
Ø |
Realized gathering throughput volume is the primary factor that
will influence whether the amount of cash available for
distribution for the twelve months ending December 31, 2008
is above or below our forecast. For example, if all other
assumptions are held constant, a 5.0% decline in volumes below
forecasted levels would result in a $5.0 million decline in
revenues. Additionally, a 5.0% decline in the trading margin
between condensate and natural gas would result in a
$0.2 million decline in cash available for distribution. A
decline in forecasted cash flow of greater than
$5.3 million would result in our generating less than the
minimum cash required to pay distributions.
|
|
|
Ø |
Transportation volumes are provided pursuant to firm and
interruptible transportation arrangements.
|
Total operating
revenue
We estimated total operating revenue for the twelve months
ending December 31, 2008 based on the following significant
assumptions:
|
|
Ø |
Gathering and treating volumes. We estimate
that we will gather and/or treat an average of
812 MMcf/d
of natural gas for the twelve months ending December 31,
2008 as compared to
845 MMcf/d
for the year ended December 31, 2006 and 870 MMcf/d
for the twelve months ended September 30, 2007. The
decreased volumes estimated for the twelve months ending
December 31, 2008 are primarily due to the end of an
interim agreement for treating services on approximately
40 MMcf/d at our Pinnacle gas treating facility, together
with the natural production declines from the wells connected to
our systems, partially offset by new well connections.
|
|
|
Ø |
Gathering and treating fees. We estimate that
we will receive an average gathering and treating fee of
$0.34/Mcf for the twelve months ending December 31, 2008 as
compared to $0.21/Mcf for the year ended December 31, 2006
and $0.25/Mcf for the twelve months ended September 30,
2007. The expected increase in our gathering and treating fees
is due to the new gathering and treating agreements that we
recently negotiated with Anadarko.
|
|
|
Ø |
Gathering and treating revenues. We estimate
that gathering and treating revenues for the twelve months
ending December 31, 2008 will be $102.1 million as
compared to $65.0 million for the year ended
December 31, 2006 and $78.1 million for the twelve
months ended September 30, 2007.
|
The expected increase in gathering and treating revenues for the
twelve months ending December 31, 2008 as compared to the
year ended December 31, 2006 and the twelve months ended
September 30, 2007 of approximately $37.1 million and
$24.0 million, respectively, is primarily due to higher
gathering and treating revenues of $39.8 million and
$29.3 million, respectively, attributable to an increase of
$0.13/Mcf and $0.09/Mcf, respectively, in average gathering and
treating fees offset by a decrease of $2.7 million and
$5.3 million, respectively, due to decreased average
volumes.
Our higher gathering and treating revenues reflect the employee
benefit costs specifically identified and associated with
operational personnel working on our assets. All of these costs
will be
54
Our cash
distribution policy and restrictions on distributions
recovered by us following this offering through the gathering
rates we will charge Anadarko under the new gas gathering
agreements. For the year ended December 31, 2006 and the
twelve months ended September 30, 2007, only those employee
benefit costs reasonably allocated by Anadarko to us were
included in and recovered through the gathering and treating
fees we charged Anadarko.
|
|
Ø |
Transportation volumes. We estimate that we
will transport an average of
178 MMcf/d
of natural gas for the twelve months ending December 31,
2008 as compared to
126 MMcf/d
for the year ended December 31, 2006 and
134 MMcf/d
for the twelve months ended September 30, 2007. The
increase in forecasted volumes is primarily attributable to an
additional 45 MMcf/d of firm capacity that was contracted
for by Anadarko in connection with the recent expansion of the
MIGC system. Our transportation volumes increased by an average
of 71 Mcf/d as a result of the inclusion of MIGC for the
full year ended December 31, 2006.
|
|
|
Ø |
Transportation fees. We estimate that we will
receive an average of $0.30/Mcf for the twelve months ended
December 31, 2008 as compared to $0.37/Mcf for the year
ended December 31, 2006 and $0.37/Mcf for the twelve months
ended September 30, 2007. Our anticipated transportation
fees are consistent with fees realized on a historical basis and
contained in the FERC-approved rates for MIGC.
|
|
|
Ø |
Transportation revenues. We estimate that
transportation revenues for the twelve months ending
December 31, 2008 will be $18.9 million as compared to
$17.0 million for the year ended December 31, 2006 and
$18.0 million for the twelve months ended
September 30, 2007.
|
The expected increase in transportation revenues for the twelve
months ending December 31, 2008 as compared to the year
ended December 31, 2006 and the twelve months ended
September 30, 2007 of approximately $1.9 million and
$0.9 million, respectively, is primarily due to higher
transportation revenues attributable to increased volumes,
partially offset by lower rates.
|
|
Ø |
Condensate margin. We estimate that we will
receive an aggregate condensate margin of $5.0 million for
the twelve months ending December 31, 2008 as compared to
$3.7 million for the year ended December 31, 2006 and
$4.1 million for the twelve months ended September 30,
2007. The expected margin increase is due primarily to a higher
forecasted spread between crude oil and natural gas prices in
2008 ($76.00/Bbl and $7.82/Mcf, respectively, based on NYMEX
prices as of September 28, 2007) than existed in the year
ended December 31, 2006 ($66.22/Bbl and $7.23/Mcf,
respectively) and in the twelve months ended September 30,
2007 ($57.64/Bbl and $6.01/Mcf, respectively). Condensate margin
is the difference between the revenue from sale of condensate
recovered during the gathering of natural gas and the cost of
the natural gas required to deliver the same thermal content to
the shipper.
|
Operating and
maintenance expense
We estimate that total operating and maintenance expense for the
twelve months ending December 31, 2008 will be
$48.5 million as compared to $43.9 million for the
year ended December 31, 2006 and $43.8 million for the
twelve months ended September 30, 2007. The expected
increase in operating and maintenance expense for the twelve
months ending December 31, 2008 as compared to the year
ended December 31, 2006 and the twelve months ended
September 30, 2007 of $4.6 million and
$4.7 million, respectively, is primarily due to higher
expected labor, maintenance and contract services costs.
Operating and maintenance expense is comprised primarily of
direct labor, insurance, property taxes, repair and maintenance,
contract services, utility costs and services provided to us or
on our behalf under our services and secondment agreement.
Our higher expected labor expense is attributable to us bearing
all of the employee benefit costs specifically identified and
associated with the operational personnel working on our assets.
For the year
55
Our cash
distribution policy and restrictions on distributions
ended December 31, 2006 and the twelve months ended
September 30, 2007, only those employee benefit costs
reasonably allocated by Anadarko to us were included in and
recovered through the gathering and treating fees we charged
Anadarko. Under our new gas gathering agreements entered into
with Anadarko, all of these costs will be recovered by us
following the offering through the gathering rates we will
charge Anadarko. As a result, our gathering and treating
revenues will increase by an amount equal to the increase in
operating and maintenance expense.
General and
administrative expense
We estimate that general and administrative expense for the
twelve months ending December 31, 2008 will be
$8.5 million and will consist of $6.0 million of costs
reimbursable to Anadarko for services performed on our behalf
pursuant to the omnibus agreement and the services and
secondment agreement and $2.5 million of general and
administrative expense related to operating as a publicly traded
partnership. General and administrative expense was
$4.5 million and $3.7 million for the year ended
December 31, 2006 and the twelve months ended
September 30, 2007, respectively. The expected increase in
general and administrative expense is driven by
$2.5 million in costs associated with being a publicly
traded partnership, with the balance of the increase
attributable to increased corporate and management services
associated with operating our business on a stand-alone basis.
Depreciation and
amortization expense
We estimate depreciation and amortization expense for the twelve
months ending December 31, 2008 of $24.0 million as
compared to $19.7 million for the year ended
December 31, 2006 and $22.5 million for the twelve
months ended September 30, 2007. Estimated depreciation and
amortization expense reflects managements estimates, which
are based on consistent average depreciable asset lives and
depreciation methodologies. The increase in depreciation and
amortization is attributable to an expected increase in capital
investments in our assets.
Interest income
and Texas margin tax
Interest income. We will loan
$337.6 million of the net proceeds from this offering to
Anadarko in exchange for an interest-only,
30-year note
bearing interest at a fixed annual rate of 6.00%, resulting in
interest income of $20.3 million during the twelve months
ending December 31, 2008.
Texas margin tax. We estimate Texas margin tax
payments for the twelve months ending December 31, 2008
will be $0.3 million based on a 1.0% tax rate on a maximum
of 70% of our projected revenues attributable to operations in
Texas for the year ending December 31, 2008.
Capital
expenditures
We estimate total capital expenditures of $43.9 million for
the twelve months ending December 31, 2008 as compared to
$42.3 million and $51.6 million for the year ended
December 31, 2006 and for the twelve months ended
September 30, 2007, respectively. Historically, we did not
make a distinction between maintenance and expansion capital
expenditures. Our estimate is based on the following assumptions:
|
|
Ø |
We estimate that maintenance capital expenditures for the twelve
months ending December 31, 2008 will be $28.0 million.
These expenditures are expected to include $13.0 million of
well connection costs associated with maintaining throughput on
our systems. The remainder of the expenditures are primarily
expected to be incurred to replace partially or fully
depreciated assets and to overhaul existing assets.
|
56
Our cash
distribution policy and restrictions on distributions
|
|
Ø |
We estimate that expansion capital expenditures for the twelve
months ending December 31, 2008 will be $15.9 million.
These expenditures are expected to include $11.5 million
associated with the expansion of the sulfur treating capacity at
our Bethel plant in East Texas that we expect to complete in
2008. We also expect to spend $3.4 million to add
additional compression on our Dew gathering system in East Texas.
|
Financing
Our forecast for the twelve months ending December 31, 2008
is based on the following financing assumptions:
|
|
Ø |
We expect to use $10 million of the net proceeds of this
offering to finance a portion of our expansion capital
expenditures during the forecast period.
|
|
|
Ø |
We expect to finance the balance of our expansion capital
expenditures of $5.9 million through borrowings under
Anadarkos credit facility, under which we are a
co-borrower, or our working capital facility.
|
|
|
Ø |
Our average debt level will be $2.9 million, comprised of
funds drawn either on Anadarkos credit facility, under
which we are a co-borrower, or our working capital facility.
|
|
|
Ø |
We estimate interest expense of $0.4 million for the twelve
months ending December 31, 2008, which includes commitment
fees of 0.175% on Anadarkos credit facility, under which
we are a co-borrower, and our working capital facility and
interest associated with funds expected to be drawn. We estimate
our borrowings under Anadarkos credit facility and our
working capital facility to bear an average annualized variable
interest rate of 6.00% through December 31, 2008. An
increase or decrease of 1.0% in the annual interest rate would
not result in a material change to our annual interest expense.
|
|
|
Ø |
Anadarko and we will remain in compliance with the financial and
other covenants in the Anadarko credit facility and other debt
instruments.
|
Regulatory,
industry and economic factors
Our forecast for the twelve months ending December 31,
2008, is based on the following significant assumptions related
to regulatory, industry and economic factors:
|
|
Ø
|
There will not be any new federal, state or local regulation of
the midstream energy sector, or any new interpretation of
existing regulations, that will be materially adverse to our
business.
|
|
Ø
|
There will not be any major adverse change in the midstream
energy sector or in market, insurance or general economic
conditions.
|
57
Provisions
of our partnership agreement relating to cash distributions
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
December 31, 2007, we distribute all of our available cash
to unitholders of record on the applicable record date. We will
adjust the minimum quarterly distribution for the period from
the closing of the offering through December 31, 2007.
Definition of
available cash
Available cash, for any quarter, consists of all cash on hand at
the end of that quarter:
|
|
Ø |
less, the amount of cash reserves established by our
general partner to:
|
|
|
|
|
-
|
provide for the proper conduct of our business;
|
|
|
-
|
comply with applicable law, any of our debt instruments or other
agreements; or
|
|
|
-
|
provide funds for distributions to our unitholders for any one
or more of the next four quarters;
|
|
|
Ø |
plus, if our general partner so determines, all or a
portion of cash on hand on the date of determination of
available cash for the quarter resulting from working capital
borrowings made after the end of the quarter.
|
Working capital borrowings are generally borrowings that are
made under a credit facility, commercial paper facility or
similar financing arrangement, and in all cases are used solely
for working capital purposes or to pay distributions to partners
and with the intent of the borrower to repay such borrowings
within 12 months.
Intent to
distribute the minimum quarterly distribution
We will distribute to the holders of common and subordinated
units on a quarterly basis at least the minimum quarterly
distribution of $0.30 per unit, or $1.20 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.
General partner
interest and incentive distribution rights
Initially, our general partner will be entitled to 2.0% of all
quarterly distributions since inception that we make prior to
our liquidation. This general partner interest will be
represented by 921,385 general partner units. General partner
units are not deemed outstanding units for purposes of voting
rights and such units represent a non-voting general partner
interest. 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. Our general
partners initial 2.0% interest in these distributions may
be reduced if we issue
58
Provisions of our
partnership agreement relating to cash distributions
additional units in the future and our general partner does not
contribute a proportionate amount of capital to us to maintain
its 2.0% general partner interest.
Our general partner also currently holds incentive distribution
rights that entitle it to receive increasing percentages, up to
a maximum of 50.0%, of the cash we distribute from operating
surplus (as defined below) in excess of $0.45 per unit per
quarter. The maximum distribution of 50.0% includes
distributions paid to our general partner on its 2.0% general
partner interest and assumes that our general partner maintains
its general partner interest at 2.0%. The maximum distribution
of 50.0% does not include any distributions that our general
partner may receive on units that it owns.
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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Ø
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$27.1 million (as described below);
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Ø
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all of our cash receipts after the closing of this offering,
excluding cash from the following:
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-
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borrowings that are not working capital borrowings;
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sales of equity and debt securities;
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sales or other dispositions of assets outside the ordinary
course of business;
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the termination of interest rate swap agreements or commodity
hedge contracts prior to the termination date specified herein;
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capital contributions received; and
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corporate reorganizations or restructurings; plus
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Ø
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working capital borrowings made after the end of a quarter but
on or before the date of determination of operating surplus for
the quarter; plus
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Ø
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cash distributions paid on equity issued to finance all or a
portion of the construction, acquisition or improvement or
replacement of a capital asset (such as equipment or facilities)
during the period beginning on the date that we enter into a
binding obligation to commence the construction, acquisition or
improvement of a capital improvement or replacement of a capital
asset and ending on the earlier to occur of the date the capital
improvement or capital asset commences commercial service or the
date that it is abandoned or disposed of; less
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Ø
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all of our operating expenditures (as defined below) after the
closing of this offering; less
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Ø
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the amount of cash reserves established by our general partner
to provide funds for future operating expenditures; less
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Ø
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all working capital borrowings not repaid within twelve months
after having been incurred or repaid within such twelve-month
period with the proceeds of additional working capital
borrowings.
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As described above, operating surplus does not reflect actual
cash on hand that is available for distribution to our
unitholders. For example, it includes a provision that will
enable us, if we choose, to distribute as operating surplus up
to $27.1 million of cash we receive in the future from
non-operating sources such as asset sales, issuances of
securities and long-term borrowings that would otherwise be
59
Provisions of our
partnership agreement relating to cash distributions
distributed as capital surplus. In addition, the effect of
including, as described above, certain cash distributions on
equity securities in operating surplus would be to increase
operating surplus by the amount of any such cash distributions.
As a result, we may also distribute as operating surplus up to
the amount of any such cash distributions we receive from
non-operating sources.
If a working capital borrowing, which increases operating
surplus, is not repaid during the twelve-month period following
the borrowing, it will be deemed repaid at the end of such
period, thus decreasing operating surplus at such time. When
such working capital borrowing is in fact repaid, it will not be
treated as a further reduction in operating surplus because
operating surplus will have been previously reduced by the
deemed repayment.
We define operating expenditures in the glossary, and it
generally means all of our cash expenditures, including, but not
limited to, taxes, reimbursement of expenses to our general
partner, reimbursement of expenses to Anadarko for services
pursuant to the omnibus agreement or personnel provided to us
under the services and secondment agreement, payments made in
the ordinary course of business under interest rate swap
agreements or commodity hedge contracts, manager and officer
compensation, repayment of working capital borrowings, debt
service payments and estimated maintenance capital expenditures
(as discussed in further detail below), provided that operating
expenditures will not include:
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repayment of working capital borrowings deducted from operating
surplus pursuant to the last bullet point of the definition of
operating surplus above when such repayment actually occurs;
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payments (including prepayments and prepayment penalties) of
principal of and premium on indebtedness, other than working
capital borrowings;
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expansion capital expenditures;
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Ø
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actual maintenance capital expenditures (as discussed in further
detail below);
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investment capital expenditures;
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payment of transaction expenses relating to interim capital
transactions;
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distributions to our partners (including distributions in
respect of our Class B units and incentive distribution
rights); or
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Ø
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non-pro rata purchases of units of any class made with the
proceeds of a substantially concurrent equity issuance.
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Capital
surplus
Capital surplus consists of:
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borrowings other than working capital borrowings;
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sales of our equity and debt securities; and
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Ø
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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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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.
We do not anticipate that we will make any distributions from
capital surplus.
60
Provisions of our
partnership agreement relating to cash distributions
For purposes of determining operating surplus, maintenance
capital expenditures are those capital expenditures required to
maintain our long-term operating capacity or operating income,
and expansion capital expenditures are those capital
expenditures that we expect will expand our operating capacity
or operating income over the long term. Examples of maintenance
capital expenditures include capital expenditures associated
with the replacement of equipment and well connections, or the
construction, development or acquisition of other facilities, to
replace expected reductions in hydrocarbons available for
gathering, compressing, treating, transporting or otherwise
handled by our facilities (which we refer to as operating
capacity). Maintenance capital expenditures will also include
interest (and related fees) on debt incurred and distributions
on equity issued to finance all or any portion of the
construction, improvement or replacement of an asset that is
paid in respect of the period that begins when we enter into a
binding obligation to commence constructing or developing a
replacement asset and ending on the earlier to occur of the date
of any such replacement asset commences commercial service or
the date that it is abandoned or disposed of. Capital
expenditures made solely for investment purposes will not be
considered maintenance capital expenditures.
Because our maintenance capital expenditures can be irregular,
the amount of our actual maintenance capital expenditures may
differ substantially from period to period, which could cause
similar fluctuations in the amounts of operating surplus,
adjusted operating surplus and cash available for distribution
to our unitholders if we subtracted actual maintenance capital
expenditures from operating surplus.
Our partnership agreement will require that an estimate of the
average quarterly maintenance capital expenditures necessary to
maintain our operating capacity or operating income over the
long term be subtracted from operating surplus each quarter as
opposed to the actual amounts spent. The amount of estimated
maintenance capital expenditures deducted from operating surplus
for those periods will be subject to review and change by our
general partner at least once a year, provided that any change
is approved by our special committee. The estimate will be made
at least annually and whenever an event occurs that is likely to
result in a material adjustment to the amount of our maintenance
capital expenditures, such as a major acquisition or the
introduction of new governmental regulations that will impact
our business. For purposes of calculating operating surplus, any
adjustment to this estimate will be prospective only. For a
discussion of the amounts we have allocated toward estimated
maintenance capital expenditures, please read Our cash
distribution policy and restrictions on distributions.
The use of estimated maintenance capital expenditures in
calculating operating surplus will have the following effects:
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it will reduce the risk that maintenance capital expenditures in
any one quarter will be large enough to render operating surplus
less than the initial quarterly distribution to be paid on all
the units for the quarter and subsequent quarters;
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Ø
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it will increase our ability to distribute as operating surplus
cash we receive from non-operating sources; and
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Ø
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it will be more difficult for us to raise our distribution above
the minimum quarterly distribution and pay incentive
distributions on the incentive distribution rights held by our
general partner.
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Expansion capital expenditures are those capital expenditures
that we expect will increase our operating capacity or operating
income. Examples of expansion capital expenditures include the
acquisition of equipment, or the construction, development or
acquisition of additional pipeline or treating capacity or new
processing capacity, to the extent such capital expenditures are
expected to expand our long-term operating capacity or operating
income. Expansion capital expenditures will also include
interest (and related fees) on debt incurred and distributions
on equity issued to finance all or any portion of the
construction of such capital improvement during the period that
commences when we enter into a
61
Provisions of our
partnership agreement relating to cash distributions
binding obligation to commence construction of a capital
improvement and ending on the date any such capital improvement
commences commercial service or the date that it is abandoned or
disposed of. Capital expenditures made solely for investment
purposes will not be considered expansion capital expenditures.
As described below, none of investment capital expenditures or
expansion capital expenditures are subtracted from operating
surplus. Because investment capital expenditures and expansion
capital expenditures include interest payments (and related
fees) on debt incurred and distributions on equity issued to
finance all of the portion of the construction, replacement or
improvement of a capital asset (such as gathering pipelines or
treating facilities) during the period that begins when we enter
into a binding obligation to commence construction of a capital
improvement and ending on the earlier to occur of the date any
such capital asset commences commercial service or the date that
it is abandoned or disposed of, such interest payments and
equity distributions are also not subtracted from operating
surplus (except, in the case of maintenance capital
expenditures, to the extent such interest payments and
distributions are included in estimated maintenance capital
expenditures).
Investment capital expenditures are those capital expenditures
that are neither maintenance capital expenditures nor expansion
capital expenditures. Investment capital expenditures largely
will consist of capital expenditures made for investment
purposes. Examples of investment capital expenditures include
traditional capital expenditures for investment purposes, such
as purchases of securities, as well as other capital
expenditures that might be made in lieu of such traditional
investment capital expenditures, such as the acquisition of a
capital asset for investment purposes or development of
facilities that are in excess of the maintenance of our existing
operating capacity or operating income, but which are not
expected to expand for more than the short term of our operating
capacity or operating income.
Capital expenditures that are made in part for maintenance
capital purposes and in part for investment capital or expansion
capital purposes will be allocated as maintenance capital
expenditures, investment capital expenditures or expansion
capital expenditure by our general partner, with the concurrence
of our special committee.
General
Our partnership agreement provides that, during the
subordination period (which we define below), the common units
will have the right to receive distributions of available cash
from operating surplus each quarter in an amount equal to $0.30
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 business
day of any quarter beginning after December 31, 2010, 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
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62
Provisions of our
partnership agreement relating to cash distributions
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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, 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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Early termination
of subordination period
Notwithstanding the foregoing, 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
of the outstanding common units, subordinated units and general
partner units equaled or exceeded $0.45 per quarter (150.0% of
the minimum quarterly distribution) for each calendar quarter in
the four-quarter period immediately preceding the date;
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the adjusted operating surplus (as defined below)
generated during each calendar quarter in the four-quarter
period immediately preceding the date equaled or exceeded the
sum of $0.45 (150.0% of the minimum quarterly distribution) on
each of the outstanding common, subordinated and general partner
units during that period on a fully diluted basis; and
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there are no arrearages in payment of the minimum quarterly
distributions on the common units.
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Expiration of the
subordination period
When the subordination period ends, 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 no units
held by our general partner and its affiliates are 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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our 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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Adjusted
operating surplus
Adjusted operating surplus is intended to reflect the cash
generated from operations during a particular period and
therefore excludes net increases in working capital borrowings
and 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;
less
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any net increase in working capital borrowings with respect to
that period; less
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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
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any net decrease in working capital borrowings with respect to
that period; plus
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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.
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63
Provisions of our
partnership agreement relating to cash distributions
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:
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first, 98.0% to the common unitholders, pro rata, and
2.0% to our general partner, until we distribute for each
outstanding common unit an amount equal to the minimum quarterly
distribution for that quarter;
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second, 98.0% to the common unitholders, pro rata, and
2.0% to our 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;
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third, 98.0% to the subordinated unitholders, pro rata,
and 2.0% to our general partner, until we distribute for each
subordinated unit an amount equal to the minimum quarterly
distribution for that quarter; and
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thereafter, in the manner described in General
partner interest and incentive distribution rights below.
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The preceding discussion is based on the assumptions that our
general partner maintains its 2.0% general partner interest and
that we do not issue additional classes of equity securities.
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
our unitholders and our 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 2.0% general partner interest and
assume our general partner has contributed any additional
capital to maintain its 2.0% general partner interest and has
not transferred its incentive distribution rights.
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Marginal
percentage
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interest in
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distributions(1)
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Total quarterly
distribution
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General
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per
unit
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Unitholders
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partner
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Minimum Quarterly Distribution
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$0.300
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98.0%
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2.0%
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First Target Distribution
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up to $0.345
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98.0%
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2.0%
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Second Target Distribution
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above $0.345 up to $0.375
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85.0%
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15.0%
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Third Target Distribution
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above $0.375 up to $0.450
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75.0%
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25.0%
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Thereafter
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above $0.450
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50.0%
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50.0%
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(1) |
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Assumes that there are no
arrearages on common units and that our general partner
maintains its 2.0% general partner interest and continues to own
the incentive distribution rights. |
64
Provisions of our
partnership agreement relating to cash distributions
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:
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first, 98.0% to all unitholders, pro rata, and 2.0% to
our general partner, until we distribute for each outstanding
unit an amount equal to the minimum quarterly distribution for
that quarter; and
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thereafter, in the manner described in
General partner interest and incentive distribution
rights below.
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The preceding discussion is based on the assumptions that our
general partner maintains its 2.0% general partner interest and
that we do not issue additional classes of equity securities.
GENERAL
PARTNER INTEREST AND INCENTIVE DISTRIBUTION RIGHTS
Our partnership agreement provides that our general partner
initially will be entitled to 2.0% 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 2.0% general partner
interest if we issue additional units. Our general
partners 2.0% 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 2.0% general partner
interest. Our general partner will be entitled to make a capital
contribution in order to maintain its 2.0% general partner
interest in the form of the contribution to us of common units
based on the current market value of the contributed common
units.
Incentive distribution rights represent the right to receive an
increasing percentage (13.0%, 23.0% and 48.0%) 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 our general partner
maintains its 2.0% general partner interest, that there are no
arrearages on common units and that our general partner
continues to own the incentive distribution rights.
If for any quarter:
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we have distributed available cash from operating surplus to the
common and subordinated unitholders in an amount equal to the
minimum quarterly distribution; and
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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;
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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:
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first, 98.0% to all unitholders, pro rata, and 2.0% to
our general partner, until each unitholder receives a total of
$0.345 per unit for that quarter (the first target
distribution);
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second, 85.0% to all unitholders, pro rata, and 15.0% to
our general partner, until each unitholder receives a total of
$0.375 per unit for that quarter (the second target
distribution);
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third, 75.0% to all unitholders, pro rata, and 25.0% to
our general partner, until each unitholder receives a total of
$0.45 per unit for that quarter (the third target
distribution); and
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thereafter, 50.0% to all unitholders, pro rata, and 50.0%
to our general partner.
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65
Provisions of our
partnership agreement relating to cash distributions
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 special 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 and general
partner 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. Our general
partner will be issued the number of general partner units
necessary to maintain our general partners interest in us
immediately prior to the reset election.
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 the
quotient determined by dividing (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 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 unit for the two
fiscal quarters immediately preceding the reset election (which
amount we refer to as the reset minimum 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:
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first, 98.0% to all unitholders, pro rata, and 2.0% to
our general partner, until each unitholder receives an amount
equal to 115.0% of the reset minimum quarterly distribution for
that quarter;
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second, 85.0% to all unitholders, pro rata, and 15.0% to
our general partner, until each unitholder receives an amount
per unit equal to 125.0% of the reset minimum quarterly
distribution for the quarter;
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third, 75.0% to all unitholders, pro rata, and 25.0% to
our general partner, until each unitholder receives an amount
per unit equal to 150.0% of the reset minimum quarterly
distribution for the quarter; and
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66
Provisions of our
partnership agreement relating to cash distributions
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|
Ø |
thereafter, 50.0% to all unitholders, pro rata, and 50.0%
to our general partner.
|
The following table illustrates the percentage allocation of
available cash from operating surplus between the unitholders
and our general partner at various cash distribution levels
(i) pursuant to the cash distribution provisions of our
partnership agreement in effect at the closing of this offering,
as well as (ii) 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
distribution
|
|
|
|
|
|
Quarterly
distribution
|
|
|
|
General
|
|
Quarterly
distribution per unit
|
|
|
|
per unit prior to
reset
|
|
Unitholders
|
|
partner
|
|
following
hypothetical reset
|
|
|
|
|
Minimum Quarterly Distribution
|
|
$0.300
|
|
98.0%
|
|
2.0%
|
|
|
$0.600
|
|
First Target Distribution
|
|
up to $0.345
|
|
98.0%
|
|
2.0%
|
|
|
up to $0.690
|
(1)
|
Second Target Distribution
|
|
above $0.345 up to $0.375
|
|
85.0%
|
|
15.0%
|
|
|
above
$0.690(1)
up to $0.750
|
(2)
|
Third Target Distribution
|
|
above $0.375 up to $0.450
|
|
75.0%
|
|
25.0%
|
|
|
above
$0.750(2)
up to $0.900
|
(3)
|
Thereafter
|
|
above $0.450
|
|
50.0%
|
|
50.0%
|
|
|
above $0.900
|
(3)
|
|
|
|
(1) |
|
This amount is 115.0% of the
hypothetical reset minimum quarterly distribution. |
|
(2) |
|
This amount is 125.0% of the
hypothetical reset minimum quarterly distribution. |
|
(3) |
|
This amount is 150.0% 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 our general partner, including in respect of
incentive distribution rights, or IDRs, based on an average of
the amounts distributed for a quarter for the two quarters
immediately prior to the reset. The table assumes that
immediately prior to the reset there are 45,147,850 common
units outstanding, our general partner has maintained its 2.0%
general partner interest, and the average distribution to each
common unit is $0.60 for the two quarters prior to the reset.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarterly
|
|
distributions
|
|
Cash
distributions to general partner prior to reset
|
|
|
|
|
distribution
|
|
to common
|
|
|
|
2.0% general
|
|
Incentive
|
|
|
|
|
|
|
per unit
|
|
unitholders
|
|
Class B
|
|
partner
|
|
distribution
|
|
|
|
Total
|
|
|
prior to
reset
|
|
prior to
reset
|
|
units
|
|
interest
|
|
rights
|
|
Total
|
|
distributions
|
|
|
Minimum Quarterly Distribution
|
|
$0.300
|
|
$
|
13,544,355
|
|
$
|
|
|
$
|
276,415
|
|
$
|
|
|
$
|
276,415
|
|
$
|
13,820,770
|
First Target Distribution
|
|
up to $0.345
|
|
|
2,031,653
|
|
|
|
|
|
41,463
|
|
|
|
|
|
41,463
|
|
|
2,073,116
|
Second Target Distribution
|
|
above $0.345
up to $0.375
|
|
|
1,354,436
|
|
|
|
|
|
31,869
|
|
|
207,149
|
|
|
239,018
|
|
|
1,593,454
|
Third Target Distribution
|
|
above $0.375
up to $0.450
|
|
|
3,386,088
|
|
|
|
|
|
90,296
|
|
|
1,038,401
|
|
|
1,128,697
|
|
|
4,514,785
|
Thereafter
|
|
above $0.450
|
|
|
6,772,178
|
|
|
|
|
|
270,887
|
|
|
6,501,290
|
|
|
6,772,177
|
|
|
13,544,355
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
27,088,710
|
|
$
|
|
|
$
|
710,930
|
|
$
|
7,746,840
|
|
$
|
8,457,770
|
|
$
|
35,546,480
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
67
Provisions of our
partnership agreement relating to cash distributions
The following table illustrates the total amount of available
cash from operating surplus that would be distributed to the
unitholders and our general partner, including in respect of
IDRs, with respect to the quarter in which the reset occurs. The
table reflects that as a result of the reset there are
45,147,850 common units and 12,911,400 Class B
units outstanding, our general partners 2.0% interest has
been maintained, and the average distribution to each common
unit is $0.60. The number of Class B units to be issued to
our general partner upon the reset was calculated by dividing
(i) the average of the amounts received by our general
partner in respect of its IDRs for the two quarters prior to the
reset as shown in the table above, or $7,746,840, by
(ii) the average available cash distributed on each common
unit for the two quarters prior to the reset as shown in the
table above, or $0.60.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarterly
|
|
distributions
|
|
Cash
distributions to general partner after reset
|
|
|
|
|
distribution
|
|
to common
|
|
|
|
2.0% General
|
|
Incentive
|
|
|
|
|
|
|
per unit
|
|
unitholders
|
|
Class B
|
|
partner
|
|
distribution
|
|
|
|
Total
|
|
|
after
reset
|
|
after
reset
|
|
units
|
|
interest
|
|
rights
|
|
Total
|
|
distributions
|
|
|
Minimum Quarterly Distribution
|
|
$0.600
|
|
$
|
27,088,710
|
|
$
|
7,746,840
|
|
$
|
710,930
|
|
$
|
|
|
$
|
8,457,770
|
|
$
|
35,546,480
|
First Target Distribution
|
|
up to $0.690
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Target Distribution
|
|
above $0.690
up to $0.750
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Third Target Distribution
|
|
above $0.750
up to $0.900
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Thereafter
|
|
above $0.900
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
27,088,710
|
|
$
|
7,746,840
|
|
$
|
710,930
|
|
$
|
|
|
$
|
8,457,770
|
|
$
|
35,546,480
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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:
|
|
Ø
|
first, 98.0% to all unitholders, pro rata, and 2.0% to
our 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;
|
|
Ø
|
second, 98.0% to the common unitholders, pro rata, and
2.0% to our 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
|
|
Ø
|
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
68
Provisions of our
partnership agreement relating to cash distributions
distribution levels will be reduced in the same proportion as
the corresponding 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 our 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 50.0%
being paid to the holders of units and 50.0% to our general
partner. The percentage interests shown for our general partner
include its 2.0% general partner interest and assume our 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:
|
|
Ø
|
the minimum quarterly distribution;
|
|
Ø
|
target distribution levels;
|
|
Ø
|
the unrecovered initial unit price; and
|
|
Ø
|
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 do 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 the minimum
quarterly distribution and the target distribution levels for
each quarter may be reduced 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 our 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
69
Provisions of our
partnership agreement relating to cash distributions
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 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 our 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:
|
|
Ø
|
first, to our 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;
|
|
Ø
|
second, 98.0% to the common unitholders, pro rata, and
2.0% to our 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;
|
|
Ø
|
third, 98.0% to the subordinated unitholders, pro rata,
and 2.0% to our 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;
|
|
Ø
|
fourth, 98.0% to all unitholders, pro rata, and 2.0% to
our 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 98.0% to the
unitholders, pro rata, and 2.0% to our general partner, for each
quarter of our existence;
|
|
Ø
|
fifth, 85.0% to all unitholders, pro rata, and 15.0% to
our 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 85.0% to the
unitholders, pro rata, and 15.0% to our general partner for each
quarter of our existence;
|
|
Ø
|
sixth, 75.0% to all unitholders, pro rata, and 25.0% to
our 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 75.0% to the
unitholders, pro rata, and 25.0% to our general partner for each
quarter of our existence; and
|
|
Ø
|
thereafter, 50.0% to all unitholders, pro rata, and 50.0%
to our general partner.
|
The percentage interests set forth above for our general partner
include its 2.0% general partner interest and assume our general
partner has not transferred the incentive distribution rights.
If the liquidation occurs after the end of the subordination
period, the distinction between common 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.
70
Provisions of our
partnership agreement relating to cash distributions
Manner of
adjustments for losses
If our liquidation occurs before the end of the subordination
period, we will generally allocate any loss to our general
partner and the unitholders in the following manner:
|
|
Ø
|
first, 98.0% to holders of subordinated units in
proportion to the positive balances in their capital accounts
and 2.0% to our general partner, until the capital accounts of
the subordinated unitholders have been reduced to zero;
|
|
Ø
|
second, 98.0% to the holders of common units in
proportion to the positive balances in their capital accounts
and 2.0% to our general partner, until the capital accounts of
the common unitholders have been reduced to zero; and
|
|
Ø
|
thereafter, 100.0% to our general partner.
|
If the liquidation occurs after the end of the subordination
period, the distinction between common 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.
71
Selected
historical and pro forma financial and operating data
The following table shows (i) the selected combined
historical financial and operating data of our Predecessor,
which are comprised of Anadarko Gathering Company and Pinnacle
Gas Treating, Inc., with MIGC, Inc. (MIGC) reported
as an acquired business of our Predecessor, and (ii) the
selected combined pro forma as adjusted financial and operating
data of the Partnership, for the periods and as of the dates
indicated. The information in the following table should also be
read together with Managements discussion and
analysis of financial condition and results of
operations.
Our Predecessors selected combined historical balance
sheet data as of December 31, 2006 and 2005 and selected
combined historical statement of income and statement of cash
flow data for the years ended December 31, 2006, 2005 and
2004 are derived from the audited historical combined financial
statements of our Predecessor included elsewhere in this
prospectus. Our Predecessors selected combined historical
balance sheet data as of December 31, 2004, 2003 and 2002
and selected combined historical statement of income for the
years ended December 31, 2003 and 2002 are derived from the
unaudited historical combined financial statements of our
Predecessor not included in this prospectus. Our
Predecessors selected combined historical balance sheet
data as of September 30, 2007 and selected combined
historical statement of income and statement of cash flow data
for the nine months ended September 30, 2007 and 2006 are
derived from the unaudited historical combined financial
statements of our Predecessor included elsewhere in this
prospectus. Our Predecessors selected combined historical
balance sheet data as of September 30, 2006 are derived
from the unaudited historical financial statements of our
Predecessor not included in this prospectus.
The Partnerships selected combined pro forma as adjusted
statement of income data for the year ended December 31,
2006 and the nine months ended September 30, 2007 and
selected combined pro forma as adjusted balance sheet data as of
September 30, 2007 are derived from the unaudited pro forma
combined financial statements of the Partnership included
elsewhere in this prospectus.
The pro forma adjustments have been prepared as if the
acquisition of MIGC by our Predecessor occurred on
January 1, 2006 and as if certain transactions to be
effected at the closing of this offering had taken place on
September 30, 2007, in the case of the pro forma balance
sheet, and on January 1, 2006, in the case of the pro forma
statements of operations for the year ended December 31,
2006 and the nine months ended September 30, 2007. These
transactions include:
|
|
Ø |
the receipt by the Partnership of gross proceeds of
$375.0 million from the issuance and sale of 18,750,000
common units at an assumed initial offering price of $20.00 per
unit;
|
|
|
Ø |
the use of the proceeds from this offering to pay underwriting
discounts and a structuring fee totaling approximately
$24.4 million and other estimated offering expenses of
$3.0 million; and
|
|
|
Ø |
the use of the remaining $347.6 million of aggregate net
proceeds of this offering to (i) make a loan of
$337.6 million to Anadarko in exchange for a
30-year note
bearing interest at a fixed annual rate of 6.00% and
(ii) provide $10.0 million for general partnership
purposes.
|
The following table includes our Predecessors historical
and our pro forma Adjusted EBITDA, which have not been prepared
in accordance with GAAP. Adjusted EBITDA is presented because it
is helpful to management, industry analysts, investors, lenders
and rating agencies and may be used to assess the financial
performance and operating results of our fundamental business
activities. For a reconciliation of Adjusted EBITDA to its most
directly comparable financial measures calculated and presented
in accordance with GAAP, please read Prospectus
summaryNon-GAAP financial measure.
72
Selected
historical and pro forma financial and operating data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partnership pro
forma
|
|
|
|
Predecessor
combined
|
|
as
adjusted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months
|
|
ended
|
|
|
Year ended
|
|
|
|
Year ended
December 31,
|
|
|
ended
September 30,
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2006
|
|
2005
|
|
|
2004
|
|
2003
|
|
2002
|
|
|
2007
|
|
2006
|
|
2007
|
|
|
2006
|
|
|
|
|
|
(in thousands,
except operating and per unit data)
|
|
|
Statement of Income Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
81,152
|
|
$
|
71,650
|
|
|
$
|
68,049
|
|
$
|
61,401
|
|
$
|
50,266
|
|
|
$
|
85,513
|
|
$
|
57,481
|
|
$
|
85,513
|
|
|
$
|
93,304
|
|
Costs and expenses
|
|
|
39,960
|
|
|
35,720
|
|
|
|
31,301
|
|
|
33,804
|
|
|
31,135
|
|
|
|
33,184
|
|
|
29,057
|
|
|
33,184
|
|
|
|
43,857
|
|
Depreciation
|
|
|
18,009
|
|
|
15,447
|
|
|
|
14,841
|
|
|
14,294
|
|
|
16,509
|
|
|
|
17,104
|
|
|
12,635
|
|
|
17,104
|
|
|
|
19,710
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
57,969
|
|
|
51,167
|
|
|
|
46,142
|
|
|
48,098
|
|
|
47,644
|
|
|
|
50,288
|
|
|
41,692
|
|
|
50,288
|
|
|
|
63,567
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
23,183
|
|
|
20,483
|
|
|
|
21,907
|
|
|
13,303
|
|
|
2,622
|
|
|
|
35,225
|
|
|
15,789
|
|
|
35,225
|
|
|
|
29,737
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other (expense) income
|
|
|
26
|
|
|
(66
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25
|
|
|
|
|
|
|
377
|
|
Interest expense (income)
|
|
|
9,631
|
|
|
8,650
|
|
|
|
7,146
|
|
|
6,782
|
|
|
9,019
|
|
|
|
6,643
|
|
|
7,943
|
|
|
(15,022
|
)
|
|
|
(20,030
|
)
|
Income tax expense (benefit)
|
|
|
3,814
|
|
|
4,789
|
|
|
|
5,504
|
|
|
2,529
|
|
|
(2,331
|
)
|
|
|
10,469
|
|
|
1,740
|
|
|
160
|
|
|
|
978
|
|
Change in accounting principle
|
|
|
|
|
|
|
|
|
|
|
|
|
1,510
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
9,712
|
|
$
|
7,110
|
|
|
$
|
9,257
|
|
$
|
5,502
|
|
$
|
(4,066
|
)
|
|
$
|
18,113
|
|
$
|
6,081
|
|
$
|
50,087
|
|
|
$
|
48,412
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner interest in pro forma net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,315
|
|
|
|
968
|
|
Common unitholders interest in pro forma net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24,386
|
|
|
|
23,772
|
|
Subordinated unitholders interest in pro forma net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24,386
|
|
|
|
23,772
|
|
Net income per common unit (basic and diluted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1.08
|
|
|
$
|
1.05
|
|
Net income per subordinated unit (basic and diluted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1.08
|
|
|
$
|
1.05
|
|
Balance Sheet Data (at period end):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net, property, plant and equipment
|
|
$
|
310,871
|
|
$
|
200,451
|
|
|
$
|
196,065
|
|
$
|
192,415
|
|
$
|
200,398
|
|
|
$
|
353,294
|
|
$
|
302,057
|
|
$
|
353,294
|
|
|
|
|
|
Total assets
|
|
|
332,228
|
|
|
206,373
|
|
|
|
199,110
|
|
|
195,747
|
|
|
203,623
|
|
|
|
360,692
|
|
|
324,772
|
|
|
708,306
|
|
|
|
|
|
Total parent net equity
|
|
|
238,531
|
|
|
160,585
|
|
|
|
162,542
|
|
|
167,881
|
|
|
175,886
|
|
|
|
273,507
|
|
|
234,063
|
|
|
691,561
|
|
|
|
|
|
73
Selected
historical and pro forma financial and operating data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partnership pro
forma
|
|
|
Predecessor
combined
|
|
|
as
adjusted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months
|
|
|
ended
|
|
Year ended
|
|
|
Year ended
December 31,
|
|
ended
September 30,
|
|
|
September 30,
|
|
December 31,
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
2002
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
2006
|
|
|
|
(in thousands,
except operating and per unit data)
|
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
|
27,323
|
|
|
|
30,131
|
|
|
|
31,160
|
|
|
|
|
|
|
|
|
|
41,810
|
|
|
|
12,941
|
|
|
|
|
|
|
|
Investing activities
|
|
|
(42,713
|
)
|
|
|
(21,076
|
)
|
|
|
(16,548
|
)
|
|
|
|
|
|
|
|
|
(37,247
|
)
|
|
|
(27,952
|
)
|
|
|
|
|
|
|
Financing activities
|
|
|
15,844
|
|
|
|
(9,067
|
)
|
|
|
(14,596
|
)
|
|
|
|
|
|
|
|
|
(5,021
|
)
|
|
|
15,007
|
|
|
|
|
|
|
|
Adjusted
EBITDA(1)
|
|
|
41,192
|
|
|
|
35,930
|
|
|
|
36,748
|
|
|
|
|
|
|
|
|
|
52,329
|
|
|
|
28,424
|
|
|
|
52,329
|
|
|
49,447
|
Capital expenditures, net
|
|
|
42,299
|
|
|
|
20,841
|
|
|
|
16,548
|
|
|
|
|
|
|
|
|
|
37,020
|
|
|
|
27,709
|
|
|
|
|
|
|
|
Operating Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput, MMBtu/d
|
|
|
820
|
|
|
|
757
|
|
|
|
715
|
|
|
|
667
|
|
|
700
|
|
|
904
|
|
|
|
778
|
|
|
|
904
|
|
|
878
|
Average rate per MMBtu
|
|
$
|
0.22
|
|
|
$
|
0.21
|
|
|
$
|
0.21
|
|
|
$
|
0.19
|
|
$
|
0.17
|
|
$
|
0.28
|
|
|
$
|
0.22
|
|
|
$
|
0.28
|
|
$
|
0.23
|
Third Party
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput, MMBtu/d
|
|
|
72
|
|
|
|
41
|
|
|
|
31
|
|
|
|
32
|
|
|
15
|
|
|
90
|
|
|
|
64
|
|
|
|
90
|
|
|
93
|
Average rate per MMBtu
|
|
$
|
0.19
|
|
|
$
|
0.16
|
|
|
$
|
0.13
|
|
|
$
|
0.09
|
|
$
|
0.14
|
|
$
|
0.25
|
|
|
$
|
0.21
|
|
|
$
|
0.25
|
|
$
|
0.23
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput, MMBtu/d
|
|
|
892
|
|
|
|
798
|
|
|
|
746
|
|
|
|
699
|
|
|
715
|
|
|
994
|
|
|
|
842
|
|
|
|
994
|
|
|
971
|
Average rate per MMBtu
|
|
$
|
0.21
|
|
|
$
|
0.21
|
|
|
$
|
0.21
|
|
|
$
|
0.18
|
|
$
|
0.16
|
|
$
|
0.28
|
|
|
$
|
0.22
|
|
|
$
|
0.28
|
|
$
|
0.23
|
|
|
|
(1) |
|
Adjusted EBITDA is defined in
Prospectus summaryNon-GAAP financial
measure. For a reconciliation of Adjusted EBITDA to their
most directly comparable financial measures calculated and
presented in accordance with GAAP, please read Prospectus
summaryNon-GAAP
financial measure. |
74
Managements
discussion and analysis of financial condition and results of
operations
The historical combined financial statements included in this
prospectus reflect the assets, liabilities and operations of our
Predecessor, which is comprised of Anadarko Gathering Company
(AGC) and Pinnacle Gas Treating, Inc.
(PGT), with MIGC, Inc. (MIGC) reported
as an acquired business of our Predecessor. All of the assets,
liabilities and operations of our Predecessor will be
contributed to us by Anadarko upon the closing of this offering.
The following discussion analyzes the financial condition and
results of operations of our Predecessor. You should read the
following discussion and analysis of financial condition and
results of operations in conjunction with the historical and pro
forma combined financial statements, and the notes thereto,
included elsewhere in this prospectus. For ease of reference, we
refer to the historical financial results of our Predecessor as
being our historical financial results.
We are a growth-oriented Delaware limited partnership recently
formed by Anadarko to own, operate, acquire and develop
midstream energy assets. We currently operate in East Texas, the
Rocky Mountains, the Mid-Continent and West Texas and are
engaged in the business of gathering, compressing, treating and
transporting natural gas for our ultimate parent, Anadarko, and
third-party producers and customers.
Our results are driven primarily by the volumes of natural gas
we gather, compress, treat and transport through our systems.
For the nine months ended September 30, 2007, approximately
84% of our revenues were derived from gathering, compression and
treating activities and 16% was derived from transportation
activities. Approximately 9% of our gathering, compression and
treating revenues were comprised of revenues from condensate
sales. For the nine months ended September 30, 2007, 89% of
our total revenues were generated by transactions with Anadarko.
In our gathering operations, we contract with producers to
gather natural gas from individual wells located near our
gathering systems. We connect wells to gathering lines through
which natural gas may be compressed and delivered to a
processing plant, treating facility or downstream pipeline, and
ultimately to end-users. We also treat a significant portion of
the natural gas that we gather so that it will meet required
specifications for pipeline transportation.
We have secured a significant dedication from our largest
customer, Anadarko, in order to maintain or increase our
existing throughput levels and to offset the natural production
declines of the wells currently connected to our gathering
systems. Specifically, Anadarko has dedicated to us all of the
natural gas production it owns or controls from (i) wells
that are currently connected to our gathering systems, and
(ii) additional wells that are drilled within one mile of
connected wells or our gathering systems, as the systems
currently exist and as they are expanded to connect additional
wells in the future. As a result, this dedication will continue
to expand as additional wells are connected to our gathering
systems. Volumes associated with this dedication averaged
approximately 736 MMBtu/d for the year ended December 31,
2006 and 738 MMBtu/d for the nine months ended
September 30, 2007.
We generally do not take title to the natural gas that we
gather, compress, treat or transport. We currently provide all
of our gathering and treating services pursuant to fee-based
contracts. Under these arrangements, we are paid a fixed fee
based on the volume and thermal content of the natural gas we
gather or treat. This type of contract provides us with a
relatively steady revenue stream that is not subject to direct
commodity price risk, except to the extent that we retain and
sell condensate that is recovered during the gathering of
natural gas from the wellhead. We have entered into new
gathering
75
Managements
discussion and analysis of financial condition and results of
operations
contracts with Anadarko pursuant to which we will receive higher
fees than we have historically realized. We have some indirect
exposure to commodity price risk in that persistent low
commodity prices may cause our current or potential customers to
delay drilling or shut in production, which would reduce the
volumes of natural gas available for gathering, compressing,
treating and transporting by our systems. Please read
Quantitative and qualitative disclosures about
market risk below for a discussion of our exposure to
commodity price risk through our condensate recovery and sales.
We provide a significant portion of our transportation services
on our MIGC system through firm contracts that obligate our
customers to pay a monthly reservation or demand charge, which
is a fixed charge applied to firm contract capacity and owed by
a customer regardless of the actual pipeline capacity used by
that customer. When a customer uses the capacity it has reserved
under these contracts, we are entitled to collect an additional
commodity usage charge based on the actual volume of natural gas
transported. These usage charges are typically a small
percentage of the total revenues received from our firm capacity
contracts. We also provide transportation services through
interruptible contracts, pursuant to which a fee is charged to
our customers based upon actual volumes transported through the
pipeline.
HOW
WE EVALUATE OUR OPERATIONS
Our management relies on certain financial and operational
metrics to analyze our performance. These metrics are
significant factors in assessing our operating results and
profitability and include (1) throughput volumes,
(2) operating expenses, (3) Adjusted EBITDA, and
(4) distributable cash flow.
Throughput
volumes
In order to maintain or increase throughput volumes on our
gathering systems, we must connect additional wells to our
systems. Our success in connecting additional wells is impacted
by successful drilling activity on the acreage dedicated to our
systems, our ability to secure volumes from new wells drilled on
non-dedicated acreage and our ability to attract natural gas
volumes currently gathered by our competitors.
To maintain and increase throughput volumes on our MIGC system,
we must continue to contract our capacity to shippers, including
producers and marketers, for transportation of their natural
gas. We monitor producer and marketing activities in the area
served by our transportation system to identify new
opportunities.
Operating
expenses
We analyze operating expenses to evaluate our performance. The
primary components of our operating expenses that we evaluate
include operation and maintenance expenses, cost of product
expenses, general and administrative expenses and direct
operating expenses. Certain of our operating expenses are
classified based on whether the expenses are accrued for or paid
to our affiliates or third-party vendors. Neither affiliate
expenses nor third-party expenses bear a direct relationship to
affiliate revenues or third-party revenues. For example, our
third-party expenses are not those expenses necessary for
generating our third-party revenues. Third-party expenses
include all amounts accrued for or paid to third parties for the
operation of our systems, whether in providing services to
Anadarko or third parties, including utilities, field labor,
measurement and analysis and other third-party disbursements.
Operation and maintenance expenses include, among other things,
direct labor, insurance, repair and maintenance, contract
services, utility costs and services provided to us or on our
behalf under our services and secondment agreement.
76
Managements
discussion and analysis of financial condition and results of
operations
Cost of product expenses include (i) costs associated with
the purchase of natural gas pursuant to the gas imbalance
provisions contained in our contracts, (ii) costs
associated with our obligation under certain contracts to
redeliver a volume of natural gas to shippers which is thermally
equivalent to condensate retained by us and sold to third
parties and (iii) our fuel tracking mechanism, which tracks
the difference between actual fuel usage and loss and amounts
recovered for estimated fuel usage and loss under our contracts.
These expenses are subject to variability. However, for the
years ended December 31, 2006, 2005 and 2004, cost of
product expenses comprised only 7.8%, 11.7% and 10.8% of total
operating expenses, respectively. Thus, we do not expect the
variability in our cost of product expenses to have a material
impact on our overall results.
In our historical combined financial statements, general and
administrative expenses included reimbursements of costs
incurred by Anadarko on our behalf and allocations from Anadarko
in the form of a management service fee in lieu of direct
reimbursements for various corporate services. In the future,
Anadarko will not receive a management services fee and we
expect general and administrative expenses to be comprised
primarily of amounts reimbursed by us to Anadarko pursuant to
our omnibus agreement with Anadarko and expenses attributable to
our status as a publicly traded partnership, such as expenses
associated with annual and quarterly reporting; tax return and
Schedule K-1
preparation and distribution expenses; Sarbanes-Oxley compliance
expenses; expenses associated with listing on the New York Stock
Exchange; independent auditor fees; legal fees; investor
relations expenses; and registrar and transfer agent fees.
Pursuant to the omnibus agreement with Anadarko, we will
reimburse Anadarko for allocated general and administrative
expenses. The amount required to be reimbursed by us to Anadarko
for certain allocated general and administrative expenses
pursuant to the omnibus agreement will be capped at
$6.0 million annually through December 31, 2009,
subject to adjustment to reflect changes in the Consumer Price
Index and, with the concurrence of the special committee of our
general partners board of directors, to reflect expansions
of our operations through the acquisition or construction of new
assets or businesses. Thereafter, our general partner will
determine the general and administrative expenses to be
reimbursed by us in accordance with our partnership agreement.
The cap contained in the omnibus agreement does not apply to
incremental general and administrative expenses we expect to
incur or to be allocated to us as a result of becoming a
publicly traded partnership. We currently expect those expenses
to be approximately $2.5 million per year.
Adjusted
EBITDA
We define Adjusted EBITDA as net income (loss), plus interest
expense, income taxes and depreciation, less interest income and
other income (expense). Adjusted EBITDA is not a presentation
made in accordance with GAAP. For a reconciliation of Adjusted
EBITDA to its most directly comparable financial measures
calculated and presented in accordance with GAAP, please read
Prospectus summaryNon-GAAP financial measure.
Distributable
cash flow
We define distributable cash flow as Adjusted EBITDA, plus
interest income, less net cash paid for interest expense,
maintenance capital expenditures and income taxes. Distributable
cash flow does not reflect changes in working capital balances.
Distributable cash flow is not a presentation made in accordance
with GAAP.
77
Managements
discussion and analysis of financial condition and results of
operations
Adjusted EBITDA and distributable cash flow are supplemental
financial measures that management and external users of our
combined financial statements, such as industry analysts,
investors, lenders and rating agencies, may use to assess:
|
|
Ø
|
our operating performance as compared to other publicly traded
partnerships in the midstream energy industry, without regard to
financing methods, capital structure or historical cost basis;
|
|
Ø
|
the ability of our assets to generate sufficient cash flow to
make distributions to our unitholders; and
|
|
Ø
|
the viability of acquisitions and capital expenditure projects
and the returns on investment of various investment
opportunities.
|
ITEMS AFFECTING
THE COMPARABILITY OF OUR FINANCIAL RESULTS
Our historical results of operations for the periods presented
below may not be comparable to our results of operations in the
future for the reasons described below:
|
|
Ø |
We anticipate incurring approximately $2.5 million of
general and administrative expenses attributable to operating as
a publicly traded partnership, such as expenses associated with
annual and quarterly reporting; tax return and
Schedule K-1
preparation and distribution expenses; Sarbanes-Oxley compliance
expenses; expenses associated with listing on the New York Stock
Exchange; independent auditor fees; legal fees; investor
relations expenses; and registrar and transfer agent fees. These
incremental general and administrative expenses are not
reflected in our historical or our pro forma combined financial
statements.
|
|
|
Ø
|
We anticipate incurring $6.0 million in general and
administrative expenses to be allocated to us by Anadarko
pursuant to the omnibus agreement. This amount is expected to be
greater than the amount allocated to us by Anadarko for the
management services fee and reflected in our historical combined
financial statements.
|
|
Ø
|
The impact of all affiliated transactions historically has been
net settled within our combined financial statements because
these transactions related to Anadarko and were funded by
Anadarkos working capital. Third-party transactions were
funded by our working capital. In the future, all affiliate and
third-party transactions will be funded by our working capital.
This will impact the comparability of our cash flow statements,
working capital analysis and liquidity discussion.
|
|
Ø
|
Prior to this offering, we incurred interest expense on
intercompany notes payable to Anadarko. These balances were
extinguished through non-cash transactions prior to this
offering; therefore, interest expense attributable to these
balances and reflected in our historical combined financial
statements will not be incurred in future periods.
|
|
Ø
|
We have entered into new gas gathering agreements with Anadarko
which include fees for gathering and treating that are higher
than those fees reflected in our historical financial results.
|
|
|
Ø |
Our combined financial statements reflect the gathering fees we
historically charged Anadarko under our affiliate cost
of service based arrangements. Under these arrangements, we
recovered, on an annual basis, our operation and maintenance,
general and administrative and depreciation expenses in addition
to earning a return on our invested capital. Effective
January 1, 2008, we entered into new
10-year gas
gathering agreements with Anadarko. Under the terms of these new
agreements, we expect our operation and maintenance expense to
increase as a result of our bearing all of the cost of employee
benefits specifically identified and related to operational
personnel working on our assets as compared to bearing only
those employee benefit costs reasonably allocated by Anadarko to
us in historic periods. Since our new gas gathering agreements
are designed to fully recover these costs, our future revenues
are expected to increase by an amount equal to the increase in
operation and maintenance expense. Although we do not expect
this change in methodology for
|
78
Managements
discussion and analysis of financial condition and results of
operations
computing affiliate gathering rates to impact our net cash flows
or net income, we do expect this methodology change to impact
the components thereof as compared to historic periods. If we
applied the methodology employed under our new gas gathering
agreements with Anadarko to historic periods, we estimate our
gathering revenues and operation and maintenance expense for the
years ended December 31, 2006, 2005, and 2004, would have
increased by $2.8 million, $1.4 million and
$0.9 million, respectively.
|
|
Ø |
Concurrently with the closing of this offering, we will loan
$337.6 million to Anadarko in exchange for an
interest-only,
30-year note
bearing interest at a fixed annual rate of 6.00%. Interest
income attributable to the note is not reflected in our
historical combined financial statements, but will be included
in our combined financial statements in the future.
|
|
|
Ø |
As a co-borrower under Anadarkos credit facility, we will
incur an annual commitment fee of 0.175% of our committed and
unused borrowing capacity of up to $100 million, or up to
$175,000. In addition, Anadarko will enter into a working
capital facility with us, under which we will incur an annual
commitment fee of 0.175% of the unused portion of our committed
borrowing capacity of $30 million, or up to $52,500.
|
|
|
Ø |
Our historical combined financial statements include
U.S. federal and state income tax expense incurred by us.
Due to our status as a partnership, we will not be subject to
U.S. federal income tax and certain state income taxes in
the future. However, we will make payments to Anadarko pursuant
to a tax sharing agreement for our share of state and local
income and other taxes that are included in combined or
consolidated tax returns filed by Anadarko.
|
|
|
Ø |
Following the closing of this offering, we intend to make cash
distributions to our unitholders and our general partner at an
initial distribution rate of $0.30 per unit per quarter ($1.20
per unit on an annualized basis). Based on the terms of our cash
distribution policy, we expect that we will distribute to our
unitholders and our general partner most of the cash generated
by our operations. As a result, we expect that we will rely upon
external financing sources, including commercial bank borrowings
and debt and equity issuances, to fund our acquisition and
expansion capital expenditures. Historically, we largely relied
on internally generated cash flows and capital contributions
from Anadarko to satisfy our capital expenditure requirements.
|
GENERAL
TRENDS AND OUTLOOK
We expect our business to continue to be affected by the
following key trends. Our expectations are based on assumptions
made by us and information currently available to us. To the
extent our underlying assumptions about, or interpretations of,
available information prove to be incorrect, our actual results
may vary materially from our expected results.
Natural gas
supply and demand
Natural gas continues to be a critical component of energy
supply in the U.S. According to the Energy Information
Administration, or EIA, total annual domestic consumption of
natural gas is expected to increase from approximately
21.7 trillion cubic feet, or Tcf, in 2006 to approximately
24.7 Tcf in 2010. During the last three years, the U.S.
has, on average, consumed approximately 22.0 Tcf per year,
while total domestic production averaged approximately 18.4 Tcf
per year during the same period. We believe that high natural
gas prices and increasing demand will continue to drive an
increase in natural gas drilling and production in the U.S.
Natural gas reserves in the U.S. have increased overall in
recent years, based on data obtained from the EIA.
There is a natural decline in production from existing wells,
but in the areas in which we operate there is a significant
level of drilling activity that can offset this decline.
Although we anticipate continued
79
Managements
discussion and analysis of financial condition and results of
operations
high levels of exploration and production activities in all of
the areas in which we operate, we have no control over this
activity. Fluctuations in energy prices could affect production
rates over time and levels of investment by Anadarko and third
parties in exploration for and development of new natural gas
reserves.
Rising operating
costs and inflation
The current high level of natural gas exploration, development
and production activities across the U.S. has resulted in
increased competition for personnel and equipment. This is
causing increases in the prices we pay for labor, supplies and
property, plant and equipment. An increase in the general level
of prices in the economy could have a similar effect. We attempt
to recover increased costs from our customers, but there may be
a delay in doing so or we may be unable to recover all these
costs. To the extent we are unable to procure necessary supplies
or recover higher costs, our operating results will be
negatively impacted.
Impact of
interest rates
Interest rates have been volatile in recent periods. If interest
rates rise, our future financing costs will increase
accordingly. In addition, because our common units are
yield-based securities, rising market interest rates could
impact the relative attractiveness of our common units to
investors, which could limit our ability to raise funds, or
increase the price of raising funds, in the capital markets.
Though our competitors may face similar circumstances, such an
environment could render us less competitive in our efforts to
expand our operations or make future acquisitions.
Benefits from
system expansions
We expect that expansion projects, including the following, will
allow us to capitalize on increased drilling activity by
Anadarko and other third-party producers:
|
|
Ø |
We are installing additional compressors on our Dew system which
will add an incremental 16,375 horsepower by the end of 2007;
|
|
|
Ø |
We are expanding our Bethel treating facility by installing an
additional 11 LTD of sulfur treating capacity in order to
provide additional sour gas treating capacity for drilling in
the area, which we expect to complete in 2008; and
|
|
|
Ø |
We are expanding our Hugoton gathering system.
|
Acquisition
opportunities
We may acquire additional midstream energy assets from Anadarko,
although Anadarko is under no legal obligation to offer assets
or business opportunities to us. In addition, we may also pursue
selected asset acquisitions from third parties to the extent
such acquisitions complement our or Anadarkos existing
asset base or allow us to capture operational efficiencies from
Anadarkos production. However, if we do not make
acquisitions on economically acceptable terms, our future growth
will be limited, and the acquisitions we do make may reduce,
rather than increase, our cash generated from operations on a
per unit basis.
80
Managements
discussion and analysis of financial condition and results of
operations
RESULTS
OF OPERATIONSCOMBINED OVERVIEW
The following table and discussion presents a summary of our
combined results of operations for the years ended
December 31, 2006, 2005 and 2004 and for the nine months
ended September 30, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended
December 31,
|
|
|
Nine months ended
September 30,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
(in
thousands)
|
|
|
Revenues-affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and transportation of natural gas
|
|
$
|
65,946
|
|
|
$
|
58,363
|
|
|
$
|
54,407
|
|
|
$
|
69,311
|
|
|
$
|
46,546
|
|
Condensate
|
|
|
7,440
|
|
|
|
7,006
|
|
|
|
6,407
|
|
|
|
6,266
|
|
|
|
5,374
|
|
Natural gas and other
|
|
|
1,327
|
|
|
|
789
|
|
|
|
4,526
|
|
|
|
918
|
|
|
|
324
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
74,713
|
|
|
|
66,158
|
|
|
|
65,340
|
|
|
|
76,495
|
|
|
|
52,244
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues-third parties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and transportation of natural gas
|
|
|
5,022
|
|
|
|
2,420
|
|
|
|
1,458
|
|
|
|
6,067
|
|
|
|
3,660
|
|
Condensate, natural gas and other
|
|
|
1,417
|
|
|
|
3,072
|
|
|
|
1,251
|
|
|
|
2,951
|
|
|
|
1,577
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
6,439
|
|
|
|
5,492
|
|
|
|
2,709
|
|
|
|
9,018
|
|
|
|
5,237
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
81,152
|
|
|
|
71,650
|
|
|
|
68,049
|
|
|
|
85,513
|
|
|
|
57,481
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses-affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of product
|
|
|
3,830
|
|
|
|
5,551
|
|
|
|
4,425
|
|
|
|
4,439
|
|
|
|
4,196
|
|
General and administrative
|
|
|
3,198
|
|
|
|
2,829
|
|
|
|
2,251
|
|
|
|
2,370
|
|
|
|
2,394
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
7,028
|
|
|
|
8,380
|
|
|
|
6,676
|
|
|
|
6,809
|
|
|
|
6,590
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses-third parties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of product
|
|
|
714
|
|
|
|
456
|
|
|
|
553
|
|
|
|
|
|
|
|
|
|
Operation and
maintenance(1)
|
|
|
27,585
|
|
|
|
23,044
|
|
|
|
20,678
|
|
|
|
21,840
|
|
|
|
18,598
|
|
General and administrative
|
|
|
|
|
|
|
9
|
|
|
|
48
|
|
|
|
751
|
|
|
|
204
|
|
Property and other taxes
|
|
|
4,633
|
|
|
|
3,831
|
|
|
|
3,346
|
|
|
|
3,784
|
|
|
|
3,665
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
32,932
|
|
|
|
27,340
|
|
|
|
24,625
|
|
|
|
26,375
|
|
|
|
22,467
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
|
|
|
18,009
|
|
|
|
15,447
|
|
|
|
14,841
|
|
|
|
17,104
|
|
|
|
12,635
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
57,969
|
|
|
|
51,167
|
|
|
|
46,142
|
|
|
|
50,288
|
|
|
|
41,692
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
23,183
|
|
|
|
20,483
|
|
|
|
21,907
|
|
|
|
35,225
|
|
|
|
15,789
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense)
|
|
|
(26
|
)
|
|
|
66
|
|
|
|
|
|
|
|
|
|
|
|
(25
|
)
|
Interest expense
|
|
|
9,631
|
|
|
|
8,650
|
|
|
|
7,146
|
|
|
|
6,643
|
|
|
|
7,943
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
13,526
|
|
|
|
11,899
|
|
|
|
14,761
|
|
|
|
28,582
|
|
|
|
7,821
|
|
Income tax expense
|
|
|
3,814
|
|
|
|
4,789
|
|
|
|
5,504
|
|
|
|
10,469
|
|
|
|
1,740
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
9,712
|
|
|
$
|
7,110
|
|
|
$
|
9,257
|
|
|
$
|
18,113
|
|
|
$
|
6,081
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted
EBITDA(2)
|
|
$
|
41,192
|
|
|
$
|
35,930
|
|
|
$
|
36,748
|
|
|
$
|
52,329
|
|
|
$
|
28,424
|
|
|
|
|
(1) |
|
Third-party operation and
maintenance expenses do not bear a direct relationship to
third-party revenues because all operating expenses ultimately
settled with third parties, including utilities, field labor,
measurement and analysis and other expenses, are included within
third-party operation and maintenance expenses. |
|
|
|
(2) |
|
We define Adjusted EBITDA as net
income (loss), plus interest expense, income taxes and
depreciation, less interest income and other income (expense).
For a reconciliation of this measure to its directly comparable
financial measures calculated and presented in accordance with
GAAP, please read Prospectus
summaryNon-GAAP financial measure. |
81
Managements
discussion and analysis of financial condition and results of
operations
Our discussion below compares the results for specific periods
to the previous comparable period. The discussion compares:
(i) the twelve months ended December 31, 2006 to the
twelve months ended December 31, 2005, (ii) the twelve
months ended December 31, 2005 to the twelve months ended
December 31, 2004 and (iii) the nine months ended
September 30, 2007 to the nine months ended
September 30, 2006.
For purposes of the following discussion:
|
|
Ø
|
any increases or decreases for the year ended
December 31, 2006 refer to the comparison of the
twelve-month period ended December 31, 2006 to the
twelve-month period ended December 31, 2005;
|
|
Ø
|
any increases or decreases for the year ended
December 31, 2005 refer to the comparison of the
twelve-month period ended December 31, 2005 to the
twelve-month period ended December 31, 2004; and
|
|
|
Ø |
any increases or decreases for the nine months ended
September 30, 2007 refer to the comparison of the
nine-month period ended September 30, 2007 to the
nine-month period ended September 30, 2006.
|
We acquired MIGC on August 23, 2006. The following
discussion only includes MIGC operating results since the date
of its acquisition.
Summary
Total revenues increased by $9.5 million and
$3.6 million for the year ended December 31, 2006 and
for the year ended December 31, 2005, respectively. Total
revenues also increased by $28.0 million for the nine
months ended September 30, 2007. The primary reason
revenues increased for the year ended December 31, 2006 and
for the nine months ended September 30, 2007 was the
acquisition of MIGC in August 2006; however, the 2006 and 2007
revenue increases were also aided by increased rates and
increased throughput volumes, respectively. The revenue increase
for the year ended December 31, 2005 was driven by higher
throughput volumes. The revenue increases for these periods were
partially offset by higher costs and expenses, as described in
more detail below.
Net income increased by $2.6 million and decreased by
$2.1 million for the year ended December 31, 2006 and
for the year ended December 31, 2005, respectively. Net
income increased by $12.0 million for the nine months ended
September 30, 2007. The increase in net income for the year
ended December 31, 2006 was attributable to the increase in
revenue discussed above, partially offset by increased operating
costs. The decrease in net income for the year ended
December 31, 2005 was attributable to increased operating
expenses, partially offset by increased revenues. The increase
in net income for the nine months ended September 30, 2007
was attributable to the revenue increase discussed above,
partially offset by increased operating costs and income tax
expense.
82
Managements
discussion and analysis of financial condition and results of
operations
Revenues
and operating statistics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months
ended
|
|
|
|
Year ended
December 31,
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
(in thousands,
except operating and per unit data)
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
$
|
74,713
|
|
|
$
|
66,158
|
|
|
$
|
65,340
|
|
|
$
|
76,495
|
|
|
$
|
52,244
|
|
Third-party
|
|
|
6,439
|
|
|
|
5,492
|
|
|
|
2,709
|
|
|
|
9,018
|
|
|
|
5,237
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
81,152
|
|
|
$
|
71,650
|
|
|
$
|
68,049
|
|
|
$
|
85,513
|
|
|
$
|
57,481
|
|
Throughput (MMbtu/d)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
820
|
|
|
|
757
|
|
|
|
715
|
|
|
|
904
|
|
|
|
778
|
|
Third-party
|
|
|
72
|
|
|
|
41
|
|
|
|
31
|
|
|
|
90
|
|
|
|
64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total throughput
|
|
|
892
|
|
|
|
798
|
|
|
|
746
|
|
|
|
994
|
|
|
|
842
|
|
Weighted average price per MMbtu
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
$
|
0.22
|
|
|
$
|
0.21
|
|
|
$
|
0.21
|
|
|
$
|
0.28
|
|
|
$
|
0.22
|
|
Third-party
|
|
$
|
0.19
|
|
|
$
|
0.16
|
|
|
$
|
0.13
|
|
|
$
|
0.25
|
|
|
$
|
0.21
|
|
Total
|
|
$
|
0.21
|
|
|
$
|
0.21
|
|
|
$
|
0.21
|
|
|
$
|
0.28
|
|
|
$
|
0.22
|
|
Total revenues. Total revenues increased by
$9.5 million and $3.6 million for the year ended
December 31, 2006 and for the year ended December 31,
2005, respectively. Total revenues also increased by
$28.0 million for the nine months ended September 30,
2007. Additional discussion regarding increases in affiliate and
third-party revenues is provided below.
Revenues affiliate. Affiliate
revenues increased by $8.6 million for the year ended
December 31, 2006. Of this amount, $4.2 million was
associated with the acquisition of MIGC. Excluding the operating
revenue increases associated with the MIGC acquisition, revenues
from affiliates increased by $4.4 million primarily due to
increased throughput volumes at PGT. AGC gathering revenues also
increased by $0.6 million, as a result of increases in
gathering volumes and condensate revenues. Increased gathering
volumes at AGC were primarily attributable to continued
development of the Haley field.
The $0.8 million increase in affiliate revenues for the
year ended December 31, 2005 was largely related to a 15%
increase in throughput volumes at AGC, which resulted in a
$3.7 million increase in revenues for the period and was
partially offset by a $3.0 million decrease in gas
imbalance revenues for AGC. The increase in throughput volume at
AGC was primarily attributable to increased production activity
at the Haley field.
The $24.3 million increase in affiliate revenues for the
nine months ended September 30, 2007 included
$8.6 million of increased revenues attributable to the
inclusion of MIGC operating results for the entire nine-month
period ended September 30, 2007 as compared to only 38 days
during the nine-month period ended September 30, 2006. The
$15.7 million increase not related to MIGC was mostly
attributable to a 6% and 3% increase in throughput volumes,
combined with a 19% and 39% increase in average rates realized,
at AGC and PGT, respectively. This combination of throughput
volume and rate increases resulted in increased gathering
revenues of $8.8 million and $5.1 million for AGC and
PGT, respectively. The increase in affiliate throughput volumes
at AGC was attributable to the continued development of the
Haley field. The increase in affiliate throughput volumes at PGT
was primarily attributable to the connection of additional wells
to the Pinnacle system. In addition, condensate and gas
imbalance revenues for AGC increased by $0.9 million and
$0.7 million, respectively.
83
Managements
discussion and analysis of financial condition and results of
operations
Revenues third-party. Third-party
revenues increased by $0.9 million for the year ended
December 31, 2006. Of this amount, $2.3 million was
associated with the acquisition of MIGC. Excluding the revenue
increases associated with the MIGC acquisition, revenues from
third parties decreased by $1.4 million due to a one-time
payment on a volume commitment received in 2005.
The $2.8 million increase in third-party revenues for the
year ended December 31, 2005 was primarily due to a
one-time payment on a volume commitment received in 2005. AGC
gathering revenues also increased by $0.7 million due to
higher realized rates.
The $3.8 million increase in third-party revenues for the
nine months ended September 30, 2007 was primarily
attributable to an increase of $4.0 million associated with
the inclusion of MIGC operating results for the entire
nine-month period ended September 30, 2007 as compared to
only 38 days during the nine-month period ended
September 30, 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months
ended
|
|
|
|
Year ended
December 31,
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
(in
thousands)
|
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
$
|
7,028
|
|
|
$
|
8,380
|
|
|
$
|
6,676
|
|
|
$
|
6,809
|
|
|
$
|
6,590
|
|
Third-party
|
|
|
32,932
|
|
|
|
27,340
|
|
|
|
24,625
|
|
|
|
26,375
|
|
|
|
22,467
|
|
Depreciation
|
|
|
18,009
|
|
|
|
15,447
|
|
|
|
14,841
|
|
|
|
17,104
|
|
|
|
12,635
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
$
|
57,969
|
|
|
$
|
51,167
|
|
|
$
|
46,142
|
|
|
$
|
50,288
|
|
|
$
|
41,692
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses. Total operating
expenses increased by $6.8 million and $5.0 million
for the year ended December 31, 2006 and for the year ended
December 31, 2005, respectively. Total operating expenses
also increased by $8.6 million for the nine months ended
September 30, 2007. Additional discussion regarding changes
in affiliate operating expenses, third-party operating expenses
and depreciation expense is provided below.
Operating expenses
affiliate. Affiliate operating expenses decreased
by $1.4 million for the year ended December 31, 2006.
This decrease was largely attributable to a $1.7 million
decrease in cost of product expenses related to our fuel
tracking mechanism. Specifically, for 2006, actual fuel consumed
and line loss was exceeded by fuel volumes recovered pursuant to
contractual arrangements.
The $1.7 million increase in affiliate operating expenses
for the year ended December 31, 2005 was attributable to a
$1.1 million increase in cost of product expenses largely
attributable to increased replacement cost of gas associated
with condensate sales, and a $0.6 million increase in
general and administrative expenses related to management fees.
Affiliate operating expenses remained relatively flat for the
nine months ended September 30, 2007.
Operating expenses
third-party. Third-party operating expenses
increased by $5.6 million for the year ended
December 31, 2006. The MIGC acquisition resulted in
$2.0 million of additional operation and maintenance
expenses. Third-party operating expenses, not related to MIGC,
increased by $3.6 million, primarily due to increases in
operation and maintenance expenses of $1.6 million and
$1.0 million for AGC and PGT, respectively, coupled with an
$0.8 million increase in property taxes. The AGC increase
in operation and maintenance expenses was primarily comprised of
surface maintenance and repair and chemical service expense
increases at the Helper, Clawson Springs and Dew gathering
systems during the period. The increase in operation and
maintenance expense at PGT was
84
Managements
discussion and analysis of financial condition and results of
operations
primarily comprised of an increase in salary and contract labor
expenses and an increase in equipment rental expense for a
rental amine unit and a rental compressor unit.
The $2.7 million increase in third-party operating expenses
for the year ended December 31, 2005 was largely
attributable to a $2.4 million increase in operation and
maintenance expenses for AGC primarily due to increased
throughput and service level improvements.
Third-party operating expenses increased by $3.9 million
for the nine months ended September 30, 2007. Of this
amount, $3.1 million was due to higher operation and
maintenance and general and administrative expenses and property
taxes associated with the inclusion of MIGC operating results
for the entire
nine-month
period ended September 30, 2007 as compared to only 38 days
during the nine-month period ended September 30, 2006.
Third-party operating expenses not related to MIGC increased by
$0.8 million, which was principally attributable to a
$1.0 million increase in operation and maintenance
expenses, partially offset by a $0.3 million decrease in
property taxes.
Operating expenses
depreciation. Depreciation expense increased by
$2.6 million for the year ended December 31, 2006.
This increase included $1.0 million in additional
depreciation expense related to the MIGC acquisition.
Depreciation expense not related to MIGC increased by
$1.6 million due to $1.2 million and $0.4 million
increases in deprecation expense related to AGC and PGT,
respectively. These increases were primarily attributable to
additional capital expenditures related to adding additional
compression at the Dew system and additional well connections at
PGT.
The $0.6 million increase in depreciation expense for the
year ended December 31, 2005 was attributable to a
$0.3 million increase in depreciation expense related to
each of AGC and PGT. The AGC increase in depreciation expense
was primarily due to the expansion at the Haley field. The PGT
increase in depreciation expense was primarily due to $4.0
million of capital spent on a project to install a tie-in for
connecting the PGT system into a nearby intrastate pipeline.
Depreciation expense increased by $4.5 million for the nine
months ended September 30, 2007. Of this amount,
$2.2 million was attributable to the inclusion of MIGC
operating results for the entire nine-month period ended
September 30, 2007 as compared to only 38 days during the
nine-month period ended September 30, 2006. The
$2.3 million increase in depreciation expense not related
to MIGC was due to an increase in AGCs depreciation
expense resulting from a $9.3 million increase in capital
expenditures related to adding compression and connecting
additional wells to the Dew system and continued expansion of
the Haley field.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months
ended
|
|
|
|
Year ended
December 31,
|
|
|
September 30,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
(in
thousands)
|
|
|
Operating income excluding MIGC
|
|
$
|
19,670
|
|
|
$
|
20,483
|
|
|
$
|
21,907
|
|
|
$
|
26,255
|
|
|
$
|
15,074
|
|
Operating income MIGC
|
|
|
3,513
|
|
|
|
|
|
|
|
|
|
|
|
8,970
|
|
|
|
715
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income reported
|
|
$
|
23,183
|
|
|
$
|
20,483
|
|
|
$
|
21,907
|
|
|
$
|
35,225
|
|
|
$
|
15,789
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reported operating income increased by $2.7 million for the
year ended December 31, 2006. This increase included a
$3.5 million increase related to the MIGC acquisition.
Operating income, excluding operating income related to MIGC,
decreased by $0.8 million, primarily due to a $1.6 and
$1.0 million increase in AGC and PGT operation and
maintenance expense, respectively, and a $1.2 million
increase in AGC depreciation expense, partially offset by a
$2.3 million and $0.7 million increase in PGT and AGC
revenues, respectively.
85
Managements
discussion and analysis of financial condition and results of
operations
Operating income decreased by $1.4 million for the year
ended December 31, 2005. This decrease was primarily due to
a $2.4 million increase in AGC operation and maintenance
expense, a $1.1 million increase in cost of product
expenses, and $0.6 million and $0.6 million increases
in general and administrative expense and depreciation,
respectively, partially offset by a $2.1 million and
$1.5 million increase in AGC and PGT revenues, respectively.
Operating income increased by $19.4 million for the nine
months ended September 30, 2007. This increase included an
increase of $8.3 million due to the inclusion of MIGC
operating results for the entire nine-month period ended
September 30, 2007 as compared to only 38 days during the
nine-month period ended September 30, 2006. Excluding the
effect of MIGC operating results, operating income increased by
$11.1 million due to a $8.1 million and
$3.0 million increase in operating income at AGC and PGT,
respectively. The $8.1 million increase in AGCs
operating income included an increase of $10.0 million in
revenues, and a $0.8 million decrease in operation and
maintenance expenses, partially offset by a $2.0 million
increase in depreciation expense. The $3.0 million increase
in PGTs operating income was principally attributable to
increased throughput volumes and realized gathering rates, which
resulted in a $5.4 million increase in revenues, partially
offset by a $2.0 million increase in operation and
maintenance expenses for the period.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended
December 31,
|
|
|
Nine months ended
September 30
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
|
|
(in thousands,
except tax rates)
|
|
|
|
|
|
Income before income taxes
|
|
$
|
13,526
|
|
|
$
|
11,899
|
|
|
$
|
14,761
|
|
|
$
|
28,582
|
|
|
$
|
7,821
|
|
Income tax expense
|
|
|
3,814
|
|
|
|
4,789
|
|
|
|
5,504
|
|
|
|
10,469
|
|
|
|
1,740
|
|
Effective tax rate
|
|
|
28.20
|
%
|
|
|
40.25
|
%
|
|
|
37.29
|
%
|
|
|
36.63
|
%
|
|
|
22.25
|
%
|
The decrease in the effective tax rate for the year ended
December 31, 2006 was primarily due to the recording of a
one-time benefit to deferred state income tax for the new Texas
margin tax enacted in May 2006. The increase in the effective
tax rate for the year ended December 31, 2005 was primarily
due to additional state income taxes attributable to an increase
in apportioned income to states with higher statutory tax rates.
The increase in the effective rate for the nine months ended
September 30, 2007 was primarily due to a one-time benefit
to deferred state income tax for the new Texas margin tax
recorded in the prior period.
The net decrease in income taxes for the year ended
December 31, 2006 was primarily due to the recording of a
one-time benefit to deferred state income tax for the new Texas
margin tax enacted in May 2006, partially offset by the tax
impact of the increase in income before income taxes. The net
decrease in income taxes for the year ended December 31,
2005 was primarily due to a decrease in income before income
taxes, partially offset by additional state income taxes
attributable to an increase in apportioned income to states with
higher statutory rates. The net increase in income taxes for the
nine months ended September 30, 2007 was primarily due to a
one-time benefit to deferred state income tax for the new Texas
margin tax recorded in the prior period and higher income before
income taxes in the nine months ended September 30, 2007.
Texas House Bill 3, signed into law in May 2006, eliminated the
taxable capital and earned surplus components of the existing
franchise tax and replaced these components with a taxable
margin tax calculated on a combined group reporting basis. Our
Predecessor was required to include the impact of the new law in
income for the period which included the date of the laws
enactment. The adjustment, a
86
Managements
discussion and analysis of financial condition and results of
operations
reduction in deferred state income taxes in the amount of
approximately $1.1 million, net of federal tax benefit, was
included in 2006 income tax expense.
LIQUIDITY
AND CAPITAL RESOURCES
Our ability to finance operations and fund maintenance capital
expenditures will largely depend on our ability to generate
sufficient cash flow to cover these expenses. Our ability to
generate cash flow is subject to a number of factors, some of
which are beyond our control. Please read Risk
factors included elsewhere in this prospectus.
Historically, our sources of liquidity included cash generated
from operations and funding from Anadarko. We historically
participated in Anadarkos cash management program, whereby
Anadarko, on a periodic basis, swept cash balances residing in
our bank accounts. Thus, our historical combined financial
statements reflect little or no cash balances. Unlike our
transactions with third parties which ultimately settle in cash,
our affiliate transactions are settled on a net basis through an
adjustment to parent net equity.
Prospectively, we will maintain our own bank accounts and
sources of liquidity and will utilize Anadarkos cash
management system and expertise.
Subsequent to this offering, we expect our sources of liquidity
to include:
|
|
Ø
|
$10 million of net offering proceeds to be retained for
general partnership purposes;
|
|
Ø
|
cash generated from operations;
|
|
|
Ø |
borrowings under Anadarkos credit facility up to the
amount of our borrowing limit;
|
|
|
Ø
|
borrowings under our working capital facility with Anadarko;
|
|
Ø
|
interest income from our $337.6 million note receivable
from Anadarko;
|
|
Ø
|
issuances of additional partnership units; and
|
|
Ø
|
debt offerings.
|
We believe that cash generated from these sources will be
sufficient to meet our short-term working capital requirements,
long-term capital expenditure requirements, and quarterly cash
distributions to unitholders.
Working
capital
Working capital, defined as the amount by which current assets
exceed current liabilities, is an indication of our liquidity
and potential need for short-term funding. Our working capital
requirements are driven by changes in accounts receivable and
accounts payable. These changes are primarily impacted by
factors such as credit extended to, and the timing of
collections from, our customers and our level of spending for
maintenance and expansion activity. Historically, all affiliated
transactions were not cash settled within our combined financial
statements, and did not require independent working capital
borrowings. Prospectively, to the extent transactions with
Anadarko and third parties require working capital, such amounts
will be independently obtained by us.
Historical
combined cash flow
The following table and discussion presents a summary of our
combined net cash provided by (used in) operating activities,
combined net cash provided by (used in) investing activities and
combined net cash provided by (used in) financing activities for
the years ended December 31, 2006, 2005 and 2004 and for
the nine months ended September 30, 2007 and 2006.
87
Managements
discussion and analysis of financial condition and results of
operations
For all periods presented below, our net cash from operating
activities and capital contributions from our parent were used
to service our cash requirements, which included our operating
expenses, maintenance capital expenditures and expansion capital
expenditures.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended
December 31,
|
|
|
Nine months ended
September 30,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
(in
thousands)
|
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
27,323
|
|
|
$
|
30,131
|
|
|
$
|
31,160
|
|
|
$
|
41,810
|
|
|
$
|
12,941
|
|
Investing activities
|
|
$
|
(42,713
|
)
|
|
$
|
(21,076
|
)
|
|
$
|
(16,548
|
)
|
|
$
|
(37,247
|
)
|
|
$
|
(27,952
|
)
|
Financing activities
|
|
$
|
15,844
|
|
|
$
|
(9,067
|
)
|
|
$
|
(14,596
|
)
|
|
$
|
(5,021
|
)
|
|
$
|
15,007
|
|
Net increase (decrease) in cash
|
|
$
|
454
|
|
|
$
|
(12
|
)
|
|
$
|
16
|
|
|
$
|
(458
|
)
|
|
$
|
(4
|
)
|
Operating Activities. Net cash provided by
operating activities decreased by $2.8 million, or 9%, for
the year ended December 31, 2006. Net cash provided by
operating activities decreased by $1.0 million, or 3%, for
the year ended December 31, 2005. Net cash provided by
operating activities increased by $31.1 million, or 240%,
for the nine months ended September 30, 2007.
The $2.8 million decrease in net cash provided by operating
activities during the year ended December 31, 2006 was
primarily due to a $6.9 million decrease in net accounts
payable and accrued expenses, natural gas imbalances, and
accounts receivable, offset by $4.4 million of additional
net cash provided by operating activities related to MIGC.
The $1.0 million decrease in net cash provided by operating
activities during the year ended December 31, 2005 was
primarily due to a $2.2 million decrease in net income,
partially offset by a $1.2 million increase in net cash
provided from changes in assets and liabilities.
The $28.9 million increase in net cash provided by
operating activities during the nine months ended
September 30, 2007 was primarily due to a
$10.4 million increase in net cash provided by operating
activities related to MIGC, a $13.4 million increase in net
income, not related to MIGC, adjusted for non-cash items and a
$6.6 million increase from changes in accounts payable and
accrued expenses.
Investing Activities. Net cash used in
investing activities for the year ended December 31, 2006
increased by $21.6 million, or 103%. Net cash used in
investing activities increased by $4.5 million, or 27%, for the
year ended December 31, 2005. Net cash used in investing
activities increased by $9.3 million, or 33%, for the nine
months ended September 30, 2007.
Our investing activities included $21.5 million,
$4.5 million, and $9.3 million in capital expenditure
increases for the year ended December 31, 2006, the year
ended December 31, 2005, and the nine months ended
September 30, 2007, respectively.
The increase in capital expenditures for the year ended
December 31, 2006 was related to additional compression and
well connections on the Dew system and additional well
connections on the Haley system.
The increase in capital expenditures for the year ended
December 31, 2005 was attributable to increased activity
within the Haley field and the Dew gathering system.
The increase in capital expenditures for the nine months ended
September 30, 2007 was attributable to adding compression
and connecting additional wells to the Dew system.
Financing Activities. Net cash provided by
financing activities for the year ended December 31, 2006
increased by $24.9 million. Net cash used in financing
activities decreased by $5.5 million for the year
88
Managements
discussion and analysis of financial condition and results of
operations
ended December 31, 2005. Net cash provided by financing
activities decreased by $20.0 million for the nine months
ended September 30, 2007. All increases and decreases were
attributable to period-to-period variances in cash contributions
from or cash payments to Anadarko.
Off-balance sheet
arrangements
We do not have any off-balance sheet arrangements.
Capital
requirements
Our businesses can be capital-intensive, requiring significant
investment to maintain and improve existing facilities. We
categorize capital expenditures as either:
|
|
Ø |
Maintenance capital expenditures, which include those
expenditures required to maintain the existing operating
capacity and service capability of our assets, including the
replacement of system components and equipment that have
suffered significant wear and tear, become obsolete or
approached the end of their useful lives, those expenditures
necessary to remain in compliance with regulatory or legal
requirements or those expenditures necessary to complete
additional well connections to maintain existing system volumes
and related cash flows; or
|
|
|
Ø |
Expansion capital expenditures, which include those expenditures
incurred in order to extend the useful lives of our assets,
increase gathering, treating and transmission throughput from
current levels, reduce costs or increase revenues.
|
Our historical accounting records did not differentiate between
maintenance and expansion capital expenditures. We estimate that
expansion capital expenditures represented approximately 63%,
49% and 35% of total capital expenditures for the years ended
December 31, 2006, 2005 and 2004, respectively. Our total
historical capital expenditures were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended
December 31,
|
|
|
Nine months ended
September 30,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
(in
thousands)
|
|
|
Total capital expenditures, net
|
|
$
|
42,299
|
|
|
$
|
20,841
|
|
|
$
|
16,548
|
|
|
$
|
37,020
|
|
|
$
|
27,709
|
|
We expect our maintenance and expansion capital expenditures for
the twelve months ending December 31, 2008 to be
$28.0 million and $15.9 million, respectively. Two
components of our strategy are growth through organic expansion
and pursuit of accretive acquisitions, and we expect to invest
capital in a manner that positions us to execute on our
strategy. Our future expansion capital expenditures may vary
significantly from period to period based on the investment
opportunities available to us. We expect to fund future capital
expenditures from cash flow generated from our operations,
borrowings under Anadarkos credit facility, the issuance
of additional partnership units and debt offerings.
Our borrowing
capacity under Anadarkos credit facility
On December 14, 2007, Anadarko amended its
$750 million credit facility, which is available for
borrowings and letters of credit, to permit us to borrow up to
$100 million under the facility. Anadarkos credit
facility has a maturity date of August 31, 2009. Our
$100 million borrowing limit under Anadarkos credit
facility is available for general partnership purposes,
including acquisitions, but only to the extent that sufficient
amounts remain unborrowed by Anadarko and its other
subsidiaries. At September 30, 2007, letters of credit
totaling $3.0 million had been issued on behalf of Anadarko
by the participating institutions under this facility and no
revolving credit loans were outstanding.
89
Managements
discussion and analysis of financial condition and results of
operations
Interest on borrowings under this credit facility is calculated
based on the election by the borrower of either: (i) a
floating rate equal to the federal funds effective rate plus
0.5% or (ii) a periodic fixed rate equal to LIBOR plus an
applicable margin. We are required to pay a commitment fee based
on the unused portion of our $100 million borrowing
capacity under the facility, currently 0.175% annually. The
applicable margin, which is currently 0.675%, and the commitment
fees are based on Anadarkos senior unsecured long-term
debt rating. Under the credit facility, Anadarko and we are
required to comply with certain covenants, including a financial
covenant that requires both Anadarko and us to maintain a
debt-to-book capitalization ratio of 60% or less. Anadarko was
in compliance with this ratio at September 30, 2007. Should
we or Anadarko fail to comply with this or any other covenant in
Anadarkos credit facility, we may not be allowed to borrow
under Anadarkos credit facility. Pursuant to the credit
facility, Anadarko is a guarantor of all borrowings under the
credit facility, including our borrowings. We are not a
guarantor of Anadarkos borrowings under the credit
facility.
Our working
capital facility
Concurrently with the closing of this offering, we will enter
into a $30 million,
three-year,
revolving credit facility with Anadarko as the lender. The
facility will be available exclusively to fund working capital
borrowings. Borrowings under the facility will bear interest at
the same rate as would apply to borrowings under the Anadarko
revolving credit facility described above. We will pay a
commitment fee to Anadarko on the unused portion of the working
capital facility of 0.175% annually.
We will be required to reduce all borrowings under our working
capital facility to zero for a period of at least
15 consecutive days at least once during each of the
twelve-month periods prior to the maturity date of the facility.
Credit
risk
We bear credit risk represented by our exposure to non-payment
or non-performance by our customers, including Anadarko.
Generally, non-payment or non-performance results from a
customers inability to satisfy receivables for services
rendered or volumes owed pursuant to gas imbalance agreements.
We examine the creditworthiness of third-party customers to whom
we grant credit and establish credit limits in accordance with
our credit policy. We are dependent upon a single producer,
Anadarko, for the majority of our natural gas volumes, and we do
not have a credit policy with respect to Anadarko. Consequently,
we are subject to the risk of non-payment or late payment by
Anadarko of gathering, treating and transmission fees, and this
risk is greater than it would be with a broader customer base
with a similar credit profile. We expect our exposure to
concentrated risk of non-payment or non-performance to continue
for as long as we remain substantially dependent on Anadarko for
our revenues.
While Anadarko currently has investment grade credit ratings, if
Anadarko becomes unable to perform under the terms of our
gathering and transportation agreements, its note payable to us
or the omnibus agreement, it may significantly reduce our
ability to make distributions to our unitholders. We will be
exposed to credit risk on the note receivable from Anadarko that
will be issued by Anadarko to us concurrently with the closing
of this offering. In addition, we will enter into an omnibus
agreement with Anadarko under which Anadarko is required to
indemnify us for certain environmental claims, losses arising
from rights-of-way claims, failures to obtain required consents
or governmental permits, and income taxes.
90
Managements
discussion and analysis of financial condition and results of
operations
Total contractual
cash obligations
A summary of our total contractual cash obligations as of
December 31, 2006, which consisted of four compressor
leases, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less than
|
|
|
|
|
|
|
|
|
More than
|
|
|
|
Total
|
|
|
1 year
|
|
|
2-3 years
|
|
|
4-5 years
|
|
|
5 years
|
|
|
|
|
|
(in
thousands)
|
|
|
Lease commitments
|
|
$
|
13,359
|
|
|
$
|
3,123
|
|
|
$
|
4,177
|
|
|
$
|
4,277
|
|
|
$
|
1,782
|
|
During the nine months ended September 30, 2007, Anadarko
exercised its option to purchase three of the four compressors
which were under lease from a third party to Anadarko and
subleased by Anadarko to us. Anadarko then transferred the
compressors to us as a contribution to our capital. This
transaction is expected to reduce operation and maintenance
expense by approximately $1.7 million annually, which will
be partially offset by a $1.5 million increase in
depreciation expense. As a result of this transaction, our
contractual cash obligations changed, and at September 30,
2007 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less than
|
|
|
|
|
|
|
|
|
More than
|
|
|
|
Total
|
|
|
1 year
|
|
|
2-3 years
|
|
|
4-5 years
|
|
|
5 years
|
|
|
|
|
|
(in
thousands)
|
|
|
Lease commitments
|
|
$
|
5,360
|
|
|
$
|
799
|
|
|
$
|
1,936
|
|
|
$
|
1,958
|
|
|
$
|
667
|
|
In addition to the obligations listed above, we will enter into
an omnibus agreement with Anadarko whereby we will reimburse
Anadarko for certain operating and general and administrative
expenses it incurs for our benefit with respect to our assets
and operations. Under the omnibus agreement, our reimbursement
to Anadarko for certain general and administrative expenses it
allocates to us will be capped at $6.0 million annually
through December 31, 2009, subject to adjustment to reflect
changes in the Consumer Price Index and, with the concurrence of
the special committee of our general partners board of
directors, to reflect expansions of our operations through the
acquisition or construction of new assets or businesses.
Thereafter, our general partner will determine the general and
administrative expenses to be reimbursed by us in accordance
with our partnership agreement. The cap contained in the omnibus
agreement does not apply to incremental general and
administrative expenses we expect to incur or to be allocated to
us as a result of becoming a publicly traded partnership. We
currently expect those expenses to be approximately
$2.5 million per year.
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity price
risk
We bear a limited degree of commodity price risk with respect to
our gathering contracts. Specifically, pursuant to our
contracts, we retain and sell condensate that is recovered
during the gathering of natural gas. As part of this
arrangement, we are required to provide a thermally equivalent
volume of natural gas or the cash equivalent thereof to the
shipper. Thus, our revenues for this portion of our contractual
arrangement are based on the price received for the condensate
and our costs for this portion of our contractual arrangement
are dependent upon the price of natural gas. Condensate
historically sells at a price representing a slight discount to
the price of crude oil. We consider our exposure to commodity
price risk associated with these arrangements to be minimal
based on the amount of operating income generated under these
arrangements compared to our overall operating income and the
fact that the balance of our operating income is fee-based. For
the years ended December 31, 2006, 2005 and 2004, a 10%
change in the trading margin between condensate and natural gas
would have resulted in a $375,000, or 1.6%, $250,000, or 1.2%,
and $206,000, or 1.0%, change in operating income for those
periods, respectively.
91
Managements
discussion and analysis of financial condition and results of
operations
Interest rate
risk
Interest rates during the periods discussed above were low
compared to rates over the last 50 years. If interest rates were
to rise, our financing costs would increase accordingly.
Although increased borrowing costs could limit our ability to
raise funds in the capital markets, we expect our competitors
would be similarly affected. We expect to have immaterial
amounts of borrowings through December 31, 2008.
Accordingly, we do not expect to have any material interest rate
risk.
CRITICAL
ACCOUNTING POLICIES AND ESTIMATES
The preparation of combined financial statements in accordance
with accounting principles generally accepted in the U.S.
requires our management to make estimates and assumptions that
affect the amounts reported in the combined financial statements
and the accompanying notes. Although these estimates are based
on managements best available knowledge of current and
expected future events, actual results may vary significantly
from those estimates. Management considers an understanding of
our critical accounting policies and estimates to be essential
to gaining a full understanding of our combined financial
results. For additional information concerning our accounting
policies not discussed below, see the Notes to the Combined
Financial Statements included elsewhere in this prospectus.
Depreciation and
impairment policy
Depreciation expense is generally computed using the
straight-line method over the estimated useful life of the
assets. Determination of depreciation expense requires judgment
regarding the estimated useful lives and salvage values of
property, plant and equipment. As circumstances warrant,
depreciation estimates are reviewed to determine if any changes
in the underlying assumptions are necessary.
Each reporting period, management assesses whether facts and
circumstances indicate that the carrying amounts of property,
plant and equipment may not be recoverable from expected
undiscounted cash flows from the use and eventual disposition of
an asset. If the carrying amount of the asset is not expected to
be recoverable from future undiscounted cash flows, an
impairment may be recognized. Any impairment is measured as the
excess of the carrying amount of the asset over its estimated
fair value. The weighted average life of our long-lived assets
is approximately 21 years. If the depreciable lives of our
assets were reduced by 10%, we estimate that depreciation
expense would increase by $2.5 million, which would result
in a corresponding reduction in our operating income.
In assessing long-lived assets for impairment, management
evaluates changes in our business and economic conditions and
their implications for recoverability of the assets
carrying amounts. Since a significant portion of our revenues
arises from gathering and transporting natural gas production
from Anadarko-operated properties, significant downward
revisions in reserve estimates or changes in future development
plans by Anadarko, to the extent they affect our operations, may
necessitate assessment of the carrying amount of our affected
assets for recoverability. Such assessment requires application
of judgment regarding the use and ultimate disposition of the
asset, long-range revenue and expense estimates, global and
regional economic conditions, including commodity prices and
drilling activity by our customers, as well as other factors
affecting estimated future net cash flows. The measure of
impairment to be recognized, if any, depends upon
managements estimate of the assets fair value, which
may be determined based on the estimates of future net cash
flows or values at which similar assets were transferred in the
market in recent transactions, if such data is available. For
the periods presented, we believe that no facts were present
that would indicate the carrying amount of assets may not be
recoverable. However, given the degree of judgment about highly
uncertain matters involved in assessing our key assets for
impairment, it is reasonably possible that such assessments in
future periods would have material effects on our financial
conditions and results of operations. If an assessment of
impairment resulted in a reduction of 1% of our assets, our
operating income would decrease by $3.5 million.
92
We are a growth-oriented Delaware limited partnership recently
formed by Anadarko (NYSE: APC) to own, operate, acquire and
develop midstream energy assets. We currently operate in East
Texas, the Rocky Mountains, the Mid-Continent and West Texas and
are engaged in the business of gathering, compressing, treating
and transporting natural gas for our ultimate parent, Anadarko,
and third-party producers and customers. We principally provide
our midstream services under long-term contracts with fee-based
rates extending for primary terms of up to 20 years. We
generally do not take title to the natural gas that we gather
and, therefore, are able to avoid significant direct commodity
price exposure.
We believe that one of our principal strengths is our
relationship with Anadarko. During each of the year ended
December 31, 2006 and the nine months ended
September 30, 2007, over 90% of our total natural gas
gathering and transportation volumes were comprised of natural
gas production owned or controlled by Anadarko. In addition,
Anadarko Petroleum Corporation has dedicated to us all of the
natural gas production it owns or controls from (i) wells
that are currently connected to our gathering systems, and
(ii) additional wells that are drilled within one mile of
connected wells or our gathering systems, as the systems
currently exist and as they are expanded to connect additional
wells in the future. As a result, this dedication will continue
to expand as additional wells are connected to our gathering
systems. Volumes associated with this dedication were
approximately 736 MMBtu/d for the year ended
December 31, 2006 and approximately 738 MMBtu/d for
the nine months ended September 30, 2007.
We expect to utilize the significant experience of
Anadarkos management team to execute our growth strategy,
which includes acquiring and constructing additional midstream
assets. For the nine months ended September 30, 2007, as
adjusted for divestitures prior to this offering and including
the assets being contributed to us, Anadarkos total
domestic midstream asset portfolio generated approximately
$250 million of cash flow from operations and consisted of
25 gathering systems and one transportation system with an
aggregate throughput of approximately 3.0 Bcf/d,
approximately 11,200 miles of pipeline and 25 processing
and/or
treating facilities.
OUR
ASSETS AND AREAS OF OPERATION
Our assets consist of six gathering systems, five natural gas
treating facilities and one interstate pipeline. Our assets are
located in East Texas, the Rocky Mountains (Utah and Wyoming),
the Mid-Continent (Kansas and Oklahoma) and West Texas. The
following table provides information regarding our assets by
operating area as of or for the nine months ended
September 30, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Approximate #
|
|
Gas
|
|
Treating
|
|
Average
|
|
|
|
|
|
|
Length
|
|
of
|
|
compression
|
|
capacity
|
|
throughput
|
|
|
Area
|
|
Asset
type
|
|
(miles)
|
|
receipt
points
|
|
(horsepower)
|
|
(MMcf/d)
|
|
(MMcf/d)
|
|
|
|
|
|
|
East Texas
|
|
Gathering and Treating
|
|
|
577
|
|
|
789
|
|
|
45,633
|
|
|
510
|
|
|
304
|
(1
|
)
|
Rocky Mountains
|
|
Gathering and Treating
|
|
|
114
|
|
|
162
|
|
|
20,385
|
|
|
92
|
|
|
55
|
|
|
|
|
Transportation
|
|
|
264
|
|
|
19
|
|
|
29,696
|
|
|
|
|
|
137
|
|
|
Mid-Continent
|
|
Gathering
|
|
|
1,753
|
|
|
1,507
|
|
|
130,720
|
|
|
|
|
|
123
|
|
|
West Texas
|
|
Gathering
|
|
|
87
|
|
|
50
|
|
|
|
|
|
|
|
|
185
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2,795
|
|
|
2,527
|
|
|
226,434
|
|
|
602
|
|
|
804
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
To avoid duplicating volumes, 213 MMcf/d that is
gathered on our Dew gathering system and delivered into our
Pinnacle gas treating system is included only once in the
calculation of average throughput.
|
93
Business
Our primary business objective is to increase our cash
distribution per unit over time. We intend to accomplish this
objective by executing the following strategy:
|
|
Ø
|
Pursuing accretive acquisitions. We expect to
pursue accretive acquisition opportunities within the midstream
energy industry from Anadarko and third parties. Given
Anadarkos large portfolio of midstream assets, we believe
that we will have access to an array of acquisition
opportunities, though Anadarko is under no legal obligation to
offer assets or business opportunities to us. In addition, we
may also pursue selected asset acquisitions from third parties
to the extent such acquisitions complement our or
Anadarkos existing asset base or allow us to capture
operational efficiencies from Anadarkos production.
|
|
Ø
|
Capitalizing on organic growth
opportunities. The significant dedication to us
by Anadarko provides us with a platform for organic growth. We
expect to achieve this growth by meeting Anadarkos
gathering needs, which we expect to increase as a result of its
anticipated drilling activity in our areas of operation. We also
intend to actively pursue new volumes associated with
Anadarkos development of undeveloped acreage that is
accessible by our gathering systems. Examples of organic growth
opportunities potentially arising from our relationship with
Anadarko include:
|
|
|
|
|
-
|
Anadarkos active drilling program in the East Texas
Bossier play, including the Cotton Valley Lime
formations; and
|
|
|
-
|
Anadarkos increased drilling and recompletion activity in
the Hugoton field as a result of recent rule changes by the
Kansas Corporation Commission.
|
|
|
Ø |
Attracting additional third-party volumes to our
systems. We intend to actively market our
midstream services to and pursue strategic relationships with
third-party producers to attract additional volumes and/or
expansion opportunities. Recent examples of such expansions
include:
|
|
|
|
|
-
|
the planned expansion of the sour gas treating capacity of our
Bethel plant to accommodate the recent drilling activity by
third parties in the Cotton Valley Lime formations; and
|
|
|
-
|
the expansion of the Hugoton gathering system to obtain volumes
previously gathered by a competitors system.
|
|
|
Ø |
Minimizing commodity price exposure. Our
midstream services are provided under fee-based arrangements
which minimize our direct commodity price exposure. We expect to
utilize hedging to manage any significant future commodity price
risk that could result from contracts we may acquire or enter
into in the future.
|
We believe that we are well positioned to successfully execute
our strategy and achieve our primary business objective because
of the following competitive strengths:
|
|
Ø |
Affiliation with Anadarko. We believe that
Anadarko, as the owner of our general partner interest, all of
our incentive distribution rights and a 57.3% limited partner
interest in us, is motivated to promote and support the
successful execution of our business plan and to pursue projects
that enhance the value of our business. We believe that our
relationship with Anadarko will enhance our ability to achieve
our primary business objective through, for example, the
following:
|
|
|
|
|
-
|
Anadarko Petroleum Corporation has dedicated to us all of the
natural gas production it owns or controls from (i) wells that
are currently connected to gathering systems, and (ii)
additional wells that are drilled within one mile of connected
wells or our gathering systems, as the systems currently exist
and as they are expanded to connect additional wells in the
future;
|
94
Business
|
|
|
|
-
|
as Anadarko develops the acreage in proximity to our gathering
systems or acquires additional acreage in our areas of
operation, we believe that it will deliver additional volumes to
our facilities, although it is not obligated to do so;
|
|
|
-
|
Anadarko manages a large portfolio of midstream assets in highly
active oil and natural gas producing areas, such as the Rocky
Mountains, and we believe that Anadarko may offer us the
opportunity to purchase some or all of such assets in the
future, although it is not obligated to do so; and
|
|
|
-
|
we have access to Anadarkos broad operational, commercial,
technical, risk management and administrative infrastructure,
its significant pool of management talent and its strong
commercial relationships throughout the energy industry.
|
|
|
Ø
|
Relatively stable and predictable cash
flow. Given the fee-based, long-term nature of
our midstream service agreements, our cash flow is largely
protected from fluctuations caused by commodity price
volatility. In addition, our contracts have primary terms
ranging up to 20 years, and we generally do not take title
to the natural gas that we gather, compress, treat or transport.
Moreover, our systems are connected to wells in producing basins
that generally have long lives with predictable flow rates.
|
|
Ø
|
Well-positioned, well-maintained and efficient
assets. We believe that our established positions
in our areas of operation provide us with opportunities to
expand and attract additional volumes to our systems. Moreover,
our systems consist of high-quality, well-maintained assets for
which we have implemented modern treating, measuring and
operating technologies. These applications have allowed us to
manage our operations efficiently with limited field personnel,
resulting in lower costs and minimal downtime.
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Financial flexibility to pursue expansion and acquisition
opportunities. We have up to $100 million of
borrowing capacity available to us under Anadarkos
$750 million credit facility and, concurrently with the
closing of this offering, we expect to obtain a $30 million
working capital facility from Anadarko. In addition, we will
have no indebtedness outstanding at the closing of this
offering. We believe that our borrowing capacity and our ability
to effectively access debt and equity capital markets provide us
with the financial flexibility necessary to achieve our organic
expansion and acquisition strategy.
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Experienced management team. Our general
partners management team, which includes senior executives
of Anadarko, has on average over 15 years of industry
experience. Members of our general partners management
team have extensive experience in building, acquiring,
integrating, financing and managing midstream assets. In
addition, our relationship with Anadarko provides us with the
services of experienced personnel who successfully managed our
assets and operations while they were owned by Anadarko.
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We believe that we will effectively leverage our competitive
strengths to successfully implement our strategy; however, our
business involves numerous risks and uncertainties which may
prevent us from achieving our primary business objective. For a
more complete description of the risks associated with an
investment in us, please read Risk factors.
OUR
RELATIONSHIP WITH ANADARKO
One of our principal attributes is our relationship with
Anadarko. It will own our general partner and a significant
interest in us following this offering. Anadarko is one of the
largest independent oil and gas exploration and production
companies in the world. Anadarko, which trades on the NYSE under
the symbol APC, has major operations in established
onshore areas of the U.S., including the Rocky Mountains, as
well as in the deepwater Gulf of Mexico and Algeria. Anadarko
also has production in China, a development project in Brazil
and is executing strategic exploration programs in several other
countries.
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Business
Anadarkos upstream oil and gas business finds and produces
natural gas, crude oil, condensate and NGLs. Anadarko is
growth-oriented and annually pursues one of the most active
drilling programs in the industry, with over 1,400 development
wells drilled onshore in the U.S. in 2006. Anadarko has
identified the Rocky Mountains and its Southern region (which
includes the Mid-Continent and Texas) as core areas from which
it expects to derive a significant portion of its future
production growth from development drilling activity. We expect
Anadarko to remain active in our areas of operation, which we
believe will provide us with both organic and
acquisition-related growth opportunities.
At September 30, 2007, including the assets being
contributed to us but adjusted for divestitures prior to this
offering, Anadarkos total domestic midstream asset
portfolio consisted of 25 gathering systems and one
transportation system with an aggregate throughput of
approximately 3.0 Bcf/d, approximately 11,200 miles of
pipeline and 25 processing
and/or
treating facilities. Following this offering, Anadarkos
remaining midstream business will consist of 19 gathering
systems with an aggregate throughput of approximately
2.2 Bcf/d, 8,400 miles of pipeline and 20 processing
and/or treating facilities. The assets to be retained by
Anadarko generated approximately $191 million of cash flow
from operating activities for the nine months ended
September 30, 2007. Anadarko has invested significant
capital in its domestic midstream business, including the assets
being contributed to us, with investments of approximately
$290 million in 2006 and planned investments of
approximately $600 million in 2007, of which approximately
$475 million had been invested as of September 30,
2007.
Although our relationship with Anadarko provides us with a
significant advantage in the midstream natural gas market, it is
also a source of potential conflicts. For example, Anadarko is
not restricted from competing with us. Please read
Conflicts of interest and fiduciary duties. Given
Anadarkos significant ownership of limited and general
partner interests in us following this offering, we believe it
will be in Anadarkos best interest for it to sell
additional assets to us over time; however, Anadarko continually
evaluates acquisitions and divestitures and may elect to
acquire, construct or dispose of midstream assets in the future
without offering us the opportunity to acquire or construct
those assets. Anadarko is under no contractual obligation to
offer any such opportunities to us, nor are we obligated to
participate in any such opportunities. We cannot state with any
certainty which, if any, opportunities to acquire assets from
Anadarko may be made available to us or, if given the
opportunity, that we will elect to pursue any such acquisitions.
At the close of this offering, we will enter into an omnibus
agreement with Anadarko and our general partner that will govern
our relationship regarding certain reimbursement and
indemnification matters. Please read Certain relationships
and related party transactionsAgreements governing the
transactionsOmnibus agreement.
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Business
The midstream natural gas industry is the link between the
exploration and production of natural gas from the wellhead or
lease and the delivery of the gas and its other components to
end-use markets. Companies within this industry create value at
various stages along the natural gas value chain by gathering
natural gas from producers at the wellhead, separating the
hydrocarbons into dry gas (primarily methane) and NGLs, and then
routing the separated dry gas and NGL streams for delivery to
end-markets or to the next intermediate stage of the value
chain. The following diagram illustrates the groups of assets
commonly found along the natural gas value chain:
Service
types
The services provided by us and other midstream natural gas
companies are generally classified into the categories described
below. As indicated below, we do not currently provide all of
these services, although we may do so in the future.
Gathering. At the initial stages of the
midstream value chain, a network of typically small diameter
pipelines known as gathering systems directly connect to
wellheads in the production area. These gathering systems
transport raw, or untreated, natural gas to a central location
for treating and processing. A large gathering system may
involve thousands of miles of gathering lines connected to
thousands of wells. Gathering systems are typically designed to
be highly flexible to allow gathering of natural gas at
different pressures and scalable to allow gathering of
additional production without significant incremental capital
expenditures. In connection with our gathering services, we
retain and sell condensate, which falls out of the natural gas
stream during gathering.
Compression. Natural gas compression is a
mechanical process in which a volume of natural gas at a given
pressure is compressed to a desired higher pressure, which
allows the natural gas to be delivered into a higher pressure
system. Field compression is typically used to allow a gathering
system to operate at a lower pressure or provide sufficient
discharge pressure to deliver natural gas into a higher pressure
system. Since wells produce at progressively lower field
pressures as they deplete, field compression is needed to
maintain throughput across the gathering system.
Treating and Dehydration. To the extent that
gathered natural gas contains contaminants, such as water vapor,
carbon dioxide
and/or
hydrogen sulfide, such natural gas is dehydrated to remove the
saturated water and treated to separate the carbon dioxide and
hydrogen sulfide from the gas stream.
Processing. Most decontaminated rich natural
gas does not meet the quality standards for long-haul pipeline
transportation or commercial use and must be processed to remove
the heavier hydrocarbon components, which are extracted as NGLs.
Our assets do not currently include processing facilities.
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Business
Fractionation. Fractionation is the separation
of the heterogeneous mixture of extracted NGLs into individual
components for end-use sale. It is accomplished by controlling
the temperature and pressure of the stream of mixed NGLs in
order to take advantage of the different boiling points of
separate products. Our assets do not currently include
fractionation operations.
Transportation and Storage. Once the raw
natural gas has been treated or processed and the raw NGL mix
fractionated into individual NGL components, the natural gas and
NGL components are stored, transported and marketed to end-use
markets. Each pipeline system typically has storage capacity
located both throughout the pipeline network and at major market
centers to help temper seasonal demand and daily supply-demand
shifts. Our assets do not currently include storage facilities.
Typical Contractual Arrangements. Midstream
natural gas services, other than transportation and storage, are
usually provided under contractual arrangements which vary in
the amount of commodity price risk they carry. Three typical
contract types are described below:
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Fee-Based. Fee-based arrangements may be used
for gathering, compression, treating and processing services.
Under these arrangements, the service provider typically
receives a fee for each unit of natural gas gathered and
compressed at the wellhead and an additional fee per unit of
natural gas treated or processed at its facility. As a result,
the service provider bears no direct commodity price risk
exposure. We provide our gathering, compression and treating
services to Anadarko and third-party producers under fee-based
arrangements which minimize our direct commodity price exposure.
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Percent-of-Proceeds, Percent-of-Value or
Percent-of-Liquids. Percent-of-proceeds,
percent-of-value or percent-of-liquids arrangements may be used
for gathering and processing services. Under these arrangements,
the service provider typically remits to the producers either a
percentage of the proceeds from the sale of residue gas
and/or NGLs
or a percentage of the actual residue gas
and/or NGLs
at the tailgate. These types of arrangements expose the
processor to commodity price risk, as the revenues from the
contracts directly correlate with the fluctuating price of
natural gas and NGLs. We do not currently have any
percent-of-proceeds, percent-of-value or percent-of-liquids
arrangements.
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Keep-Whole. Keep-whole arrangements may be
used for processing services. Under these arrangements, the
service provider keeps 100% of the NGLs produced, and the
processed natural gas, or value of the gas, is returned to the
producer. Since some of the gas is used and removed during
processing, the processor compensates the producer for the
amount of gas used and removed in processing by supplying
additional gas or by paying an
agreed-upon
value for the gas utilized. These arrangements have the highest
commodity price exposure for the processor because the costs are
dependent on the price of natural gas and the revenues are based
on the price of NGLs. We do not currently have any keep-whole
arrangements.
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There are two forms of contracts utilized in the transportation
and storage of natural gas, as described below:
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Firm. Firm transportation service requires the
reservation of pipeline capacity by a customer between certain
receipt and delivery points. Firm customers generally pay a
demand or capacity reservation fee based
on the amount of capacity being reserved, regardless of whether
the capacity is used, plus a usage fee based on the amount of
natural gas transported. Firm storage contracts involve the
reservation of a specific amount of storage capacity, including
injection and withdrawal rights, and generally include a
capacity reservation charge based on the amount of capacity
being reserved plus an injection
and/or
withdrawal fee.
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Interruptible. Interruptible transportation
and storage service is typically short-term in nature and is
generally used by customers that either do not need firm service
or have been unable to contract for firm service. These
customers pay only for the volume of gas actually transported or
stored. The obligation to provide this service is limited to
available capacity not otherwise used by firm
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customers, and as such, customers receiving services under
interruptible contracts are not assured capacity on the pipeline
or at the storage facility.
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Natural gas
demand and production
Natural gas is a critical component of energy supply in the U.S.
According to the Energy Information Administration, or the EIA,
total annual domestic consumption of natural gas is expected to
increase from approximately 21.7 trillion cubic feet, or
Tcf, in 2006 to approximately 24.7 Tcf in 2010. The
industrial and electricity generation sectors are the largest
consumers of natural gas in the U.S. During the last three
years, these sectors accounted for approximately 57% of the
total natural gas consumed in the U.S. In 2006, natural gas
provided approximately 22% of all end-user commercial and
residential energy requirements. During the last three years,
the U.S. has, on average, consumed approximately 22.0 Tcf
per year, with average annual domestic production of
approximately 18.4 Tcf during the same period. Driven by
growth in natural gas demand and high natural gas prices,
domestic natural gas production is projected to increase from
18.6 Tcf per year to 19.6 Tcf per year between 2006
and 2016. The graph below represents projected U.S. natural
gas production versus U.S. natural gas consumption (in Tcf)
through the year 2030.
Source:
Energy Information Administration
We own and operate all of our assets, which consist of six
gathering systems, five natural gas treating facilities and one
interstate pipeline, in East Texas, the Rocky Mountains (Utah
and Wyoming), the Mid-Continent (Kansas and Oklahoma) and West
Texas. Other than the natural gas that is gathered by our
Hugoton gathering system, which is currently processed by third
parties, none of the natural gas serviced by our assets requires
processing. The following sections describe in more detail the
services provided by our assets in our areas of operation.
East
Texas
Dew gathering
system
General. The
317-mile Dew
gathering system is located in Anderson, Freestone, Leon and
Robertson Counties of East Texas. The Dew gathering system was
placed into service in November 1998 to provide gathering
services for Anadarkos active drilling program in the
Bossier play. The system provides gathering, dehydration and
compression services and ultimately delivers into the Pinnacle
gas treating system for any required treating.
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Business
Average throughput on the Dew gathering system for the year
ended December 31, 2006 and the nine months ended
September 30, 2007 was
235 MMcf/d
and
217 MMcf/d,
respectively, from approximately 725 receipt points. The Dew
gathering system has pipeline diameters ranging from three to
12 inches and has 14 compressor stations with a combined
44,368 horsepower of compression.
Customers. Anadarko is the only significant
shipper on the Dew gathering system. Anadarkos equity gas
accounted for
213 MMcf/d
of throughput during the nine months ended September 30,
2007, which represented approximately 98% of the total volume on
the system.
Delivery Points. The Dew gathering
systems primary delivery point is Pinnacle Gas Treating,
Inc., which is described in more detail below, but it also has a
connection to Kinder Morgans Tejas pipeline.
Supply. Anadarko has drilled over
750 gross wells to date in the Bossier play and controls
approximately 230,000 gross acres in the area. For the last
three years, Anadarko has maintained an active drilling program
in the Bossier play utilizing four or five rigs to drill
approximately 30 gross wells per year. With this level of
activity, we believe Anadarko has a drilling location inventory
of over five years.
Pinnacle Gas
Treating LLC
General. Pinnacle Gas Treating LLC includes
our Pinnacle gathering system and our Bethel treating plant.
Pinnacle Gas Treating provides sour gas gathering and treating
service in Anderson, Freestone, Leon, Limestone and Robertson
Counties of East Texas. The gathering system consists of
256 miles of pipeline with diameters ranging from three to
24 inches and one compressor station with 1,265 horsepower.
The Bethel treating plant, located in Anderson County, has total
CO2
treating capacity of
500 MMcf/d
and nine long tons per day, or LTD, of sulfur treating capacity.
We are currently expanding the plant by installing an additional
11 LTD of sulfur treating capacity, which we expect to have
completed in 2008, in order to provide additional sour gas
treating capacity for drilling in the area.
Average throughput on the Pinnacle gathering system for the year
ended December 31, 2006 and the nine months ended
September 30, 2007 was
307 MMcf/d
and
300 MMcf/d,
respectively, from approximately 70 receipt points.
Customers. Anadarko is the largest shipper on
the Pinnacle gathering system with
272 MMcf/d
of throughput for the nine months ended September 30, 2007,
which represented approximately 91% of the total throughput on
the system during such period. Eighty percent of Anadarkos
throughput is equity production, which includes Bossier natural
gas delivered from the Dew gathering system and several wells
directly connected to the Pinnacle system that produce from the
Cotton Valley Lime formations. The remaining 20% of
Anadarkos throughput consists of natural gas purchased by
Anadarko from third parties.
Other shippers on the Pinnacle gathering system are
ConocoPhillips Company, Hunt Petroleum Corp., EnCana
Oil & Gas (USA) Inc., Paragon Energy Inc. and Newfield
Exploration Company. These shippers accounted for
27 MMcf/d
for the nine months ended September 30, 2007, which
represented approximately 9% of total throughput on the system
during such period.
Delivery Points. The Pinnacle gathering system
is connected to Enterprise Texas Pipeline, LPs pipeline,
the Energy Transfer Fuels pipeline, the ETC Texas pipeline,
Kinder Morgans Tejas pipeline, the ATMOS Texas pipeline
and the Enbridge Pipelines (East Texas) LP pipeline. These
pipelines provide transportation to the Carthage, Waha and
Houston Ship Channel market hubs in Texas.
Supply. The Pinnacle gathering system is well
positioned to provide gathering and treating services to the
five county area over which it extends. With an average of
400 wells drilled in each of the last five
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Business
years, this area has experienced significant recent growth and,
as of September 30, 2007, had a total well count exceeding
5,000 wells and production of over 1.5 Bcf/d.
With the recent drilling activity in the Cotton Valley Lime
formations, which contain higher concentrations of
H2S
and
CO2,
we were able to obtain a commitment from a third-party producer
that allows us to expand the Bethel treating facilities. With
this expansion, we believe that we are well positioned to
benefit from future sour gas production in the area.
Rocky
Mountains
MIGC
system
General. The MIGC system is a
264-mile
interstate pipeline operating within the Powder River Basin of
Wyoming that is regulated by the Federal Energy Regulatory
Commission, or FERC. The MIGC system traverses the Powder River
Basin from north to south, extending approximately
150 miles to Glenrock, Wyoming. As a result, the MIGC
system is well positioned to provide transportation for the
extensive natural gas volumes received from various coal-bed
methane gathering systems and conventional gas processing plants
throughout the Powder River Basin. MIGC offers both forward-haul
and backhaul transportation services, and additional capacity is
available from time to time on an interruptible basis.
Average throughput on the MIGC system for the year ended
December 31, 2006 and the nine months ended
September 30, 2007 was
126 MMcf/d
and
137 MMcf/d,
respectively, from approximately 20 receipt points.
MIGC recently completed the installation of, and placed into
service, the Python compression station, which increased
capacity on the MIGC system by approximately
50 MMcf/d.
In April 2007, Anadarko entered into a firm transportation
contract for 45 MMcf/d of this additional capacity. MIGC is
currently certificated for 175
MMcf/d of
firm transportation capacity, all of which is fully subscribed.
Customers. Anadarko is the largest firm
shipper on the MIGC system, with approximately 72% and 71% of
throughput for the year ended December 31, 2006 and the
nine months ended September 30, 2007, respectively. For the
year ended December 31, 2006 and the nine months ended
September 30, 2007, Williams Production RMT Company and KFx
Plant, LLC together accounted for approximately 28% and 29%,
respectively, of throughput on the system.
Revenues on the MIGC system are generated from contract demand
charges and volumetric fees paid by shippers under firm and
interruptible gas transportation agreements. Our current firm
transportation agreements range in term from approximately three
months to 11 years. Of the current certificated capacity of
175 MMcf/d, 40 MMcf/d
is contracted through October 2018,
45 MMcf/d
is contracted through September 2012,
85 MMcf/d
is contracted through January 2009 and 5 MMcf/d is contracted
through December 2007. Most of our interruptible gas
transportation agreements are month-to-month with the remainder
generally having terms of less than one year. Approximately 64%
and 85% of our revenues for the year ended December 31,
2006 and the nine months ended September 30, 2007,
respectively, were associated with firm transportation demand
charges.
Delivery Points. MIGC volumes can be
redelivered to five interstate market pipelines, including the
Williston Basin Interstate pipeline at the northern end of the
Powder River Basin, the MGTC pipeline, a pipeline that supplies
local markets in Wyoming, the Wyoming Interstate Companys
Medicine Bow lateral pipeline, the Colorado Interstate Gas
pipeline and the Kinder Morgan interstate pipeline at the
southern end of the Powder River Basin near Glenrock, Wyoming.
Supply. Anadarko has an interest in over one
million gross acres within the prolific Powder River Basin. It
currently operates approximately 3,500 gross coal-bed methane
wells and has non-operating interests in more than 3,400
additional gross coal-bed methane wells. Anadarkos acreage
is
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Business
approximately 50% developed with a substantial undeveloped
acreage position in the expanding Big George coal fairway. The
historical development pace on Anadarko acreage has been 600 to
800 gross wells per year, suggesting that a five- to seven-year
development inventory remains.
Helper gathering
system
General. The
67-mile
Helper gathering system, located in Carbon County, Utah, was
built to provide gathering services for Anadarkos coal-bed
methane development of the Ferron Coal. The Helper gathering
system provides gathering, dehydration, compression and treating
services for coal-bed methane gas. The Helper gathering system
has pipeline diameters ranging from four to 20 inches and
includes two compressor stations with a combined 11,575
horsepower and two
CO2
treating facilities.
Average throughput on the Helper gathering system for the year
ended December 31, 2006 and the nine months ended
September 30, 2007, was
38 MMcf/d
and
36 MMcf/d,
respectively, from approximately 120 receipt points.
Customers. Anadarko is the largest shipper on
the Helper gathering system. For the nine months ended
September 30, 2007, Anadarkos equity production
represented approximately 99% of the Helper gathering
systems volume.
Delivery Points. The Helper gathering system
delivers into the Questar Transportation Services Companys
pipeline. Questar provides transportation to regional markets in
Wyoming, Colorado and Utah and also delivers into the Kern River
Pipeline, which provides transportation to markets in the
western U.S., primarily California.
Supply. Helper Field is an Anadarko-operated
field on the southwestern edge of the Uinta Basin that produces
from the Cretaceous Ferron sands and coals. Helper Field
consists of approximately 19,000 gross acres and currently has
116 gross producing wells. Cardinal Draw, which lies immediately
to the east of Helper Field, currently has 24 gross
producing wells and covers another approximately 15,000 gross
acres.
In 2003, Anadarko entered into an agreement with Westport Oil
and Gas Company, LP, which was acquired by Kerr-McGee
Corporation in 2004, to gather volumes from its Cardinal Draw
development play. Since the acquisition of Kerr-McGee by
Anadarko in 2006, Anadarko has continued the development of the
Cardinal Draw area. During the nine months ended
September 30, 2007, Anadarko drilled 12 gross wells in the
Cardinal Draw area and it has disclosed that it has identified
an additional 56 drilling locations. Production in the Helper
Field/Cardinal Draw area began in 1994 and since then has
produced over 92 Bcf.
Clawson gathering
system
General. The
47-mile
Clawson gathering system, located in Carbon and Emery Counties
of Utah, was built in 2001 to provide gathering services for
Anadarkos coal-bed methane development of the Ferron Coal.
The Clawson gathering system provides gathering, dehydration,
compression and treating services for coal-bed methane gas. The
Clawson gathering system has pipeline diameters ranging from
four to 18 inches and includes one compressor station, with
8,810 horsepower, and a
CO2-treating
facility.
Average throughput on the Clawson gathering system for the year
ended December 31, 2006 and the nine months ended
September 30, 2007 was
22 MMcf/d
and
19 MMcf/d,
respectively, from approximately 45 receipt points.
Customers. Anadarko is the largest shipper on
the Clawson gathering system with approximately 96% of the total
throughput delivered into the system during the nine months
ended September 30, 2007. The remaining throughput on the
system was comprised of production from third-party producers.
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Business
Delivery Points. The Clawson gathering system
delivers into the Questar Transportation Services Companys
pipeline.
Supply. Clawson Springs Field consists of 45
gross wells on approximately 7,200 gross acres. Production for
Clawson Springs is primarily from the Cretaceous Ferron sands
and coals. First gas sales in Clawson Springs occurred in 2001
and the field has produced over 54 Bcf.
Mid-Continent
Hugoton gathering
system
General. The 1,753-mile Hugoton gathering
system provides gathering service to the Hugoton field and is
primarily located in Seward, Stevens, Grant and Morton Counties
of Southwest Kansas and Texas County in Oklahoma.
Average throughput on the Hugoton gathering system for the year
ended December 31, 2006 and the nine months ended
September 30, 2007, was
117 MMcf/d
and
123 MMcf/d,
respectively, from approximately 1,500 receipt points. The
Hugoton gathering system has pipeline diameters ranging from two
to 26 inches and 44 compressor stations with a
combined 130,720 horsepower of compression.
Customers. Anadarko is the largest customer on
the Hugoton gathering system with
112 MMcf/d
of average throughput during the nine months ended
September 30, 2007, representing 86% of the total volume on
the system during such period. Of these volumes, 63% represent
Anadarkos equity production and 37% represent volumes
purchased by Anadarko from third parties, including EOG
Resources, Inc. and Merit Energy Company, among others.
Other significant shippers on the Hugoton gathering system,
including DCP Midstream, LP, Oxy Oil and Gas, Pioneer Natural
Resources USA, Inc. and ExxonMobil Gas & Power
Marketing Company, LP, collectively comprised fourteen percent
of the system throughput volume for the nine months ended
September 30, 2007.
Delivery Points. The Hugoton gathering system
is connected to DCP Midstream, LPs National Helium Plant,
which extracts NGLs and helium and redelivers residue gas into
the Panhandle Eastern Pipeline. The system is also connected to
Pioneer Natural Resources Corporations Satanta Plant for
NGL processing and to the adjacent Mid-Continent Market Center,
which provides access to the Panhandle Eastern pipeline, the
Northern Natural Gas pipeline, the Natural Gas (NGPL) pipeline,
the Southern Star pipeline, and the ANR pipeline. These
pipelines provide transportation and market access to Midwestern
and Northeastern markets.
Supply. The Hugoton Field is one of the
largest natural gas fields in North America. Anadarko operates
approximately 1,250 gross wells in the area and has an
extensive acreage position with approximately 425,000 gross
acres in the Hugoton Field. We believe that recent changes to
the Hugoton and Panoma Council Grove Proration Orders will
provide opportunities for significant recompletion, redrilling
and density drilling activities.
By virtue of a farmout agreement between EOG Resources, Inc. and
Anadarko, EOG gained the right to explore below the primary
formations in the Hugoton Field. EOG plans to drill
approximately 50 gross wells in 2008 and 60 gross wells in
2009 in proximity to the Hugoton gathering system. We believe we
are well-positioned to gather volumes that may be produced from
these new wells.
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Business
West
Texas
Haley gathering
system
General. The
87-mile
Haley gathering system is located in Loving County, Texas and
gathers Anadarkos production from the Delaware Basin. The
Haley gathering system provides gathering and dehydration
services and has pipeline diameters ranging from four to
16 inches.
Average throughput on the Haley gathering system for the year
ended December 31, 2006 and the nine months ended
September 30, 2007 was
139 MMcf/d
and
185 MMcf/d,
respectively, from approximately 50 wells. The Haley
gathering system has experienced rapid growth as a result of
Anadarkos successful drilling activity in the area. Since
2004, volumes gathered by the Haley system have increased from
13 MMcf/d
to over
200 MMcf/d.
Anadarko has maintained an active drilling program in the area,
utilizing eight to nine rigs to explore and develop its Delaware
Basin acreage.
Customers. Anadarkos and its
partners production represented 99% of the Haley gathering
systems throughput for the nine months ended
September 30, 2007.
Delivery Points. The Haley gathering system
has multiple delivery points. The primary delivery points are to
the El Paso Natural Gas pipeline or the Enterprise GC, L.P.
pipeline for ultimate delivery into Energy Transfers Oasis
pipeline. We also have the ability to deliver into Southern
Union Energy Services pipeline for further delivery into
the Oasis Pipeline. The pipelines at these delivery points
provide transportation to both the Waha and Houston Ship Channel
Markets.
Supply. In the greater Delaware basin,
Anadarko has access to over 400,000 gross undeveloped acres,
currently operates nine rigs and is a non-operating partner in
three additional rigs. Within the area serviced by the Haley
gathering system, over 60 gross wells have already been
drilled and completed and we anticipate that four to five rigs
will continuously operate on 100,000 Anadarko-controlled
acres. We believe that this activity and Anadarkos
controlled acreage indicate a 5 to 10-year drilling inventory on
the acreage serviced by the Haley gathering system.
Given that over 90% of the volume on our systems is owned or
controlled by Anadarko and Anadarko has dedicated to us future
production from acreage surrounding our gathering systems, we do
not currently face significant competition for our natural gas
volumes. In the future, we may face competition for
Anadarkos production drilled outside the dedication and in
attracting third-party volumes to our systems.
Competition on
gathering systems
The natural gas gathering, compression, treating and
transportation business is very competitive. Our competitors
include other midstream companies, producers, intrastate and
interstate pipelines. Competition for natural gas volumes is
primarily based on reputation, commercial terms, reliability,
service levels, location, available capacity, capital
expenditures and fuel efficiencies. Our major competitors for
each area include:
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Dew gathering and Pinnacle gas treating: ETC Texas
Pipeline, Ltd., Enbridge Pipelines (East Texas) LP, XTO Energy
and Kinder Morgan Tejas Pipeline, LP.
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Helper and Clawson gathering systems: Questar
Transportation Services Company.
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Hugoton gathering system: ONEOK Gas Gathering
Company, DCP Midstream, LP, Pioneer Resources.
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Haley gathering system: Enterprise GC, LP, Southern
Union Energy Services Company.
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Competition on
MIGC
MIGC competes with other pipelines that service regional market
and transport gas volumes from the Powder River Basin to
Glenrock, Wyoming. MIGC competitors seek to attract and connect
new gas volumes throughout the Powder River Basin, including the
volumes currently being transported on MIGC. An increase in
competition could result from new pipeline installations or
expansions by existing pipelines. Competitive factors include
the commercial terms, available capacity, fuel efficiencies, the
interconnected pipelines and gas quality issues MIGC major
competitors are Fort Union Gas Gathering, L.L.C. and
ThunderCreek Gas Services.
We are subject to regulation by the Pipeline and Hazardous
Materials Safety Administration, or PHMSA, of the Department of
Transportation, or the DOT, pursuant to the Natural Gas Pipeline
Safety Act of 1968, or the NGPSA, and the Pipeline Safety
Improvement Act of 2002, or the PSIA, which was recently
reauthorized and amended by the Pipeline Inspection, Protection,
Enforcement and Safety Act of 2006. The NGPSA regulates safety
requirements in the design, construction, operation and
maintenance of gas pipeline facilities, while the PSIA
establishes mandatory inspections for all U.S. oil and natural
gas transportation pipelines and some gathering lines in
high-consequence areas. The PHMSA has developed regulations
implementing the PSIA that require transportation pipeline
operators to implement integrity management programs, including
more frequent inspections and other measures to ensure pipeline
safety in high consequence areas, such as high
population areas, areas unusually sensitive to environmental
damage and commercially navigable waterways. Our transportation
pipeline system, MIGC, includes no high consequence areas and
thus these particular integrity management programs are not
applicable.
We or the entities in which we own an interest inspect our
pipelines regularly using equipment rented from third-party
suppliers. Third parties also assist us in interpreting the
results of the inspections.
States are largely preempted by federal law from regulating
pipeline safety for interstate lines but most are certified by
the DOT to assume responsibility for enforcing federal
intrastate pipeline regulations and inspection of intrastate
pipelines. In practice, because states can adopt stricter
standards for intrastate pipelines that those imposed by the
federal government for interstate lines, states vary
considerably in their authority and capacity to address pipeline
safety. We do not anticipate any significant difficulty in
complying with applicable state laws and regulations. Our
natural gas pipelines have continuous inspection and compliance
programs designed to keep the facilities in compliance with
pipeline safety and pollution control requirements.
In addition, we are subject to a number of federal and state
laws and regulations, including the federal Occupational Safety
and Health Act, or OSHA, and comparable state statutes, the
purposes of which are to protect the health and safety of
workers, both generally and within the pipeline industry. In
addition, the OSHA hazard communication standard, the
Environmental Protection Agency, or EPA, community right-to-know
regulations under Title III of the federal Superfund
Amendment and Reauthorization Act and comparable state statutes
require that information be maintained concerning hazardous
materials used or produced in our operations and that such
information be provided to employees, state and local government
authorities and citizens. We and the entities in which we own an
interest are also subject to OSHA Process Safety Management
regulations, which are designed to prevent or minimize the
consequences of catastrophic releases of toxic, reactive,
flammable or explosive chemicals. These regulations apply to any
process which involves a chemical at or above the specified
thresholds or any process which involves flammable liquid or
gas, pressurized tanks, caverns and wells in excess of 10,000
pounds at various locations. Flammable liquids stored in
atmospheric tanks below their normal boiling points without the
benefit of chilling or refrigeration are exempt. We have an
internal program of inspection designed to monitor and enforce
compliance with worker safety
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requirements. We believe that we are in material compliance with
all applicable laws and regulations relating to worker health
and safety.
Regulation of pipeline gathering and transportation services,
natural gas sales and transportation of NGLs may affect certain
aspects of our business and the market for our products and
services.
Interstate
transportation pipeline regulation
MIGC, our interstate natural gas transportation system, is
subject to regulation by FERC under the Natural Gas Act of 1938,
or the NGA.
Under the NGA, FERC has authority to regulate natural gas
companies that provide natural gas pipeline transportation
services in interstate commerce. Federal regulation extends to
such matters as:
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rates, services, and terms and conditions of service;
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the types of services MIGC may offer to its customers;
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the certification and construction of new facilities;
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the acquisition, extension, disposition or abandonment of
facilities;
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the maintenance of accounts and records;
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relationships between affiliated companies involved in certain
aspects of the natural gas business;
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the initiation and discontinuation of services;
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market manipulation in connection with interstate sales,
purchases or transportation of natural gas; and
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participation by interstate pipelines in cash management
arrangements.
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Natural gas companies are prohibited from charging rates that
have been determined not to be just and reasonable by FERC. In
addition, FERC prohibits natural gas companies from unduly
preferring or unreasonably discriminating against any person
with respect to pipeline rates or terms and conditions of
service.
The rates and terms and conditions for our interstate pipeline
services are set forth in FERC-approved tariffs. Pursuant to
FERCs jurisdiction over rates, existing rates may be
challenged by complaint and proposed rate increases may be
challenged by protest. Any successful complaint or protest
against our rates could have an adverse impact on our revenues
associated with providing transportation service.
Commencing in 2003, FERC issued a series of orders adopting
rules for new Standards of Conduct for Transmission Providers
(Order No. 2004), which apply to interstate natural gas
pipelines and certain natural gas storage companies that provide
storage services in interstate commerce. Order No. 2004
became effective in 2004. Among other matters, Order
No. 2004 required interstate pipeline and storage companies
to operate independently from their energy affiliates,
prohibited interstate pipeline and storage companies from
providing non-public transportation or shipper information to
their energy affiliates, prohibited interstate pipeline and
storage companies from favoring their energy affiliates in
providing service and obligated interstate pipeline and storage
companies to post on their websites a number of items of
information concerning the company, including its organizational
structure, facilities shared with energy affiliates, discounts
given for service and instances in which the company has agreed
to waive discretionary terms of its tariff.
Late in 2006, the D.C. Circuit vacated and remanded Order
No. 2004 as it relates to natural gas transportation
providers, including MIGC. The D.C. Circuit found that FERC had
not adequately justified its expansion of the prior standards of
conduct to include energy affiliates, and vacated the
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entire rule as it relates to natural gas transportation
providers. On January 9, 2007, and as clarified on
March 21, 2007, FERC issued an interim rule re-promulgating
on an interim basis the standards of conduct that were not
challenged before the court, while FERC decides how to respond
to the courts decision on a permanent basis. The interim
rule makes the standards of conduct apply to the relationship
between natural gas transportation providers and their marketing
affiliates, but not to energy affiliates who are not also
marketing affiliates. Several companies requested rehearing and
clarification of the interim rule. The March 21, 2007 order
on clarification granted some of the requested clarifications
and stated that FERC would address the other requests in its
proceeding establishing a permanent rule. FERC has issued a
notice of proposed rulemaking, or NOPR, that proposes permanent
standards of conduct that FERC states will avoid the aspects of
the previous standards of conduct rejected by the court. With
respect to natural gas transportation providers, the NOPR
proposes (1) that the permanent standards of conduct apply
only to the relationship between natural gas transportation
providers and their marketing affiliates, and (2) to make
permanent the changes adopted in the interim rule permitting
risk management employees to be shared by natural gas
transportation providers and their marketing affiliates and
requiring that tariff waivers be maintained in a written waiver
log and available upon request.
On July 7, 2004, FERC issued an order providing MIGC with a
partial waiver of the independent functioning and information
access provisions of the standards of conduct. FERC has stated
that waivers of the standards of conduct have not been impacted
by the D.C. Circuits decision to vacate the attempted
expansion of the standards of conduct as to natural gas
transmission providers, by the implementation of the interim
rule, or by the currently pending NOPR. Nonetheless, we have no
way to predict with certainty the scope of FERCs permanent
rules on the standards of conduct. However, we do not believe
that MIGC will be affected by any action taken previously or in
the future on these matters in a fashion which is materially
different than that affecting similarly situated natural gas
service providers.
In May 2005, FERC issued a policy statement permitting the
inclusion of an income tax allowance in the cost of
service-based rates of a pipeline organized as a tax
pass-through partnership entity, if the pipeline proves that the
ultimate owner of its equity interests has an actual or
potential income tax liability on public utility income. The
policy statement also provides that whether a pipelines
owners have such actual or potential income tax liability will
be reviewed by FERC on a
case-by-case
basis. In August 2005, FERC dismissed requests for rehearing of
its new policy statement. On December 16, 2005, FERC issued
its first significant case-specific review of the income tax
allowance issue in a pipeline partnerships rate case. FERC
reaffirmed its new income tax allowance policy and directed the
subject pipeline to provide certain evidence necessary for the
pipeline to determine its income tax allowance. The new tax
allowance policy and the December 16, 2005 order were
appealed to the D.C. Circuit. The D.C. Circuit issued an order
on May 29, 2007 in which it denied these appeals and upheld
FERCs new tax allowance policy and the application of that
policy in the December 16, 2005 order on all points subject
to appeal. The D.C. Circuit denied rehearing of the May 29,
2007 decision on August 20, 2007, and the D.C.
Circuits decision is final.
On December 8, 2006, FERC issued another order addressing
the income tax allowance in rates. In the December 8, 2006
order, FERC refined and reaffirmed prior statements regarding
its income tax allowance policy, and notably raised a new issue
regarding the implication of the policy statement for publicly
traded partnerships. It noted that the tax deferral features of
a publicly traded partnership may cause some investors to
receive, for some indeterminate duration, cash distributions in
excess of their taxable income, which FERC characterized as a
tax savings. FERC stated that it is concerned that
this created an opportunity for those investors to earn an
additional return, funded by ratepayers. Responding to this
concern, FERC chose to adjust the pipelines equity rate of
return downward based on the percentage by which the publicly
traded partnerships cash flow exceeded taxable income. On
February 7, 2007, the pipeline filed a request for
rehearing on this issue, which is currently pending
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before FERC. The ultimate outcome of this proceeding is not
certain and could result in changes to FERCs treatment of
income tax allowances in cost of service and to potential
adjustment in a future rate case of our pipelines
respective equity rate of return that underlies its recourse
rates to the extent that cash distributions in excess of taxable
income are allowed to some unitholders. If FERC were to disallow
a substantial portion of MIGCs income tax allowance, it
may cause its recourse rates to be set at a level that is
different, and in some instances lower, than the level otherwise
in effect.
On July 19, 2007, FERC issued a proposed policy statement
regarding the composition of proxy groups for determining the
appropriate return on equity for natural gas and oil pipelines.
The proposed policy statement would permit the inclusion of
distributions capped at a master limited partnerships
reported earnings in calculating the equity returns of a proxy
group of pipeline enterprises under the Discounted Cash Flow, or
DCF, analysis. The determination of which master limited
partnerships should be included will be made on a case by case
basis, after a review of whether a master limited
partnerships earnings have been stable over a multi-year
period. In November 2007, the FERC requested additional comments
and announced a technical conference regarding the method to be
used for creating growth forecasts for publicly traded
partnerships. FERC proposes to apply the final policy statement
to all natural gas rate cases that have not completed the
hearing phase as of the date FERC issues the final policy
statement. FERCs proposed policy statement is subject to
change based on comments it has received, and therefore, we
cannot predict the scope of the final policy statement.
On August 8, 2005, Congress enacted the Energy Policy Act
of 2005, or the EPAct 2005. Among other matters, EPAct 2005
amends the NGA to add an anti-manipulation provision which makes
it unlawful for any entity to engage in prohibited behavior in
contravention of rules and regulations to be prescribed by FERC
and, furthermore, provides FERC with additional civil penalty
authority. On January 19, 2006, FERC issued Order
No. 670, a rule implementing the anti-manipulation
provision of EPAct 2005, and subsequently denied rehearing. The
rules make it unlawful for any entity, directly or indirectly:
(1) in connection with the purchase or sale of natural gas
subject to the jurisdiction of FERC or the purchase or sale of
transportation services subject to the jurisdiction of FERC to
use or employ any device, scheme or artifice to defraud;
(2) to make any untrue statement of material fact or omit
to make any such statement necessary to make the statements made
not misleading; or (3) to engage in any act or practice
that operates as a fraud or deceit upon any person. The new
anti-manipulation rules apply to interstate gas pipelines and
storage companies and intrastate gas pipelines and storage
companies that provide interstate services, such as
Section 311 service, as well as otherwise
non-jurisdictional entities to the extent the activities are
conducted in connection with gas sales, purchases or
transportation subject to FERC jurisdiction. The new
anti-manipulation rules do not apply to activities that relate
only to intrastate or other non-jurisdictional sales or
gathering, but only to the extent such transactions do not have
a nexus to jurisdictional transactions. EPAct 2005
also amends the NGA and the NGPA to give FERC authority to
impose civil penalties for violations of these statutes, up to
$1,000,000 per day per violation for violations occurring after
August 8, 2005. In connection with this enhanced civil
penalty authority, FERC issued a policy statement on enforcement
to provide guidance regarding the enforcement of the statutes,
orders, rules and regulations it administers, including factors
to be considered in determining the appropriate enforcement
action to be taken. Should we fail to comply with all applicable
FERC-administered statutes, rule, regulations and orders, we
could be subject to substantial penalties and fines.
Gathering
pipeline regulation
Section 1(b) of the NGA exempts natural gas gathering
facilities from the jurisdiction of FERC. We believe that our
natural gas pipelines meet the traditional tests that FERC has
used to determine that a pipeline is a gathering pipeline and
is, therefore, not subject to FERC jurisdiction. The distinction
between FERC-regulated transmission services and federally
unregulated gathering services, however, is the subject of
substantial, on-going litigation, so the classification and
regulation of our gathering
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facilities are subject to change based on future determinations
by FERC, the courts or Congress. State regulation of gathering
facilities generally includes various safety, environmental and,
in some circumstances, nondiscriminatory take requirements and
complaint-based rate regulation. In recent years, FERC has taken
a more light-handed approach to regulation of the gathering
activities of interstate pipeline transmission companies, which
has resulted in a number of such companies transferring
gathering facilities to unregulated affiliates. As a result of
these activities, natural gas gathering may begin to receive
greater regulatory scrutiny at both the state and federal
levels. Our natural gas gathering operations could be adversely
affected should they be subject to more stringent application of
state or federal regulation of rates and services. Our natural
gas gathering operations also may be or become subject to
additional 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.
Our natural gas gathering operations are subject to ratable take
and common purchaser statutes in most of the states in which we
operate. These statutes generally require our gathering
pipelines to take natural gas without undue discrimination as to
source of supply or producer. These statutes are designed to
prohibit discrimination in favor of one producer over another
producer or one source of supply over another source of supply.
The regulations under these statutes can have the effect of
imposing some restrictions on our ability as an owner of
gathering facilities to decide with whom we contract to gather
natural gas. The states in which we operate have adopted a
complaint-based regulation of natural gas gathering activities,
which allows natural gas producers and shippers to file
complaints with state regulators in an effort to resolve
grievances relating to gathering access and rate discrimination.
We cannot predict whether such a complaint will be filed against
us in the future. Failure to comply with state regulations can
result in the imposition of administrative, civil and criminal
remedies. To date, there has been no adverse effect to our
system due to these regulations.
During the 2007 legislative session, the Texas State Legislature
passed H.B. 3273, or the Competition Bill, and
H.B. 1920, or the LUG Bill. The Texas Competition Bill and
LUG Bill contain provisions applicable to gathering facilities.
The Competition Bill allows the Railroad Commission of Texas, or
the TRRC, the ability to use either a cost-of-service method or
a market-based method for setting rates for natural gas
gathering in formal rate proceedings. It also gives the TRRC
specific authority to enforce its statutory duty to prevent
discrimination in natural gas gathering, to enforce the
requirement that parties participate in an informal complaint
process and to punish purchasers, transporters and gatherers for
taking discriminatory actions against shippers and sellers. The
LUG Bill modifies the informal complaint process at the TRRC
with procedures unique to lost and unaccounted for gas issues.
It extends the types of information that can be requested and
gives the TRRC the authority to make determinations and issue
orders in specific situations. Both the Competition Bill and the
LUG Bill became effective September 1, 2007. We cannot
predict what effect, if any, either the Competition Bill or the
LUG Bill might have on our gathering operations.
General
Our operation of pipelines, plants and other facilities for the
gathering, compressing, treating and transporting of natural gas
and other products is subject to stringent and complex federal,
state and local laws and regulations relating to the protection
of the environment. As an owner or operator of
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these facilities, we must comply with these laws and regulations
at the federal, state and local levels. These laws and
regulations can restrict or impact our business activities in
many ways, such as:
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requiring the installation of pollution-control equipment or
otherwise restricting the way we can handle or dispose of our
wastes;
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limiting or prohibiting construction activities in sensitive
areas, such as wetlands, coastal regions or areas inhabited by
endangered or threatened species;
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requiring investigatory and remedial actions to mitigate
pollution conditions caused by our operations or attributable to
former operations; and
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enjoining the operations of facilities deemed to be in
non-compliance with permits issued pursuant to such
environmental laws and regulations.
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Failure to comply with these laws and regulations may trigger a
variety of administrative, civil and criminal enforcement
measures, including the assessment of monetary penalties, the
imposition of remedial obligations and the issuance of orders
enjoining future operations or imposing additional compliance
requirements. Certain environmental statutes impose strict joint
and several liability for costs required to clean up and restore
sites where substances, hydrocarbons or wastes 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.
The trend in environmental regulation is to place more
restrictions and limitations on activities that may affect the
environment, and thus, there can be no assurance as to the
amount or timing of future expenditures for environmental
compliance or remediation and actual future expenditures may be
different from the amounts we currently anticipate. We try to
anticipate future regulatory requirements that might be imposed
and plan accordingly to remain in compliance with changing
environmental laws and regulations and to minimize the costs of
such compliance. We also actively participate in industry groups
that help formulate recommendations for addressing existing or
future regulations.
We do not believe that compliance with federal, state or local
environmental laws and regulations will have a material adverse
effect on our business, financial position or results of
operations or cash flows. In addition, we believe that the
various environmental activities in which we are presently
engaged are not expected to materially interrupt or diminish our
operational ability to gather, compress, treat and transport
natural gas. We cannot assure you, however, that future events,
such as changes in existing laws or enforcement policies, the
promulgation of new laws or regulations or the development or
discovery of new facts or conditions will not cause us to incur
significant costs. Below is a discussion of the material
environmental laws and regulations that relate to our business.
We believe that we are in substantial compliance with all of
these environmental laws and regulations.
Hazardous
substances and waste
Our operations are subject to environmental laws and regulations
relating to the management and release of hazardous substances,
solid and hazardous wastes and petroleum hydrocarbons. These
laws generally regulate the generation, storage, treatment,
transportation and disposal of solid and hazardous waste and may
impose strict joint and several liability for the investigation
and remediation of affected areas where hazardous substances may
have been released or disposed. For instance, the Comprehensive
Environmental Response, Compensation, and Liability Act,
referred to as CERCLA or the Superfund law, and comparable state
laws impose liability, without regard to fault or the legality
of the original conduct, on certain classes of persons that
contributed to the release of a hazardous substance into the
environment. These persons include current and prior owners or
operators of the site where the release occurred and companies
that disposed or arranged for the disposal of the hazardous
substances found at the site. Under CERCLA, these persons may be
subject to joint and several strict liability for the costs
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of cleaning up the hazardous substances that have been released
into the environment, for damages to natural resources and for
the costs of certain health studies. CERCLA also authorizes the
EPA and, in some instances, third parties to act in response to
threats to the public health or the environment and to seek to
recover the costs they incur from the responsible classes of
persons. It is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property
damage allegedly caused by hazardous substances or other
pollutants released into the environment. Despite the
petroleum exclusion of CERCLA Section 101(14),
which currently encompasses natural gas, we may nonetheless
handle hazardous substances within the meaning of CERCLA, or
similar state statutes, in the course of our ordinary operations
and, as a result, may be jointly and severally liable under
CERCLA for all or part of the costs required to clean up sites
at which these hazardous substances have been released into the
environment.
We also generate solid wastes, including hazardous wastes, that
are subject to the requirements of the Resource Conservation and
Recovery Act, referred to as RCRA, and comparable state
statutes. While RCRA regulates both solid and hazardous wastes,
it imposes strict requirements on the generation, storage,
treatment, transportation and disposal of hazardous wastes.
Certain petroleum production wastes are excluded from
RCRAs hazardous waste regulations. However, it is possible
that these wastes, which could include wastes currently
generated during our operations, will in the future be
designated as hazardous wastes and, therefore, be
subject to more rigorous and costly disposal requirements. Any
such changes in the laws and regulations could have a material
adverse effect on our maintenance capital expenditures and
operating expenses.
We currently own or lease, and our Predecessor has in the past
owned or leased, properties where hydrocarbons are being or have
been handled for many years. Although we have utilized operating
and disposal practices that were standard in the industry at the
time, hydrocarbons or other wastes may have been disposed of or
released on or under the properties owned or leased by us or on
or under the other locations where these hydrocarbons and wastes
have been transported for treatment or disposal. In addition,
certain of these properties have been operated by third parties
whose treatment and disposal or release of hydrocarbons and
other wastes was not under our control. These properties and the
wastes disposed thereon may be subject to CERCLA, RCRA and
analogous state laws. Under these laws, we could be required to
remove or remediate previously disposed wastes (including wastes
disposed of or released by prior owners or operators), to clean
up contaminated property (including contaminated groundwater) or
to perform remedial operations to prevent future contamination.
We are not currently aware of any facts, events or conditions
relating to such requirements that could materially impact our
operations or financial condition.
Air
emissions
Our operations are subject to the federal Clean Air Act and
comparable state laws and regulations. These laws and
regulations regulate emissions of air pollutants from various
industrial sources, including our compressor stations, and also
impose various monitoring and reporting requirements. Such laws
and regulations may require that we obtain pre-approval for the
construction or modification of certain projects or facilities
expected to produce or significantly increase air emissions,
obtain and strictly comply with air permits containing various
emissions and operational limitations and utilize specific
emission control technologies to limit emissions. Our failure to
comply with these requirements could subject us to monetary
penalties, injunctions, conditions or restrictions on operations
and, potentially, criminal enforcement actions. We believe that
we are in substantial compliance with these requirements. We may
be required to incur certain capital expenditures in the future
for air pollution control equipment in connection with obtaining
and maintaining operating permits and approvals for air
emissions. We believe, however, that our operations will not be
materially adversely affected by such requirements, and the
requirements are not expected to be any more burdensome to us
than to any other similarly situated companies.
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Water
discharges
The Federal Water Pollution Control Act, or the Clean Water Act,
and analogous state laws impose restrictions and strict controls
regarding the discharge of pollutants into state waters as well
as waters of the U.S. The discharge of pollutants into regulated
waters is prohibited, except in accordance with the terms of a
permit issued by the EPA or an analogous state agency. Spill
prevention, control and countermeasure requirements of federal
laws require appropriate containment berms and similar
structures to help prevent the contamination of regulated waters
in the event of a hydrocarbon tank spill, rupture or leak. In
addition, the Clean Water Act and analogous state laws require
individual permits or coverage under general permits for
discharges of storm water runoff from certain types of
facilities. These permits may require us to monitor and sample
the storm water runoff from certain of our facilities. Some
states also maintain groundwater protection programs that
require permits for discharges or operations that may impact
groundwater conditions. Federal and state regulatory agencies
can impose administrative, civil and criminal penalties for
non-compliance with discharge permits or other requirements of
the Clean Water Act and analogous state laws and regulations. We
believe that compliance with existing permits and compliance
with foreseeable new permit requirements will not have a
material adverse effect on our financial condition, results of
operations or cash flow.
Endangered
species
The Endangered Species Act, or ESA, restricts activities that
may affect endangered or threatened species or their habitats.
While some of our pipelines may be located in areas that are
designated as habitats for endangered or threatened species, we
believe that we are in substantial compliance with the ESA.
However, the designation of previously unidentified endangered
or threatened species could cause us to incur additional costs
or become subject to operating restrictions or bans in the
affected states.
Global warming
and climate control
Recent scientific studies have suggested that emissions of
certain gases, commonly referred to as greenhouse
gases and including carbon dioxide and methane, may be
contributing to warming of the Earths atmosphere. In
response to such studies, the U.S. Congress is actively
considering legislation to reduce emissions of greenhouse gases.
In addition, at least 17 states have already taken legal
measures to reduce emissions of greenhouse gases, primarily
through the planned development of greenhouse gas emission
inventories
and/or
regional greenhouse gas cap and trade programs. Also, as a
result of the U.S. Supreme Courts decision on
April 2, 2007 in Massachusetts, et al. v.
EPA, the EPA may be required to regulate greenhouse gas
emissions from mobile sources (e.g., cars and trucks) even if
Congress does not adopt new legislation specifically addressing
emissions of greenhouse gases. The Courts holding in
Massachusetts that greenhouse gases fall under the
federal Clean Air Acts definition of air
pollutant may also result in future regulation of
greenhouse gas emissions from stationary sources under certain
Clean Air Act programs. New legislation or regulatory programs
that restrict emissions of greenhouse gases in areas where we
conduct business could adversely affect our operations and
demand for our services.
Anti-terrorism
measures
The Department of Homeland Security Appropriation Act of 2007
requires the Department of Homeland Security, or DHS, to issue
regulations establishing risk-based performance standards for
the security of chemical and industrial facilities, including
oil and gas facilities that are deemed to present high
levels of security risk. The DHS issued an interim final
rule in April 2007 regarding risk-based performance standards to
be attained pursuant to this act and, on November 20, 2007,
further issued an Appendix A to the interim rules that
establish chemicals of interest and their respective threshold
quantities that will trigger compliance with these interim
rules. We have not yet determined the extent
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to which our facilities are subject to the interim rules or the
associated costs to comply, but it is possible that such costs
could be substantial.
TITLE
TO PROPERTIES AND RIGHTS-OF-WAY
Our real property falls into two categories: (1) parcels
that we own in fee and (2) parcels in which our interest
derives from leases, easements, rights-of-way, permits or
licenses from landowners or governmental authorities, permitting
the use of such land for our operations. Portions of the land on
which our plants and other major facilities are located are
owned by us in fee title, and we believe that we have
satisfactory title to these lands. The remainder of the land on
which our plant sites and major facilities are located are held
by us pursuant to surface leases between us, as lessee, and the
fee owner of the lands, as lessors. We, or our predecessors,
have leased or owned these lands for many years without any
material challenge known to us relating to the title to the land
upon which the assets are located, and we believe that we have
satisfactory leasehold estates or fee ownership to such lands.
We have no knowledge of any challenge to the underlying fee
title of any material lease, easement, right-of-way, permit or
license held by us or to our title to any material lease,
easement, right-of-way, permit or lease, and we believe that we
have satisfactory title to all of our material leases,
easements, rights-of-way, permits and licenses.
Some of the leases, easements, rights-of-way, permits and
licenses to be transferred to us at the close of this offering
require the consent of the grantor of such rights, which in
certain instances is a governmental entity. Our general partner
expects to obtain, prior to the closing of this offering,
sufficient third-party consents, permits and authorizations for
the transfer of the assets necessary to enable us to operate our
business in all material respects as described in this
prospectus. With respect to any material consents, permits or
authorizations that have not been obtained prior to the close of
this offering, the closing will not occur unless a reasonable
basis exists that permits our general partner to conclude that
such consents, permits or authorizations will be obtained within
a reasonable period following the closing, or the failure to
obtain such consents, permits or authorizations will have no
material adverse effect on the operation of our business.
Anadarko may initially continue to hold record title to portions
of certain assets until we make the appropriate filings in the
jurisdictions in which such assets are located and obtain any
consents and approvals that are not obtained prior to transfer.
Such consents and approvals would include those required by
federal and state agencies or political subdivisions. In some
cases, Anadarko may, where required consents or approvals have
not been obtained, temporarily hold record title to property as
nominee for our benefit and in other cases may, on the basis of
expense and difficulty associated with the conveyance of title,
cause its affiliates to retain title, as nominee for our
benefit, until a future date. We anticipate that there will be
no material change in the tax treatment of our common units
resulting from Anadarko holding the title to any part of such
assets subject to future conveyance or as our nominee.
113
Business
We do not have any employees. The officers of our general
partner will manage our operations and activities. As of
September 30, 2007, Anadarko employed approximately
110 people who will provide direct, full-time support to
our operations. All of the employees required to conduct and
support our operations will be employed by Anadarko and all of
our direct, full-time personnel are subject to a service and
secondment agreement between our general partner and Anadarko.
None of these employees are covered by collective bargaining
agreements, and Anadarko considers its employee relations to be
good.
We are not a party to any legal proceeding other than legal
proceedings arising in the ordinary course of our business. We
are a party to various administrative and regulatory proceedings
that have arisen in the ordinary course of our business. Please
read Regulation of operationsInterstate
transportation pipeline regulation and
Environmental matters.
114
MANAGEMENT
OF THE PARTNERSHIP
Western Gas Holdings, LLC, our general partner, will manage our
operations and activities. Our general partner is not elected by
our unitholders and will not be subject to re-election in the
future. The directors of our general partner oversee our
operations. Unitholders will not be entitled to elect the
directors of our general partner or directly or indirectly
participate in our management or operations. However, our
general partner owes a fiduciary duty to our unitholders. There
are no existing arrangements pursuant to which a person has been
named as a member of the board of directors of our general
partner. Our general partner will be liable, as general partner,
for all of our debts (to the extent not paid from our assets),
except for indebtedness or other obligations that are made
specifically nonrecourse to it. Our general partner, therefore,
may cause us to incur indebtedness or other obligations that are
nonrecourse to it.
Upon the closing of this offering, we expect that our general
partner will have nine directors, four of whom will be
independent as defined under the independence standards
established by the NYSE and the Exchange Act. One of such
independent directors will be appointed prior to the
effectiveness of the registration statement of which this
prospectus forms a part. The NYSE does not require a listed
publicly traded partnership, such as ours, to have a majority of
independent directors on the board of directors of our general
partner or to establish a compensation committee or a nominating
committee.
At least two independent members of the board of directors of
our general partner will serve on a special committee to review
specific matters that the board believes may involve conflicts
of interest (including certain transactions with
Anadarko).
will serve as the initial members of the special committee. The
special committee will determine if the resolution of the
conflict of interest is fair and reasonable to us. The members
of the special committee may not be officers or employees of our
general partner or directors, officers, or employees of its
affiliates, including Anadarko, and must meet the independence
and experience standards established by the NYSE and the
Exchange Act to serve on an audit committee of a board of
directors, along with other requirements. Any matters approved
by the special committee will be conclusively deemed to be fair
and reasonable to us, approved by all of our partners and not a
breach by our general partner of any duties it may owe us or our
unitholders.
In addition, our general partner will have an audit committee of
at least three directors who meet the independence and
experience standards established by the NYSE and the Exchange
Act.
will serve as the initial independent members of the audit
committee. The audit committee will assist the board of
directors in its oversight of the integrity of our combined
financial statements and our compliance with legal and
regulatory requirements and partnership policies and controls.
The audit committee will have the sole authority to
(1) retain and terminate our independent registered public
accounting firm, (2) approve all auditing services and
related fees and the terms thereof performed by our independent
registered public accounting firm, and (3) pre-approve any
non-audit services and tax services to be rendered by our
independent registered public accounting firm. The audit
committee will also be responsible for confirming the
independence and objectivity of our independent registered
public accounting firm. Our independent registered public
accounting firm will be given unrestricted access to the audit
committee and our management, as necessary.
All of the executive officers of our general partner listed
below will manage and conduct our operations. The executive
officers of our general partner will allocate their time between
managing our business and affairs and the business and affairs
of Anadarko. The executive officers of our general partner may
face a conflict regarding the allocation of their time between
our business and the other business interests of Anadarko. We
expect that the officers of our general partner will initially
devote less than a majority of their time to our business,
although we expect the amount of time that they
115
Management
devote may increase or decrease in future periods as our
business develops. These officers of our general partner and
other Anadarko employees will operate our business and provide
us with general and administrative services pursuant to the
omnibus agreement and the services and secondment agreement
described in Certain relationships and related party
transactionsAgreements governing the
transactionsServices and secondment agreement. We
will reimburse Anadarko for allocated expenses of operational
personnel who perform services for our benefit, and certain
direct expenses.
Our general partner will not receive any management fee or other
compensation for its management of our partnership under the
omnibus agreement, the services and secondment agreement or
otherwise. Under the omnibus agreement, our reimbursement to
Anadarko for certain general and administrative expenses it
allocates to us will be capped at $6.0 million annually
through December 31, 2009, subject to adjustments to
reflect changes in the Consumer Price Index and, with the
concurrence of the special committee of our general
partners board of directors, to reflect expansions of our
operations through the acquisition or construction of new assets
or businesses. Thereafter, our general partner will determine
the general and administrative expenses to be reimbursed by us
in accordance with our partnership agreement. The cap contained
in the omnibus agreement does not apply to incremental general
and administrative expenses we expect to incur or be allocated
to us as a result of becoming a publicly traded partnership. We
currently expect those expenses to be approximately
$2.5 million per year. Please read Certain
relationships and related party transactionsAgreements
governing the transactionsOmnibus agreement.
DIRECTORS
AND EXECUTIVE OFFICERS
The following table shows information regarding the current
executive officers and directors of our general partner.
Directors are appointed for a term of one year.
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Name
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Age
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Position with
Western Gas Holdings, LLC
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Robert G. Gwin
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44
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President, Chief Executive Officer and Director
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Danny J. Rea
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49
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Senior Vice President, Chief Operating Officer and Director
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Michael C. Pearl
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36
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Senior Vice President, Chief Financial Officer and Chief
Accounting Officer
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Lora W. Mays
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44
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Vice President and General Counsel
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Jeremy M. Smith
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35
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Vice President and Treasurer
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R.A. Walker
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50
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Chairman of the Board and Director
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Karl F. Kurz
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46
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Director
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Robert K. Reeves
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50
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Director
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Our directors hold office until their successors shall have been
duly elected and qualified or until the earlier of their death,
resignation, removal or disqualification. Officers serve at the
discretion of the board of directors. There are no family
relationships among any of our directors or executive officers.
Robert G. Gwin has served as President and Chief
Executive Officer and as a director of our general partner since
August 2007 and as Vice President, Finance and Treasurer of
Anadarko since January 2006. Prior to joining Anadarko, he
served as Chief Executive Officer of Community Broadband
Ventures, LP from November 2004 to January 2006. Prior to this
position, he was with Prosoft Learning Corporation, serving as
Chairman and Chief Executive Officer from November 2002 to
November 2004 and Chief Financial Officer from 2000 to November
2002. Previously, Mr. Gwin spent 10 years at
Prudential Capital Group in merchant banking roles of increasing
responsibility, including serving as Managing Director with
responsibility for the firms energy investments worldwide.
Mr. Gwin holds a Bachelor of Science degree from the
University of Southern California and a Master of Business
Administration degree from the Fuqua School of Business at Duke
University, and he is a Chartered Financial Analyst.
116
Management
Danny J. Rea has served as Senior Vice President and
Chief Operating Officer and as a director of our general partner
since August 2007 and as Vice President, Midstream of Anadarko
since May 2007. Previously, Mr. Rea served as Manager,
Midstream Services from May 2004 to May 2007 and Manager, Gas
Field Services from August 2000 to May 2007. Mr. Rea joined
Anadarko as an engineer in 1981 and has held positions of
increasing responsibility over his 26 years with the
Company. He holds a Bachelor of Science degree in petroleum
engineering from Louisiana Tech University, and a Master of
Business Administration degree from the University of Houston.
He currently serves on the board of directors for the Wyoming
Pipeline Authority and is a member of the Gas Processors
Association and the Society of Petroleum Engineers.
Michael C. Pearl has served as Senior Vice President and
Chief Financial Officer of our general partner since August 2007
and as Director, Corporate Tax of Anadarko since August 2006.
Prior to this position, he served as corporate tax manager for
Anadarko from September 2004 to August 2006. Prior to joining
Anadarko, Mr. Pearl joined Ernst & Young LLP in
1995, where he held positions of increasing responsibility,
including senior manager, and advised multinational energy
companies on structured acquisitions, divestitures, and
financings, including advising on partnership taxation and
accounting matters. He holds a Bachelor of Business
Administration degree and a Master of Science degree in
Accounting from Texas A&M University and is a Certified
Public Accountant.
Lora W. Mays has served as Vice President and General
Counsel of our general partner since August 2007 and as
Associate General Counsel of Anadarko since January 2003.
Ms. Mays joined Anadarko in 1997, and prior to being
promoted to her current position, she held the positions of
Senior Attorney, Counsel, Senior Counsel and Assistant General
Counsel within Anadarko. Prior to joining Anadarko,
Ms. Mays was in private practice. She holds a Bachelor of
Arts degree and a Juris Doctor degree from the University of
Houston.
Jeremy M. Smith has served as Vice President and
Treasurer of our general partner since August 2007 and as
Assistant Treasurer, Corporate Finance of Anadarko since July
2006. Prior to joining Anadarko, he served as Assistant
Treasurer to Plains Exploration & Production Company
from June 2003 to June 2006 and as Assistant Treasurer of 3TEC
Energy Corporation from May 2000 until its sale to Plains
Exploration & Production Company in June 2003.
Mr. Smith holds a Bachelor of Arts degree in Economics from
Rice University, a Master of Science degree in Accounting from
Texas A&M University and a Master of Business
Administration degree from Rice University, and he is a
Chartered Financial Analyst.
R.A. Walker has served as Chairman of the Board and a
director of our general partner since August 2007 and as Senior
Vice President, Finance and Chief Financial Officer of Anadarko
since 2005. Prior to joining Anadarko, he was a Managing
Director for the Global Energy Group of UBS Investment Bank from
2003 to 2005 and was President, Chief Financial Officer and a
director of 3TEC Energy Corporation from 2000 to 2003, until its
sale to Plains Exploration. From 1987 to 2000, he worked for
Prudential Financial in a variety of merchant banking positions,
including Senior Managing Director and co-head of Prudential
Capital at the time of his departure. Mr. Walker has served
on the boards of directors of numerous publicly traded
companies, including TEPPCO Partners, L.P. (a NYSE-listed
publicly traded partnership) where he served as chairman of the
audit committee.
Karl F. Kurz has served as a director of our general
partner since August 2007 and as Chief Operating Officer of
Anadarko since December 2006. He began his employment at
Anadarko in 2000, and he has served in a number of leadership
positions at Anadarko, including Senior Vice President,
Marketing, General Manager, U.S. Onshore, Vice President,
Marketing and Manager, Energy Marketing.
Robert K. Reeves has served as a director of our general
partner since August 2007 and as Senior Vice President, General
Counsel and Chief Administrative Officer of Anadarko since
February 2007. He previously served as Senior Vice President,
Corporate Affairs & Law and Chief Governance Officer
beginning in 2004. He has also served as a director of Key
Energy Services, Inc., a publicly traded oil
117
Management
field services company, since October 2007. Prior to
joining Anadarko, he served as Executive Vice President,
Administration and General Counsel of North Sea New Ventures
from 2003 to 2004 and as Executive Vice President, General
Counsel and Secretary of Ocean Energy, Inc. and its predecessor
companies from 1997 to 2003.
We and our general partner were formed in August 2007.
Accordingly, our general partner has not accrued any obligations
with respect to management incentive or retirement benefits for
our directors and officers for the fiscal year ended
December 31, 2006, or for any prior periods. Because the
executive officers of our general partner are employees of
Anadarko, compensation other than the long-term incentive plan
benefits described below will be determined and paid by
Anadarko. The officers of our general partner, as well as the
employees of Anadarko who provide services to us, may
participate in employee benefit plans and arrangements sponsored
by Anadarko, including plans that may be established in the
future. Our general partner has not entered into any employment
agreements with any of our officers. We anticipate that, in
connection with the closing of this offering, the board of
directors of our general partner will grant awards to our key
employees and our outside directors pursuant to the long-term
incentive plan described below in connection with the closing of
this offering; however, the board has not yet made any
determination as to the number of awards, the type of awards or
when the awards would be granted.
COMPENSATION
OF DIRECTORS
Officers or employees of Anadarko who also serve as directors of
our general partner will not receive additional compensation for
their service as a director of our general partner. Our general
partner anticipates that independent directors who are not
officers or employees of Anadarko will receive compensation for
attending meetings of the board of directors and committees of
the board. Such compensation will consist of an annual retainer
of $ , a fee of
$ for each board meeting attended
and an additional fee of $ for
each committee meeting attended. The chairman of the audit and
special committees will each receive an additional annual
retainer of $ . The independent,
non-management directors will also receive an annual grant
of
restricted units, which will vest 100% on the first anniversary
of the date of grant (with vesting to be accelerated upon a
change of control). In addition, each non-employee director will
be reimbursed for out-of-pocket expenses in connection with
attending meetings of the board of directors or committees. Each
director will be fully indemnified by us, pursuant to individual
indemnification agreements and our partnership agreement, for
actions associated with being a director to the fullest extent
permitted under Delaware law.
COMPENSATION
DISCUSSION AND ANALYSIS
Overview
We do not directly employ any of the persons responsible for
managing our business, and we do not have a compensation
committee. Western Gas Holdings, LLC, our general partner, will
manage our operations and activities, and its board of directors
and officers will make decisions on our behalf.
Some of the officers of our general partner also serve as
officers of Anadarko. The compensation of Anadarkos
employees that perform services on our behalf (other than the
long-term incentive plan benefits described below), including
our executive officers, will be approved by Anadarkos
management. Awards under our long-term incentive plan will be
recommended by Anadarkos management and approved by the
board of directors of our general partner. Our reimbursement for
the compensation of executive officers is governed by, and
subject to the limitations contained in, the omnibus agreement
and will be based on Anadarkos methodology used for
allocating general and administrative expenses to us. Under the
omnibus agreement, our reimbursement of certain general and
118
Management
administrative expenses will be capped at $6.0 million
annually through December 31, 2009, subject to adjustment
to reflect changes in the Consumer Price Index and, with the
concurrence of the special committee of our general
partners board of directors, to reflect expansions of our
operations through the acquisition or construction of new assets
or businesses. Thereafter, our general partner will determine
the general and administrative expenses to be reimbursed by us
in accordance with our partnership agreement. The cap contained
in the omnibus agreement does not apply to incremental general
and administrative expenses we expect to incur or be allocated
to us as a result of becoming a publicly traded partnership. We
currently expect those expenses to be approximately
$2.5 million per year. Please read Certain
relationships and related party transactionsAgreements
governing the transactionsOmnibus agreement.
As previously discussed, our general partner has not accrued any
obligations with respect to management incentive or retirement
benefits for its directors and officers for the fiscal year
ended December 31, 2006, or for any prior periods.
Accordingly, we are not presenting any compensation for
historical periods. Following the consummation of this offering,
we expect that the most highly compensated executive officers of
our general partner for 2007 will be Robert G. Gwin (the
principal executive officer), Danny J. Rea (principal operating
officer), and Michael C. Pearl (the principal financial officer
and principal accounting officer) (collectively, the named
executive officers). We expect that the named executive
officers will have less than a majority of their total
compensation allocated to us as compensation expense in 2007.
Compensation paid or awarded by us in 2007 with respect to the
named executive officers will reflect only the portion of
compensation expense that is allocated to us pursuant to
Anadarkos allocation methodology and subject to the terms
of the omnibus agreement. Anadarko has the ultimate
decision-making authority with respect to the total compensation
of the named executive officers and, subject to the terms of the
omnibus agreement, the portion of such compensation that is
allocated to us pursuant to Anadarkos allocation
methodology. The following discussion relating to compensation
paid by Anadarko is based on information provided to us by
Anadarko and does not purport to be a complete discussion and
analysis of Anadarkos executive compensation philosophy
and practices. The elements of compensation discussed below, and
Anadarkos decisions with respect to the levels of such
compensation, will not be subject to approvals by the board of
directors of our general partner, including the audit or special
committee thereof. Awards under our long-term incentive plan to
our general partners independent, non-management directors
will be made by the board of directors of our general partner.
Anadarkos
executive compensation program objectives, design and
process
The objectives of Anadarkos executive compensation program
are as follows:
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to align the interests of Anadarkos executives with those
of its shareholders;
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to attract and retain highly qualified and talented executives
to lead Anadarko; and
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to foster a team approach to achievement of Anadarkos
business objectives.
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Anadarko establishes target total compensation levels for each
executive officer, which are generally designed to place
Anadarkos executive compensation at or near the top
quartile as compared to an Anadarko industry peer group, if
Anadarko performance exceeds that of its peers and individual
performance targets are achieved. In addition, in setting total
compensation levels of each executive officer, Anadarko compares
target compensation levels among each of its executive officers
to ensure they are appropriate when considering each
executives role, experience level and contribution to the
organization. In the case of our executive officers, we would
expect Anadarko to take into account the additional duties, as
applicable, our executive officers will assume in connection
with their roles as officers of our general partner.
With respect to compensation objectives and decisions regarding
the named executive officers for 2007, we anticipate that
Anadarkos management will review market data for
determining relevant
119
Management
compensation levels and compensation program elements. In
addition, Anadarkos management may review and, in certain
cases, participate in, various relevant compensation surveys and
consult with compensation consultants with respect to
determining 2007 compensation for our named executive officers.
All compensation determinations are discretionary and, as noted
above, subject to Anadarkos decision-making authority.
Elements of
compensation
The primary elements of Anadarkos compensation program are
a combination of annual cash and long-term equity-based
compensation. For 2007, the principal elements of compensation
for the named executive officers are expected to be the
following:
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base salary;
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bonuses;
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equity compensation, which may include both equity-based
compensation under Anadarkos 1999 Stock Incentive Plan as
well as Western Gas Holdings, LLCs long-term incentive
plan; and
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Anadarkos other benefits, including welfare and retirement
benefits, perquisites, severance benefits and change of control
benefits, plus other benefits on the same basis as other
eligible Anadarko employees.
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Base Salary. Anadarkos management is
expected to establish base salaries for our named executive
officers based on the historical salaries for services rendered
to Anadarko, competitive market data and responsibilities of our
named executive officers that may or may not be related to our
business. As discussed above, a portion of the base salaries of
our named executive officers will be allocated to us based on
Anadarkos methodology used for allocating general and
administrative expenses, subject to the limitations in the
omnibus agreement.
Bonuses. Anadarkos management also may
award annual cash awards to our named executive officers in 2007
under Anadarkos Annual Incentive Plan. Anadarko is
expected to use cash incentive awards for achieving financial
and operational goals for Anadarko, including us, and for
achieving individual performance objectives. The plan puts a
significant portion of an executives compensation at risk
by linking potential annual compensation to Anadarkos
achievement of specific performance metrics during the year
related to operational, financial and safety measures internal
to Anadarko. Executives may receive up to 200% of their
individual bonus target if Anadarko significantly exceeds the
specified performance metrics and, conversely, no bonus is paid
if Anadarko does not achieve a minimum threshold level of
performance. Actual bonus awards are determined by the
compensation and benefits committee of Anadarkos board of
directors, or Anadarkos compensation committee, according
to Anadarkos and each named executive officers level
of achievement against the established performance metrics. The
bonus targets are intended to provide a designated level of
compensation opportunity when the executive officers achieve
their specified performance metrics as approved by
Anadarkos compensation committee.
The portion of any annual cash awards allocable to us will be
based on Anadarkos methodology used for allocating general
and administrative expenses, subject to the limitations in the
omnibus agreement. Anadarkos general policy is to pay
these awards during the first quarter of each calendar year.
Long-Term Incentive Awards Under Anadarkos 1999 Stock
Incentive Plan. Anadarko periodically makes
equity-based awards under its 1999 Stock Incentive Plan to align
the interests of its executive officers with those of Anadarko
shareholders by emphasizing the long-term growth in
Anadarkos value. For 2006, the annual equity awards
consisted of a combination of stock options, time-based
restricted stock and performance unit awards. The annual
long-term incentive target value of the awards has been
allocated so that approximately one-third of the value is
provided by each of the three incentive vehicles. This award
structure is intended to provide a combination of equity-based
vehicles that is
120
Management
performance-based in absolute and relative terms, while also
encouraging retention. In addition, the use of performance unit
awards and restricted shares enables Anadarko to better manage
its stock dilution.
Our Long-Term Incentive Plan. Our general
partner intends to adopt a long-term incentive plan for the
employees, consultants and directors of our general partner and
its affiliates, including Anadarko, who perform services for us.
The long-term incentive plan provides for the grant of unit
awards, restricted units, phantom units, unit options, unit
appreciation rights, distribution equivalent rights and
substitute awards. For a more detailed description of this plan,
please read Long-term incentive plan.
The equity-based awards to both the named executive officers and
the directors of our general partner are intended to align their
long-term interests with those of our unitholders. As discussed
above, a portion of the equity-based awards to be granted to the
named executive officers will be allocated to us upon the
completion of this offering, and a portion of any future awards
under our long-term incentive plan will be allocable to us in
accordance with the allocation of general and administrative
expenses pursuant to the omnibus agreement.
Other Benefits. In addition to the
compensation discussed above, Anadarko also provides other
benefits to certain of our executive officers who are also
executive officers of Anadarko, including:
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retirement benefits to match competitive practices in
Anadarkos industry, including the Anadarko Employee
Savings Plan, Anadarkos Savings Restoration Plan, and the
Anadarko Retirement Plan and Retirement Restoration Plan;
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Ø
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severance benefits under the Anadarko Severance Plan or the
Anadarko Officer Severance Plan, as applicable;
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certain change of control benefits under key employee change of
control contracts or key manager change of control contracts;
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director and officer indemnification agreements;
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a limited number of perquisites, including financial counseling,
tax preparation and estate planning, an executive physical
program, management disability insurance, and personal excess
liability insurance; and
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medical, dental, vision, flexible spending accounts, life
insurance and disability coverage, which are also provided to
all other eligible
U.S.-based
Anadarko employees.
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For a more detailed summary of Anadarkos executive
compensation program and the benefits provided thereunder,
please read Compensation Discussion and Analysis in
Anadarkos proxy statement for its annual meeting of
stockholders, which was filed with the SEC on March 27,
2007.
Role of executive
officers in executive compensation
Anadarkos management determines the compensation (other
than the long-term incentive plan benefits described above)
payable to each of our named executive officers. The board of
directors of our general partner determines compensation for the
independent, non-management directors of our general
partners board of directors.
Compensation
mix
We believe that the mix of base salary, cash awards, awards
under our long-term incentive plan and other compensation fit
Anadarkos and our overall compensation objectives. We
believe this mix of compensation provides competitive
compensation opportunities to align and drive employee
performance in support of Anadarkos business strategies,
as well as our own, and to attract, motivate and retain high
quality talent with the skills and competencies required by
Anadarko and us.
121
Management
General
Our general partner intends to adopt a Long-Term Incentive Plan,
which we refer to as the Plan, for employees, consultants and
directors of our general partner and its affiliates, including
Anadarko, who perform services for us. The summary of the Plan
contained herein does not purport to be complete and is
qualified in its entirety by reference to the Plan. The Plan
provides for the grant of unit awards, restricted units, phantom
units, unit options, unit appreciation rights, distribution
equivalent rights and substitute awards. Subject to adjustment
for certain events, an aggregate
of common
units may be delivered pursuant to awards under the Plan. Units
that are cancelled, forfeited or are withheld to satisfy our
general partners tax withholding obligations or payment of
an awards exercise price are available for delivery
pursuant to other awards. The Plan will be administered by our
general partners board of directors. The Plan has been
designed to furnish additional compensation to employees,
consultants and directors and to align their economic interests
with those of our common unitholders.
Unit
awards
Our general partners board of directors may grant unit
awards to eligible individuals under the Plan. A unit award is
an award of common units that are fully vested upon grant and
are not subject to forfeiture.
Restricted units
and phantom units
A restricted unit is a common unit that is subject to
forfeiture. Upon vesting, the forfeiture restrictions lapse and
the recipient holds a common unit that is not subject to
forfeiture. A phantom unit is a notional unit that entitles the
grantee to receive a common unit upon the vesting of the phantom
unit or, in the discretion of our general partners board
of directors, cash equal to the fair market value of a common
unit. Our general partners board of directors may make
grants of restricted and phantom units under the Plan that
contain such terms, consistent with the Plan, as the board may
determine are appropriate, including the period over which
restricted phantom units will vest. The board may, in its
discretion, base vesting on the grantees completion of a
period of service or upon the achievement of specified financial
objectives or other criteria. In addition, the restricted and
phantom units will vest automatically upon a change of control
(as defined in the Plan) of us or our general partner, subject
to any contrary provisions in the award agreement.
If a grantees employment, consulting or membership on the
board of directors terminates for any reason, the grantees
restricted and phantom units will be automatically forfeited
unless, and to the extent that the award agreement or the board
provides otherwise.
Distributions made by us with respect to awards of restricted
units may, in the boards discretion, be subject to the
same vesting requirements as the restricted units. The board, in
its discretion, may also grant tandem distribution equivalent
rights with respect to phantom units.
We intend for the restricted and phantom units granted under the
Plan to serve as a means of incentive compensation for
performance and not primarily as an opportunity to participate
in the equity appreciation of the common units. Therefore,
participants will not pay any consideration for the common units
they receive with respect to these types of awards, and neither
we nor our general partner will receive remuneration for the
units delivered with respect to these awards.
Unit options and
unit appreciation rights
The Plan also permits the grant of options covering common units
and unit appreciation rights. Unit options represent the right
to purchase a number of common units at a specified exercise
price. Unit appreciation rights represent the right to receive
the appreciation in the value of a number of common
122
Management
units over a specified exercise price, either in cash or in
common units as determined by the board. Unit options and unit
appreciation rights may be granted to such eligible individuals
and with such terms as the board may determine, consistent with
the Plan; however, a unit option or unit appreciation right must
have an exercise price equal to the fair market value of a
common unit on the date of grant.
Distribution
equivalent rights
Distribution equivalent rights are rights to receive all or a
portion of the distributions otherwise payable on units during a
specified time. Distribution equivalent rights may be granted
alone or in combination with another award.
Substitute
awards
The board, in its discretion, may grant substitute or
replacement awards to eligible individuals who, in connection
with an acquisition made by us, our general partner or an
affiliate, have forfeited an equity-based award in their former
employer. A substitute award that is an option may have an
exercise price less than the value of a common unit on the date
of grant of the award.
Source of common
units; cost
Common units to be delivered with respect to awards may be
common units acquired by our general partner in the open market,
common units already owned by our general partner, common units
acquired by our general partner directly from us or any other
person or any combination of the foregoing. Our general partner
will be entitled to reimbursement by us for the cost incurred in
acquiring such common units. With respect to unit options, our
general partner will be entitled to reimbursement from us for
the difference between the cost it incurs in acquiring these
common units and the proceeds it receives from an optionee at
the time of exercise. Thus, we will bear the cost of the unit
options. If we issue new common units with respect to these
awards, the total number of common units outstanding will
increase, and our general partner will remit the proceeds it
receives from a participant, if any, upon exercise of an award
to us. With respect to any awards settled in cash, our general
partner will be entitled to reimbursement by us for the amount
of the cash settlement.
Amendment or
termination of long-term incentive plan
Our general partners board of directors, in its
discretion, may terminate the Plan at any time with respect to
the common units for which a grant has not previously been made.
The Plan will automatically terminate on the earlier of the
10th anniversary of the date it was initially approved by
our unitholders or when common units are no longer available for
delivery pursuant to awards under the Plan. Our general
partners board of directors will also have the right to
alter or amend the Plan or any part of it from time to time or
to amend any outstanding award made under the Plan; provided,
however, that no change in any outstanding award may be made
that would materially impair the rights of the participant
without the consent of the affected participant.
123
Security
ownership of certain beneficial owners and management
The following table sets forth the beneficial ownership of our
units that, upon the consummation of this offering and the
related transactions and assuming that underwriters do not
exercise their option to purchase up to 2,812,500 additional
common units, will be owned by:
|
|
Ø
|
each person or group of persons known by us to be a beneficial
owner of 5% or more of the then outstanding units;
|
|
Ø
|
each member of the board of directors of our general partner;
|
|
Ø
|
each named executive officer of our general partner; and
|
|
Ø
|
all directors and officers of our general partner as a group.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of
|
|
Percentage of
|
|
|
|
|
Percentage of
|
|
|
|
subordinated
|
|
total common
|
|
|
|
|
common units
|
|
Subordinated
|
|
units
|
|
and
subordinated
|
|
|
Common units
|
|
to be
|
|
units to be
|
|
to be
|
|
units to be
|
Name and address
of
|
|
to be
|
|
beneficially
|
|
beneficially
|
|
beneficially
|
|
beneficially
|
beneficial
owner(1)
|
|
beneficially
owned
|
|
owned
|
|
owned
|
|
owned
|
|
owned
|
|
|
Anadarko Petroleum
Corporation(2)
|
|
|
3,823,925
|
|
|
16.9%
|
|
|
22,573,925
|
|
|
100.0%
|
|
|
58.5%
|
WGR Holdings,
LLC(2)
|
|
|
3,823,925
|
|
|
16.9%
|
|
|
22,573,925
|
|
|
100.0%
|
|
|
58.5%
|
Robert G. Gwin
|
|
|
|
|
|
%
|
|
|
|
|
|
%
|
|
|
%
|
Danny J. Rea
|
|
|
|
|
|
%
|
|
|
|
|
|
%
|
|
|
%
|
Michael C. Pearl
|
|
|
|
|
|
%
|
|
|
|
|
|
%
|
|
|
%
|
Jeremy M. Smith
|
|
|
|
|
|
%
|
|
|
|
|
|
%
|
|
|
%
|
Lora W. Mays
|
|
|
|
|
|
%
|
|
|
|
|
|
%
|
|
|
%
|
R.A. Walker
|
|
|
|
|
|
%
|
|
|
|
|
|
%
|
|
|
%
|
Karl F. Kurz
|
|
|
|
|
|
%
|
|
|
|
|
|
%
|
|
|
%
|
Robert K. Reeves
|
|
|
|
|
|
%
|
|
|
|
|
|
%
|
|
|
%
|
All directors and executive officers as a group (8 persons)
|
|
|
|
|
|
%
|
|
|
|
|
|
%
|
|
|
%
|
|
|
|
* |
|
Less than 1% |
|
(1) |
|
Unless otherwise indicated, the
address for all beneficial owners in this table is 1201 Lake
Robbins Drive, The Woodlands, Texas 77380. |
|
(2) |
|
Anadarko Petroleum Corporation
is the ultimate parent company of WGR Holdings, LLC and may,
therefore, be deemed to beneficially own the units held by WGR
Holdings, LLC. Following this offering, WGR Holdings, LLC will
own a 100% interest in our general partner and a 57.3% limited
interest in us. |
The following table set forth, as
of ,
the number of shares of common stock of Anadarko owned by each
of the executive officers and directors of our general partner
and all directors and executive officers of our general partner
as a group.
124
Security
ownership of certain beneficial owners and management
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
|
|
Percentage of
|
|
|
Shares of
|
|
underlying
|
|
Total shares
of
|
|
total shares
of
|
|
|
common stock
|
|
options
|
|
common stock
|
|
common stock
|
Name and address
of
|
|
owned directly
|
|
exercisable
|
|
beneficially
|
|
beneficially
|
beneficial
owner(1)
|
|
or
indirectly
|
|
within
60 days
|
|
owned
|
|
owned
|
|
|
Robert G. Gwin
|
|
|
|
|
|
|
|
|
|
|
|
%
|
Danny J. Rea
|
|
|
|
|
|
|
|
|
|
|
|
%
|
Michael C. Pearl
|
|
|
|
|
|
|
|
|
|
|
|
%
|
Jeremy M. Smith
|
|
|
|
|
|
|
|
|
|
|
|
%
|
Lora W. Mays
|
|
|
|
|
|
|
|
|
|
|
|
%
|
R.A. Walker
|
|
|
|
|
|
|
|
|
|
|
|
%
|
Karl F. Kurz
|
|
|
|
|
|
|
|
|
|
|
|
%
|
Robert K. Reeves
|
|
|
|
|
|
|
|
|
|
|
|
%
|
All directors and executive officers as a group (8 persons)
|
|
|
|
|
|
|
|
|
|
|
|
%
|
|
|
|
* |
|
Less than 1% |
|
(1) |
|
Unless otherwise indicated, the
address for all beneficial owners in this table is 1201 Lake
Robbins Drive, The Woodlands, Texas 77380. |
125
Certain
relationships and related party transactions
After this offering, Anadarko will indirectly own 3,823,925
common units and 22,573,925 subordinated units, representing an
aggregate 57.3% limited partner interest in us. In addition, our
general partner will own 921,385 general partner units
representing a 2.0% general partner interest in us and all of
our incentive distribution rights.
DISTRIBUTIONS
AND PAYMENTS TO OUR GENERAL PARTNER AND ITS AFFILIATES
The following table summarizes the distributions and payments to
be made by us to our general partner and its affiliates in
connection with our formation, ongoing operation and any
liquidation of Western Gas Partners, LP, assuming that the
underwriters do not exercise their option to purchase additional
common units. These distributions and payments were determined
by and among affiliated entities and, consequently, are not the
result of arms-length negotiations.
Formation
stage
|
|
|
The consideration received by Anadarko and its subsidiaries for
the contribution of the assets and liabilities to us |
|
Ø 3,823,925
common units;
|
|
|
|
Ø 22,573,925
subordinated units;
|
|
|
|
|
|
Ø 921,385
general partner units, and
|
|
|
|
|
|
Ø our
incentive distribution rights.
|
Operational
stage
|
|
|
Distributions of available cash to our general partner and its
affiliates |
|
We will generally make cash distributions 98.0% to our
unitholders pro rata, including Anadarko as the indirect holder
of an aggregate 3,823,925 common units and 22,573,925
subordinated units, and 2.0% to our general partner, assuming it
makes any capital contributions necessary to maintain its 2.0%
interest in us. In addition, if distributions exceed the minimum
quarterly distribution and other higher target distribution
levels, our general partner will be entitled to increasing
percentages of the distributions, up to 50.0% of the
distributions above the highest target distribution level. |
|
|
|
|
|
Assuming we have sufficient available cash to pay the full
minimum quarterly distribution on all of our outstanding units
for four quarters, our general partner and its affiliates would
receive an annual distribution of approximately
$1.1 million on their general partner units and
$31.7 million on their common and subordinated units. |
|
|
|
Payments to our general partner and its affiliates |
|
Our general partner and its affiliates will be entitled to
reimbursement for all expenses incurred on our behalf, including
salaries and employee benefit costs for employees who provide
services to us, and all other necessary or |
126
Certain
relationships and related party transactions
|
|
|
|
|
appropriate expenses allocable to us or reasonably incurred by
our general partner and its affiliates in connection with
operating our business. The partnership agreement provides that
our general partner will determine in good faith the amount of
such expenses that are allocable to us. |
|
Withdrawal or removal of our general partner |
|
If our general partner withdraws or is removed, its general
partner interest and its incentive distribution rights will
either be sold to the new general partner for cash or converted
into common units, in each case for an amount equal to the fair
market value of those interests. Please read The
partnership agreementWithdrawal or removal of the general
partner. |
Liquidation
stage
|
|
|
Liquidation |
|
Upon our liquidation, our partners, including our general
partner, will be entitled to receive liquidating distributions
according to their respective capital account balances. |
AGREEMENTS
GOVERNING THE TRANSACTIONS
We and other parties have or will enter into the various
documents and agreements that will effect the offering
transactions, including the vesting of assets in, and the
assumption of liabilities by, us and our subsidiaries, and the
application of the proceeds of this offering. These agreements
will not be the result of arms-length negotiations, and as
such, they, or any of the transactions that they provide for,
may not be effected on terms at least as favorable to the
parties to these agreements as the parties could have been
obtained from unaffiliated third parties. All of the transaction
expenses incurred in connection with these transactions,
including the expenses associated with transferring assets into
our subsidiaries, will be paid from the proceeds of this
offering.
Upon the closing of this offering, we will enter into an omnibus
agreement with Anadarko and our general partner that will
address the following matters:
|
|
Ø
|
Anadarkos obligation to indemnify us for certain
liabilities and our obligation to indemnify Anadarko for certain
liabilities;
|
|
Ø
|
our obligation to reimburse Anadarko for all expenses incurred
or payments made on our behalf in conjunction with
Anadarkos provision of general and administrative services
to us, including salary and benefits of Anadarko personnel, our
public company expenses, general and administrative expenses and
salaries and benefits of our executive management who are
employees of Anadarko; and
|
|
Ø
|
our obligation to reimburse Anadarko for all insurance coverage
expenses it incurs or payments it makes with respect to our
assets.
|
127
Certain
relationships and related party transactions
The table below reflects the categories of expenses for which we
are obligated to reimburse Anadarko pursuant to the omnibus
agreement, and, by category, sets forth an estimate of the
amount that we will pay to Anadarko for the twelve months ending
December 31, 2008.
|
|
|
|
|
|
Estimates for
the
|
|
|
twelve months
|
|
|
ending
|
|
|
December 31,
|
|
|
2008
|
|
|
|
(in
millions)
|
|
Reimbursement of general and administrative expenses
|
|
$
|
6.0
|
Reimbursement of public company expenses
|
|
$
|
2.5
|
Our general partner and its affiliates will also receive
payments from us pursuant to the contractual arrangements
described below under the caption Contracts with
affiliates.
Any or all of the provisions of the omnibus agreement will be
terminable by Anadarko at its option if our general partner is
removed without cause and units held by our general partner and
its affiliates are not voted in favor of that removal. The
omnibus agreement will also generally terminate in the event of
a change of control of us or our general partner.
Services and
secondment agreement
Concurrently with the closing of this offering, Anadarko and our
general partner will enter into a services and secondment
agreement pursuant to which we anticipate that specified
employees of Anadarko will be seconded to our general partner to
provide operating, routine maintenance and other services with
respect to our business under the direction, supervision and
control of our general partner. Our general partner will
reimburse Anadarko pursuant to the omnibus agreement for the
services provided by the seconded employees pursuant to the
services and secondment agreement. The initial term of the
services and secondment agreement will be 10 years. The
term will extend for additional
12-month
periods unless either party provides 180 days written
notice otherwise prior to the expiration of the applicable
12-month
period. Either party may terminate the agreement at any time
upon 180 days written notice.
Tax sharing
agreement
Prior to the closing of this offering, we intend to enter into a
tax sharing agreement pursuant to which we will reimburse
Anadarko for our share of state and local income and other taxes
borne by Anadarko as a result of our results being included in a
combined or consolidated tax return filed by Anadarko. Anadarko
may use its tax attributes to cause its combined or consolidated
group, of which we may be a member for this purpose, to owe no
tax. However, we would nevertheless reimburse Anadarko for the
tax we would have owed had the attributes not been available or
used for our benefit, even though Anadarko had no cash expense
for that period.
Administrative
services and reimbursement
Under the omnibus agreement, we will reimburse Anadarko for the
payment of certain operating expenses and for the provision of
various general and administrative services for our benefit with
respect to the assets contributed to us at the closing of this
offering. The omnibus agreement will further provide that we
will reimburse Anadarko for all expenses it incurs or payments
it makes with respect to our assets.
Pursuant to these arrangements, Anadarko will perform
centralized corporate functions for us, such as legal,
accounting, treasury, cash management, insurance administration
and claims processing, risk
128
Certain
relationships and related party transactions
management, health, safety and environmental, information
technology, human resources, credit, payroll, internal audit,
tax, marketing and midstream. We will reimburse Anadarko for all
of the expenses it incurs or payments it makes on our behalf,
including salary and benefits of Anadarko personnel, our public
company expenses, our general and administrative expenses and
salaries and benefits of our executive management who are also
employees of Anadarko.
Under the omnibus agreement, our reimbursement to Anadarko for
certain general and administrative expenses it allocates to us
will be capped at $6.0 million annually through
December 31, 2009, subject to adjustment to reflect changes
in the Consumer Price Index and, with the concurrence of the
special committee of our general partners board of
directors, to reflect expansions of our operations through the
acquisition or construction of new assets or businesses.
Thereafter, our general partner will determine the general and
administrative expenses to be allocated to us in accordance with
our partnership agreement. The cap contained in the omnibus
agreement does not apply to incremental general and
administrative expenses that we expect to incur or to be
allocated to us as a result of becoming a publicly traded
partnership. We currently expect those expenses to be
approximately $2.5 million per year.
Indemnification
Under the omnibus agreement, Anadarko will indemnify us for a
period of three years after the closing of this offering
against certain potential environmental claims, losses and
expenses associated with the operation of our assets, which
occur before the closing date of this offering or relate to any
investigation, claim or proceeding under environmental laws
relating to such assets and pending as of the closing of this
offering. Anadarko will have no indemnification obligation with
respect to environmental claims made as a result of additions to
or modifications of environmental laws that are promulgated
after the closing date of this offering.
Additionally, Anadarko will indemnify us for losses attributable
to the following:
(1) our failure, as of the closing date of this
offering, to have valid easements, fee title or leasehold
interests in and to the lands on which our assets are located,
to the extent such failure renders us unable to use or operate
our assets in substantially the same manner in which they were
used and operated immediately prior to the closing of this
offering;
(2) our failure, as of the closing date of this
offering, to have any consent or governmental permit necessary
to allow (i) the transfer of assets from Anadarko to us at
the closing of this offering or (ii) us to use or operate
our assets in substantially the same manner in which they were
used and operated immediately prior to the closing of this
offering;
(3) all income tax liabilities
(i) attributable to the pre-closing operations of our
assets,
(ii) arising from or relating to the formation
transactions, or
(iii) arising under Treasury
Regulation Section 1.1502-6
and any similar provision from state, local or foreign
applicable law, by contract, as successor or transferee or
otherwise, provided that such income tax is attributable to
having been a member of any consolidated, combined or unitary
group prior to the closing of this offering;
(4) all liabilities, other than covered environmental
laws and other than liabilities incurred in the ordinary course
of business conducted in compliance with the applicable laws,
that arise prior to the closing date; and
(5) all liabilities attributable to any assets or
entities retained by Anadarko.
129
Certain
relationships and related party transactions
Anadarkos maximum liability for indemnification is
unlimited in amount. Anadarko will not have any obligation to
indemnify us, unless a claim for indemnification specifying in
reasonable detail the basis for such claim is furnished to us in
good faith (a) with respect to a claim under
clause (1) or (2) above, prior to the third
anniversary date of the closing of this offering or
(b) with respect to a claim under clause (3) above,
prior to the first day after expiration of the statute of
limitations period applicable to such claim. In no event shall
Anadarko be obligated to indemnify us for any losses or income
taxes to the extent we have made reservations for any such
losses or income taxes in our combined financial statements as
of December 31, 2006, or to the extent we recover any such
losses or income taxes under available insurance coverage or
from contractual rights against any third party.
Under the omnibus agreement, we have agreed to indemnify
Anadarko for all claims, losses and expenses attributable to the
post-closing operations of the gathering, compression, treating
and transportation assets contributed to us at the closing of
this offering, to the extent not that such losses are not
subject to Anadarkos indemnification obligations.
CONTRACTS
WITH AFFILIATES
Gas Gathering
Agreements
Our gathering agreements with Anadarko accounted for
approximately 94% of our gathering throughput for the nine
months ended September 30, 2007. Eightyeight percent
of this throughput came from volumes of natural gas owned by
Anadarko and its partners and the remainder was comprised of
volumes purchased from third parties by Anadarko Energy Services
Company, Anadarkos wholly owned marketing affiliate.
Anadarko Petroleum Corporation. We have entered into new
gas gathering agreements with Anadarko Petroleum Corporation for
each of our gathering systems. These agreements provide us with
dedication of all of the natural gas owned or controlled by
Anadarko and produced from (i) wells that are currently
connected to our gathering systems, and (ii) additional
wells that are drilled within one mile of connected wells or our
gathering systems, as the systems currently exist and as they
are expanded to connect additional wells in the future. As a
result, this dedication will continue to expand as additional
wells are connected to our gathering systems. Each gas gathering
agreement is fee-based, and we provide gathering, compression,
treating, dehydration and well connections within the dedicated
area for the specified gathering fee per MMbtu or Mcf. The
gathering fee varies on each system and is subject to an
automatic annual escalator and may also be adjusted if Anadarko
requests improvements to the level of service we currently
provide under the agreement. Each of the gas gathering
agreements has a
10-year
primary term. After the expiration of the primary term, either
party may annually request a re-determination of the gathering
fee. If a re-determination of the fee takes place, the same
methodology which was utilized to calculate the original
gathering fee will be utilized to calculate the new fee and the
new fee will take into account production forecasts, capital
expenditures and operating expenses. The agreements allow us to
retain and sell the condensate that is recovered from gas during
gathering. The gas gathering agreements are assignable by
Anadarko to an affiliate without our consent and Anadarko will
be permitted to sell the production which is dedicated to our
systems to an affiliate or third-party purchaser, provided that
the purchaser of the dedicated gas will be subject to the terms
and conditions of our agreements and Anadarko will remain liable
under the agreements in the event the purchaser defaults. The
fees we will charge Anadarko under our new gas gathering
agreements are higher than the fees reflected in our historical
financial results.
Anadarko Energy Services Company
(AESC). AESC is Anadarkos
marketing affiliate that purchases gas and is a shipper on our
gathering systems. Approximately 12% of the throughput we
gathered for the nine months ended September 30, 2007 was
comprised of third-party volumes purchased by AESC, and gathered
under gathering agreements we have in place with AESC. We
provide our services to AESC under fixed-fee arrangements
whereby gathering fees and contract terms are based on a variety
of
130
Certain
relationships and related party transactions
factors, including gas quality and level of service provided.
The term of our agreements with AESC can vary from
month-to-month to 20 years.
Transportation
Agreements
Western Gas Resources, Inc. and MGTC, Inc., affiliates of
Anadarko, have contracted for 170,000 MMBtu/d of firm capacity
on our MIGC system in agreements ranging in term from just over
one year to 11 years. Anadarko has released 40,000 MMBtu/d of
firm capacity under one agreement to a third party, and this
released capacity will revert back to Anadarko in February 2009
for the duration of the term, which expires in 2018. For the
nine months ended September 30, 2007, our transportation
agreements with Anadarko accounted for approximately 70% of the
throughput on the MIGC system.
131
Conflicts
of interest and fiduciary duties
Conflicts of interest exist and may arise in the future as a
result of the relationships between our general partner and its
affiliates, including Anadarko, on the one hand, and our
partnership and our limited partners, on the other hand. The
directors and officers of our general partner have fiduciary
duties to manage our general partner in a manner beneficial to
its owners. At the same time, our general partner has a
fiduciary duty to manage our partnership in a manner beneficial
to us and our unitholders.
Whenever a conflict arises between our general partner or its
affiliates, on the one hand, and us and our limited partners, on
the other hand, our general partner will resolve that conflict.
Our partnership agreement contains provisions that modify and
limit our general partners fiduciary duties to our
unitholders. Our partnership agreement also restricts the
remedies available to our unitholders for actions taken by our
general partner that, without those limitations, might
constitute breaches of its fiduciary duty.
Our general partner will not be in breach of its obligations
under the partnership agreement or its fiduciary duties to us or
our unitholders if the resolution of the conflict is:
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approved by the special committee of our general partner,
although our general partner is not obligated to seek such
approval;
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approved by the vote of a majority of the outstanding common
units, excluding any common units owned by our general partner
or any of its affiliates;
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on terms no less favorable to us than those generally being
provided to or available from unrelated third parties; or
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fair and reasonable to us, taking into account the totality of
the relationships among the parties involved, including other
transactions that may be particularly favorable or advantageous
to us.
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Our general partner may, but is not required to, seek the
approval of such resolution from the special committee of its
board of directors. In connection with a situation involving a
conflict of interest, any determination by our general partner
involving the resolution of the conflict of interest must be
made in good faith, provided that, if our general partner does
not seek approval from the special committee and its board of
directors determines that the resolution or course of action
taken with respect to the conflict of interest satisfies either
of the standards set forth in the third and fourth bullet points
above, then it will be presumed that, in making its decision,
the board of directors acted in good faith, and in any
proceeding brought by or on behalf of any limited partner or the
partnership, the person bringing or prosecuting such proceeding
will have the burden of overcoming such presumption. Unless the
resolution of a conflict is specifically provided for in our
partnership agreement, our general partner or the special
committee may consider any factors that it determines in good
faith to be appropriate when resolving a conflict. When our
partnership agreement provides that someone act in good faith,
it requires that person to reasonably believe he is acting in
the best interests of the partnership.
Conflicts of interest could arise in the situations described
below, among others.
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Conflicts of
interest and fiduciary duties
Neither our
partnership agreement nor any other agreement requires Anadarko
to pursue a business strategy that favors us or utilizes our
assets or dictates what markets to pursue or grow.
Anadarkos directors have a fiduciary duty to make these
decisions in the best interests of the owners of Anadarko, which
may be contrary to our interests.
Because certain of the directors of our general partner are also
directors
and/or
officers of Anadarko, such directors have fiduciary duties to
Anadarko that may cause them to pursue business strategies that
disproportionately benefit Anadarko or which otherwise are not
in our best interests.
Anadarko is not
limited in its ability to compete with us, which could cause
conflicts of interest and limit our ability to acquire
additional assets or businesses which in turn could adversely
affect our results of operations and cash available for
distribution to our unitholders.
Neither our partnership agreement nor the omnibus agreement
between us and Anadarko will prohibit Anadarko from owning
assets or engaging in businesses that compete directly or
indirectly with us. In addition, Anadarko 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. Anadarko 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
these entities with respect to commercial activities as well as
for acquisitions candidates. As a result, competition from these
entities could adversely impact our results of operations and
cash available for distribution.
Our general
partner and its affiliates are allowed to take into account the
interests of parties other than us in resolving conflicts of
interest.
Our partnership agreement contains provisions that reduce the
fiduciary standards to which our general partner would otherwise
be held by state fiduciary duty law. For example, our
partnership agreement permits our general partner to make a
number of decisions in its individual capacity, as opposed to in
its capacity as our general partner. This entitles our general
partner to consider only the interests and factors that it
desires, and it has no duty or obligation to give any
consideration to any interest of, or factors affecting, us, our
affiliates or our limited partners. Examples include our general
partners limited call right, its voting rights with
respect to the units it owns, its registration rights and its
determination whether or not to consent to any merger or
consolidation of the partnership.
The officers of
our general partner will also devote significant time to the
business of Anadarko and will be compensated by Anadarko
accordingly.
All of our executive management personnel will be employees of
Anadarko and will devote a portion of their time to our business
and affairs. We will also utilize a significant number of
employees of Anadarko to operate our business and provide us
with general and administrative services for which we will
reimburse Anadarko for allocated expenses of operational
personnel who perform services for our benefit and we will
reimburse Anadarko for allocated general and administrative
expenses. Our general partner and Anadarko will also conduct
businesses and activities of their own in which we will have no
economic interest. If these separate activities are
significantly greater than our activities, there could be
material competition for the time and effort of the officers and
employees who provide services to Anadarko.
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Conflicts of
interest and fiduciary duties
Our partnership
agreement limits the liability of and reduces the fiduciary
duties owed by our general partner, and also restricts the
remedies available to our unitholders for actions that, without
the limitations, might constitute breaches of its fiduciary
duty.
In addition to the provisions described above, our partnership
agreement contains provisions that restrict the remedies
available to our unitholders for actions that might otherwise
constitute breaches of our general partners fiduciary
duty. For example, our partnership agreement:
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provides that our general partner shall not have any liability
to us or our unitholders for decisions made in its capacity as a
general partner so long as such decisions are made in good
faith, meaning it believed that the decision was in the best
interest of our partnership;
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provides generally that affiliated transactions and resolutions
of conflicts of interest not approved by the special committee
of the board of directors of our general partner and not
involving a vote of the common unitholders must either be
(1) on terms no less favorable to us than those generally
provided to or available from unrelated third parties or
(2) fair and reasonable to us, as determined by
our general partner in good faith, provided that, in determining
whether a transaction or resolution is fair and
reasonable, our general partner may consider the totality
of the relationships between the parties involved, including
other transactions that may be particularly advantageous or
beneficial to us; and
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provides that our general partner and its officers and directors
will not be liable for monetary damages to us, or our limited
partners or their assignees resulting from any act or omission
unless there has been a final and non-appealable judgment
entered by a court of competent jurisdiction determining that
our general partner or its officers or directors, as the case
may be, acted in bad faith or engaged in fraud or willful
misconduct.
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Except in limited
circumstances, our general partner has the power and authority
to conduct our business without unitholder approval.
Under our partnership agreement, our general partner has full
power and authority to do all things, other than those items
that require unitholder approval or with respect to which our
general partner has sought special committee approval, on such
terms as it determines to be necessary or appropriate to conduct
our business including, but not limited to, the following:
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the making of any expenditures, the lending or borrowing of
money, the assumption or guarantee of or other contracting for,
indebtedness and other liabilities, the issuance of evidences of
indebtedness, including indebtedness that is convertible into
our securities, and the incurring of any other obligations;
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the purchase, sale or other acquisition or disposition of our
securities, or the issuance of additional options, rights,
warrants and appreciation rights relating to our securities;
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the mortgage, pledge, encumbrance, hypothecation or exchange of
any or all of our assets;
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the negotiation, execution and performance of any contracts,
conveyances or other instruments;
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the distribution of our cash;
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the selection and dismissal of employees and agents, outside
attorneys, accountants, consultants and contractors and the
determination of their compensation and other terms of
employment or hiring;
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the maintenance of insurance for our benefit and the benefit of
our partners;
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the formation of, or acquisition of an interest in, the
contribution of property to, and the making of loans to, any
limited or general partnership, joint venture, corporation,
limited liability company or other entity;
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Conflicts of
interest and fiduciary duties
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the control of any matters affecting our rights and obligations,
including the bringing and defending of actions at law or in
equity, otherwise engaging in the conduct of litigation,
arbitration or mediation and the incurring of legal expense, the
settlement of claims and litigation;
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the indemnification of any person against liabilities and
contingencies to the extent permitted by law;
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the making of tax, regulatory and other filings, or the
rendering of periodic or other reports to governmental or other
agencies having jurisdiction over our business or assets; and
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the entering into of agreements with any of its affiliates to
render services to us or to itself in the discharge of its
duties as our general partner.
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Our partnership agreement provides that our general partner must
act in good faith when making decisions on our
behalf, and our partnership agreement further provides that in
order for a determination to be made in good faith,
our general partner must believe that the determination is in
our best interests. Please read The partnership
agreementVoting rights for information regarding
matters that require unitholder approval.
Our general
partner determines the amount and timing of asset purchases and
sales, capital expenditures, borrowings, issuance of additional
partnership securities and the creation, reduction or increase
of reserves, each of which can affect the amount of cash that is
distributed to our unitholders.
The amount of cash that is available for distribution to our
unitholders is affected by the decisions of our general partner
regarding such matters as:
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the amount and timing of asset purchases and sales;
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cash expenditures;
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borrowings;
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the issuance of additional units; and
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the creation, reduction or increase of reserves in any quarter.
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Our general partner determines the amount and timing of any
capital expenditures and whether a capital expenditure is
classified as a maintenance capital expenditure, which reduces
operating surplus, or an expansion capital expenditure, which
does not reduce operating surplus. This determination can affect
the amount of cash that is distributed to our unitholders and to
our general partner and the ability of the subordinated units to
convert to common units.
In addition, our general partner may use an amount, initially
equal to $27.1 million, which would not otherwise
constitute available cash from operating surplus, in order to
permit the payment of cash distributions on its units and
incentive distribution rights. All of these actions may affect
the amount of cash distributed to our unitholders and our
general partner and may facilitate the conversion of
subordinated units into common units. Please read
Provisions of our partnership agreement relating to cash
distributions.
In addition, borrowings by us and our affiliates do not
constitute a breach of any duty owned by our general partner to
our unitholders, including borrowings that have the purpose or
effect of:
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enabling our general partner or its affiliates to receive
distributions on any subordinated units held by them or the
incentive distribution rights; or
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hastening the expiration of the subordination period.
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For example, in the event we have not generated sufficient cash
from our operations to pay the minimum quarterly distribution on
our common and subordinated units, our partnership agreement
permits us to borrow funds, which would enable us to make this
distribution on all of our outstanding
135
Conflicts of
interest and fiduciary duties
units. Please read Provisions of our partnership agreement
related to cash distributionsSubordination period.
Our partnership agreement provides that we and our subsidiaries
may borrow funds from our general partner and its affiliates.
Our general partner and its affiliates may borrow funds from us,
or our operating company and its operating subsidiaries.
Our general
partner determines which of the costs it incurs on our behalf
are reimbursable by us.
We will reimburse our general partner and its affiliates for the
costs incurred in managing and operating us, including costs
incurred in rendering corporate staff and support services to
us. Our partnership agreement provides that our general partner
will determine in good faith the expenses that are allocable to
us.
Our partnership
agreement does not restrict our general partner from causing us
to pay it or its affiliates for any services rendered to us or
from entering into additional contractual arrangements with any
of these entities on our behalf.
Our partnership agreement allows our general partner to
determine, in good faith, any amounts to pay itself or its
affiliates for any services rendered to us. Our general partner
may also enter into additional contractual arrangements with any
of its affiliates on our behalf. Neither our partnership
agreement nor any of the other agreements, contracts or
arrangements between us, on the one hand, and our general
partner and its affiliates, on the other hand, that will be in
effect as of the closing of this offering, will be the result of
arms-length negotiations. Similarly, agreements, contracts
or arrangements between us and our general partner and its
affiliates that are entered into following the closing of this
offering will not be required to be negotiated on an
arms-length basis, although, in some circumstances, our
general partner may determine that the special committee of our
general partner may make a determination on our behalf with
respect to such arrangements.
Our general partner will determine, in good faith, the terms of
any such transactions entered into after the close of this
offering.
Our general partner and its affiliates will have no obligation
to permit us to use any of its or its affiliates
facilities or assets, except as may be provided in contracts
entered into specifically for such use. There is no obligation
of our general partner or its affiliates to enter into any
contracts of this kind.
Our general
partner intends to limit its liability regarding our
obligations.
Our general partner intends to limit its liability under
contractual arrangements so that counterparties to such
agreements have recourse only against our assets, and not
against our general partner or its assets. The partnership
agreement provides that any action taken by our general partner
to limit its liability is not a breach of our general
partners fiduciary duties, even if we could have obtained
more favorable terms without the limitation on liability.
Our general
partner may exercise its right to call and purchase all of the
common units not owned by it and its affiliates if they own more
than 80% of our common units.
Our general partner may exercise its right to call and purchase
common units, as provided in our partnership agreement, or may
assign this right to one of its affiliates or to us. Our general
partner is not bound by fiduciary duty restrictions in
determining whether to exercise this right. As a result, a
common unitholder may be required to sell his common units at an
undesirable time or price. Please read The partnership
agreementLimited call right.
136
Conflicts of
interest and fiduciary duties
Our general
partner controls the enforcement of its and its affiliates
obligations to us.
Any agreements between us, on the one hand, and our general
partner and its affiliates, on the other, will not grant to the
unitholders, separate and apart from us, the right to enforce
the obligations of our general partner and its affiliates in our
favor.
Our general
partner decides whether to retain separate counsel, accountants
or others to perform services for us.
The attorneys, independent accountants and others who have
performed services for us regarding this offering have been
retained by our general partner. Attorneys, independent
accountants and others who perform services for us are selected
by our general partner or the special committee and may perform
services for our general partner and its affiliates. We may
retain separate counsel for ourselves or the holders of common
units in the event of a conflict of interest between our general
partner and its affiliates, on the one hand, and us or the
holders of common units, on the other, depending on the nature
of the conflict. We do not intend to do so in most cases.
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 special committee of the
board of directors of our general partner or our unitholders.
This election may result in lower distributions to our common
unitholders in certain situations.
Our general partner has the right, at any 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 target distribution levels at higher levels based on
our cash distribution at the time of the exercise of the reset
election. Following a reset election by our general partner, the
minimum quarterly distribution will be reset to an amount equal
to the average cash distribution 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.
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 we are experiencing declines in
our aggregate cash distributions or at a time when our general
partner expects that we will experience declines in our
aggregate cash distributions in the foreseeable future. In such
situations, our general partner may be experiencing, or may
expect 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 specified priorities with respect to our
distributions and which therefore may be more advantageous for
the general partner to own in lieu of the right to receive
incentive distribution payments based on target distribution
levels that are less certain to be achieved in the then current
business environment. 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 read Provisions of our partnership agreement
relating to cash distributionsGeneral partner interest and
incentive distribution rights.
137
Conflicts of
interest and fiduciary duties
Our general partner is accountable to us and our unitholders as
a fiduciary. Fiduciary duties owed to unitholders by our general
partner are prescribed by law and the partnership agreement. The
Delaware Act provides that Delaware limited partnerships may, in
their partnership agreements, modify, restrict or expand the
fiduciary duties otherwise owed by a general partner to limited
partners and the partnership.
Our partnership agreement contains various provisions modifying
and restricting the fiduciary duties that might otherwise be
owed by our general partner. We have adopted these restrictions
to allow our general partner or its affiliates to engage in
transactions with us that would otherwise be prohibited by
state-law fiduciary duty standards and to take into account the
interests of other parties in addition to our interests when
resolving conflicts of interest. We believe this is appropriate
and necessary because our general partners board of
directors will have fiduciary duties to manage our general
partner in a manner that is beneficial to its owners, as well as
to you. Without these modifications, our general partners
ability to make decisions involving conflicts of interest would
be restricted. The modifications to the fiduciary standards
enable our general partner to take into consideration all
parties involved in the proposed action, so long as the
resolution is fair and reasonable to us. These modifications
also enable our general partner to attract and retain
experienced and capable directors. These modifications are
detrimental to our unitholders because they restrict the
remedies available to unitholders for actions that, without
those limitations, might constitute breaches of fiduciary duty,
as described below, and permit our general partner to take into
account the interests of third parties in addition to our
interests when resolving conflicts of interest. The following is
a summary of the material restrictions of the fiduciary duties
owed by our general partner to the limited partners:
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State-law fiduciary duty standards |
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Fiduciary duties are generally considered to include an
obligation to act in good faith and with due care and loyalty.
The duty of care, in the absence of a provision in a partnership
agreement providing otherwise, would generally require a general
partner to act for the partnership in the same manner as a
prudent person would act on his own behalf. The duty of loyalty,
in the absence of a provision in a partnership agreement
providing otherwise, would generally prohibit a general partner
of a Delaware limited partnership from taking any action or
engaging in any transaction where a conflict of interest is
present. |
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The Delaware Act generally provides that a limited partner may
institute legal action on behalf of the partnership to recover
damages from a third party where a general partner has refused
to institute the action or where an effort to cause a general
partner to do so is not likely to succeed. In addition, the
statutory or case law of some jurisdictions may permit a limited
partner to institute legal action on behalf of himself and all
other similarly situated limited partners to recover damages
from a general partner for violations of its fiduciary duties to
the limited partners. |
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Partnership agreement modified standards |
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Our partnership agreement contains provisions that waive or
consent to conduct by our general partner and its affiliates
that might otherwise raise issues about compliance with
fiduciary duties or applicable law. For example, our partnership
agreement provides that when our general partner is acting in |
138
Conflicts of
interest and fiduciary duties
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its capacity as our general partner, as opposed to in its
individual capacity, it must act in good faith and
will not be subject to any other standard under applicable law.
In addition, when our general partner is acting in its
individual capacity, as opposed to in its capacity as our
general partner, it may act without any fiduciary obligation to
us or the unitholders whatsoever. These standards reduce the
obligations to which our general partner would otherwise be held. |
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In addition to the other more specific provisions limiting the
obligations of our general partner, our partnership agreement
further provides that our general partner and its officers and
directors will not be liable for monetary damages to us, our
limited partners or their assignees for errors of judgment or
for any acts or omissions unless there has been a final and
non-appealable judgment by a court of competent jurisdiction
determining that our general partner or its officers and
directors acted in bad faith or engaged in fraud or willful
misconduct. |
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Special provisions regarding affiliated transactions. Our
partnership agreement generally provides that affiliated
transactions and resolutions of conflicts of interest that are
not approved by a vote of common unitholders and that are not
approved by the special committee of the board of directors of
our general partner must be on terms no less favorable to us
than those generally being provided to, or available from,
unrelated third parties; or fair and reasonable to
us, taking into account the totality of the relationships
between the parties involved (including other transactions that
may be particularly favorable or advantageous to us). |
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If our general partner does not seek approval from the special
committee and the board of directors determines that the
resolution or course of action taken with respect to the
conflict of interest satisfies either of the standards set forth
in the bullet points above, then it will be presumed that, in
making its decision, the board of directors, which may include
board members affected by the conflict of interest, acted in
good faith. In any proceeding brought by or on behalf of any
limited partner or the partnership, the person bringing or
prosecuting such proceeding will have the burden of overcoming
such presumption. These standards reduce the obligations to
which our general partner would otherwise be held. |
By purchasing our common units, each common unitholder
automatically agrees to be bound by the provisions in the
partnership agreement, including the provisions discussed above.
This is in accordance with the policy of the Delaware Act
favoring the principle of freedom of contract and the
enforceability of partnership agreements. The failure of a
limited partner or assignee to sign a partnership agreement does
not render the partnership agreement unenforceable against that
person.
We must indemnify our general partner and its officers,
directors, managers and certain other specified persons, to the
fullest extent permitted by law, against liabilities, costs and
expenses incurred by our
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Conflicts of
interest and fiduciary duties
general partner or these other persons. We must provide this
indemnification unless there has been a final and non-appealable
judgment by a court of competent jurisdiction determining that
these persons acted in bad faith or engaged in fraud or willful
misconduct. We must also provide this indemnification for
criminal proceedings unless our general partner or these other
persons acted with knowledge that their conduct was unlawful.
Thus, our general partner could be indemnified for its negligent
acts if it meets the requirements set forth above. To the extent
these provisions purport to include indemnification for
liabilities arising under the Securities Act, in the opinion of
the SEC, such indemnification is contrary to public policy and,
therefore, unenforceable. Please read The partnership
agreementIndemnification.
140
Description
of the common units
The common units and the subordinated units are separate classes
of limited partner interests in us. The holders of units are
entitled to participate in partnership distributions and
exercise the rights or privileges available to limited partners
under our partnership agreement. For a description of the
relative rights and preferences of holders of common and
subordinated units in and to partnership distributions, please
read this section and Our cash distribution policy and
restrictions on distributions. For a description of the
rights and privileges of limited partners under our partnership
agreement, including voting rights, please read The
partnership agreement.
TRANSFER
AGENT AND REGISTRAR
Duties
will serve as the registrar and transfer agent for the common
units. We will pay all fees charged by the transfer agent for
transfers of common units except the following that must be paid
by unitholders:
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surety bond premiums to replace lost or stolen certificates,
taxes and other governmental charges;
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special charges for services requested by a common unitholder;
and
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other similar fees or charges.
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There will be no charge to unitholders for disbursements of our
cash distributions. We will indemnify the transfer agent, its
agents and each of their stockholders, directors, officers and
employees against all claims and losses that may arise out of
acts performed or omitted for its activities in that capacity,
except for any liability due to any gross negligence or
intentional misconduct of the indemnified person or entity.
Resignation or
removal
The transfer agent may resign, by notice to us, or be removed by
us. The resignation or removal of the transfer agent will become
effective upon our appointment of a successor transfer agent and
registrar and its acceptance of the appointment. If no successor
has been appointed and accepted the appointment within
30 days after notice of the resignation or removal, our
general partner may act as the transfer agent and registrar
until a successor is appointed.
By transfer of common units in accordance with our partnership
agreement, each transferee of common units shall be admitted as
a limited partner with respect to the common units transferred
when such transfer and admission are reflected in our books and
records. Each transferee:
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represents that the transferee has the capacity, power and
authority to become bound by our partnership agreement;
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automatically agrees to be bound by the terms and conditions of,
and is deemed to have executed, our partnership agreement; and
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is deemed to have given the consents and approvals contained in
our partnership agreement, such as the approval of all
transactions and agreements that we are entering into in
connection with our formation and this offering.
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141
Description of
the common units
A transferee will become a substituted limited partner of our
partnership for the transferred common units automatically upon
the recording of the transfer on our books and records. Our
general partner will cause any transfers to be recorded on our
books and records no less frequently than quarterly.
We may, at our discretion, treat the nominee holder of a common
unit as the absolute owner. In that case, the beneficial
holders rights are limited solely to those that it has
against the nominee holder as a result of any agreement between
the beneficial owner and the nominee holder.
Common units are securities that are transferable according to
the laws governing the transfer of securities. In addition to
other rights acquired upon transfer, the transferor gives the
transferee the right to become a substituted limited partner in
our partnership for the transferred common units.
Until a common unit has been transferred on our books, we and
the transfer agent may treat the record holder of the unit as
the absolute owner for all purposes, except as otherwise
required by law or stock exchange regulations.
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The
partnership agreement
The following is a summary of the material provisions of our
partnership agreement. The form of our partnership agreement is
included in this prospectus as Appendix A. We will provide
prospective investors with a copy of our partnership agreement
upon request at no charge.
We summarize the following provisions of our partnership
agreement elsewhere in this prospectus:
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with regard to distributions of available cash, please read
Provisions of our partnership agreement relating to cash
distributions;
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with regard to the fiduciary duties of our general partner,
please read Conflicts of interest and fiduciary
duties;
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with regard to the transfer of common units, please read
Description of the common unitsTransfer of common
units; and
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with regard to allocations of taxable income and taxable loss,
please read Material tax consequences.
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ORGANIZATION
AND DURATION
Our partnership was organized in August 2007 and will have a
perpetual existence.
Our purpose, as set forth in our partnership agreement, is
limited to any business activity that is approved by our general
partner and that lawfully may be conducted by a limited
partnership organized under Delaware law; provided, that our
general partner shall not cause us to engage, directly or
indirectly, in any business activity that the general partner
determines would cause us to be treated as an association
taxable as a corporation or otherwise taxable as an entity for
federal income tax purposes.
Although our general partner has the ability to cause us and our
subsidiaries to engage in activities other than the business of
gathering, compressing, treating and transporting natural gas,
our general partner has no current plans to do so and may
decline to do so free of any fiduciary duty or obligation
whatsoever to us or the limited partners, including any duty to
act in good faith or in the best interests of us or the limited
partners. Our general partner is generally authorized to perform
all acts it determines to be necessary or appropriate to carry
out our purposes and to conduct our business.
Each limited partner, and each person who acquires a unit from a
unitholder, by accepting the common unit, automatically grants
to our general partner and, if appointed, a liquidator, a power
of attorney to, among other things, execute and file documents
required for our qualification, continuance or dissolution. The
power of attorney also grants our general partner the authority
to amend, and to make consents and waivers under, our
partnership agreement.
Our partnership agreement specifies the manner in which we will
make cash distributions to holders of our common units and other
partnership securities as well as to our general partner in
respect of its general partner interest and its incentive
distribution rights. For a description of these cash
distribution provisions, please read Provisions of our
partnership agreement relating to cash distributions.
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The partnership
agreement
Unitholders are not obligated to make additional capital
contributions, except as described below under
Limited liability.
If we issue additional units, our general partner has the right,
but not the obligation, to contribute a proportionate amount of
capital to us to maintain its 2.0% general partner interest. Our
general partners 2.0% 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 to maintain its 2.0%
general partner interest. Our general partner will be entitled
to make a capital contribution in order to maintain its 2.0%
general partner interest in the form of the contribution to us
of common units based on the current market value of the
contributed common units.
The following is a summary of the unitholder vote required for
approval of the matters specified below. General partner units
are not deemed outstanding units for purposes of voting rights
and such units represent a non-voting general partner interest.
Matters that require the approval of a unit majority
require:
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during the subordination period, the approval of a majority of
the common units, excluding those common units held by our
general partner and its affiliates, and a majority of the
subordinated units, voting as separate classes; and
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after the subordination period, the approval of a majority of
the common units and Class B units, if any, voting as a single
class.
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In voting their common and subordinated units, our general
partner and its affiliates will have no fiduciary duty or
obligation whatsoever to us or the limited partners, including
any duty to act in good faith or in the best interests of us or
the limited partners.
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Issuance of additional units |
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No approval right. |
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Amendment of the partnership agreement |
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Certain amendments may be made by the general partner without
the approval of the unitholders. Other amendments generally
require the approval of a unit majority. Please read
Amendment of the partnership agreement. |
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Merger of our partnership or the sale of all or substantially
all of our assets |
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Unit majority in certain circumstances. Please read
Merger, consolidation, conversion, sale or other
disposition of assets. |
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Dissolution of our partnership |
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Unit majority. Please read Termination and
dissolution. |
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Continuation of our business upon dissolution |
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Unit majority. Please read Termination and
dissolution. |
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Withdrawal of the general partner |
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Under most circumstances, the approval of a majority of the
common units, excluding common units held by our general partner
and its affiliates, is required for the withdrawal of our
general partner prior to December 31, 2017 in a manner that
would cause a dissolution of our partnership. Please read
Withdrawal or removal of the general partner. |
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The partnership
agreement
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Removal of the general partner |
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Not less than
662/3%
of the outstanding units, voting as a single class, including
units held by our general partner and its affiliates. Please
read Withdrawal or removal of the general
partner. |
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Transfer of the general partner interest |
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Our general partner may transfer all, but not less than all, of
its general partner interest in us without a vote of our
unitholders to an affiliate or another person in connection with
its merger or consolidation with or into, or sale of all or
substantially all of its assets to, such person. The approval of
a majority of the common units, excluding common units held by
the general partner and its affiliates, is required in other
circumstances for a transfer of the general partner interest to
a third party prior to December 31, 2017. Please read
Transfer of general partner units. |
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Transfer of incentive distribution rights |
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Except for transfers to an affiliate or another person as part
of our general partners merger or consolidation, sale of
all or substantially all of its assets or the sale of all of the
ownership interests in such holder, the approval of a majority
of the common units, excluding common units held by the general
partner and its affiliates, is required in most circumstances
for a transfer of the incentive distribution rights to a third
party prior to December 31, 2017. Please read
Transfer of incentive distribution rights. |
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Transfer of ownership interests in our general partner |
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No approval required at any time. Please read
Transfer of ownership interests in the general
partner. |
Assuming that a limited partner does not participate in the
control of our business within the meaning of the Delaware Act
and that he otherwise acts in conformity with the provisions of
the partnership agreement, his liability under the Delaware Act
will be limited, subject to possible exceptions, to the amount
of capital he is obligated to contribute to us for his common
units plus his share of any undistributed profits and assets.
However, if it were determined that the right, or exercise of
the right, by the limited partners as a group:
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to remove or replace the general partner;
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to approve some amendments to the partnership agreement; or
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to take other action under the partnership agreement;
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constituted participation in the control of our
business for the purposes of the Delaware Act, then the limited
partners could be held personally liable for our obligations
under the laws of Delaware, to the same extent as the general
partner. This liability would extend to persons who transact
business with us under the reasonable belief that the limited
partner is a general partner. Neither the partnership agreement
nor the Delaware Act specifically provides for legal recourse
against the general partner if a limited partner were to lose
limited liability through any fault of the general partner.
While this does
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The partnership
agreement
not mean that a limited partner could not seek legal recourse,
we know of no precedent for this type of a claim in Delaware
case law.
Under the Delaware Act, a limited partnership may not make a
distribution to a partner if, after the distribution, all
liabilities of the limited partnership, other than liabilities
to partners on account of their partnership interests and
liabilities for which the recourse of creditors is limited to
specific property of the partnership, would exceed the fair
value of the assets of the limited partnership. For the purpose
of determining the fair value of the assets of a limited
partnership, the Delaware Act provides that the fair value of
property subject to liability for which recourse of creditors is
limited shall be included in the assets of the limited
partnership only to the extent that the fair value of that
property exceeds the nonrecourse liability. The Delaware Act
provides that a limited partner who receives a distribution and
knew at the time of the distribution that the distribution was
in violation of the Delaware Act shall be liable to the limited
partnership for the amount of the distribution for three years.
Under the Delaware Act, a substituted limited partner of a
limited partnership is liable for the obligations of his
assignor to make contributions to the partnership, except that
such person is not obligated for liabilities unknown to him at
the time he became a limited partner and that could not be
ascertained from the partnership agreement.
Our subsidiaries conduct business in five states and we may have
subsidiaries that conduct business in other states in the
future. Maintenance of our limited liability as a limited
partner of the operating partnership may require compliance with
legal requirements in the jurisdictions in which the operating
partnership conducts business, including qualifying our
subsidiaries to do business there.
Limitations on the liability of limited partners for the
obligations of a limited partnership have not been clearly
established in many jurisdictions. If, by virtue of our
partnership interest in our operating partnership or otherwise,
it were determined that we were conducting business in any state
without compliance with the applicable limited partnership or
limited liability company statute, or that the right or exercise
of the right by the limited partners as a group to remove or
replace the general partner, to approve some amendments to the
partnership agreement, or to take other action under the
partnership agreement constituted participation in the
control of our business for purposes of the statutes of
any relevant jurisdiction, then the limited partners could be
held personally liable for our obligations under the law of that
jurisdiction to the same extent as the general partner under the
circumstances. We will operate in a manner that the general
partner considers reasonable and necessary or appropriate to
preserve the limited liability of the limited partners.
ISSUANCE
OF ADDITIONAL SECURITIES
Our partnership agreement authorizes us to issue an unlimited
number of additional partnership securities for the
consideration and on the terms and conditions determined by our
general partner without the approval of the unitholders.
It is possible that we will fund acquisitions through the
issuance of additional common units, subordinated units or other
partnership securities. Holders of any additional common units
we issue will be entitled to share equally with the
then-existing holders of common units in our distributions of
available cash. In addition, the issuance of additional common
units or other partnership securities may dilute the value of
the interests of the then-existing holders of common units in
our net assets.
In accordance with Delaware law and the provisions of our
partnership agreement, we may also issue additional partnership
securities that, as determined by our general partner, may have
special voting rights to which the common units are not
entitled. In addition, our partnership agreement does not
prohibit our subsidiaries from issuing equity securities, which
may effectively rank senior to the common units.
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The partnership
agreement
Upon issuance of additional partnership securities (other than
the issuance of partnership securities issued in connection with
a reset of the incentive distribution target levels relating to
our general partners incentive distribution rights or the
issuance of partnership securities upon conversion of
outstanding partnership securities), our general partner will be
entitled, but not required, to make additional capital
contributions to the extent necessary to maintain its 2.0%
general partner interest in us. Our general partners 2.0%
interest in us will 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 2.0%
general partner interest. Moreover, our general partner will
have the right, which it may from time to time assign in whole
or in part to any of its affiliates, to purchase common units,
subordinated units or other partnership securities whenever, and
on the same terms that, we issue those securities to persons
other than our general partner and its affiliates, to the extent
necessary to maintain the percentage interest of the general
partner and its affiliates, including such interest represented
by common and subordinated units, that existed immediately prior
to each issuance. The holders of common units will not have
preemptive rights to acquire additional common units or other
partnership securities.
AMENDMENT
OF THE PARTNERSHIP AGREEMENT
General
Amendments to our partnership agreement may be proposed only by
or with the consent of our general partner. However, our general
partner will have no duty or obligation to propose any amendment
and may decline to do so free of any fiduciary duty or
obligation whatsoever to us or the limited partners, including
any duty to act in good faith or in the best interests of us or
the limited partners. In order to adopt a proposed amendment,
other than the amendments discussed below, our general partner
is required to seek written approval of the holders of the
number of units required to approve the amendment or to call a
meeting of the limited partners to consider and vote upon the
proposed amendment. Except as described below, an amendment must
be approved by a unit majority.
Prohibited
amendments
No amendment may be made that would:
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enlarge the obligations of any limited partner without its
consent, unless approved by at least a majority of the type or
class of limited partner interests so affected; or
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enlarge the obligations of, restrict in any way any action by or
rights of, or reduce in any way the amounts distributable,
reimbursable or otherwise payable by us to our general partner
or any of its affiliates without the consent of our general
partner, which consent may be given or withheld at its option.
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The provision of our partnership agreement preventing the
amendments having the effects described in the clauses above can
be amended upon the approval of the holders of at least 90% of
the outstanding units, voting as a single class (including units
owned by our general partner and its affiliates). Upon
completion of the offering, our general partner and its
affiliates will own approximately 58.5% of our outstanding
common and subordinated units.
No unitholder
approval
Our general partner may generally make amendments to our
partnership agreement without the approval of any limited
partner or assignee to reflect:
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a change in our name, the location of our principal place of
business, our registered agent or our registered office;
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The partnership
agreement
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the admission, substitution, withdrawal or removal of partners
in accordance with our partnership agreement;
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a change that our general partner determines to be necessary or
appropriate to qualify or continue our qualification as a
limited partnership or a partnership in which the limited
partners have limited liability under the laws of any state or
to ensure that neither we nor the operating partnership nor any
of its subsidiaries will be treated as an association taxable as
a corporation or otherwise taxed as an entity for federal income
tax purposes;
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an amendment that is necessary, in the opinion of our counsel,
to prevent us or our general partner or its directors, officers,
agents or trustees from in any manner being subjected to the
provisions of the Investment Company Act of 1940, the Investment
Advisors Act of 1940 or plan asset regulations
adopted under the Employee Retirement Income Security Act of
1974, or ERISA, whether or not substantially similar to plan
asset regulations currently applied or proposed;
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an amendment that our general partner determines to be necessary
or appropriate for the authorization of additional partnership
securities or the right to acquire partnership securities,
including any amendment that our general partner determines is
necessary or appropriate in connection with:
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the adjustments of the minimum quarterly distribution, first
target distribution, second target distribution and third target
distribution in connection with the reset of our general
partners incentive distribution rights as described under
Provisions of our partnership agreement relating to cash
distributionsGeneral partners right to reset
incentive distribution levels, or
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any modification of the incentive distribution rights made in
connection with the issuance of additional partnership
securities or rights to acquire partnership securities, provided
that, any such modifications and related issuance of partnership
securities have received approval by a majority of the members
of the special committee of our general partner;
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any amendment expressly permitted in our partnership agreement
to be made by our general partner acting alone;
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an amendment effected, necessitated or contemplated by a merger
agreement that has been approved under the terms of our
partnership agreement;
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any amendment that our general partner determines to be
necessary or appropriate for the formation by us of, or our
investment in, any corporation, partnership or other entity, as
otherwise permitted by our partnership agreement;
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a change in our fiscal year or taxable year and related changes;
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conversions into, mergers with or conveyances to another limited
liability entity that is newly formed and has no assets,
liabilities or operations at the time of the conversion, merger
or conveyance other than those it receives by way of the
conversion, merger or conveyance; or
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any other amendments substantially similar to any of the matters
described in the clauses above.
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In addition, our general partner may make amendments to our
partnership agreement, without the approval of any limited
partner, if our general partner determines that those amendments:
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do not adversely affect the limited partners (or any particular
class of limited partners) in any material respect;
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are necessary or appropriate to satisfy any requirements,
conditions or guidelines contained in any opinion, directive,
order, ruling or regulation of any federal or state agency or
judicial authority or contained in any federal or state statute;
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148
The partnership
agreement
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are necessary or appropriate to facilitate the trading of
limited partner interests or to comply with any rule,
regulation, guideline or requirement of any securities exchange
on which the limited partner interests are or will be listed for
trading;
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are necessary or appropriate for any action taken by our general
partner relating to splits or combinations of units under the
provisions of our partnership agreement; or
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are required to effect the intent expressed in this prospectus
or the intent of the provisions of our partnership agreement or
are otherwise contemplated by our partnership agreement.
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Opinion of
counsel and unitholder approval
Our general partner will not be required to obtain an opinion of
counsel that an amendment will neither result in a loss of
limited liability to the limited partners nor result in our
being treated as an entity for federal income tax purposes in
connection with any of the amendments. No other amendments to
our partnership agreement will become effective without the
approval of holders of at least 90% of the outstanding units,
voting as a single class, unless we first obtain an opinion of
counsel to the effect that the amendment will not affect the
limited liability under applicable law of any of our limited
partners.
In addition to the above restrictions, any amendment that would
have a material adverse effect on the rights or preferences of
any type or class of outstanding units in relation to other
classes of units will require the approval of at least a
majority of the type or class of units so affected. Any
amendment that reduces the voting percentage required to take
any action is required to be approved by the affirmative vote of
limited partners whose aggregate outstanding units constitute
not less than the voting requirement sought to be reduced.
MERGER,
CONSOLIDATION, CONVERSION, SALE OR OTHER DISPOSITION OF
ASSETS
A merger, consolidation or conversion of us requires the prior
consent of our general partner. However, our general partner
will have no duty or obligation to consent to any merger,
consolidation or conversion and may decline to do so free of any
fiduciary duty or obligation whatsoever to us or the limited
partners, including any duty to act in good faith or in the best
interest of us or the limited partners.
In addition, the partnership agreement generally prohibits our
general partner, without the prior approval of the holders of a
unit majority, from causing us to, among other things, sell,
exchange or otherwise dispose of all or substantially all of our
assets in a single transaction or a series of related
transactions, including by way of merger, consolidation or other
combination, or approving on our behalf the sale, exchange or
other disposition of all or substantially all of the assets of
our subsidiaries. Our general partner may, however, mortgage,
pledge, hypothecate or grant a security interest in all or
substantially all of our assets without such approval. Our
general partner may also sell all or substantially all of our
assets under a foreclosure or other realization upon those
encumbrances without such approval. Finally, our general partner
may consummate any merger without the prior approval of our
unitholders if we are the surviving entity in the transaction,
our general partner has received an opinion of counsel regarding
limited liability and tax matters, the transaction would not
result in a material amendment to the partnership agreement,
each of our units will be an identical unit of our partnership
following the transaction and the partnership securities to be
issued do not exceed 20% of our outstanding partnership
securities immediately prior to the transaction.
If the conditions specified in the partnership agreement are
satisfied, our general partner may convert us or any of our
subsidiaries into a new limited liability entity or merge us or
any of our subsidiaries into, or convey all of our assets to, a
newly formed entity, if the sole purpose of that conversion,
merger or
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The partnership
agreement
conveyance is to effect a mere change in our legal form into
another limited liability entity, our general partner has
received an opinion of counsel regarding limited liability and
tax matters and the governing instruments of the new entity
provide the limited partners and our general partner with the
same rights and obligations as contained in the partnership
agreement. Our unitholders are not entitled to dissenters
rights of appraisal under the partnership agreement or
applicable Delaware law in the event of a conversion, merger or
consolidation, a sale of substantially all of our assets or any
other similar transaction or event.
TERMINATION
AND DISSOLUTION
We will continue as a limited partnership until terminated under
our partnership agreement. We will dissolve upon:
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the election of our general partner to dissolve us, if approved
by the holders of units representing a unit majority;
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there being no limited partners, unless we are continued without
dissolution in accordance with applicable Delaware law;
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the entry of a decree of judicial dissolution of our
partnership; or
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the withdrawal or removal of our general partner or any other
event that results in its ceasing to be our general partner
other than by reason of a transfer of its general partner
interest in accordance with our partnership agreement or its
withdrawal or removal following the approval and admission of a
successor.
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Upon a dissolution under the last clause above, the holders of a
unit majority may also elect, within specific time limitations,
to continue our business on the same terms and conditions
described in our partnership agreement by appointing as a
successor general partner an entity approved by the holders of
units representing a unit majority, subject to our receipt of an
opinion of counsel to the effect that:
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the action would not result in the loss of limited liability of
any limited partner; and
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neither our partnership, our operating partnership nor any of
our other subsidiaries would be treated as an association
taxable as a corporation or otherwise be taxable as an entity
for federal income tax purposes upon the exercise of that right
to continue.
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LIQUIDATION
AND DISTRIBUTION OF PROCEEDS
Upon our dissolution, unless we are continued as a new limited
partnership, the liquidator authorized to wind up our affairs
will, acting with all of the powers of our general partner that
are necessary or appropriate, liquidate our assets and apply the
proceeds of the liquidation as described in Provisions of
our partnership agreement relating to cash
distributionsDistributions of cash upon liquidation.
The liquidator may defer liquidation or distribution of our
assets for a reasonable period of time or distribute assets to
partners in kind if it determines that a sale would be
impractical or would cause undue loss to our partners.
WITHDRAWAL
OR REMOVAL OF THE GENERAL PARTNER
Except as described below, our general partner has agreed not to
withdraw voluntarily as our general partner prior to
December 31, 2017 without obtaining the approval of the
holders of at least a majority of the outstanding common units,
excluding common units held by the general partner and its
affiliates, and furnishing an opinion of counsel regarding
limited liability and tax matters. On or after December 31,
2017, our general partner may withdraw as general partner
without first obtaining approval of any unitholder by giving
90 days written notice, and that withdrawal will not
constitute a
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The partnership
agreement
violation of our partnership agreement. Notwithstanding the
information above, our general partner may withdraw without
unitholder approval upon 90 days notice to the
limited partners if at least 50% of the outstanding common units
are held or controlled by one unitholder and its affiliates,
other than the general partner and its affiliates. In addition,
the partnership agreement permits our general partner, in some
instances, to sell or otherwise transfer all of its general
partner interest in us without the approval of the unitholders.
Please read Transfer of general partner units
and Transfer of incentive distribution rights.
Upon withdrawal of our general partner under any circumstances,
other than as a result of a transfer by our general partner of
all or a part of its general partner interest in us, the holders
of a unit majority, voting as separate classes, may select a
successor to that withdrawing general partner. If a successor is
not elected, or is elected but an opinion of counsel regarding
limited liability and tax matters cannot be obtained, we will be
dissolved, wound up and liquidated, unless within a specified
period after that withdrawal, the holders of a unit majority
agree in writing to continue our business and to appoint a
successor general partner. Please read Termination
and dissolution.
Our general partner may not be removed unless that removal is
approved by the vote of the holders of not less than
662/3%
of the outstanding units, voting together as a single class,
including units held by our general partner and its affiliates,
and we receive an opinion of counsel regarding limited liability
and tax matters. Any removal of our general partner is also
subject to the approval of a successor general partner by the
vote of the holders of a majority of the outstanding common
units, voting as a single class, and the outstanding
subordinated units, voting as a single class. The ownership of
more than
331/3%
of the outstanding units by our general partner and its
affiliates would give them the practical ability to prevent our
general partners removal. At the close of this offering,
our general partner and its affiliates will own 58.5% of our
outstanding common and subordinated units.
Our partnership agreement also provides that if our general
partner is removed as our general partner under circumstances
where cause does not exist and the units held by the general
partner and its affiliates are not voted in favor of that
removal:
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the subordination period will end, and all outstanding
subordinated units will immediately convert into common units on
a one-for-one basis;
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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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our general partner will have the right to convert its general
partner interest and its incentive distribution rights into
common units or to receive cash in exchange for those interests
based on the fair market value of those interests at that time.
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In the event of the removal of a general partner under
circumstances where cause exists or withdrawal of a general
partner where that withdrawal violates our partnership
agreement, a successor general partner will have the option to
purchase the general partner interest and incentive distribution
rights of the departing general partner for a cash payment equal
to the fair market value of those interests. Under all other
circumstances where a general partner withdraws or is removed by
the limited partners, the departing general partner will have
the option to require the successor general partner to purchase
the general partner interest of the departing general partner
and its incentive distribution rights for fair market value. In
each case, this fair market value will be determined by
agreement between the departing general partner and the
successor general partner. If no agreement is reached, an
independent investment banking firm or other independent expert
selected by the departing general partner and the successor
general partner will determine the fair market value. Or, if the
departing general partner and the successor general partner
cannot agree upon an expert, then an expert chosen by agreement
of the experts selected by each of them will determine the fair
market value.
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The partnership
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If the option described above is not exercised by either the
departing general partner or the successor general partner, the
departing general partners general partner interest and
its incentive distribution rights will automatically convert
into common units equal to the fair market value of those
interests as determined by an investment banking firm or other
independent expert selected in the manner described in the
preceding paragraph.
In addition, we will be required to reimburse the departing
general partner for all amounts due to the departing general
partner, including, without limitation, all employee-related
liabilities, including severance liabilities incurred as a
result of the termination of any employees employed for our
benefit by the departing general partner or its affiliates.
TRANSFER
OF GENERAL PARTNER UNITS
Except for transfer by our general partner of all, but not less
than all, of its general partner units to:
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an affiliate of our general partner (other than an individual);
or
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another entity as part of the merger or consolidation of our
general partner with or into another entity or the transfer by
our general partner of all or substantially all of its assets to
another entity,
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our general partner may not transfer all or any of its general
partner units to another person prior to December 31, 2017
without the approval of the holders of at least a majority of
the outstanding common units, excluding common units held by our
general partner and its affiliates. As a condition of this
transfer, the transferee must assume, among other things, the
rights and duties of our general partner, agree to be bound by
the provisions of our partnership agreement and furnish an
opinion of counsel regarding limited liability and tax matters.
Our general partner and its affiliates may, at any time,
transfer units to one or more persons, without unitholder
approval, except that they may not transfer subordinated units
to us.
TRANSFER
OF OWNERSHIP INTERESTS IN THE GENERAL PARTNER
At any time, Anadarko and its affiliates may sell or transfer
all or part of its partnership interests in our general partner
to an affiliate or third party without the approval of our
unitholders.
TRANSFER
OF INCENTIVE DISTRIBUTION RIGHTS
Our general partner or its affiliates or a subsequent holder may
transfer its incentive distribution rights to an affiliate of
the holder (other than an individual) or another entity as part
of the merger or consolidation of such holder with or into
another entity, the sale of all of the ownership interest in the
holder or the sale of all or substantially all of the
holders assets to that entity without the prior approval
of the unitholders; provided that, in the case of the sale of
ownership interests in the holder, the initial holder of the
incentive distribution rights continues to remain the general
partner following such sale. Prior to December 31, 2017,
other transfers of incentive distribution rights will require
the affirmative vote of holders of a majority of the outstanding
common units, excluding common units held by our general partner
and its affiliates. On or after December 31, 2017, the
incentive distribution rights will be freely transferable.
CHANGE
OF MANAGEMENT PROVISIONS
Our partnership agreement contains specific provisions that are
intended to discourage a person or group from attempting to
remove Western Gas Holdings, LLC as our general partner or from
otherwise changing our management. If any person or group, other
than our general partner and its affiliates, acquires beneficial
ownership of 20% or more of any class of units, that person or
group loses voting
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agreement
rights on all of its units. This loss of voting rights does not
apply to any person or group that acquires the units directly
from our general partner or its affiliates or any transferee of
that person or group that is approved by our general partner or
to any person or group who acquires the units with the prior
approval of the board of directors of our general partner.
Our partnership agreement also provides that if our general
partner is removed as our general partner under circumstances
where cause does not exist and units held by our general partner
and its affiliates are not voted in favor of that removal:
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the subordination period will end and all outstanding
subordinated units will immediately convert into common units on
a one-for-one basis;
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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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our 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 based
on the fair market value of those interests at that time.
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If at any time our general partner and its affiliates own more
than 80% of the then-issued and outstanding limited partner
interests of any class, our general partner will have the right,
which it may assign in whole or in part to any of its affiliates
or to us, to acquire all, but not less than all, of the limited
partner interests of the class held by unaffiliated persons as
of a record date to be selected by our general partner, on at
least 10, but not more than 60, days notice. The purchase price
in the event of this purchase is the greater of:
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the highest cash price paid by our general partner or any of its
affiliates for any limited partner interests of the class
purchased within the 90 days preceding the date on which
our general partner first mails notice of its election to
purchase those limited partner interests; and
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the current market price as of the date three days before the
date the notice is mailed.
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As a result of our general partners right to purchase
outstanding limited partner interests, a holder of limited
partner interests may have his limited partner interests
purchased at a price that may be lower than market prices at
various times prior to such purchase or lower than a unitholder
may anticipate the market price to be in the future. The tax
consequences to a unitholder of the exercise of this call right
are the same as a sale by that unitholder of his common units in
the market. Please read Material tax
consequencesDisposition of common units.
Except as described below regarding a person or group owning 20%
or more of any class of units then outstanding, record holders
of units on the record date will be entitled to notice of, and
to vote at, meetings of our limited partners and to act upon
matters for which approvals may be solicited.
Our general partner does not anticipate that any meeting of our
unitholders will be called in the foreseeable future. Any action
that is required or permitted to be taken by the unitholders may
be taken either at a meeting of the unitholders or without a
meeting, if consents in writing describing the action so taken
are signed by holders of the number of units necessary to
authorize or take that action at a meeting. Meetings of the
unitholders may be called by our general partner or by
unitholders owning at least 20% of the outstanding units of the
class for which a meeting is proposed. Unitholders may vote
either in person or by proxy at meetings. The holders of a
majority of the outstanding units of the class or classes for
which a meeting has been called, represented in person or by
proxy, will constitute a
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The partnership
agreement
quorum, unless any action by the unitholders requires approval
by holders of a greater percentage of the units, in which case
the quorum will be the greater percentage.
Each record holder of a unit has a vote according to his
percentage interest in us, although additional limited partner
interests having special voting rights could be issued. Please
read Issuance of additional securities.
However, if at any time any person or group, other than our
general partner and its affiliates, or a direct or subsequently
approved transferee of our general partner or its affiliates,
acquires, in the aggregate, beneficial ownership of 20% or more
of any class of units then outstanding, that person or group
will lose voting rights on all of its units and the units may
not be voted on any matter and will not be considered to be
outstanding when sending notices of a meeting of unitholders,
calculating required votes, determining the presence of a quorum
or for other similar purposes. Common units held in nominee or
street name account will be voted by the broker or other nominee
in accordance with the instruction of the beneficial owner
unless the arrangement between the beneficial owner and his
nominee provides otherwise. Except as our partnership agreement
otherwise provides, subordinated units will vote together with
common units, as a single class.
Any notice, demand, request, report or proxy material required
or permitted to be given or made to record holders of common
units under our partnership agreement will be delivered to the
record holder by us or by the transfer agent.
STATUS
AS LIMITED PARTNER
By transfer of common units in accordance with our partnership
agreement, each transferee of common units shall be admitted as
a limited partner with respect to the common units transferred
when such transfer and admission are reflected in our books and
records. Except as described under Limited
liability, the common units will be fully paid, and
unitholders will not be required to make additional
contributions.
NON-CITIZEN
ASSIGNEES; REDEMPTION
If we are or become subject to federal, state or local laws or
regulations that, in the reasonable determination of our general
partner, create a substantial risk of cancellation or forfeiture
of any property that we have an interest in because of the
nationality, citizenship or other related status of any limited
partner, we may redeem the units held by that limited partner at
their current market price. In order to avoid any cancellation
or forfeiture, our general partner may require each limited
partner to furnish information about his nationality,
citizenship or related status. If a limited partner fails to
furnish information about his nationality, citizenship or other
related status within 30 days of a request for the
information or our general partner determines after receipt of
the information that the limited partner is not an eligible
citizen, the limited partner may be treated as a non-citizen
assignee. A non-citizen assignee is entitled to an interest
equivalent to that of a limited partner for the right to share
in allocations and distributions from us, including liquidating
distributions. A non-citizen assignee does not have the right to
direct the voting of his units and may not receive distributions
in-kind upon our liquidation.
Under our partnership agreement, in most circumstances, we will
indemnify the following persons, to the fullest extent permitted
by law, from and against all losses, claims, damages or similar
events:
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our general partner;
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any departing general partner;
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any person who is or was an affiliate of a general partner or
any departing general partner;
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The partnership
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any person who is or was a director, officer, member, partner,
fiduciary or trustee of any entity set forth in the preceding
three bullet points;
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any person who is or was serving as director, officer, member,
partner, fiduciary or trustee of another person at the request
of our general partner or any departing general partner; and
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any person designated by our general partner.
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Any indemnification under these provisions will only be out of
our assets. Unless our general partner otherwise agrees, it will
not be personally liable for, or have any obligation to
contribute or lend funds or assets to us to enable us to
effectuate, indemnification. We may purchase insurance against
liabilities asserted against and expenses incurred by persons
for our activities, regardless of whether we would have the
power to indemnify the person against liabilities under our
partnership agreement.
REIMBURSEMENT
OF EXPENSES
Our partnership agreement requires us to reimburse our general
partner for all direct and indirect expenses it incurs or
payments it makes on our behalf and all other expenses allocable
to us or otherwise incurred by our general partner in connection
with the operation of our business. These expenses include
salary, bonus, incentive compensation and other amounts paid to
persons who perform services for us or on our behalf and
expenses allocated to our general partner by its affiliates. Our
general partner is entitled to determine in good faith the
expenses that are allocable to us.
Our general partner is required to keep appropriate books of our
business at our principal offices. These books will be
maintained for both tax and financial reporting purposes on an
accrual basis. For tax and fiscal reporting purposes, our fiscal
year is the calendar year.
We will furnish or make available to record holders of our
common units, within 120 days after the close of each
fiscal year, an annual report containing audited combined
financial statements and a report on those combined financial
statements by our independent public accountants. Except for our
fourth quarter, we will also furnish or make available summary
financial information within 90 days after the close of
each quarter.
We will furnish each record holder with information reasonably
required for tax reporting purposes within 90 days after
the close of each calendar year. This information is expected to
be furnished in summary form so that some complex calculations
normally required of partners can be avoided. Our ability to
furnish this summary information to our unitholders will depend
on their cooperation in supplying us with specific information.
Every unitholder will receive information to assist him in
determining his federal and state tax liability and in filing
his federal and state income tax returns, regardless of whether
he supplies us with the necessary information.
RIGHT
TO INSPECT OUR BOOKS AND RECORDS
Our partnership agreement provides that a limited partner can,
for a purpose reasonably related to his interest as a limited
partner, upon reasonable written demand stating the purpose of
such demand and at his own expense, have furnished to him:
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a current list of the name and last known address of each
partner;
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a copy of our tax returns;
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information as to the amount of cash, and a description and
statement of the agreed value of any other property or services,
contributed or to be contributed by each partner and the date on
which each partner became a partner;
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The partnership
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copies of our partnership agreement, our certificate of limited
partnership and related amendments and powers of attorney under
which they have been executed;
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information regarding the status of our business and our
financial condition; and
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any other information regarding our affairs as is just and
reasonable.
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Our general partner may, and intends to, keep confidential from
the limited partners trade secrets or other information
the disclosure of which our general partner believes in good
faith is not in our best interests or that we are required by
law or by agreements with third parties to keep confidential.
Under our partnership agreement, we have agreed to register for
resale under the Securities Act and applicable state securities
laws any common units, subordinated units or other partnership
securities proposed to be sold by our general partner or any of
its affiliates or their assignees if an exemption from the
registration requirements is not otherwise available. These
registration rights continue for two years following any
withdrawal or removal of Western Gas Holdings, LLC as our
general partner. We are obligated to pay all expenses incidental
to the registration, excluding underwriting discounts and fees.
Please read Units eligible for future sale.
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Units
eligible for future sale
After the sale of the common units offered hereby, Anadarko will
hold an aggregate of 3,823,925 common units, assuming that the
underwriters do not exercise their option to purchase up to
2,812,500 additional common units, and 22,573,925 subordinated
units. All of the subordinated units will convert into common
units at the end of the subordination period and some may
convert earlier. The sale of these units could have an adverse
impact on the price of the common units or on any trading market
that may develop.
The common units sold in the offering will generally be freely
transferable without restriction or further registration under
the Securities Act, except that any common units owned by an
affiliate of ours may not be resold publicly except
in compliance with the registration requirements of the
Securities Act or under an exemption under Rule 144 or
otherwise. Rule 144 permits securities acquired by an
affiliate of the issuer to be sold into the market in an amount
that does not exceed, during any three-month period, the greater
of:
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1% of the total number of the securities outstanding, or
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the average weekly reported trading volume of the common units
for the four calendar weeks prior to the sale.
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Sales under Rule 144 are also subject to specific manner of
sale provisions, holding period requirements, notice
requirements and the availability of current public information
about us. A person who is not deemed to have been an affiliate
of ours at any time during the three months preceding a sale,
and who has beneficially owned his common units for at least two
years, would be entitled to sell common units under
Rule 144 without regard to the rules public
information requirements, volume limitations, manner of sale
provisions and notice requirements.
The partnership agreement does not restrict our ability to issue
any partnership securities. Any issuance of additional common
units or other equity securities would result in a corresponding
decrease in the proportionate ownership interest in us
represented by, and could adversely affect the cash
distributions to and market price of, our common units then
outstanding. Please read The partnership
agreementissuance of additional securities.
Under our partnership agreement, our general partner and its
affiliates have the right to cause us to register under the
Securities Act and state securities laws the offer and sale of
any common units, subordinated units or other partnership
securities that they hold. Subject to the terms and conditions
of our partnership agreement, these registration rights allow
our general partner and its affiliates or their assignees
holding any units or other partnership securities to require
registration of any of these units or other partnership
securities and to include them in a registration by us of other
units, including units offered by us or by any unitholder. Our
general partner will continue to have these registration rights
for two years following its withdrawal or removal as our general
partner. In connection with any registration of this kind, we
will indemnify each unitholder participating in the registration
and its officers, directors and controlling persons from and
against any liabilities under the Securities Act or any state
securities laws arising from the registration statement or the
prospectus. We will bear all costs and expenses incidental to
any registration, excluding any underwriting discounts and fees.
Except as described below, our general partner and its
affiliates may sell their units or other partnership interests
in private transactions at any time, subject to compliance with
applicable laws.
Anadarko, our partnership, our general partner and its
affiliates, including the executive officers and directors of
our general partner, and the participants in our directed unit
program have agreed not to sell any common units they
beneficially own for a period of 180 days from the date of
this prospectus. For a description of these
lock-up
provisions, please read Underwriting.
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Material
tax consequences
This section is a summary of the material tax considerations
that may be relevant to prospective unitholders who are
individual citizens or residents of the U.S. and, unless
otherwise noted in the following discussion, is the opinion of
Vinson & Elkins L.L.P., counsel to our general partner
and us, insofar as it relates to legal conclusions with respect
to matters of U.S. federal income tax law. This section is based
upon current provisions of the Internal Revenue Code, existing
and proposed regulations and current administrative rulings and
court decisions, all of which are subject to change. Later
changes in these authorities may cause the tax consequences to
vary substantially from the consequences described below. Unless
the context otherwise requires, references in this section to
us or we are references to Western Gas
Partners, LP and our operating company.
The following discussion does not comment on all federal income
tax matters affecting us or our unitholders. Moreover, the
discussion focuses on unitholders who are individual citizens or
residents of the U.S. and has only limited application to
corporations, estates, trusts, nonresident aliens or other
unitholders subject to specialized tax treatment, such as
tax-exempt institutions, foreign persons, individual retirement
accounts (IRAs), real estate investment trusts (REITs), employee
benefit plans or mutual funds. Accordingly, we encourage each
prospective unitholder to consult, and depend on, his own tax
advisor in analyzing the federal, state, local and foreign tax
consequences particular to him of the ownership or disposition
of common units.
All statements as to matters of law and legal conclusions, but
not as to factual matters, contained in this section, unless
otherwise noted, are the opinion of Vinson & Elkins
L.L.P. and are based on the accuracy of the representations made
by us.
No ruling has been or will be requested from the IRS regarding
any matter affecting us or prospective unitholders. Instead, we
will rely on opinions of Vinson & Elkins L.L.P. Unlike
a ruling, an opinion of counsel represents only that
counsels best legal judgment and does not bind the IRS or
the courts. Accordingly, the opinions and statements made herein
may not be sustained by a court if contested by the IRS. Any
contest of this sort with the IRS may materially and adversely
impact the market for the common units and the prices at which
the common units trade. In addition, the costs of any contest
with the IRS, principally legal, accounting and related fees,
will result in a reduction in cash available for distribution to
our unitholders and our general partner and thus will be borne
indirectly by our unitholders and our general partner.
Furthermore, the tax treatment of us, or of an investment in us,
may be significantly modified by future legislative or
administrative changes or court decisions. Any modifications may
or may not be retroactively applied.
For the reasons described below, Vinson & Elkins
L.L.P. has not rendered an opinion with respect to the following
specific federal income tax issues: (1) the treatment of a
unitholder whose common units are loaned to a short seller to
cover a short sale of common units (please read Tax
consequences of unit ownershipTreatment of short
sales); (2) whether our monthly convention for
allocating taxable income and losses is permitted by existing
Treasury Regulations (please read Disposition of
common unitsAllocations between transferors and
transferees); and (3) whether our method for
depreciating Section 743 adjustments is sustainable in
certain cases (please read Tax consequences of unit
ownershipSection 754 election and
Uniformity of units).
A partnership is not a taxable entity and incurs no federal
income tax liability. Instead, each partner of a partnership is
required to take into account his share of items of income,
gain, loss and deduction of the partnership in computing his
federal income tax liability, regardless of whether cash
distributions are made to him by the partnership. Distributions
by a partnership to a partner are generally not
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Material tax
consequences
taxable to the partner unless the amount of cash distributed is
in excess of the partners adjusted basis in his
partnership interest.
Section 7704 of the Internal Revenue Code provides that
publicly traded partnerships will, as a general rule, be taxed
as corporations. However, an exception, referred to as the
Qualifying Income Exception, exists with respect to
publicly traded partnerships of which 90% or more of the gross
income for every taxable year consists of qualifying
income. Qualifying income includes income and gains
derived from the transportation, storage, processing and
marketing of crude oil, natural gas and products thereof. Other
types of qualifying income include interest (other than from a
financial business), dividends, gains from the sale of real
property and gains from the sale or other disposition of capital
assets held for the production of income that otherwise
constitutes qualifying income. We estimate that less
than % of our current gross income
is not qualifying income; however, this estimate could change
from time to time. Based upon and subject to this estimate, the
factual representations made by us and our general partner and a
review of the applicable legal authorities, Vinson &
Elkins L.L.P. is of the opinion that at least 90% of our current
gross income constitutes qualifying income. The portion of our
income that is qualifying income can change from time to time.
A publicly traded partnership may not rely upon the Qualifying
Income Exception if it is registered under the Investment
Company Act of 1940, or the Investment Company Act. If we were
required to register under the Investment Company Act, we would
be taxed as a corporation even if we met the Qualifying Income
Exception. Vinson & Elkins L.L.P. is of the opinion
that we may rely on the Qualifying Income Exception.
No ruling has been or will be sought from the IRS and the IRS
has made no determination as to our status or the status of the
operating company for federal income tax purposes or whether our
operations generate qualifying income under
Section 7704 of the Internal Revenue Code. Instead, we will
rely on the opinion of Vinson & Elkins L.L.P. on such
matters. It is the opinion of Vinson & Elkins L.L.P.
that, based upon the Internal Revenue Code, Treasury
Regulations, published revenue rulings and court decisions and
the representations described below, we will be classified as a
partnership and our operating company will be disregarded as an
entity separate from us for federal income tax purposes.
In rendering its opinion, Vinson & Elkins L.L.P. has
relied on factual representations made by us and our general
partner. The representations made by us and our general partner
upon which Vinson & Elkins L.L.P. has relied are:
(a) Neither we nor the operating company has elected
or will elect to be treated as a corporation;
(b) For each taxable year, more than 90% of our gross
income has been and will be income that Vinson &
Elkins L.L.P. has opined or will opine is qualifying
income within the meaning of Section 7704(d) of the
Internal Revenue Code; and
(c) Each hedging transaction that we treat as
resulting in qualifying income has been and will be
appropriately identified as a hedging transaction pursuant to
applicable Treasury Regulations, and has been and will be
associated with oil, gas, or products thereof that are held or
to be held by us in activities that Vinson & Elkins
L.L.P. has opined or will opine result in qualifying income.
If we fail to meet the Qualifying Income Exception, other than a
failure that is determined by the IRS to be inadvertent and that
is cured within a reasonable time after discovery, in which case
the IRS may also require us to make adjustments with respect to
our unitholders or pay other amounts, we will be treated as if
we had transferred all of our assets, subject to liabilities, to
a newly formed corporation, on the first day of the year in
which we fail to meet the Qualifying Income Exception, in return
for stock
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Material tax
consequences
in that corporation, and then distributed that stock to the
unitholders in liquidation of their interests in us. This deemed
contribution and liquidation should be tax-free to unitholders
and us so long as we, at that time, do not have liabilities in
excess of the tax basis of our assets. Thereafter, we would be
treated as a corporation for federal income tax purposes.
If we were treated as an association taxable as a corporation in
any taxable year, either as a result of a failure to meet the
Qualifying Income Exception or otherwise, our items of income,
gain, loss and deduction would be reflected only on our tax
return rather than being passed through to our unitholders, and
our net income would be taxed to us at corporate rates. In
addition, any distribution made to a unitholder would be treated
as either taxable dividend income, to the extent of our current
or accumulated earnings and profits, or, in the absence of
earnings and profits, a nontaxable return of capital, to the
extent of the unitholders tax basis in his common units,
or taxable capital gain, after the unitholders tax basis
in his common units is reduced to zero. Accordingly, taxation as
a corporation would result in a material reduction in a
unitholders cash flow and after-tax return and thus would
likely result in a substantial reduction of the value of the
units.
The discussion below is based on Vinson & Elkins
L.L.P.s opinion that we will be classified as a
partnership for federal income tax purposes.
Unitholders who have become limited partners of Western Gas
Partners, LP will be treated as partners of Western Gas
Partners, LP for federal income tax purposes. Also, unitholders
whose common units are held in street name or by a nominee and
who have the right to direct the nominee in the exercise of all
substantive rights attendant to the ownership of their common
units will be treated as partners of Western Gas Partners, LP
for federal income tax purposes.
A beneficial owner of common units whose units have been
transferred to a short seller to complete a short sale would
appear to lose his status as a partner with respect to those
units for federal income tax purposes. Please read
Tax consequences of unit ownershipTreatment of
short sales.
Income, gain, deductions or losses are not reportable by a
unitholder who is not a partner for federal income tax purposes,
and any cash distributions received by a unitholder who is not a
partner for federal income tax purposes would therefore appear
to be fully taxable as ordinary income. These holders are urged
to consult their own tax advisors with respect to their tax
consequences of holding common units in Western Gas Partners,
LP. References to unitholders in the discussion that
follows are to persons who are treated as partners in Western
Gas Partners, LP for federal income tax purposes.
TAX
CONSEQUENCES OF UNIT OWNERSHIP
Flow-through of
taxable income
We will not pay any federal income tax. Instead, each unitholder
will be required to report on his income tax return his share of
our income, gains, losses and deductions without regard to
whether we make cash distributions to him. Consequently, we may
allocate income to a unitholder even if he has not received a
cash distribution. Each unitholder will be required to include
in income his allocable share of our income, gains, losses and
deductions for our taxable year ending with or within his
taxable year. Our taxable year ends on December 31.
Treatment of
distributions
Distributions by us to a unitholder generally will not be
taxable to the unitholder for federal income tax purposes,
except to the extent the amount of any such cash distribution
exceeds his tax basis in his
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Material tax
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common units immediately before the distribution. Our cash
distributions in excess of a unitholders tax basis in his
common units generally will be considered to be gain from the
sale or exchange of the common units, taxable in accordance with
the rules described under Disposition of common
units below. Any reduction in a unitholders share of
our liabilities for which no partner, including the general
partner, bears the economic risk of loss, known as
nonrecourse liabilities, will be treated as a
distribution of cash to that unitholder. To the extent our
distributions cause a unitholders at-risk
amount to be less than zero at the end of any taxable year, the
unitholder must recapture any losses deducted in previous years.
Please read Tax consequences of unit
ownershipLimitations on deductibility of losses.
A decrease in a unitholders percentage interest in us
because of our issuance of additional common units will decrease
his share of our nonrecourse liabilities, and thus will result
in a corresponding deemed distribution of cash, which may
constitute a non-pro rata distribution. A non-pro rata
distribution of money or property may result in ordinary income
to a unitholder, regardless of his tax basis in his common
units, if the distribution reduces the unitholders share
of our unrealized receivables, including
depreciation recapture,
and/or
substantially appreciated inventory items, both as
defined in Section 751 of the Internal Revenue Code, and
collectively, Section 751 Assets. To that
extent, he will be treated as having been distributed his
proportionate share of the Section 751 Assets and then
having exchanged those assets with us in return for the non-pro
rata portion of the actual distribution made to him. This latter
deemed exchange will generally result in the unitholders
realization of ordinary income, which will equal the excess of
(1) the non-pro rata portion of that distribution over
(2) the unitholders tax basis (generally zero) for
the share of Section 751 Assets deemed relinquished in the
exchange.
Ratio of taxable
income to distributions
We estimate that a purchaser of common units in this offering
who owns those common units from the date of closing of this
offering through the record date for distributions for the
period
ending ,
will be allocated, on a cumulative basis, an amount of federal
taxable income for that period that will
be %
or less of the cash distributed to the unitholder with respect
to that period. Thereafter, we anticipate that the ratio of
allocable taxable income to cash distributions to the
unitholders will increase. These estimates are based upon the
assumption that gross income from operations will approximate
the amount required to pay the minimum quarterly distribution on
all units and other assumptions with respect to capital
expenditures, cash flow, net working capital and anticipated
cash distributions. These estimates and assumptions are subject
to, among other things, numerous business, economic, regulatory,
legislative, competitive and political uncertainties beyond our
control. Further, the estimates are based on current tax law and
tax reporting positions that we will adopt and with which the
IRS could disagree. Accordingly, we cannot assure you that these
estimates will prove to be correct. The actual percentage of
distributions that will constitute taxable income could be
higher or lower than expected, and any differences could be
material and could materially affect the value of the common
units. For example, the ratio of allocable taxable income to
cash distributions to a purchaser of common units in this
offering will be greater, and perhaps substantially greater,
than our estimate with respect to the period described above if:
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gross income from operations exceeds the amount required to pay
the minimum quarterly distributions on all units, yet we only
distribute the minimum quarterly distributions on all units; or
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we make a future offering of common units and use the proceeds
of the offering in a manner that does not produce substantial
additional deductions during the period described above, such as
to repay indebtedness outstanding at the time of this offering
or to acquire property that is not eligible for depreciation or
amortization for federal income tax purposes or that is
depreciable or
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amortizable at a rate significantly slower than the rate
applicable to our assets at the time of this offering.
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Basis of common
units
A unitholders initial tax basis for his common units will
be the amount he paid for the common units plus his share of our
nonrecourse liabilities. That basis will be increased by his
share of our income and by any increases in his share of our
nonrecourse liabilities. That basis generally will be decreased,
but not below zero, by distributions from us, by the
unitholders share of our losses, by any decreases in his
share of our nonrecourse liabilities and by his share of our
expenditures that are not deductible in computing taxable income
and are not required to be capitalized. A unitholder will have
no share of our debt that is recourse to our general partner,
but will have a share, generally based on his share of profits,
of our nonrecourse liabilities. Please read
Disposition of common unitsRecognition of gain
or loss.
Limitations on
deductibility of losses
The deduction by a unitholder of his share of our losses will be
limited to the tax basis in his units and, in the case of an
individual unitholder, estate, trust, or corporate unitholder
(if more than 50% of the value of the corporate
unitholders stock is owned directly or indirectly by or
for five or fewer individuals) or some tax-exempt organizations,
to the amount for which the unitholder is considered to be
at risk with respect to our activities, if that is
less than his tax basis. A common unitholder subject to these
limitations must recapture losses deducted in previous years to
the extent that distributions cause his at-risk amount to be
less than zero at the end of any taxable year. Losses disallowed
to a unitholder or recaptured as a result of these limitations
will carry forward and will be allowable as a deduction in a
later year to the extent that his tax basis or at-risk amount,
whichever is the limiting factor, is subsequently increased.
Upon the taxable disposition of a unit, any gain recognized by a
unitholder can be offset by losses that were previously
suspended by the at-risk limitation but may not be offset by
losses suspended by the basis limitation. Any loss previously
suspended by the at-risk or basis limitations in excess of that
gain would no longer be utilizable.
In general, a unitholder will be at risk to the extent of the
tax basis of his units, excluding any portion of that basis
attributable to his share of our nonrecourse liabilities,
reduced by (i) any portion of that basis representing
amounts otherwise protected against loss because of a guarantee,
stop loss agreement or other similar arrangement and
(ii) any amount of money he borrows to acquire or hold his
units, if the lender of those borrowed funds owns an interest in
us, is related to the unitholder or can look only to the units
for repayment. A unitholders at-risk amount will increase
or decrease as the tax basis of the unitholders units
increases or decreases, other than tax basis increases or
decreases attributable to increases or decreases in his share of
our nonrecourse liabilities.
In addition to the basis and at-risk limitations on the
deductibility of losses, the passive loss limitations generally
provide that individuals, estates, trusts and some closely-held
corporations and personal service corporations are permitted to
deduct losses from passive activities, which are generally trade
or business activities in which the taxpayer does not materially
participate, only to the extent of the taxpayers income
from those passive activities. The passive loss limitations are
applied separately with respect to each publicly traded
partnership. Consequently, any passive losses we generate will
only be available to offset our passive income generated in the
future and will not be available to offset income from other
passive activities or investments, including our investments or
investments in other publicly traded partnerships, or a
unitholders salary or active business income. Passive
losses that are not deductible because they exceed a
unitholders share of income we generate may be deducted in
full when the unitholder disposes of his entire investment in us
in a fully taxable transaction with an
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unrelated party. The passive loss limitations are applied after
other applicable limitations on deductions, including the
at-risk rules and the basis limitation.
A unitholders share of our net income may be offset by any
of our suspended passive losses, but it may not be offset by any
other current or carryover losses from other passive activities,
including those attributable to other publicly traded
partnerships.
Limitations on
interest deductions
The deductibility of a non-corporate taxpayers
investment interest expense is generally limited to
the amount of that taxpayers net investment
income. Investment interest expense includes:
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interest on indebtedness properly allocable to property held for
investment;
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our interest expense attributed to portfolio income; and
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the portion of interest expense incurred to purchase or carry an
interest in a passive activity to the extent attributable to
portfolio income.
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The computation of a unitholders investment interest
expense will take into account interest on any margin account
borrowing or other loan incurred to purchase or carry a unit.
Net investment income includes gross income from property held
for investment and amounts treated as portfolio income under the
passive loss rules, less deductible expenses, other than
interest, directly connected with the production of investment
income, but generally does not include gains attributable to the
disposition of property held for investment. The IRS has
indicated that the net passive income earned by a publicly
traded partnership will be treated as investment income to its
unitholders. In addition, the unitholders share of our
portfolio income will be treated as investment income.
Entity-level collections
If we are required or elect under applicable law to pay any
federal, state, local or foreign income tax on behalf of any
unitholder or our general partner or any former unitholder, we
are authorized to pay those taxes from our funds. That payment,
if made, will be treated as a distribution of cash to the
unitholder on whose behalf the payment was made. If the payment
is made on behalf of a person whose identity cannot be
determined, we are authorized to treat the payment as a
distribution to all current unitholders. We are authorized to
amend our partnership agreement in the manner necessary to
maintain uniformity of intrinsic tax characteristics of units
and to adjust later distributions, so that after giving effect
to these distributions, the priority and characterization of
distributions otherwise applicable under our partnership
agreement is maintained as nearly as is practicable. Payments by
us as described above could give rise to an overpayment of tax
on behalf of an individual unitholder in which event the
unitholder would be required to file a claim in order to obtain
a credit or refund.
Allocation of
income, gain, loss and deduction
In general, if we have a net profit, our items of income, gain,
loss and deduction will be allocated among our general partner
and the unitholders in accordance with their percentage
interests in us. At any time that distributions are made to the
common units in excess of distributions to the subordinated
units, or incentive distributions are made to our general
partner, gross income will be allocated to the recipients to the
extent of these distributions. If we have a net loss for the
entire year, that loss will be allocated first to our general
partner and the unitholders in accordance with their percentage
interests in us to the extent of their positive capital accounts
and, second, to our general partner.
Specified items of our income, gain, loss and deduction will be
allocated under Section 704(c) of the Internal Revenue Code
to account for the difference between the tax basis and fair
market value of
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property contributed to us by the general partner and its
affiliates, referred to in this discussion as Contributed
Property. The effect of these allocations, referred to as
Section 704(c) Allocations, to a unitholder purchasing
common units from us in this offering will be essentially the
same as if the tax basis of our assets were equal to their fair
market value at the time of this offering. In the event we issue
additional common units or engage in certain other transactions
in the future Reverse Section 704(c)
Allocations, similar to the Section 704(c)
Allocations described above, will be made to all holders of
partnership interests, including purchasers of common units in
this offering, to account for the difference, at the time of the
future transaction, between the book basis for
purposes of maintaining capital accounts and the fair market
value of all property held by us at the time of the future
transaction. In addition, items of recapture income will be
allocated to the extent possible to the unitholder who was
allocated the deduction giving rise to the treatment of that
gain as recapture income in order to minimize the recognition of
ordinary income by other unitholders. Finally, although we do
not expect that our operations will result in the creation of
negative capital accounts, if negative capital accounts
nevertheless result, items of our income and gain will be
allocated in an amount and manner to eliminate the negative
balance as quickly as possible.
An allocation of items of our income, gain, loss or deduction,
other than an allocation required by Section 704(c) of the
Internal Revenue Code to eliminate the difference between a
partners book capital account, credited with
the fair market value of Contributed Property, and
tax capital account, credited with the tax basis of
Contributed Property, referred to in this discussion as the
Book-Tax Disparity, will generally be given effect
for federal income tax purposes in determining a partners
share of an item of income, gain, loss or deduction only if the
allocation has substantial economic effect.
In any other case, a partners share of an item will be
determined on the basis of his interest in us, which will be
determined by taking into account all the facts and
circumstances, including:
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his relative contributions to us;
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the interests of all the partners in profits and losses;
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the interest of all the partners in cash flow; and
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the rights of all the partners to distributions of capital upon
liquidation.
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Vinson & Elkins L.L.P. is of the opinion that, with
the exception of the issues described in Tax
consequences of unit ownershipSection 754
election, Uniformity of units and
Disposition of common unitsAllocations between
transferors and transferees, allocations under our
partnership agreement will be given effect for federal income
tax purposes in determining a partners share of an item of
income, gain, loss or deduction.
Treatment of
short sales
A unitholder whose units are loaned to a short
seller to cover a short sale of units may be considered as
having disposed of those units. If so, he would no longer be
treated for tax purposes as a partner with respect to those
units during the period of the loan and may recognize gain or
loss from the disposition. As a result, during this period:
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any of our income, gain, loss or deduction with respect to those
units would not be reportable by the unitholder;
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any cash distributions received by the unitholder as to those
units would be fully taxable; and
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all of these distributions would appear to be ordinary income.
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Vinson & Elkins L.L.P. has not rendered an opinion
regarding the treatment of a unitholder where common units are
loaned to a short seller to cover a short sale of common units;
therefore, unitholders desiring to assure their status as
partners and avoid the risk of gain recognition from a loan to a
short seller are urged to modify any applicable brokerage
account agreements to prohibit their brokers from loaning their
units. The IRS has announced that it is actively studying issues
relating to the tax treatment of short sales of partnership
interests. Please also read Disposition of common
unitsrecognition of gain or loss.
Alternative
minimum tax
Each unitholder will be required to take into account his
distributive share of any items of our income, gain, loss or
deduction for purposes of the alternative minimum tax. The
current minimum tax rate for noncorporate taxpayers is 26% on
the first $175,000 of alternative minimum taxable income in
excess of the exemption amount and 28% on any additional
alternative minimum taxable income. Prospective unitholders are
urged to consult with their tax advisors as to the impact of an
investment in units on their liability for the alternative
minimum tax.
Tax
rates
In general, the highest effective U.S. federal income tax rate
for individuals is currently 35%, and the maximum U.S. federal
income tax rate for net capital gains of an individual where the
asset disposed of was held for more than twelve months at the
time of disposition, is scheduled to remain at 15% for years
2008-2010
and then increase to 20% beginning January 1, 2011.
Section 754
election
We will make the election permitted by Section 754 of the
Internal Revenue Code. That election is irrevocable without the
consent of the IRS. The election will generally permit us to
adjust a common unit purchasers tax basis in our assets
(inside basis) under Section 743(b) of the
Internal Revenue Code to reflect his purchase price. This
election does not apply to a person who purchases common units
directly from us. The Section 743(b) adjustment belongs to
the purchaser and not to other unitholders. For purposes of this
discussion, a unitholders inside basis in our assets will
be considered to have two components: (1) his share of our
tax basis in our assets (common basis) and
(2) his Section 743(b) adjustment to that basis.
Where the remedial allocation method is adopted (which we will
generally adopt as to our properties), the Treasury Regulations
under Section 743 of the Internal Revenue Code require a
portion of the Section 743(b) adjustment that is
attributable to recovery property under Section 168 of the
Internal Revenue Code whose book basis is in excess of its tax
basis to be depreciated over the remaining cost recovery period
for the propertys unamortized Book-Tax Disparity. Under
Treasury
Regulation Section 1.167(c)-1(a)(6),
a Section 743(b) adjustment attributable to property
subject to depreciation under Section 167 of the Internal
Revenue Code, rather than cost recovery deductions under
Section 168, is generally required to be depreciated using
either the straight-line method or the 150% declining balance
method. Under our partnership agreement, our general partner is
authorized to take a position to preserve the uniformity of
units even if that position is not consistent with these and any
other Treasury Regulations. Please read Uniformity
of units.
Although Vinson & Elkins L.L.P. is unable to opine as
to the validity of this approach because there is no direct or
indirect controlling authority on this issue, we intend to
depreciate the portion of a Section 743(b) adjustment
attributable to unrealized appreciation in the value of
Contributed Property, to the extent of any unamortized Book-Tax
Disparity, using a rate of depreciation or amortization derived
from the depreciation or amortization method and useful life
applied to the propertys
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Material tax
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unamortized Book-Tax Disparity, or treat that portion as
non-amortizable
to the extent attributable to property which is not amortizable.
This method is consistent with the regulations under
Section 743 of the Internal Revenue Code but is arguably
inconsistent with Treasury
Regulation Section 1.167(c)-1(a)(6),
which is not expected to directly apply to a material portion of
our assets. To the extent this Section 743(b) adjustment is
attributable to appreciation in value in excess of the
unamortized Book-Tax Disparity, we will apply the rules
described in the Treasury Regulations and legislative history.
If we determine that this position cannot reasonably be taken,
we may take a depreciation or amortization position under which
all purchasers acquiring units in the same month would receive
depreciation or amortization, whether attributable to common
basis or a Section 743(b) adjustment, based upon the same
applicable rate as if they had purchased a direct interest in
our assets. This kind of aggregate approach may result in lower
annual depreciation or amortization deductions than would
otherwise be allowable to some unitholders. Please read
Uniformity of units. A unitholders tax
basis for his common units is reduced by his share of our
deductions (whether or not such deductions were claimed on an
individuals income tax return) so that any position we
take that understates deductions will overstate the common
unitholders basis in his common units, which may cause the
unitholder to understate gain or overstate loss on any sale of
such units. Please read Disposition of common
unitsRecognition of gain or loss. The IRS may
challenge our position with respect to depreciating or
amortizing the Section 743(b) adjustment we take to
preserve the uniformity of the units. If such a challenge were
sustained, the gain from the sale of units might be increased
without the benefit of additional deductions.
A Section 754 election is advantageous if the
transferees tax basis in his units is higher than the
units share of the aggregate tax basis of our assets
immediately prior to the transfer. In that case, as a result of
the election, the transferee would have, among other items, a
greater amount of depreciation and depletion deductions and his
share of any gain or loss on a sale of our assets would be less.
Conversely, a Section 754 election is disadvantageous if
the transferees tax basis in his units is lower than those
units share of the aggregate tax basis of our assets
immediately prior to the transfer. Thus, the fair market value
of the units may be affected either favorably or unfavorably by
the election. A basis adjustment is required regardless of
whether a Section 754 election is made in the case of a
transfer of an interest in us if we have a substantial built-in
loss immediately after the transfer, or if we distribute
property and have a substantial basis reduction. Generally a
built-in loss or a basis reduction is substantial if it exceeds
$250,000.
The calculations involved in the Section 754 election are
complex and will be made on the basis of assumptions as to the
value of our assets and other matters. For example, the
allocation of the Section 743(b) adjustment among our
assets must be made in accordance with the Internal Revenue
Code. The IRS could seek to reallocate some or all of any
Section 743(b) adjustment allocated by us to our tangible
assets to goodwill instead. Goodwill, as an intangible asset, is
generally either nonamortizable or amortizable over a longer
period of time or under a less accelerated method than our
tangible assets. We cannot assure you that the determinations we
make will not be successfully challenged by the IRS and that the
deductions resulting from them will not be reduced or disallowed
altogether. Should the IRS require a different basis adjustment
to be made, and should, in our opinion, the expense of
compliance exceed the benefit of the election, we may seek
permission from the IRS to revoke our Section 754 election.
If permission is granted, a subsequent purchaser of units may be
allocated more income than he would have been allocated had the
election not been revoked.
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TAX
TREATMENT OF OPERATIONS
Accounting method
and taxable year
We use the year ending December 31 as our taxable year and the
accrual method of accounting for federal income tax purposes.
Each unitholder will be required to include in income his share
of our income, gain, loss and deduction for our taxable year
ending within or with his taxable year. In addition, a
unitholder who has a taxable year ending on a date other than
December 31 and who disposes of all of his units following the
close of our taxable year but before the close of his taxable
year must include his share of our income, gain, loss and
deduction in income for his taxable year, with the result that
he will be required to include in income for his taxable year
his share of more than one year of our income, gain, loss and
deduction. Please read Disposition of common
unitsAllocations between transferors and transferees.
Initial tax
basis, depreciation and amortization
The tax basis of our assets will be used for purposes of
computing depreciation and cost recovery deductions and,
ultimately, gain or loss on the disposition of these assets. The
federal income tax burden associated with the difference between
the fair market value of our assets and their tax basis
immediately prior to this offering will be borne by our general
partner. Please read Tax consequences of unit
ownershipAllocation of income, gain, loss and
deduction.
To the extent allowable, we may elect to use the depreciation
and cost recovery methods that will result in the largest
deductions being taken in the early years after assets subject
to these allowances are placed in service. Please read
Uniformity of units. Property we subsequently
acquire or construct may be depreciated using accelerated
methods permitted by the Internal Revenue Code.
If we dispose of depreciable property by sale, foreclosure or
otherwise, all or a portion of any gain, determined by reference
to the amount of depreciation previously deducted and the nature
of the property, may be subject to the recapture rules and taxed
as ordinary income rather than capital gain. Similarly, a
unitholder who has taken cost recovery or depreciation
deductions with respect to property we own will likely be
required to recapture some or all of those deductions as
ordinary income upon a sale of his interest in us. Please read
Tax consequences of unit ownershipAllocation
of income, gain, loss and deduction and
Disposition of common unitsRecognition of gain
or loss.
The costs incurred in selling our units (called
syndication expenses) must be capitalized and cannot
be deducted currently, ratably or upon our termination. There
are uncertainties regarding the classification of costs as
organization expenses, which may be amortized by us, and as
syndication expenses, which may not be amortized by us. The
underwriting discounts we incur will be treated as syndication
expenses.
Valuation and tax
basis of our properties
The federal income tax consequences of the ownership and
disposition of units will depend in part on our estimates of the
relative fair market values, and the initial tax bases, of our
assets. Although we may from time to time consult with
professional appraisers regarding valuation matters, we will
make many of the relative fair market value estimates ourselves.
These estimates and determinations of basis are subject to
challenge and will not be binding on the IRS or the courts. If
the estimates of fair market value or basis are later found to
be incorrect, the character and amount of items of income, gain,
loss or deductions previously reported by unitholders might
change, and unitholders might be required to adjust their tax
liability for prior years and incur interest and penalties with
respect to those adjustments.
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DISPOSITION
OF COMMON UNITS
Recognition of
gain or loss
Gain or loss will be recognized on a sale of units equal to the
difference between the unitholders amount realized and the
unitholders tax basis for the units sold. A
unitholders amount realized will be measured by the sum of
the cash or the fair market value of other property received by
him plus his share of our nonrecourse liabilities attributable
to the common units sold. Because the amount realized includes a
unitholders share of our nonrecourse liabilities, the gain
recognized on the sale of units could result in a tax liability
in excess of any cash received from the sale.
Prior distributions from us in excess of cumulative net taxable
income for a common unit that decreased a unitholders tax
basis in that common unit will, in effect, become taxable income
if the common unit is sold at a price greater than the
unitholders tax basis in that common unit, even if the
price received is less than his original cost.
Except as noted below, gain or loss recognized by a unitholder,
other than a dealer in units, on the sale or
exchange of a unit held for more than one year will generally be
taxable as capital gain or loss. Capital gain recognized by an
individual on the sale of units held more than twelve months
will generally be taxed at a maximum rate of 15%. However, a
portion of this gain or loss, which will likely be substantial,
will be separately computed and taxed as ordinary income or loss
under Section 751 of the Internal Revenue Code to the
extent attributable to assets giving rise to depreciation
recapture or other unrealized receivables or to
inventory items we own. The term unrealized
receivables includes potential recapture items, including
depreciation recapture. Ordinary income attributable to
unrealized receivables, inventory items and depreciation
recapture may exceed net taxable gain realized upon the sale of
a unit and may be recognized even if there is a net taxable loss
realized on the sale of a unit. Thus, a unitholder may recognize
both ordinary income and a capital loss upon a sale of units.
Net capital losses may offset capital gains and no more than
$3,000 of ordinary income, in the case of individuals, and may
only be used to offset capital gains in the case of corporations.
The IRS has ruled that a partner who acquires interests in a
partnership in separate transactions must combine those
interests and maintain a single adjusted tax basis for all those
interests. Upon a sale or other disposition of less than all of
those interests, a portion of that tax basis must be allocated
to the interests sold using an equitable
apportionment method, which generally means that the tax
basis allocated to the interest sold equals an amount that bears
the same relation to the partners tax basis in his entire
interest in the partnership as the value of the interest sold
bears to the value of the partners entire interest in the
partnership. Treasury Regulations under Section 1223 of the
Internal Revenue Code allow a selling unitholder who can
identify common units transferred with an ascertainable holding
period to elect to use the actual holding period of the common
units transferred. Thus, according to the ruling, a common
unitholder will be unable to select high or low basis common
units to sell as would be the case with corporate stock, but,
according to the regulations, may designate specific common
units sold for purposes of determining the holding period of
units transferred. A unitholder electing to use the actual
holding period of common units transferred must consistently use
that identification method for all subsequent sales or exchanges
of common units. A unitholder considering the purchase of
additional units or a sale of common units purchased in separate
transactions is urged to consult his tax advisor as to the
possible consequences of this ruling and application of the
Treasury Regulations.
Specific provisions of the Internal Revenue Code affect the
taxation of some financial products and securities, including
partnership interests, by treating a taxpayer as having sold an
appreciated
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Material tax
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partnership interest, one in which gain would be recognized if
it were sold, assigned or terminated at its fair market value,
if the taxpayer or related persons enter(s) into:
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a short sale;
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an offsetting notional principal contract; or
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a futures or forward contract with respect to the partnership
interest or substantially identical property.
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Moreover, if a taxpayer has previously entered into a short
sale, an offsetting notional principal contract or a futures or
forward contract with respect to the partnership interest, the
taxpayer will be treated as having sold that position if the
taxpayer or a related person then acquires the partnership
interest or substantially identical property. The Secretary of
the Treasury is also authorized to issue regulations that treat
a taxpayer that enters into transactions or positions that have
substantially the same effect as the preceding transactions as
having constructively sold the financial position.
Allocations
between transferors and transferees
In general, our taxable income or loss will be determined
annually, will be prorated on a monthly basis and will be
subsequently apportioned among the unitholders in proportion to
the number of units owned by each of them as of the opening of
the applicable exchange on the first business day of the month,
which we refer to in this prospectus as the Allocation
Date. However, gain or loss realized on a sale or other
disposition of our assets other than in the ordinary course of
business will be allocated among the unitholders on the
Allocation Date in the month in which that gain or loss is
recognized. As a result, a unitholder transferring units may be
allocated income, gain, loss and deduction realized after the
date of transfer.
The use of this method may not be permitted under existing
Treasury Regulations. Accordingly, Vinson & Elkins
L.L.P. is unable to opine on the validity of this method of
allocating income and deductions between transferor and
transferee unitholders. We use this method because it is not
administratively feasible to make these allocations on a more
frequent basis. If this method is not allowed under the Treasury
Regulations, or only applies to transfers of less than all of
the unitholders interest, our taxable income or losses
might be reallocated among the unitholders. We are authorized to
revise our method of allocation between transferor and
transferee unitholders, as well as unitholders whose interests
vary during a taxable year, to conform to a method permitted
under future Treasury Regulations.
A unitholder who owns units at any time during a quarter and who
disposes of them prior to the record date set for a cash
distribution for that quarter will be allocated items of our
income, gain, loss and deductions attributable to that quarter
but will not be entitled to receive that cash distribution.
Notification
requirements
A unitholder who sells any of his units is generally required to
notify us in writing of that sale within 30 days after the
sale (or, if earlier, January 15 of the year following the
sale). A purchaser of units who purchases units from another
unitholder is also generally required to notify us in writing of
that purchase within 30 days after the purchase. Upon
receiving such notifications, we are required to notify the IRS
of any such transfer of units and to furnish specified
information to the transferor and transferee. Failure to notify
us of a transfer of units may, in some cases, lead to the
imposition of penalties. However, these reporting requirements
do not apply to a sale by an individual who is a citizen of the
U.S. and who effects the sale or exchange through a broker who
will satisfy such requirements.
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Constructive
termination
We will be considered to have been terminated for tax purposes
if there is a sale or exchange of 50.0% or more of the total
interests in our capital and profits or assets within a
twelve-month period. A constructive termination results in the
closing of our taxable year for all unitholders. In the case of
a unitholder reporting on a taxable year other than a taxable
year ending December 31, the closing of our taxable year
may result in more than twelve months of our taxable income or
loss being includable in his taxable income for the year of
termination. We would be required to make new tax elections
after a termination, including a new election under
Section 754 of the Internal Revenue Code, and a termination
would result in a deferral of our deductions for depreciation. A
termination could also result in penalties if we were unable to
determine that the termination had occurred. Moreover, a
termination might either accelerate the application of, or
subject us to, any tax legislation enacted before the
termination.
Because we cannot match transferors and transferees of units, we
must maintain uniformity of the economic and tax characteristics
of the units to a purchaser of these units. In the absence of
uniformity, we may be unable to completely comply with a number
of federal income tax requirements, both statutory and
regulatory. A lack of uniformity can result from a literal
application of Treasury
Regulation Section 1.167(c)-1(a)(6).
Any non-uniformity could have a negative impact on the value of
the units. Please read Tax consequences of unit
ownershipSection 754 election.
We intend to depreciate the portion of a Section 743(b)
adjustment attributable to unrealized appreciation in the value
of Contributed Property, to the extent of any unamortized
Book-Tax Disparity, using a rate of depreciation or amortization
derived from the depreciation or amortization method and useful
life applied to the propertys unamortized Book-Tax
Disparity, or treat that portion as nonamortizable, to the
extent attributable to property which is not amortizable,
consistent with the regulations under Section 743 of the
Internal Revenue Code, even though that position may be
inconsistent with Treasury
Regulation Section 1.167(c)-1(a)(6),
which is not expected to directly apply to a material portion of
our assets. Please read Tax consequences of unit
ownershipSection 754 election. To the extent
that the Section 743(b) adjustment is attributable to
appreciation in value in excess of the unamortized Book-Tax
Disparity, we will apply the rules described in the Treasury
Regulations and legislative history. If we determine that this
position cannot reasonably be taken, we may adopt a depreciation
and amortization position under which all purchasers acquiring
units in the same month would receive depreciation and
amortization deductions, whether attributable to a common basis
or Section 743(b) adjustment, based upon the same
applicable rate as if they had purchased a direct interest in
our property. If this position is adopted, it may result in
lower annual depreciation and amortization deductions than would
otherwise be allowable to some unitholders and risk the loss of
depreciation and amortization deductions not taken in the year
that these deductions are otherwise allowable. This position
will not be adopted if we determine that the loss of
depreciation and amortization deductions will have a material
adverse effect on the unitholders. If we choose not to utilize
this aggregate method, we may use any other reasonable
depreciation and amortization method to preserve the uniformity
of the intrinsic tax characteristics of any units that would not
have a material adverse effect on the unitholders. Our counsel,
Vinson & Elkins L.L.P., is unable to opine on the
validity of any of these positions. The IRS may challenge any
method of depreciating the Section 743(b) adjustment
described in this paragraph. If this challenge were sustained,
the uniformity of units might be affected, and the gain from the
sale of units might be increased without the benefit of
additional deductions. Please read Disposition of
common unitsRecognition of gain or loss.
170
Material tax
consequences
TAX-EXEMPT
ORGANIZATIONS AND OTHER INVESTORS
Ownership of units by employee benefit plans, other tax-exempt
organizations, non-resident aliens, foreign corporations and
other foreign persons raises issues unique to those investors
and, as described below, may have substantially adverse tax
consequences to them.
Employee benefit plans and most other organizations exempt from
federal income tax, including individual retirement accounts and
other retirement plans, are subject to federal income tax on
unrelated business taxable income. Virtually all of our income
allocated to a unitholder that is a tax-exempt organization will
be unrelated business taxable income and will be taxable to them.
Non-resident aliens and foreign corporations, trusts or estates
that own units will be considered to be engaged in business in
the U.S. because of the ownership of units. As a consequence,
they will be required to file federal tax returns to report
their share of our income, gain, loss or deduction and pay
federal income tax at regular rates on their share of our net
income or gain. Moreover, under rules applicable to publicly
traded partnerships, we will withhold tax at the highest
applicable effective tax rate from cash distributions made
quarterly to foreign unitholders. Each foreign unitholder must
obtain a taxpayer identification number from the IRS and submit
that number to our transfer agent on a
Form W-8BEN
or applicable substitute form in order to obtain credit for
these withholding taxes. A change in applicable law may require
us to change these procedures.
In addition, because a foreign corporation that owns units will
be treated as engaged in a U.S. trade or business, that
corporation may be subject to the U.S. branch profits tax at a
rate of 30%, in addition to regular federal income tax, on its
share of our income and gain, as adjusted for changes in the
foreign corporations U.S. net equity,
which is effectively connected with the conduct of a U.S. trade
or business. That tax may be reduced or eliminated by an income
tax treaty between the U.S. and the country in which the foreign
corporate unitholder is a qualified resident. In
addition, this type of unitholder is subject to special
information reporting requirements under Section 6038C of
the Internal Revenue Code.
Under a ruling of the IRS, a foreign unitholder who sells or
otherwise disposes of a unit will be subject to federal income
tax on gain realized on the sale or disposition of that unit to
the extent that this gain is effectively connected with a U.S.
trade or business of the foreign unitholder. Because a foreign
unitholder is considered to be engaged in trade or business in
the U.S. by virtue of the ownership of units, under this ruling
a foreign unitholder who sells or otherwise disposes of a unit
generally will be subject to federal income tax on gain realized
on the sale or other disposition of units. Apart from the
ruling, a foreign unitholder will not be taxed or subject to
withholding upon the sale or disposition of a unit if he has
owned less than 5% in value of the units during the five-year
period ending on the date of the disposition and if the units
are regularly traded on an established securities market at the
time of the sale or disposition.
Information
returns and audit procedures
We intend to furnish to each unitholder, within 90 days
after the close of each taxable year, specific tax information,
including a
Schedule K-1,
which describes each unitholders share of our income,
gain, loss and deduction for our preceding taxable year. In
preparing this information, which will not be reviewed by
counsel, we will take various accounting and reporting
positions, some of which have been mentioned earlier, to
determine each unitholders share of income, gain, loss and
deduction. We cannot assure you that those positions will yield
a result that conforms to the requirements of the Internal
Revenue Code, Treasury Regulations or administrative
interpretations of the IRS. Neither we nor Vinson &
Elkins L.L.P. can assure prospective unitholders that the IRS
will not successfully contend in
171
Material tax
consequences
court that those positions are impermissible. Any challenge by
the IRS could negatively affect the value of the units.
The IRS may audit our federal income tax information returns.
Adjustments resulting from an IRS audit may require each
unitholder to adjust a prior years tax liability, and
possibly may result in an audit of his return. Any audit of a
unitholders return could result in adjustments not related
to our returns as well as those related to our returns.
Partnerships generally are treated as separate entities for
purposes of federal tax audits, judicial review of
administrative adjustments by the IRS and tax settlement
proceedings. The tax treatment of partnership items of income,
gain, loss and deduction are determined in a partnership
proceeding rather than in separate proceedings with the
partners. The Internal Revenue Code requires that one partner be
designated as the Tax Matters Partner for these
purposes. Our partnership agreement names our general partner as
our Tax Matters Partner.
The Tax Matters Partner will make some elections on our behalf
and on behalf of unitholders. In addition, the Tax Matters
Partner can extend the statute of limitations for assessment of
tax deficiencies against unitholders for items in our returns.
The Tax Matters Partner may bind a unitholder with less than a
1% profits interest in us to a settlement with the IRS unless
that unitholder elects, by filing a statement with the IRS, not
to give that authority to the Tax Matters Partner. The Tax
Matters Partner may seek judicial review, by which all the
unitholders are bound, of a final partnership administrative
adjustment and, if the Tax Matters Partner fails to seek
judicial review, judicial review may be sought by any unitholder
having at least a 1% interest in profits or by any group of
unitholders having in the aggregate at least a 5% interest in
profits. However, only one action for judicial review will go
forward, and each unitholder with an interest in the outcome may
participate in that action.
A unitholder must file a statement with the IRS identifying the
treatment of any item on his federal income tax return that is
not consistent with the treatment of the item on our return.
Intentional or negligent disregard of this consistency
requirement may subject a unitholder to substantial penalties.
Nominee
reporting
Persons who hold an interest in us as a nominee for another
person are required to furnish to us:
(a) the name, address and taxpayer identification
number of the beneficial owner and the nominee;
(b) a statement regarding whether the beneficial
owner is:
(i) a person that is not a U.S. person;
(ii) a foreign government, an international
organization or any wholly owned agency or instrumentality of
either of the foregoing; or
(iii) a tax-exempt entity;
(c) the amount and description of units held,
acquired or transferred for the beneficial owner; and
(d) specific information including the dates of
acquisitions and transfers, means of acquisitions and transfers,
and acquisition cost for purchases, as well as the amount of net
proceeds from sales.
Brokers and financial institutions are required to furnish
additional information, including whether they are U.S. persons
and specific information on units they acquire, hold or transfer
for their own account. A penalty of $50 per failure, up to a
maximum of $100,000 per calendar year, is imposed by the
Internal Revenue Code for failure to report that information to
us. The nominee is required to supply the beneficial owner of
the units with the information furnished to us.
172
Material tax
consequences
Accuracy-related
penalties
An additional tax equal to 20% of the amount of any portion of
an underpayment of tax that is attributable to one or more
specified causes, including negligence or disregard of rules or
regulations, substantial understatements of income tax and
substantial valuation misstatements, is imposed by the Internal
Revenue Code. No penalty will be imposed, however, for any
portion of an underpayment if it is shown that there was a
reasonable cause for that portion and that the taxpayer acted in
good faith regarding that portion.
For individuals, a substantial understatement of income tax in
any taxable year exists if the amount of the understatement
exceeds the greater of 10% of the tax required to be shown on
the return for the taxable year or $5,000. The amount of any
understatement subject to penalty generally is reduced if any
portion is attributable to a position adopted on the return:
(1) for which there is, or was, substantial
authority; or
(2) as to which there is a reasonable basis if the
pertinent facts of that position are adequately disclosed on the
return.
If any item of income, gain, loss or deduction included in the
distributive shares of unitholders might result in that kind of
an understatement of income for which no
substantial authority exists, we must disclose the
pertinent facts on our return. In addition, we will make a
reasonable effort to furnish sufficient information for
unitholders to make adequate disclosure on their returns and to
take other actions as may be appropriate to permit unitholders
to avoid liability for this penalty. More stringent rules apply
to tax shelters, which we do not believe includes us.
A substantial valuation misstatement exists if the value of any
property, or the adjusted basis of any property, claimed on a
tax return is 150% or more of the amount determined to be the
correct amount of the valuation or adjusted basis. For
individuals, no penalty is imposed unless the portion of the
underpayment attributable to a substantial valuation
misstatement exceeds $5,000 ($10,000 for most corporations). If
the valuation claimed on a return is 200% or more than the
correct valuation, the penalty imposed increases to 40%.
Reportable
transactions
If we were to engage in a reportable transaction, we
(and possibly you and others) would be required to make a
detailed disclosure of the transaction to the IRS. A transaction
may be a reportable transaction based upon any of several
factors, including the fact that it is a type of tax avoidance
transaction publicly identified by the IRS as a listed
transaction or a transaction of interest or
that it produces certain kinds of losses for partnerships,
individuals, S corporations and trusts in excess of
$2 million in any single year, or $4 million in any
combination of six successive tax years. Our participation in a
reportable transaction could increase the likelihood that our
federal income tax information return (and possibly your tax
return) would be audited by the IRS. Please read
Administrative mattersInformation returns and
audit procedures.
Moreover, if we were to participate in a reportable transaction
with a significant purpose to avoid or evade tax, or in any
listed transaction, you may be subject to the following
provisions of the American Jobs Creation Act of 2004:
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accuracy-related penalties with a broader scope, significantly
narrower exceptions, and potentially greater amounts than
described above at Administrative
mattersAccuracy-related penalties;
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for those persons otherwise entitled to deduct interest on
federal tax deficiencies, nondeductibility of interest on any
resulting tax liability; and
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Material tax
consequences
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in the case of a listed transaction, an extended statute of
limitations.
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We do not expect to engage in any reportable
transactions.
STATE,
LOCAL, FOREIGN AND OTHER TAX CONSIDERATIONS
In addition to federal income taxes, you likely will be subject
to other taxes, such as state, local and foreign income taxes,
unincorporated business taxes, and estate, inheritance or
intangible taxes that may be imposed by the various
jurisdictions in which we do business or own property or in
which you are a resident. Although an analysis of those various
taxes is not presented here, each prospective unitholder should
consider their potential impact on his investment in us. We will
initially own property or do business in the states of Kansas,
Oklahoma, Texas, Utah and Wyoming. Each of these states, other
than Texas and Wyoming, currently imposes a personal income tax,
and all of theses states also impose taxes on income of
corporations and other entities. We may also own property or do
business in other jurisdictions in the future. Although you may
not be required to file a return and pay taxes in some
jurisdictions if your income from that jurisdiction falls below
the filing and payment requirement, you will be required to file
income tax returns and to pay income taxes in many of these
jurisdictions in which we do business or own property and may be
subject to penalties for failure to comply with those
requirements. In some jurisdictions, tax losses may not produce
a tax benefit in the year incurred and may not be available to
offset income in subsequent taxable years. Some of the
jurisdictions may require us, or we may elect, to withhold a
percentage of income from amounts to be distributed to a
unitholder who is not a resident of the jurisdiction.
Withholding, the amount of which may be greater or less than a
particular unitholders income tax liability to the
jurisdiction, generally does not relieve a nonresident
unitholder from the obligation to file an income tax return.
Amounts withheld will be treated as if distributed to
unitholders for purposes of determining the amounts distributed
by us. Please read Tax consequences of unit
ownershipEntity-level collections. Based on
current law and our estimate of our future operations, our
general partner anticipates that any amounts required to be
withheld will not be material.
It is the responsibility of each unitholder to investigate
the legal and tax consequences, under the laws of pertinent
jurisdictions, of his investment in us. Accordingly, each
prospective unitholder is urged to consult, and depend upon, his
tax counsel or other advisor with regard to those matters.
Further, it is the responsibility of each unitholder to file all
state, local and foreign, as well as U.S. federal tax returns,
that may be required of him. Vinson & Elkins L.L.P.
has not rendered an opinion on the state, local or foreign tax
consequences of an investment in us.
174
Investment
in Western Gas Partners, LP by employee benefit plans
An investment in us by an employee benefit plan is subject to
additional considerations because the investments of these plans
are subject to the fiduciary responsibility and prohibited
transaction provisions of ERISA and the restrictions imposed by
Section 4975 of the Internal Revenue Code. For these
purposes the term employee benefit plan includes,
but is not limited to, qualified pension, profit-sharing and
stock bonus plans, Keogh plans, simplified employee pension
plans and tax deferred annuities or IRAs established or
maintained by an employer or employee organization. Among other
things, consideration should be given to:
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whether the investment is prudent under
Section 404(a)(1)(B) of ERISA;
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whether in making the investment, the plan will satisfy the
diversification requirements of Section 404(a)(1)(C) of
ERISA; and
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whether the investment will result in recognition of unrelated
business taxable income by the plan and, if so, the potential
after-tax investment return. Please read Material tax
consequencesTax-Exempt organizations and other
investors.
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The person with investment discretion with respect to the assets
of an employee benefit plan, often called a fiduciary, should
determine whether an investment in us is authorized by the
appropriate governing instrument and is a proper investment for
the plan.
Section 406 of ERISA and Section 4975 of the Internal
Revenue Code prohibit employee benefit plans, and IRAs that are
not considered part of an employee benefit plan, from engaging
in specified transactions involving plan assets with
parties that, with respect to the plan, are parties in
interest under ERISA or disqualified persons
under the Internal Revenue Code.
In addition to considering whether the purchase of common units
is a prohibited transaction, a fiduciary should consider whether
the plan will, by investing in us, be deemed to own an undivided
interest in our assets, with the result that our operations
would be subject to the regulatory restrictions of ERISA,
including its prohibited transaction rules, as well as the
prohibited transaction rules of the Internal Revenue Code.
The Department of Labor regulations provide guidance with
respect to whether, in certain circumstances, the assets of an
entity in which employee benefit plans acquire equity interests
would be deemed plan assets. Under these
regulations, an entitys assets would not be considered to
be plan assets if, among other things:
(a) the equity interests acquired by the employee
benefit plan are publicly offered securitiesi.e., the
equity interests are widely held by 100 or more investors
independent of the issuer and each other, are freely
transferable and are registered under some provision of the
federal securities laws;
(b) the entity is an operating
company,i.e., it is primarily engaged in the
production or sale of a product or service, other than the
investment of capital, either directly or through a
majority-owned subsidiary or subsidiaries; or
(c) there is no significant investment by benefit
plan investors, which is defined to mean that less than 25% of
the value of each class of equity interest is held by the
employee benefit plans referred to above, IRAs and other
employee benefit plans not subject to ERISA, including
governmental plans.
Our assets should not be considered plan assets
under these regulations because it is expected that the
investment will satisfy the requirements in (a) above.
In light of the serious penalties imposed on persons who engage
in prohibited transactions or other violations, plan fiduciaries
contemplating a purchase of common units should consult with
their own counsel regarding the consequences under ERISA and the
Internal Revenue Code.
175
We are offering our common units described in this prospectus
through the underwriters named below. UBS Securities LLC is the
representative of the underwriters and the sole bookrunning
manager of this offering. Subject to the terms and conditions of
the underwriting agreement, dated as of the date of this
prospectus, which will be filed as an exhibit to the
registration statement, each of the underwriters has severally
agreed to purchase the number of common units listed next to its
name in the following table:
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Number of
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Underwriters
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common
units
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UBS Securities LLC
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Total
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18,750,000
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The underwriting agreement provides that the underwriters must
buy all of the common units if they buy any of them. However,
the underwriters are not required to take or pay for the common
units covered by the underwriters option to purchase
additional common units described below.
Our common units and the common units to be sold upon the
exercise of the underwriters option to purchase additional
common units, if any, are offered subject to a number of
conditions, including:
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receipt and acceptance of our common units by the underwriters;
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the validity of the representations and warranties made to the
underwriters;
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the absence of any material change in the financial markets;
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our delivery of customary closing documents to the underwriters;
and
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the underwriters right to reject orders in whole or in
part.
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We have been advised by the representative that the underwriters
intend to make a market in our common units, but they are not
obligated to do so and may discontinue making a market at any
time without notice.
OPTION
TO PURCHASE ADDITIONAL COMMON UNITS
We have granted the underwriters an option to purchase up to
2,812,500 additional common units. This option may be exercised
if the underwriters sell more than 18,750,000 common units in
connection with this offering. The underwriters have
30 days from the date of this prospectus to exercise this
option. If the underwriters exercise this option, they will each
purchase additional common units approximately in proportion to
the amounts specified in the table above. If and to the extent
the underwriters exercise their option, the number of units
purchased by the underwriters pursuant to such exercise will be
issued to the public and the remainder, if any, will be issued
to Anadarko. The net proceeds from any exercise of the
underwriters option to purchase additional common units
will be used to reimburse Anadarko for capital expenditures it
incurred with respect to the assets contributed to us during the
two-year period prior to this offering.
COMMISSIONS
AND DISCOUNTS
Common units sold by the underwriters to the public will
initially be offered at the initial offering price set forth on
the cover of this prospectus. Any common units sold by the
underwriters to securities dealers may be sold at a discount of
up to $ per common unit from the
initial public offering price. Any of these securities dealers
may resell any common units purchased from the underwriters to
other brokers or dealers at a discount of up to
$ per common unit from the initial
public offering price. If all the common units are not sold at
the initial public offering price, the representatives may
change the offering price and the other selling terms. Sales of
common units made outside of the U.S. may be
176
Underwriting
made by affiliates of the underwriters. Upon execution of the
underwriting agreement, the underwriters will be obligated to
purchase the common units at the prices and upon the terms
stated therein, and, as a result, will thereafter bear any risk
associated with changing the offering price to the public or
other selling terms.
The following table shows the per unit and total underwriting
discounts we will pay to the underwriters, assuming both no
exercise and full exercise of the underwriters option to
purchase up to an additional 2,812,500 units.
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No
exercise
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Full
exercise
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Per Unit
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$
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$
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Total
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$
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$
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We estimate that the total expenses of this offering payable by
us, not including the underwriting discounts and the structuring
fee, will be approximately $3.0 million.
In addition, we will pay the representatives a structuring fee
of $
of the gross proceeds of this offering and any exercise of the
underwriters option to purchase additional common units
for their role in the evaluation, analysis and structuring of
our partnership.
NO
SALES OF SIMILAR SECURITIES
We, Anadarko and our general partner and its affiliates,
including the executive officers and directors of our general
partner, and the participants in our directed unit program will
enter into
lock-up
agreements with the underwriters. Under these agreements, we and
each of these persons may not, without the prior written
approval of UBS Securities LLC, offer, sell, contract to sell or
otherwise dispose of or hedge our common units or securities
convertible into or exchangeable for our common units, enter
into any swap or other agreement that transfers, in whole or in
part, any of the economic consequences of ownership of the
common units, make any demand for or exercise any right or file
or cause to be filed a registration statement with respect to
the registration of any common units or securities convertible,
exercisable or exchangeable into common units or any of our
other securities or publicly disclose the intention to do any of
the foregoing. These restrictions will be in effect for a period
of 180 days after the date of this prospectus. The
lock-up
period will be extended under certain circumstances where either
(i) we release our earnings or announce material news or a
material event during the 15 calendar days plus three business
days preceding the termination of the
180-day
period or (ii) we pre-announce that we will release our
earnings during the 16 days following the termination of
the 180-day
period. In either case, the restrictions described above will
continue to apply until the expiration of the period that
extends 15 calendar days plus three business days after the
date of the issuance of the earnings release or the announcement
of the material news or material event, as the case may be. At
any time and without public notice, UBS Securities LLC may in
its discretion, release all or some of the securities from these
lock-up
agreements. The representatives have no present understanding or
intent to release any of the securities from these
lock-up
agreements.
We and our general partner and certain of its affiliates, have
agreed to indemnify the underwriters and their controlling
persons against certain liabilities, including liabilities under
the Securities Act and liabilities incurred in connection with
the directed unit program referred to below. If we are unable to
provide this indemnification, we will contribute to payments the
underwriters and their controlling persons may be required to
make in respect of those liabilities.
177
Underwriting
We have applied to list our common units on the New York Stock
Exchange under the trading symbol WES.
PRICE
STABILIZATION, SHORT POSITIONS
In connection with this offering, the underwriters may engage in
activities that stabilize, maintain or otherwise affect the
price of our common units including:
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stabilizing transactions;
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short sales;
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purchases to cover positions created by short sales;
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imposition of penalty bids; and
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syndicate covering transactions.
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Stabilizing transactions consist of bids or purchases made for
the purpose of preventing or retarding a decline in the market
price of our common units while this offering is in progress.
These transactions may also include making short sales of our
common units, which involves the sale by the underwriters of a
greater number of common units than they are required to
purchase in this offering, and purchasing common units on the
open market to cover positions created by short sales. Short
sales may be covered short sales, which are short
positions in an amount not greater than the underwriters
option to purchase additional common units referred to above, or
may be naked short sales, which are short positions
in excess of that amount.
The underwriters may close out any covered short position by
either exercising their option to purchase additional common
units, in whole or in part, or by purchasing common units in the
open market. In making this determination, the underwriters will
consider, among other things, the price of common units
available for purchase in the open market as compared to the
price at which they may purchase common units through their
option to purchase additional common units.
Naked short sales are in excess of the underwriters option
to purchase additional common units. The underwriters must close
out any naked short position by purchasing common units in the
open market. A naked short position is more likely to be created
if the underwriters are concerned that there may be downward
pressure on the price of the common units in the open market
that could adversely affect investors who purchased in this
offering.
The underwriters also may impose a penalty bid. This occurs when
a particular underwriter repays to the underwriters a portion of
the underwriting discount received by it because the
representatives have repurchased common units sold by or for the
account of that underwriter in stabilizing or short covering
transactions.
As a result of these activities, the price of our common units
may be higher than the price that otherwise might exist in the
open market. If these activities are commenced, they may be
discontinued by the underwriters at any time. The underwriters
may carry out these transactions on the New York Stock Exchange,
in the over-the-counter market or otherwise.
DETERMINATION
OF OFFERING PRICE
Prior to this offering, there has been no public market for our
common units. The initial public offering price was determined
by negotiation by us and the representatives of the
underwriters. The principal factors considered in determining
the initial public offering price include:
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the information set forth in this prospectus and otherwise
available to the representatives;
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178
Underwriting
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our history and prospects, and the history and prospects of the
industry in which we compete;
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our past and present financial performance and an assessment of
the directors and officers of our general partner;
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our prospects for future earnings and cash flow and the present
state of our development;
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the general condition of the securities markets at the time of
this offering;
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the recent market prices of, and demand for, publicly traded
common units of generally comparable master limited
partnerships; and
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other factors determined relevant by the underwriters and us.
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At our request, certain of the underwriters have reserved up
to
of the common units being offered by this prospectus for sale at
the initial public offering price to the officers, directors and
employees of our general partner and its affiliates, including
Anadarko, and certain other persons associated with us, as
designated by us. The sales will be made by UBS Financial
Services, Inc., an affiliate of UBS Securities LLC, through a
directed unit program. We do not know if these persons will
choose to purchase all or any portion of these reserved units,
but any purchases they make will reduce the number of units
available to the general public. Any reserved units not so
purchased will be offered by the underwriters to the general
public on the same basis as the other units offered by this
prospectus. These persons must commit to purchase no later than
before the open of business on the day following the date of
this prospectus, but in any event these persons are not
obligated to purchase common units and may not commit to
purchase common units prior to the effectiveness of the
registration statement relating to this offering. Any directed
unit participants purchasing these reserved units will be
subject to the restrictions described in No sale of
similar securities above.
A prospectus in electronic format may be made available on the
Internet sites or through other online services maintained by
one or more of the underwriters
and/or
selling group members participating in this offering, or by
their affiliates. In those cases, prospective investors may view
offering terms online and, depending upon the particular
underwriter or selling group member, prospective investors may
be allowed to place orders online. The underwriters may agree
with us to allocate a specific number of units for sale to
online brokerage account holders. Any such allocation for online
distributions will be made by the representatives on the same
basis as other allocations.
Other than the prospectus in electronic format, the information
on any underwriters or selling group members web
site and any information contained in any other web site
maintained by an underwriter or selling group member is not part
of the prospectus or the registration statement of which this
prospectus forms a part, has not been approved
and/or
endorsed by us or any underwriter or selling group member in its
capacity as underwriter or selling group member and should not
be relied upon by investors.
The underwriters have informed us that they do not intend to
confirm sales to discretionary accounts that exceed five percent
of the total number of units offered by them.
If you purchase common units offered in this prospectus, you may
be required to pay stamp taxes and other charges under the laws
and practices of the country of purchase, in addition to the
offering price listed on the cover page of this prospectus.
179
Underwriting
Certain of the underwriters and their affiliates have in the
past provided and may from time to time in the future provide
services to Anadarko and us for which they have received and, in
the future, will be entitled to receive, customary fees and
expenses. In particular:
|
|
Ø |
Affiliates of UBS Securities LLC
and
are lenders under Anadarkos $750 million credit
facility, under which we are a co-borrower;
|
|
|
Ø
|
In July 2007, UBS Securities LLC provided advisory services to
Anadarko in connection with the disposition of certain assets;
|
|
Ø
|
In the ordinary course of its business, Anadarko engages in
numerous interest rate and commodity hedging transactions with a
variety of counterparties, including affiliates of UBS
Securities LLC
and
; and
|
|
Ø
|
In April 2007, UBS Securities LLC served as a Co-Advisor, Joint
Lead Arranger and Joint Bookrunning Manager of Anadarkos
354-day
credit facility. An affiliate of UBS Securities LLC serves as
the Administrative Agent of this facility.
|
In addition, affiliates of UBS Securities LLC
and
are lenders under Anadarkos
354-day
credit facility. Anadarko has informed us that it intends to use
the $337.6 million of proceeds that we loan to it, and any
other proceeds that it receives from this offering, to repay a
portion of the amount outstanding under this facility, and the
affiliates of UBS Securities LLC
and
will receive their proportionate shares of any such repayment.
Because the Financial Industry Regulatory Authority, or the
FINRA (formerly known as the National Association of Securities
Dealers, Inc., or the NASD), views the common units offered
hereby as interests in a direct participation program, this
offering is being made in compliance with Rule 2810 of the
NASDs Conduct Rules (which are part of the FINRA rules).
Investor suitability with respect to the common units should be
judged similarly to the suitability with respect to other
securities that are listed for trading on a national securities
exchange.
180
Underwriting
Validity
of the common units
The validity of the common units will be passed upon for us by
Vinson & Elkins L.L.P., Houston, Texas. Certain legal
matters in connection with the common units offered hereby will
be passed upon for the underwriters by Andrews Kurth LLP,
Houston, Texas.
The combined financial statements of Western Gas Partners
Predecessor as of December 31, 2006 and 2005 and for each
of the years in the three-year period ended December 31,
2006, have been included herein in reliance upon the report of
KPMG LLP, independent registered public accounting firm,
appearing elsewhere herein, and upon the authority of said firm
as experts in accounting and auditing.
The balance sheet of Western Gas Partners, LP as of
August 21, 2007 and the balance sheet of Western Gas
Holdings, LLC as of August 21, 2007, have been included
herein in reliance upon the reports of KPMG LLP, independent
registered public accounting firm, appearing elsewhere herein,
and upon the authority of said firm as experts in accounting and
auditing.
The financial statements of MIGC, Inc. as of December 31,
2005 and for the period from January 1 to August 23, 2006
and for the year ended December 31, 2005, have been
included herein in reliance upon the report of KPMG LLP,
independent registered public accounting firm, appearing
elsewhere herein, and upon the authority of said firm as experts
in accounting and auditing.
Where
you can find more information
We have filed with the SEC a registration statement on
Form S-l
regarding the common units. This prospectus does not contain all
of the information found in the registration statement. For
further information regarding us and the common units offered by
this prospectus, you may desire to review the full registration
statement, including its exhibits and schedules, filed under the
Securities Act. The registration statement of which this
prospectus forms a part, including its exhibits and schedules,
may be inspected and copied at the public reference room
maintained by the SEC at 100 F Street, N.E.,
Room 1580, Washington, D.C. 20549. Copies of the
materials may also be obtained from the SEC at prescribed rates
by writing to the public reference room maintained by the SEC at
100 F Street, N.E., Room 1580,
Washington, D.C. 20549. You may obtain information on the
operation of the public reference room by calling the SEC at
1-800-SEC-0330.
The SEC maintains a web site on the Internet at
http://www.sec.gov.
Our registration statement, of which this prospectus constitutes
a part, can be downloaded from the SECs web site.
We intend to furnish our unitholders annual reports containing
our audited combined financial statements and to furnish or make
available to our unitholders quarterly reports containing our
unaudited interim financial information for the first three
fiscal quarters of each of our fiscal years.
181
Forward-looking
statements
Some of the information in this prospectus may contain
forward-looking statements. These statements can be identified
by the use of forward-looking terminology including
may, believe, expect,
anticipate, estimate,
continue, or other similar words. These statements
discuss future expectations, contain projections of results of
operations or of financial condition or state other
forward-looking information. These forward-looking
statements involve risks and uncertainties. When considering
these forward-looking statements, you should keep in mind the
risk factors and other cautionary statements in this prospectus.
The risk factors and other factors noted throughout this
prospectus could cause our actual results to differ materially
from those contained in any forward-looking statement.
182
Western Gas
Partners, LP
Index
to financial statements
|
|
|
|
|
WESTERN GAS PARTNERS, LP UNAUDITED PRO FORMA COMBINED
FINANCIAL STATEMENTS:
|
|
|
|
|
Introduction
|
|
|
F-2
|
|
Unaudited Pro Forma Combined Statement of Income
for the year ended December 31, 2006
|
|
|
F-4
|
|
Unaudited Pro Forma Combined Statement of Income
for the nine months ended September 30, 2007
|
|
|
F-5
|
|
Unaudited Pro Forma Combined Balance Sheet as of
September 30, 2007
|
|
|
F-6
|
|
Notes to the Unaudited Pro Forma Combined
Financial Statements
|
|
|
F-7
|
|
|
|
|
|
|
WESTERN GAS PARTNERS PREDECESSOR COMBINED FINANCIAL
STATEMENTS:
|
|
|
|
|
Report of Independent Registered Public
Accounting Firm
|
|
|
F-10
|
|
Combined Statements of Income for the years ended
December 31, 2006, 2005 and 2004
|
|
|
F-11
|
|
Combined Balance Sheets as of December 31,
2006 and 2005
|
|
|
F-12
|
|
Combined Statements of Cash Flows for the years
ended December 31, 2006, 2005 and 2004
|
|
|
F-13
|
|
Combined Statements of Parent Net Equity for the
years ended December 31, 2006, 2005 and 2004
|
|
|
F-14
|
|
Notes to Combined Financial Statements
|
|
|
F-15
|
|
Unaudited Combined Statements of Income for the
nine months ended September 30, 2007 and 2006
|
|
|
F-26
|
|
Unaudited Combined Balance Sheets as of
September 30, 2007 and December 31, 2006
|
|
|
F-27
|
|
Unaudited Combined Statements of Cash Flows for
the nine months ended September 30, 2007 and 2006
|
|
|
F-28
|
|
Unaudited Combined Statements of Parent Net
Equity for the nine months ended September 30, 2007 and
2006
|
|
|
F-29
|
|
Notes to the Unaudited Combined Financial
Statements
|
|
|
F-30
|
|
|
|
|
|
|
MIGC, INC. FINANCIAL STATEMENTS:
|
|
|
|
|
Report of Independent Registered Public
Accounting Firm
|
|
|
F-35
|
|
Statements of Income for the period from
January 1, 2006 through August 23, 2006 and for the
year ended December 31, 2005
|
|
|
F-36
|
|
Balance Sheet as of December 31, 2005
|
|
|
F-37
|
|
Statements of Cash Flows for the period from
January 1, 2006 through August 23, 2006 and for the
year ended December 31, 2005
|
|
|
F-38
|
|
Statements of Parent Net Equity for the period
from January 1, 2006 through August 23, 2006 and for
the year ended December 31, 2005
|
|
|
F-39
|
|
Notes to Financial Statements
|
|
|
F-40
|
|
|
|
|
|
|
WESTERN GAS PARTNERS, LP FINANCIAL STATEMENTS:
|
|
|
|
|
Report of Independent Registered Public
Accounting Firm
|
|
|
F-47
|
|
Balance Sheet as of August 21, 2007
|
|
|
F-48
|
|
Note to the Balance Sheet
|
|
|
F-49
|
|
|
|
|
|
|
WESTERN GAS HOLDINGS, LLC FINANCIAL STATEMENTS:
|
|
|
|
|
Report of Independent Registered Public
Accounting Firm
|
|
|
F-50
|
|
Balance Sheet as of August 21, 2007
|
|
|
F-51
|
|
Note to the Balance Sheet
|
|
|
F-52
|
|
F-1
Western Gas
Partners, LP
Unaudited pro forma
combined financial statements
The unaudited pro forma combined statement of income of Western
Gas Partners, LP (the Partnership) for the year
ended December 31, 2006 and the nine months ended
September 30, 2007 and the unaudited pro forma combined
balance sheet as of September 30, 2007 are based upon the
audited historical combined and unaudited interim financial
statements of Western Gas Partners Predecessor (the
Predecessor), which is comprised of Anadarko
Gathering Company (AGC) and Pinnacle Gas Treating,
Inc. (PGT), with MIGC, Inc. (MIGC) being
reported as an acquired business of the Predecessor. The assets
contributed to the Partnership include AGC, PGT and MIGC
(collectively the Contributed Assets). Each of AGC,
PGT, MIGC, and the Partnership is an indirect subsidiary of
Anadarko. For purposes of these financial statements,
Anadarko refers to Anadarko Petroleum Corporation
and its consolidated subsidiaries.
The contribution by Western Gas Holdings, LLC, (Holdings
GP) and WGR Holdings, LLC (Holdings LP), both
Anadarko affiliates, of the Contributed Assets to the
Partnership will be recorded at historical cost as these
contributions are considered reorganizations of entities under
common control.
The unaudited pro forma combined statement of income for the
year ended December 31, 2006 has been prepared as if the
acquisition of MIGC by the Predecessor occurred on
January 1, 2006, as opposed to the actual date of
acquisition, August 23, 2006. Offering adjustments have
been prepared as if the transactions to be effected at the
closing of this offering occurred on September 30, 2007, in
the case of the pro forma balance sheet, and as of
January 1, 2006, in the case of the pro forma statements of
income for the year ended December 31, 2006 and the nine
months ended September 30, 2007. The unaudited pro forma
combined financial statements have been prepared based on the
assumption that the Partnership will be treated as a partnership
for federal and state income tax purposes and therefore will not
be subject to U.S. federal income taxes and state income
taxes, except for the Texas margin tax. The unaudited pro forma
combined financial statements should be read in conjunction with
the notes accompanying such unaudited pro forma combined
financial statements and with the unaudited and audited combined
financial statements and the notes thereto set forth elsewhere
in this Prospectus.
The unaudited pro forma combined balance sheet and the unaudited
pro forma combined statements of income were derived by
adjusting the audited historical and unaudited interim combined
financial statements of the Predecessor and its acquired
business, MIGC. These adjustments are based upon currently
available information and certain assumptions and estimates;
therefore, the actual effects of these transactions will differ
from the pro forma adjustments. However, the Partnerships
management is of the opinion that the estimates applied and the
assumptions made provide a reasonable basis for the presentation
of the significant effects of contemplated transactions that are
expected to have a continuing impact on the Partnership. In
addition, the Partnerships management considers the pro
forma adjustments to be factually supportable and to
appropriately represent the expected impact of items that are
directly attributable to the formation of the Partnership and
the transfer of the Contributed Assets to the Partnership.
The unaudited pro forma combined financial statements reflect
the following significant assumptions and transaction:
|
|
Ø |
Holdings GP and Holdings LP will contribute the Contributed
Assets to the Partnership;
|
F-2
Unaudited pro
forma combined financial statements
|
|
Ø |
The Partnership will issue to Holdings GP 921,385 general
partner units representing a 2.0% general partner interest in
the Partnership and 100% of the Partnership incentive
distribution rights, which will entitle Holdings GP to
increasing percentages of cash distributions. Please read
Our cash distribution policy and restrictions on
distributions, contained elsewhere in this prospectus;
|
|
|
Ø
|
The Partnership will issue 3,823,925 common units and 22,573,925
subordinated units, representing an aggregate 57.3% limited
partner interest in the Partnership, to Holdings LP, assuming
that the underwriters do not exercise their option to purchase
additional common units;
|
|
Ø
|
The Partnership will issue 18,750,000 common units to the public
in connection with this offering, representing a 40.7% limited
partner interest;
|
|
Ø
|
The Partnership will receive gross proceeds of
$375.0 million from the issuance and sale of the 18,750,000
common units at an assumed initial offering price of
$20.00 per unit;
|
|
Ø
|
The Partnership will use proceeds from this offering to pay
underwriting discounts and a structuring fee totaling
$24.375 million and other offering expenses estimated to be
$3.0 million;
|
|
Ø
|
The Partnership will use the remaining $347.625 million of
aggregate net proceeds of this offering to (i) make a loan
of $337.625 million to Anadarko in exchange for a 30-year
note bearing interest at a fixed annual rate of 6.00% and
(ii) provide $10.0 million for general partnership
purposes;
|
|
|
Ø |
The Partnership is a co-borrower under Anadarkos
$750 million credit facility and has up to
$100 million of long-term borrowing capacity available to
it;
|
|
|
Ø
|
The Partnership will enter into a $30 million working
capital facility with Anadarko as the lender;
|
|
Ø
|
The Partnership will enter into an omnibus agreement with
Anadarko and Holdings GP pursuant to which, among other things,
(i) the Partnership will reimburse Anadarko and Holdings GP
for certain expenses incurred on behalf of the Partnership,
including expenses for various general and administrative
services rendered by Anadarko and Holdings GP to the
Partnership, and (ii) the parties will agree to certain
indemnification obligations; and
|
|
Ø
|
Holdings GP will enter into a services and secondment agreement
with Anadarko, pursuant to which certain employees of Anadarko
will be under the control of and render services to or on behalf
of the Partnership.
|
The unaudited pro forma combined financial statements are not
necessarily indicative of the results that would have occurred
if the Predecessor had acquired MIGC or if the Partnership had
assumed the operations of the Predecessor on the dates indicated
nor is it indicative of the future operating results of the
Partnership. The pro forma adjustments do not include the
effects of an exercise by the underwriters of their option to
purchase additional common units in the Partnership. If and to
the extent the underwriters exercise their option to purchase up
to 2,812,500 additional common units within 30 days of this
offering, the number of units purchased by the underwriters
pursuant to such exercise will be issued to the public and the
remainder, if any, will be issued to Anadarko. The net proceeds
from any exercise of the underwriters option to purchase
additional common units will be used to reimburse Anadarko for
capital expenditures it incurred with respect to the assets
contributed to the Partnership during the two-year period prior
to this offering.
F-3
Western Gas
Partners, LP
Pro
forma combined statement of income
Year ended
December 31, 2006
unaudited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MIGC
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Western Gas
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners
|
|
through
|
|
|
Pro forma
|
|
|
|
|
Offering
|
|
|
|
|
|
|
Predecessor
|
|
August 23,
|
|
|
adjustments
|
|
|
|
|
adjustments
|
|
|
Pro forma
|
|
|
|
historical
|
|
2006
|
|
|
(see note
2)
|
|
|
Pro
forma
|
|
(see note
3)
|
|
|
as
adjusted
|
|
|
|
|
|
(in thousands,
except unit and per unit data)
|
|
|
Revenues affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and transportation of natural gas
|
|
$
|
65,946
|
|
$
|
7,583
|
|
|
$
|
|
|
|
$
|
73,529
|
|
$
|
|
|
|
$
|
73,529
|
|
Condensate
|
|
|
7,440
|
|
|
|
|
|
|
|
|
|
|
7,440
|
|
|
|
|
|
|
7,440
|
|
Natural gas and other
|
|
|
1,327
|
|
|
103
|
|
|
|
|
|
|
|
1,430
|
|
|
|
|
|
|
1,430
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues affiliates
|
|
|
74,713
|
|
|
7,686
|
|
|
|
|
|
|
|
82,399
|
|
|
|
|
|
|
82,399
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues third parties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and transportation of natural gas
|
|
|
5,022
|
|
|
3,427
|
|
|
|
|
|
|
|
8,449
|
|
|
|
|
|
|
8,449
|
|
Condensate, natural gas and other
|
|
|
1,417
|
|
|
1,039
|
|
|
|
|
|
|
|
2,456
|
|
|
|
|
|
|
2,456
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues third parties
|
|
|
6,439
|
|
|
4,466
|
|
|
|
|
|
|
|
10,905
|
|
|
|
|
|
|
10,905
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenues
|
|
|
81,152
|
|
|
12,152
|
|
|
|
|
|
|
|
93,304
|
|
|
|
|
|
|
93,304
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of product
|
|
|
3,830
|
|
|
|
|
|
|
|
|
|
|
3,830
|
|
|
|
|
|
|
3,830
|
|
General and administrative
|
|
|
3,198
|
|
|
|
|
|
|
|
|
|
|
3,198
|
|
|
|
|
|
|
3,198
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses affiliates
|
|
|
7,028
|
|
|
|
|
|
|
|
|
|
|
7,028
|
|
|
|
|
|
|
7,028
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses third parties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of product
|
|
|
714
|
|
|
|
|
|
|
|
|
|
|
714
|
|
|
|
|
|
|
714
|
|
Operation and maintenance
|
|
|
27,585
|
|
|
2,592
|
|
|
|
|
|
|
|
30,177
|
|
|
|
|
|
|
30,177
|
|
General and administrative
|
|
|
|
|
|
1,305
|
|
|
|
|
|
|
|
1,305
|
|
|
|
|
|
|
1,305
|
|
Property and other taxes
|
|
|
4,633
|
|
|
|
|
|
|
|
|
|
|
4,633
|
|
|
|
|
|
|
4,633
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses third parties
|
|
|
32,932
|
|
|
3,897
|
|
|
|
|
|
|
|
36,829
|
|
|
|
|
|
|
36,829
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
|
|
|
18,009
|
|
|
918
|
|
|
|
783
|
(a)
|
|
|
19,710
|
|
|
|
|
|
|
19,710
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Expenses
|
|
|
57,969
|
|
|
4,815
|
|
|
|
783
|
|
|
|
63,567
|
|
|
|
|
|
|
63,567
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
|
23,183
|
|
|
7,337
|
|
|
|
(783
|
)
|
|
|
29,737
|
|
|
|
|
|
|
29,737
|
|
Interest expense (income) affiliates
|
|
|
9,631
|
|
|
(574
|
)
|
|
|
|
|
|
|
9,057
|
|
|
(9,057
|
)(a)
|
|
|
(20,030
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(20,258
|
)(b)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
228
|
(c)
|
|
|
|
|
Other expense
|
|
|
26
|
|
|
351
|
|
|
|
|
|
|
|
377
|
|
|
|
|
|
|
377
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before Income Taxes
|
|
|
13,526
|
|
|
7,560
|
|
|
|
(783
|
)
|
|
|
20,303
|
|
|
29,087
|
|
|
|
49,390
|
|
Income Tax Expense
|
|
|
3,814
|
|
|
2,647
|
|
|
|
(245
|
)(b)
|
|
|
6,216
|
|
|
(5,238
|
)(d)
|
|
|
978
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
9,712
|
|
$
|
4,913
|
|
|
$
|
(538
|
)
|
|
$
|
14,087
|
|
$
|
34,325
|
|
|
$
|
48,412
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partners interest in net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
968
|
|
Common limited partners interest in net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
23,722
|
|
Subordinated limited partners interest in net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
23,722
|
|
Net income per limited partner unit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units (basic and diluted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1.05
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subordinated units (basic and diluted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1.05
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of limited partner units
outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units (basic and diluted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22,573,925
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subordinated units (basic and diluted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22,573,925
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See the accompanying notes to the
unaudited pro forma combined financial statements.
F-4
Western Gas
Partners, LP
Pro
forma combined statement of income
Nine months ended
September 30, 2007
unaudited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Western Gas
|
|
|
|
|
|
|
|
|
Partners
|
|
Offering
|
|
|
Pro forma
|
|
|
|
Predecessor
|
|
adjustments
|
|
|
as
|
|
|
|
historical
|
|
(see note
3)
|
|
|
adjusted
|
|
|
|
|
|
(in thousands
except unit and per unit data)
|
|
|
Revenues affiliates
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and transportation of natural gas
|
|
$
|
69,311
|
|
$
|
|
|
|
$
|
69,311
|
|
Condensate
|
|
|
6,266
|
|
|
|
|
|
|
6,266
|
|
Natural gas and other
|
|
|
918
|
|
|
|
|
|
|
918
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues affiliates
|
|
|
76,495
|
|
|
|
|
|
|
76,495
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues third parties
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and transportation of natural gas
|
|
|
6,067
|
|
|
|
|
|
|
6,067
|
|
Condensate, natural gas and other
|
|
|
2,951
|
|
|
|
|
|
|
2,951
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues third parties
|
|
|
9,018
|
|
|
|
|
|
|
9,018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenues
|
|
|
85,513
|
|
|
|
|
|
|
85,513
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses affiliates
|
|
|
|
|
|
|
|
|
|
|
|
Cost of product
|
|
|
4,439
|
|
|
|
|
|
|
4,439
|
|
General and administrative
|
|
|
2,370
|
|
|
|
|
|
|
2,370
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses affiliates
|
|
|
6,809
|
|
|
|
|
|
|
6,809
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses third parties
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
21,840
|
|
|
|
|
|
|
21,840
|
|
General and administrative
|
|
|
751
|
|
|
|
|
|
|
751
|
|
Property and other taxes
|
|
|
3,784
|
|
|
|
|
|
|
3,784
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses third parties
|
|
|
26,375
|
|
|
|
|
|
|
26,375
|
|
Depreciation
|
|
|
17,104
|
|
|
|
|
|
|
17,104
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Expenses
|
|
|
50,288
|
|
|
|
|
|
|
50,288
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
|
35,225
|
|
|
|
|
|
|
35,225
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense (income) affiliates
|
|
|
6,643
|
|
|
(6,643
|
)(a)
|
|
|
(15,022
|
)
|
|
|
|
|
|
|
(15,193
|
)(b)
|
|
|
|
|
|
|
|
|
|
|
171
|
(c)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before Income Taxes
|
|
|
28,582
|
|
|
21,665
|
|
|
|
50,247
|
|
Income Tax Expense
|
|
|
10,469
|
|
|
(10,309
|
)(d)
|
|
|
160
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
18,113
|
|
$
|
31,974
|
|
|
$
|
50,087
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partners interest in net income
|
|
|
|
|
|
|
|
|
$
|
1,315
|
|
Common limited partners interest in net income
|
|
|
|
|
|
|
|
|
$
|
24,386
|
|
Subordinated limited partners interest in net income
|
|
|
|
|
|
|
|
|
$
|
24,386
|
|
Net income per limited partner unit
|
|
|
|
|
|
|
|
|
|
|
|
Common units (basic and diluted)
|
|
|
|
|
|
|
|
|
|
1.08
|
|
Subordinated units (basic and diluted)
|
|
|
|
|
|
|
|
|
|
1.08
|
|
Weighted average number of limited partner units
outstanding
|
|
|
|
|
|
|
|
|
|
|
|
Common units (basic and diluted)
|
|
|
|
|
|
|
|
|
|
22,573,925
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subordinated units (basic and diluted)
|
|
|
|
|
|
|
|
|
|
22,573,925
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See the accompanying notes to the unaudited pro forma combined
financial statements.
F-5
Western Gas
Partners, LP
Pro
forma combined balance sheet
September 30,
2007
unaudited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Western Gas
Partners
|
|
|
Offering
|
|
|
Pro forma
|
|
|
|
Predecessor
|
|
|
adjustments
|
|
|
as
|
|
|
|
historical
|
|
|
(see note
3)
|
|
|
adjusted
|
|
|
|
|
|
(in
thousands)
|
|
|
Current Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
|
|
$
|
|
|
|
$
|
375,000
|
(e)
|
|
$
|
10,000
|
|
|
|
|
|
|
|
|
(27,375
|
)(f)
|
|
|
|
|
|
|
|
|
|
|
|
(337,625
|
)(g)
|
|
|
|
|
Accounts receivable
|
|
|
1,732
|
|
|
|
|
|
|
|
1,732
|
|
Natural gas imbalance receivable affiliate
|
|
|
820
|
|
|
|
|
|
|
|
820
|
|
Deferred tax asset
|
|
|
16
|
|
|
|
(11
|
)(d)
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
2,568
|
|
|
|
9,989
|
|
|
|
12,557
|
|
Other assets
|
|
|
47
|
|
|
|
|
|
|
|
47
|
|
Property, Plant and Equipment
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost
|
|
|
477,251
|
|
|
|
|
|
|
|
477,251
|
|
Less accumulated depreciation
|
|
|
(123,957
|
)
|
|
|
|
|
|
|
(123,957
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
|
353,294
|
|
|
|
|
|
|
|
353,294
|
|
Note Receivable Affiliate
|
|
|
|
|
|
|
337,625
|
(g)
|
|
|
337,625
|
|
Goodwill
|
|
|
4,783
|
|
|
|
|
|
|
|
4,783
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
360,692
|
|
|
$
|
347,614
|
|
|
$
|
708,306
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
1,197
|
|
|
|
|
|
|
$
|
1,197
|
|
Natural gas imbalance payables
|
|
|
453
|
|
|
|
|
|
|
|
453
|
|
Accrued ad valorem taxes
|
|
|
3,498
|
|
|
|
|
|
|
|
3,498
|
|
Income taxes payable
|
|
|
3,406
|
|
|
|
(3,247
|
)(d)
|
|
|
159
|
|
Accrued liabilities
|
|
|
3,128
|
|
|
|
|
|
|
|
3,128
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
11,682
|
|
|
|
(3,247
|
)
|
|
|
8,435
|
|
Long-term Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income taxes
|
|
|
68,176
|
|
|
|
(67,193
|
)(d)
|
|
|
983
|
|
Asset retirement obligations
|
|
|
7,327
|
|
|
|
|
|
|
|
7,327
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term liabilities
|
|
|
75,503
|
|
|
|
(67,193
|
)
|
|
|
8,310
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities
|
|
|
87,185
|
|
|
|
(70,440
|
)
|
|
|
16,745
|
|
Partners Capital/Parent Net Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent net investment
|
|
|
273,507
|
|
|
|
70,429
|
(d)
|
|
|
|
|
|
|
|
|
|
|
|
(343,936
|
)(h)
|
|
|
|
|
Common unitholders public
|
|
|
|
|
|
|
375,000
|
(e)
|
|
|
347,625
|
|
|
|
|
|
|
|
|
(27,375
|
)(f)
|
|
|
|
|
Common unitholders affiliate
|
|
|
|
|
|
|
48,141
|
(h)
|
|
|
48,141
|
|
Subordinated unitholders affiliate
|
|
|
|
|
|
|
284,195
|
(h)
|
|
|
284,195
|
|
General partner interest
|
|
|
|
|
|
|
11,600
|
(h)
|
|
|
11,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Partners Capital/Parent Net Equity
|
|
|
273,507
|
|
|
|
418,054
|
|
|
|
691,561
|
|
Commitments and Contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Parent Net Equity
|
|
$
|
360,692
|
|
|
$
|
347,614
|
|
|
$
|
708,306
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See the accompanying notes to the unaudited pro forma combined
financial statements.
F-6
Western Gas
Partners, LP
Notes to
unaudited pro forma combined financial statements
1. BASIS
OF PRESENTATION, OTHER TRANSACTIONS AND THE OFFERING
The unaudited pro forma combined statement of income of Western
Gas Partners, LP (the Partnership) for the year
ended December 31, 2006 and the nine months ended
September 30, 2007 and the unaudited pro forma combined
balance sheet as of September 30, 2007 are based upon the
audited historical and unaudited interim combined financial
statements of Western Gas Partners Predecessor (the
Predecessor), which is comprised of Anadarko
Gathering Company (AGC) and Pinnacle Gas Treating,
Inc. (PGT), with MIGC, Inc. being reported as an
acquired business of the Predecessor. The assets contributed to
the Partnership include AGC, PGT and MIGC (collectively the
Contributed Assets). Each of AGC, PGT, MIGC and the
Partnership is an indirect subsidiary of Anadarko. For purposes
of these financial statements, Anadarko refers to
Anadarko Petroleum Corporation and its consolidated subsidiaries.
Upon completion of this offering, the Partnership anticipates
incurring incremental general and administrative expense of
approximately $2.5 million per year as a result of being a
publicly traded partnership, including expenses associated with
annual and quarterly reporting; tax return and Schedule K-1
preparation and distribution expenses; Sarbanes-Oxley compliance
expenses; expenses associated with listing on the New York Stock
Exchange; independent auditor fees; legal fees; investor
relations expenses; and registrar and transfer agent fees. The
unaudited pro forma combined financial statements do not reflect
these additional public company costs.
In addition, while other general and administrative expenses
have not yet been determined, the Partnership intends to enter
into an omnibus agreement with Anadarko pursuant to which
reimbursement of general and administrative expenses by the
Partnership to Anadarko will be capped at $6.0 million
annually through December 31, 2009, subject to increases
based on increases in the Consumer Price Index and, with the
concurrence of the special committee of the board of directors
of the general partner of the Partnership, subject to further
increases arising in connection with expansions of the
Partnerships operations through the acquisition or
construction of new assets or businesses. The $6.0 million
cap does not apply to any reimbursement by the Partnership to
Anadarko for additional public company costs.
2. PRO
FORMA ADJUSTMENTS
The following pro forma adjustments have been prepared to
reflect the Predecessors acquisition of MIGC as if it
occurred on January 1, 2006:
(a) Reflects depreciation expense in excess of
historical amounts recorded for MIGC, computed based on
MIGCs adjusted basis, as determined under the purchase
method of accounting.
(b) Reflects the related income tax effects of the
depreciation expense adjustment in item (a) above, based on
applicable effective tax rates.
3. OFFERING
ADJUSTMENTS
The following offering adjustments for the Partnership have been
prepared as if the transactions to be effected at the closing of
this offering had taken place on September 30, 2007, in the
case of the pro forma balance sheet, and as of January 1,
2006 or 2007, in the case of the pro forma statements of
F-7
Notes to
unaudited pro forma combined financial statements of Western Gas
Partners, LP
income for the year ended December 31, 2006 and for the
nine months ended September 30, 2007, respectively:
(a) Reflects the elimination of historical interest
expense resulting from the non-cash settlement of receivables
held by Anadarko prior to the offering.
(b) Reflects the inclusion of interest income on the
Partnerships $337.625 million
30-year note
receivable from Anadarko, which bears interest at a fixed annual
rate of 6.00%.
(c) Reflects the payment by the Partnership of a
commitment fee of 0.175% with respect to each of the
Partnerships $30.0 million working capital facility
and $100.0 million of available borrowing capacity under
Anadarkos credit facility, for a total of $227,500 and
$170,625 in aggregate commitment fees for the year ended
December 31, 2006 and for the nine months ended
September 30, 2007, respectively.
(d) Reflects the elimination of historical current
and deferred income taxes as a result of operating as a
partnership for tax purposes. Texas margin taxes have not been
eliminated and will continue to be borne by the Partnership
subsequent to the closing of this offering.
(e) Reflects the assumed gross offering proceeds to
the Partnership of $375.0 million from the issuance and
sale of 18,750,000 common units at an assumed initial public
offering price of $20.00 per unit.
(f) Reflects the payment of underwriting discounts
and a structuring fee totaling $24.375 million and
estimated offering expenses of $3.0 million for a total of
$27.375 million, all of which will be allocated to the
public common units. The $3.0 million of estimated offering
expenses will be paid to Anadarko to reimburse it for offering
expenses that it incurred on our behalf.
(g) Reflects the loan of $337.625 million by the
Partnership to Anadarko in exchange for a
30-year note
bearing interest at a fixed annual rate of 6.00%.
(h) Reflects the conversion of adjusted parent net
investment of $343.936 million to common, subordinated and
general partner capital of the Partnership. The conversion is
allocated as follows:
|
|
Ø |
$48.141 million for 3,823,925 common units;
|
|
|
Ø |
$284.195 million for 22,573,925 subordinated
units; and
|
|
|
Ø |
$11.600 million for 921,385 general partner units.
|
After the conversion, the equity amounts of the common and
subordinated units will be 49.0% and 49.0%, respectively, with
the general partner units representing the remaining 2.0%.
The adjustments described above assume no exercise the
underwriters option to purchase additional common units.
If the underwriters exercise their option to purchase additional
common units in full, the Partnership would receive
approximately $52.6 million in exchange for
2,812,500 common units and will use the proceeds from the
issuance of these units to reimburse Anadarko for capital
expenditures it incurred in respect of the Contributed Assets
during the two-year period prior to the formation of the
Partnership.
4. PRO
FORMA NET INCOME PER UNIT
Pro forma net income per unit is determined by dividing the pro
forma net income that would have been allocated, in accordance
with the provisions of the limited partnership agreement, to the
common and subordinated unitholders by the number of common and
subordinated units expected to be outstanding at the closing of
the offering. For purposes of this calculation, we assumed that
(1) pro forma cash distributions were equal to pro forma
earnings and (2) 22,573,925 common units and
F-8
Notes to
unaudited pro forma combined financial statements of Western Gas
Partners, LP
22,573,925 subordinated units were outstanding, since the
beginning of the periods presented. Because the limited
partnership agreement requires the Partnership to distribute
available cash rather than the earnings reflected in the
Partnerships income statement, actual cash distributions
declared and paid by the Partnership may vary significantly from
reported pro forma net income per unit. Pursuant to the
partnership agreement, to the extent that the quarterly
distributions exceed certain targets, the general partner is
entitled to receive certain incentive distributions that will
result in more net income being proportionately allocated to the
general partner than to the holders of common and subordinated
units. The pro forma net income per unit is sufficient to have
generated incentive distribution payments to our general partner
for the nine months ended September 30, 2007, but not for
the twelve months ended December 31, 2006. Incentive
distributions allocated to the general partner would have been
$313,000 for the nine months ended September 30, 2007.
F-9
Western Gas
Partners Predecessor
Report
of independent registered public accounting firm
The Board of Directors
Anadarko Petroleum Corporation:
We have audited the accompanying combined balance sheets of
Western Gas Partners Predecessor (the Predecessor)
as of December 31, 2006 and 2005, and the related combined
statements of income, parent net equity and cash flows for each
of the years in the three-year period ended December 31,
2006. These combined financial statements are the responsibility
of the Predecessors management. Our responsibility is to
express an opinion on these combined financial statements based
on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the combined financial statements referred to
above present fairly, in all material respects, the financial
position of the Predecessor as of December 31, 2006 and
2005, and the results of their operations and their cash flows
for each of the years in the three-year period ended
December 31, 2006, in conformity with U.S. generally
accepted accounting principles.
/s/ KPMG LLP
Houston, Texas
October 13, 2007
F-10
Western Gas
Partners Predecessor
Combined
statements of
income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
(in
thousands)
|
|
|
Revenues affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and transportation of natural gas
|
|
$
|
65,946
|
|
|
$
|
58,363
|
|
|
$
|
54,407
|
|
Condensate
|
|
|
7,440
|
|
|
|
7,006
|
|
|
|
6,407
|
|
Natural gas and other
|
|
|
1,327
|
|
|
|
789
|
|
|
|
4,526
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues affiliates
|
|
|
74,713
|
|
|
|
66,158
|
|
|
|
65,340
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues third parties
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and transportation of natural gas
|
|
|
5,022
|
|
|
|
2,420
|
|
|
|
1,458
|
|
Condensate, natural gas and other
|
|
|
1,417
|
|
|
|
3,072
|
|
|
|
1,251
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues third parties
|
|
|
6,439
|
|
|
|
5,492
|
|
|
|
2,709
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenues
|
|
|
81,152
|
|
|
|
71,650
|
|
|
|
68,049
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of product
|
|
|
3,830
|
|
|
|
5,551
|
|
|
|
4,425
|
|
General and administrative
|
|
|
3,198
|
|
|
|
2,829
|
|
|
|
2,251
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses affiliates
|
|
|
7,028
|
|
|
|
8,380
|
|
|
|
6,676
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses third parties
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of product
|
|
|
714
|
|
|
|
456
|
|
|
|
553
|
|
Operation and maintenance
|
|
|
27,585
|
|
|
|
23,044
|
|
|
|
20,678
|
|
General and administrative
|
|
|
|
|
|
|
9
|
|
|
|
48
|
|
Property and other taxes
|
|
|
4,633
|
|
|
|
3,831
|
|
|
|
3,346
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses third parties
|
|
|
32,932
|
|
|
|
27,340
|
|
|
|
24,625
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
|
|
|
18,009
|
|
|
|
15,447
|
|
|
|
14,841
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Expenses
|
|
|
57,969
|
|
|
|
51,167
|
|
|
|
46,142
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
|
23,183
|
|
|
|
20,483
|
|
|
|
21,907
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense affiliates
|
|
|
9,631
|
|
|
|
8,650
|
|
|
|
7,146
|
|
Other income (expense)
|
|
|
(26
|
)
|
|
|
66
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before Income Taxes
|
|
|
13,526
|
|
|
|
11,899
|
|
|
|
14,761
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax Expense
|
|
|
3,814
|
|
|
|
4,789
|
|
|
|
5,504
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
9,712
|
|
|
$
|
7,110
|
|
|
$
|
9,257
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See the accompanying notes to the combined financial statements.
F-11
Western Gas
Partners Predecessor
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
(in
thousands)
|
|
|
Current Assets
|
|
|
|
|
|
|
|
|
Cash
|
|
$
|
458
|
|
|
$
|
4
|
|
Accounts receivable
|
|
|
817
|
|
|
|
872
|
|
Natural gas imbalance receivables
|
|
|
673
|
|
|
|
798
|
|
Deferred tax asset
|
|
|
14,569
|
|
|
|
4,248
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
16,517
|
|
|
|
5,922
|
|
Other assets
|
|
|
57
|
|
|
|
|
|
Property, Plant and Equipment
|
|
|
|
|
|
|
|
|
Cost
|
|
|
417,951
|
|
|
|
289,936
|
|
Less accumulated depreciation
|
|
|
(107,080
|
)
|
|
|
(89,485
|
)
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
|
310,871
|
|
|
|
200,451
|
|
Goodwill
|
|
|
4,783
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
332,228
|
|
|
$
|
206,373
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
4,581
|
|
|
$
|
5,706
|
|
Natural gas imbalance payables
|
|
|
2,365
|
|
|
|
235
|
|
Accrued ad valorem taxes
|
|
|
975
|
|
|
|
770
|
|
Accrued liabilities
|
|
|
3,297
|
|
|
|
1,413
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
11,218
|
|
|
|
8,124
|
|
Long-term Liabilities
|
|
|
|
|
|
|
|
|
Deferred income taxes
|
|
|
75,665
|
|
|
|
36,741
|
|
Asset retirement obligations
|
|
|
6,814
|
|
|
|
923
|
|
|
|
|
|
|
|
|
|
|
Total long-term liabilities
|
|
|
82,479
|
|
|
|
37,664
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities
|
|
|
93,697
|
|
|
|
45,788
|
|
Parent Net Equity
|
|
|
238,531
|
|
|
|
160,585
|
|
Commitments and Contingencies (see Note 11)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Parent Net Equity
|
|
$
|
332,228
|
|
|
$
|
206,373
|
|
|
|
|
|
|
|
|
|
|
See the accompanying notes to the combined financial statements.
F-12
Western Gas
Partners Predecessor
Combined
statements of cash flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
(in
thousands)
|
|
|
Cash Flow from Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
9,712
|
|
|
$
|
7,110
|
|
|
$
|
9,257
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
|
|
|
18,009
|
|
|
|
15,447
|
|
|
|
14,841
|
|
Deferred income taxes
|
|
|
3,814
|
|
|
|
4,789
|
|
|
|
5,504
|
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
(Increase) decrease in accounts receivable
|
|
|
374
|
|
|
|
(662
|
)
|
|
|
933
|
|
Increase (decrease) in accounts payable and accrued expenses
|
|
|
(4,556
|
)
|
|
|
3,373
|
|
|
|
(551
|
)
|
Increase (decrease) in other items, net
|
|
|
(30
|
)
|
|
|
74
|
|
|
|
1,176
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by operating activities
|
|
|
27,323
|
|
|
|
30,131
|
|
|
|
31,160
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow from Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, net
|
|
|
(42,299
|
)
|
|
|
(20,841
|
)
|
|
|
(16,548
|
)
|
Other investing activities
|
|
|
(414
|
)
|
|
|
(235
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash used in investing activities
|
|
|
(42,713
|
)
|
|
|
(21,076
|
)
|
|
|
(16,548
|
)
|
Cash Flow from Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in parent net equity (see Note 5)
|
|
|
15,844
|
|
|
|
(9,067
|
)
|
|
|
(14,596
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by (used in) financing activities
|
|
|
15,844
|
|
|
|
(9,067
|
)
|
|
|
(14,596
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase (Decrease) in Cash
|
|
|
454
|
|
|
|
(12
|
)
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash at Beginning of Year
|
|
|
4
|
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash at End of Year
|
|
$
|
458
|
|
|
$
|
4
|
|
|
$
|
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Disclosures
|
|
|
|
|
|
|
|
|
|
|
|
|
Significant non-cash investing and financing transactions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition, net of cash received
|
|
$
|
52,390
|
|
|
$
|
|
|
|
$
|
|
|
See the accompanying notes to the combined financial statements.
F-13
Western Gas
Partners Predecessor
Combined
statements of parent net equity
|
|
|
|
|
|
|
Parent net
|
|
|
|
equity
|
|
|
|
|
|
(in
thousands)
|
|
|
Balance, January 1, 2004
|
|
$
|
167,881
|
|
|
|
|
|
|
Net income
|
|
|
9,257
|
|
Net advance to parent
|
|
|
(14,596
|
)
|
|
|
|
|
|
Balance, December 31, 2004
|
|
|
162,542
|
|
|
|
|
|
|
Net income
|
|
|
7,110
|
|
Net advance to parent
|
|
|
(9,067
|
)
|
|
|
|
|
|
Balance, December 31, 2005
|
|
|
160,585
|
|
|
|
|
|
|
Net income
|
|
|
9,712
|
|
Net advance from parent
|
|
|
15,844
|
|
Investment by parent
|
|
|
52,390
|
|
|
|
|
|
|
Balance, December 31, 2006
|
|
$
|
238,531
|
|
|
|
|
|
|
See the accompanying notes to the combined financial statements.
F-14
Western Gas
Partners Predecessor
Notes to
combined financial statements
|
|
1.
|
DESCRIPTION OF
BUSINESS AND BASIS OF PRESENTATION
|
These financial statements of Western Gas Partners Predecessor
(the Predecessor) have been prepared in connection
with the proposed initial public offering of limited partner
units in Western Gas Partners, LP (the Partnership),
which was formed in Delaware on August 21, 2007 and is
expected to own the operations and assets of the Predecessor
upon closing. The Predecessor is comprised of Anadarko Gathering
Company (AGC) and Pinnacle Gas Treating, Inc.
(PGT), with MIGC, Inc. (MIGC) being
reported as an acquired business of the Predecessor. PGT, AGC
and MIGC, collectively, constitute the assets to be contributed
to the Partnership (the Contributed Assets). Each
of AGC, PGT, MIGC and the Partnership is an indirect subsidiary
of Anadarko. For purposes of these financial statements,
Anadarko refers to Anadarko Petroleum Corporation
and its consolidated subsidiaries.
The Predecessors assets consist of six gathering systems,
five natural gas treating facilities and one interstate
pipeline. The Predecessors assets are located in East
Texas, the Rocky Mountains (Utah and Wyoming), the Mid-Continent
(Kansas and Oklahoma) and West Texas. As part of the initial
public offering of limited partner units of the Partnership,
Western Gas Holdings, LLC (Holdings GP) and WGR
Holdings, LLC, both Anadarko affiliates, will collectively
contribute the Contributed Assets to the Partnership. Holdings
GP will serve as the general partner of the Partnership and
together with Anadarko will provide services to the Partnership
pursuant to an omnibus agreement and a services and secondment
agreement between the parties.
On August 23, 2006, Anadarko acquired Western Gas
Resources, Inc. (Western), including Westerns
subsidiary, MIGC. Under the purchase method of accounting,
Anadarko allocated $52.4 million of the Western purchase
price to MIGC. These financial statements are prepared as if
MIGC was acquired by the Predecessor on August 23, 2006,
the date of Anadarkos acquisition of Western.
The combined financial statements of the Predecessor have been
prepared in accordance with accounting principles generally
accepted in the United States on the basis of Anadarkos
historical ownership of the Contributed Assets. These combined
financial statements have been prepared from the separate
records maintained by Anadarko and may not necessarily be
indicative of the actual results of operations that might have
occurred if the Predecessor had been operated separately during
the periods reported. Because a direct ownership relationship
did not exist among the businesses comprising the Predecessor,
the net investment in the Predecessor is shown as parent net
equity, in lieu of owners equity, in the combined
financial statements.
The Predecessors costs of doing business incurred by
Anadarko on behalf of the Predecessor have been reflected in the
accompanying financial statements. These costs include general
and administrative expenses charged as a management services fee
by Anadarko to the Predecessor in exchange for:
|
|
Ø
|
business services, such as payroll, accounts payable and
facilities management;
|
|
Ø
|
corporate services, such as finance and accounting, legal, human
resources, investor relations and public and regulatory policy;
|
|
Ø
|
executive compensation, but not including share-based
compensation; and
|
|
Ø
|
pension and other post-retirement benefit costs.
|
Transactions between the Predecessor and Anadarko have been
identified in the combined financial statements as transactions
between affiliates (see Note 5).
F-15
Notes to
combined financial statements of Western Gas Partners
Predecessor
|
|
2.
|
SUMMARY OF
SIGNIFICANT ACCOUNTING POLICIES
|
Use of
estimates
To conform to generally accepted accounting principles in the
United States, management makes estimates and assumptions that
affect the amounts reported in the combined financial statements
and the notes thereto. These estimates are evaluated on an
ongoing basis, utilizing historical experience, consultation
with outside advisers and other methods considered reasonable in
the particular circumstances. Although these estimates are based
on managements best available knowledge at the time,
actual results could differ. Effects on the Predecessors
business, financial position and results of operations resulting
from revisions to estimates are recognized when the facts that
give rise to the revision become known.
Property, plant
and equipment
Property, plant and equipment are stated at the lower of
historical cost, less accumulated depreciation or fair value, if
impaired. The Predecessor capitalizes all construction-related
direct labor and material costs. The cost of renewals and
betterments that extend the useful life of property, plant and
equipment is also capitalized. The cost of repairs, replacements
and major maintenance projects, which do not extend the useful
life or increase the expected output of property, plant and
equipment, is expensed as it is incurred. Depreciation is
computed over the assets estimated useful life using the
straight-line method.
Goodwill
Goodwill represents the excess of the purchase price of an
entity over the estimated fair value of the identifiable assets
acquired and liabilities assumed.
Asset retirement
obligations
The Predecessor recognizes a liability based on estimated costs
of retiring tangible long-lived assets. The liability is
recognized at the fair value of the asset retirement obligation
when the obligation is incurred, which generally is when an
asset is acquired or constructed. The carrying amount of the
associated asset is increased commensurate with the liability
recognized. Subsequent to the initial recognition, the liability
is adjusted for any changes in the expected value of the
retirement obligation (with corresponding adjustments to
property, plant and equipment) and for accretion of the
liability due to the passage of time, until the obligation is
settled.
Goodwill and
long-lived asset impairment
The Predecessor evaluates whether goodwill or long-lived assets
have been impaired. In the case of goodwill, impairment testing
is performed annually, unless facts and circumstances make it
necessary to test more frequently. Goodwill impairment
assessment is a two-step process. Step one focuses on
identifying a potential impairment by comparing the fair value
of the reporting unit with the carrying amount of the reporting
unit. If the fair value of the reporting unit exceeds its
carrying amount, no further action is required. However, if the
carrying amount of the reporting unit exceeds its fair value,
step two of the process is performed, directed at measuring the
goodwill impairment, if any.
For long-lived assets, the Predecessor evaluates circumstances
that indicate the carrying amount of the asset may not be
recoverable. Impairment exists when the carrying amount of an
asset exceeds estimates of the undiscounted cash flows expected
to result from the use and eventual disposition of the asset.
When alternative courses of action to recover the carrying
amount of a long-lived asset are under
F-16
Notes to
combined financial statements of Western Gas Partners
Predecessor
consideration, estimates of future undiscounted cash flows take
into account possible outcomes and probabilities of their
occurrence. If the carrying amount of the long-lived asset is
not recoverable, based on the estimated future undiscounted cash
flows, the impairment loss is measured as the excess of the
assets carrying amount over its estimated fair value, such
that the assets carrying amount is adjusted to its
estimated fair value.
Management assesses the fair value of long-lived assets using
commonly accepted techniques and may use more than one source in
making such determinations. Sources used to determine fair value
include, but are not limited to, recent third-party comparable
sales, internally developed discounted cash flow analysis and
analysis from outside advisors. Significant changes in market
conditions resulting from events such as changes in commodity
prices or the condition of an asset or a change in
managements intent to utilize the asset would generally
require management to re-assess the cash flows related to the
long-lived assets.
No long-lived asset or goodwill impairment has been recognized
in these financial statements.
Natural gas
imbalances
The combined balance sheets include natural gas imbalance
receivables or payables resulting from differences in gas
volumes received and gas volumes delivered to customers. Natural
gas volumes owed to or by the Predecessor that are subject to
tariffs are valued at market index prices, as of the balance
sheet dates, and are subject to cash settlement procedures.
Other natural gas volumes owed to or by the Predecessor are
valued at the Predecessors weighted average cost of
natural gas as of the balance sheet dates and are settled
in-kind. Accounts receivable related to gas imbalances were
$673,000 and $798,000 as of December 31, 2006 and 2005,
respectively.
Environmental
expenditures
The Predecessor expenses environmental expenditures related to
conditions caused by past operations that do not generate
current or future revenues. Environmental expenditures related
to operations that generate current or future revenues are
expensed or capitalized, as appropriate. Liabilities are
recorded when the necessity for environmental remediation
becomes probable and the costs can be reasonably estimated, or
when other potential environmental liabilities are probable and
may be reasonably estimated.
Revenue
recognition
Revenues for natural gas gathering, compression, treating and
transportation services are recognized when the service is
provided. From time to time, certain revenues may be subject to
refund pending the outcome of rate matters before the Federal
Energy Regulatory Commission, and reserves are established as
necessary. During the periods presented, there were no pending
rate cases, and no such reserves have been required.
Income
taxes
Anadarko files various United States federal and state income
tax returns. Deferred federal and state income taxes are
provided on temporary differences between the financial
statement carrying amounts of recognized assets and liabilities
and their respective tax bases as if the Predecessor filed tax
returns as a stand-alone entity.
F-17
Notes to
combined financial statements of Western Gas Partners
Predecessor
New accounting
standards
The following new accounting standards were adopted by the
Predecessor during the year ended December 31, 2005:
SFAS No. 154 Accounting Changes and Error
Corrections. In June 2005, the FASB issued
SFAS 154, a replacement of APB Opinion No. 20,
Accounting Changes and SFAS 3,
Reporting Accounting Changes in Interim Financial
Statements. Among other changes, SFAS 154
requires that a voluntary change in accounting principle be
applied retrospectively with all prior period financial
statements presented under the new accounting principle, unless
it is impracticable to do so. SFAS 154 also
(1) provides that a change in depreciation or amortization
of a long-lived non-financial asset be accounted for as a change
in estimate (prospectively) that was effected by a change in
accounting principle, and (2) carries forward without
change the guidance within APB 20 for reporting the correction
of an error in previously issued financial statements and a
change in accounting estimate. The adoption of SFAS 154 did
not have an impact on the Predecessors combined results of
operations, cash flows or financial position.
FASB Interpretation No. 47 Accounting for
Conditional Asset Retirement Obligations. In March
2005, the FASB issued FIN 47, which clarifies the
accounting for conditional asset retirement obligations as used
in SFAS 143. A conditional asset retirement obligation is
an unconditional legal obligation to perform an asset retirement
activity in which the timing
and/or
method of settlement are conditional on a future event that may
or may not be within the control of the entity. Therefore, an
entity is required to recognize a liability for the fair value
of a conditional asset retirement obligation under SFAS 143
if the fair value of the liability can be reasonably estimated.
The provisions of FIN 47 were effective for the Predecessor
as of December 31, 2005. The adoption of FIN 47 did
not have an impact on the Predecessors combined results of
operations, cash flows or financial position.
Recently issued
accounting standards not yet adopted
The following new accounting standards have been issued, but as
of December 31, 2006 had not yet been adopted by the
Predecessor:
FASB Interpretation No. 48 Accounting for
Uncertainty in Income Taxesan Interpretation of FASB
Statement No. 109. FIN 48 was issued in 2006
and became effective January 1, 2007 for the Predecessor.
FIN 48 defines the criteria an individual tax position must
meet for any part of the benefit of that position to be
recognized in the financial statements. FIN 48 also
provides guidance on the measurement of the income tax benefit
associated with uncertain tax positions, de-recognition,
classification, interest and penalties and financial statement
disclosures. Management does not expect the adoption of
FIN 48 to have a material impact on the Predecessor
financial statements.
SFAS No. 159 The Fair Value Option for
Financial Assets and Financial Liabilitiesincluding an
amendment of FAS 115. In February 2007, the FASB
issued SFAS 159, which allows entities to choose, at
specified election dates, to measure eligible financial assets
and liabilities at fair value. If a company elects the fair
value option for an eligible item, changes in that items
fair value in subsequent reporting periods must be recognized in
current earnings. SFAS 159 also establishes presentation
and disclosure requirements designed to draw comparison between
entities that elect different measurement attributes for similar
assets and liabilities and mitigate volatility in reported
earnings caused by measuring related assets and liabilities
differently without having to apply complex hedge accounting
provisions. SFAS 159 is effective for the Predecessor on
January 1, 2008. The Predecessor does not expect to apply
the provisions of SFAS 159 on its combined results of
operations, cash flows or financial position.
F-18
Notes to
combined financial statements of Western Gas Partners
Predecessor
SFAS No. 157 Fair Value Measurements.
In September 2006, the FASB issued SFAS 157, which
defines fair value, establishes a framework for measuring fair
value and expands disclosures about fair value measurements.
SFAS 157 does not require any new fair value measurements.
However, in some cases, the application of SFAS 157 may
change the Predecessors current practice for measuring and
disclosing fair values under other accounting pronouncements
that require or permit fair value measurements. For the
Predecessor, SFAS 157 is effective as of January 1,
2008 and must be applied prospectively, except in certain cases.
The Predecessor is currently evaluating the impact of adopting
SFAS 157 and cannot currently estimate the impact of
adoption on its combined results of operations, cash flows or
financial position.
On August 23, 2006, Anadarko completed its acquisition of
Western. This transaction included MIGC, a subsidiary of
Western, which was allocated a fair value of $52.4 million
under the purchase method of accounting. MIGC will be
contributed to the Partnership upon the closing of this
offering, and the Predecessors combined financial
statements are prepared as if MIGC had been acquired by the
Predecessor on August 23, 2006, when Anadarko acquired
Western.
The acquisition of MIGC was accounted for under the purchase
method of accounting. Accordingly, the assets and liabilities of
MIGC are recorded at their estimated fair values by the
Predecessor as of the date of Anadarkos acquisition of
Western.
The following table presents the allocation of the purchase
price to the assets acquired and liabilities assumed in the MIGC
acquisition, as of the acquisition date:
|
|
|
|
|
|
|
Allocation of
|
|
|
|
purchase
price
|
|
|
|
|
|
(in
thousands)
|
|
|
Current assets
|
|
$
|
193
|
|
Other assets
|
|
|
27
|
|
Property, plant, and equipment
|
|
|
79,273
|
|
Goodwill
|
|
|
4,783
|
|
Current liabilities
|
|
|
(5,813
|
)
|
Deferred income taxes
|
|
|
(24,790
|
)
|
Asset retirement obligations
|
|
|
(1,283
|
)
|
|
|
|
|
|
Total purchase price
|
|
$
|
52,390
|
|
|
|
|
|
|
The purchase price allocation was based on an assessment of the
fair value of the MIGC assets acquired and liabilities assumed.
Other assets and liabilities were recorded at their historical
book values, which the Predecessor believed to represent the
best estimate of fair value at the date of acquisition. The
liabilities assumed included certain amounts associated with
contingencies, such as legal and environmental, the fair values
of which were estimated by management.
F-19
Notes to
combined financial statements of Western Gas Partners
Predecessor
The following table presents selected pro forma results of
operations data for the Predecessor as if the MIGC acquisition
occurred on January 1, 2006 and 2005:
|
|
|
|
|
|
|
|
|
Years ended
December 31,
|
|
|
2006
|
|
2005
|
|
|
|
(in
thousands)
|
|
Revenues
|
|
$
|
93,304
|
|
$
|
88,809
|
Operating income
|
|
$
|
29,737
|
|
$
|
27,533
|
Net income
|
|
$
|
14,087
|
|
$
|
11,497
|
The pro forma information set forth above is presented for
illustration purposes only, in accordance with the assumptions
set forth below, and is not necessarily indicative of the
operating results that would have occurred had the acquisition
been completed at the assumed date, nor is it necessarily
indicative of future operating results of the combined
enterprise. The pro forma adjustments include estimates and
assumptions based on currently available information. Management
believes that the estimates and assumptions are reasonable and
that the significant effects of the transaction are properly
reflected.
The pro forma information for 2006 and 2005 is a result of
combining the income statements of the Predecessor with the
pre-acquisition results from January 1, 2006 and 2005 of
MIGC, adjusted for (1) depreciation expense for MIGC
property, plant and equipment calculated by reference to the
adjusted basis of the properties acquired, and (2) the
related income tax effects of these adjustments based on the
applicable effective tax rates.
For 2006, the Predecessor recognized goodwill of
$4.8 million in connection with the acquisition of MIGC.
None of the Predecessors goodwill is deductible for income
tax purposes.
|
|
5.
|
TRANSACTIONS WITH
AFFILIATES
|
Affiliate
transactions
The Predecessor provides natural gas gathering, compression,
treating and transportation services to Anadarko resulting in
affiliate transactions. The Predecessors expenditures are
paid through Anadarko, which also results in affiliate
transactions. Unlike transactions with third parties that settle
in cash, settlement of these affiliate transactions occurs on a
net basis through an adjustment to parent net equity. Anadarko
also charges the Predecessor interest on the amounts settled
through parent net equity. Interest is computed based on an
interest rate equal to Anadarkos weighted average cost of
capital.
Centralized cash
management
Anadarko operates a cash management system whereby excess cash
from most of its various subsidiaries, held in separate bank
accounts, is swept to a centralized account. Sales and purchases
related to third-party transactions are settled in cash but are
received or paid by Anadarko within the centralized cash
management system and are deemed to have occurred through parent
net equity.
Allocation of
costs
The employees supporting the Predecessors operations are
employees of Anadarko. The combined financial statements of the
Predecessor include costs allocated by Anadarko in the form of a
F-20
Notes to
combined financial statements of Western Gas Partners
Predecessor
management services fee and related to: (i) various
business services, including, but not limited to, payroll,
accounts payable and facilities management, (ii) various
corporate services, including, but not limited to, legal,
accounting, treasury, information technology and human resources
and (iii) compensation, benefit, and pension and
post-retirement costs. Costs were allocated to the Predecessor
based on its proportionate share of Anadarkos assets and
revenues. Management believes these allocation methodologies are
reasonable.
The following table summarizes the affiliate transactions and
other payments made to or received from Anadarko which are
settled through parent net equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
(in
thousands)
|
|
|
Revenues affiliates
|
|
$
|
(74,713
|
)
|
|
$
|
(66,158
|
)
|
|
$
|
(65,340
|
)
|
Operating expense affiliates
|
|
|
7,028
|
|
|
|
8,380
|
|
|
|
6,676
|
|
Interest expense affiliates
|
|
|
9,631
|
|
|
|
8,650
|
|
|
|
7,146
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate transactions
|
|
|
(58,054
|
)
|
|
|
(49,128
|
)
|
|
|
(51,518
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash used in investing activities
|
|
|
42,713
|
|
|
|
21,076
|
|
|
|
16,548
|
|
Other third-party payments
|
|
|
31,185
|
|
|
|
18,985
|
|
|
|
20,374
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Third-party transactions
|
|
|
73,898
|
|
|
|
40,061
|
|
|
|
36,922
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net advance from (to) parent
|
|
$
|
15,844
|
|
|
$
|
(9,067
|
)
|
|
$
|
(14,596
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Components of income tax expense are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
(in
thousands)
|
|
|
Current income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
State
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
5,237
|
|
|
|
3,823
|
|
|
|
4,985
|
|
State
|
|
|
(1,423
|
)
|
|
|
966
|
|
|
|
519
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred income taxes
|
|
|
3,814
|
|
|
|
4,789
|
|
|
|
5,504
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense
|
|
$
|
3,814
|
|
|
$
|
4,789
|
|
|
$
|
5,504
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-21
Notes to
combined financial statements of Western Gas Partners
Predecessor
Total income taxes differed from the amounts computed by
applying the statutory income tax rate to Income before
income taxes. The sources of these differences are as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
(in
thousands)
|
|
|
Income before income taxes
|
|
$
|
13,526
|
|
|
$
|
11,899
|
|
|
$
|
14,761
|
|
Income tax expense, computed at the statutory rate of 35%
|
|
|
4,734
|
|
|
|
4,165
|
|
|
|
5,166
|
|
Adjustments resulting from:
|
|
|
|
|
|
|
|
|
|
|
|
|
State income tax, net of federal income tax effect
|
|
|
179
|
|
|
|
628
|
|
|
|
337
|
|
Texas law change, net of federal income tax effect
|
|
|
(1,104
|
)
|
|
|
|
|
|
|
|
|
Other items
|
|
|
5
|
|
|
|
(4
|
)
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense
|
|
$
|
3,814
|
|
|
$
|
4,789
|
|
|
$
|
5,504
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective tax rate
|
|
|
28.20
|
%
|
|
|
40.25
|
%
|
|
|
37.29
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas House Bill 3, signed into law in May 2006, eliminates the
taxable capital and earned surplus components of the existing
franchise tax and replaces these components with a taxable
margin tax calculated on a combined group reporting basis. There
is no impact for the Texas law change on the Predecessors
2006 current state income taxes as the new tax is effective for
reports due on or after January 1, 2008 (based on business
activity during 2007). The Predecessor is required to record the
impact of the law change to its deferred state income taxes for
the period which includes the date of the laws enactment.
The adjustment, a reduction to the Predecessors deferred
state income taxes in the amount of approximately
$1.1 million, net of the federal tax benefit, is included
in 2006 tax expense.
The tax effects of temporary differences that give rise to
significant portions of deferred tax assets and liabilities at
December 31, 2006 and 2005 are as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
(in
thousands)
|
|
|
Net operating loss and credit carryforwards
|
|
$
|
14,569
|
|
|
$
|
4,248
|
|
|
|
|
|
|
|
|
|
|
Net current deferred income tax assets
|
|
|
14,569
|
|
|
|
4,248
|
|
|
|
|
|
|
|
|
|
|
Depreciable properties
|
|
|
(75,887
|
)
|
|
|
(53,055
|
)
|
Net operating loss carryforward
|
|
|
222
|
|
|
|
16,314
|
|
|
|
|
|
|
|
|
|
|
Net long-term deferred income tax liabilities
|
|
|
(75,665
|
)
|
|
|
(36,741
|
)
|
|
|
|
|
|
|
|
|
|
Total net deferred income tax liabilities
|
|
$
|
(61,096
|
)
|
|
$
|
(32,493
|
)
|
|
|
|
|
|
|
|
|
|
Tax loss and credit carryforwards at December 31, 2006,
generated by the Predecessor, are as follows:
|
|
|
|
|
|
|
|
|
Net operating loss federal
|
|
$
|
40,527 statutory expiration 2022-2024
|
|
Net operating loss state
|
|
$
|
22,602 statutory expiration 2013-2014
|
|
State credit
|
|
$
|
14 statutory expiration 2027
|
|
F-22
Notes to
combined financial statements of Western Gas Partners
Predecessor
|
|
7.
|
CONCENTRATION OF
CREDIT RISK
|
The customers accounting for 10% or more of combined revenues
for the years ended December 31, 2006, 2005 and 2004 are as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended
December 31,
|
|
Customer
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
Anadarko
|
|
|
92
|
%
|
|
|
92
|
%
|
|
|
96
|
%
|
Other
|
|
|
8
|
%
|
|
|
8
|
%
|
|
|
4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Predecessors principal customer for natural gas
gathering, compression, treating and transportation services is
Anadarko. Total revenues were approximately $81.2 million,
$71.7 million and $68.0 million for the periods ended
December 31, 2006, 2005 and 2004, respectively. Except for
Anadarko, no other customer accounted for greater than 10% of
revenue during any of the three years ended December 31,
2006. Where exposed to third-party credit risk, it is the policy
of the Predecessor to (1) analyze the counterparties
financial condition prior to entering into an agreement,
(2) establish credit limits and (3) monitor the
appropriateness of those limits on an ongoing basis. The
Predecessor maintains no credit policy with respect to Anadarko.
|
|
8.
|
PROPERTY, PLANT
AND EQUIPMENT
|
A summary of the historical cost of the Predecessors
property, plant and equipment is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
|
|
December 31,
|
|
|
|
useful
life
|
|
2006
|
|
|
2005
|
|
|
|
|
|
(in thousands,
except for estimated useful life)
|
|
|
Land
|
|
n/a
|
|
$
|
229
|
|
|
$
|
229
|
|
Gathering systems
|
|
15 to 25 years
|
|
|
312,514
|
|
|
|
277,495
|
|
Pipeline and equipment
|
|
30 years
|
|
|
79,956
|
|
|
|
|
|
Compressor improvements
|
|
7 years
|
|
|
9,615
|
|
|
|
9,615
|
|
Assets under construction
|
|
n/a
|
|
|
12,613
|
|
|
|
|
|
Other
|
|
5 to 25 years
|
|
|
3,024
|
|
|
|
2,597
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment
|
|
|
|
|
417,951
|
|
|
|
289,936
|
|
Accumulated depreciation
|
|
|
|
|
(107,080
|
)
|
|
|
(89,485
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Total net property, plant and equipment
|
|
|
|
$
|
310,871
|
|
|
$
|
200,451
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation is calculated using the straight-line method, based
on estimated useful lives and salvage values of assets.
Uncertainties that may impact these estimates include, among
others, changes in laws and regulations relating to restoration
and abandonment requirements, economic conditions and supply and
demand in the area. When assets are placed into service, the
Predecessor makes estimates with respect to useful lives and
salvage values that the Predecessor believes are reasonable.
However, subsequent events could cause a change in estimates,
thereby impacting future depreciation amounts. The cost of
property classified as Assets under construction is
excluded from capitalized costs being depreciated. This amount
represents property elements that are
work-in-progress
and not yet suitable to be placed into productive service as of
the balance sheet date.
F-23
Notes to
combined financial statements of Western Gas Partners
Predecessor
|
|
9.
|
ASSET RETIREMENT
OBLIGATIONS
|
The Predecessors asset retirement obligations are related
to the capping or dismantling of its gathering and
transportation pipelines. The liability for asset retirement
obligations is initially recorded at estimated fair value, with
an offsetting increase to property, plant and equipment.
Accretion expense is recognized over the estimated productive
life of the related assets, increasing the liability to its
expected settlement value. If the fair value of the estimated
asset retirement obligation changes, an adjustment is recorded
for both the asset retirement obligation and the asset
retirement cost.
The following table provides a rollforward of asset retirement
obligations. Revisions in estimated liabilities during the
period relate primarily to revisions of estimated cost
escalation rates and current cost estimates, which may include,
among other things, changes in property lives and the expected
timing of settling asset retirement obligations.
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
(in
thousands)
|
|
|
Carrying amount of asset retirement obligations at beginning of
year
|
|
$
|
923
|
|
|
$
|
970
|
|
Additions
|
|
|
55
|
|
|
|
2
|
|
Liabilities assumed with MIGC acquisition
|
|
|
1,283
|
|
|
|
|
|
Accretion expense
|
|
|
197
|
|
|
|
62
|
|
Revisions in estimated liabilities:
|
|
|
|
|
|
|
|
|
Increase in cost escalation assumption
|
|
|
2,331
|
|
|
|
|
|
Change in other estimates
|
|
|
2,025
|
|
|
|
(111
|
)
|
|
|
|
|
|
|
|
|
|
Carrying amount of asset retirement obligations at end of year
|
|
$
|
6,814
|
|
|
$
|
923
|
|
|
|
|
|
|
|
|
|
|
The Predecessors operations are organized into a single
business segment, all of the assets of which consist of natural
gas pipelines and related plant and equipment.
|
|
11.
|
COMMITMENTS AND
CONTINGENCIES
|
Environmental
The Predecessor is subject to federal, state and local
regulations regarding air and water quality, hazardous and solid
waste disposal and other environmental matters. Management
believes there are no such matters that are expected to have a
material adverse effect on the Predecessors results of
operations, cash flows or financial position.
Litigation and
legal proceedings
From time to time, the Predecessor is involved in legal, tax,
regulatory and other proceedings in various forums regarding
performance, contracts and other matters that arise in the
ordinary course of business. Management is not aware of any such
proceeding for which a final disposition could have a material
adverse effect on the Predecessors results of operations,
cash flows or financial position.
Lease
commitments
The Predecessor enters into leases primarily for compression
equipment. These leases have original terms ranging from 10 to
15 years and meet the criteria for classification as
operating leases. Each compression equipment lease contains a
purchase option, which is exercisable at various times over the
term of the respective lease. Each compressor lease also
contains a renewal provision. Rent expense
F-24
Notes to
combined financial statements of Western Gas Partners
Predecessor
under the compressor operating leases was approximately
$3.0 million, $2.8 million and $2.7 million for
2006, 2005 and 2004, respectively. Future minimum rent payments
due under the compressor leases are as follows:
|
|
|
|
|
|
Minimum
|
|
|
rental
|
|
|
payments
|
|
|
|
(in
thousands)
|
|
2007
|
|
$
|
3,123
|
2008
|
|
|
2,050
|
2009
|
|
|
2,127
|
2010
|
|
|
2,132
|
2011
|
|
|
2,145
|
Thereafter
|
|
|
1,782
|
|
|
|
|
Total
|
|
$
|
13,359
|
|
|
|
|
|
|
12.
|
PENSION PLANS,
OTHER POSTRETIREMENT AND EMPLOYEE SAVINGS PLANS
|
The Predecessor does not sponsor any pension, postretirement or
employee savings plan. However, the Predecessor participates in
certain plans sponsored by Anadarko. The Predecessor
participates in Anadarkos non-contributory defined pension
plans, including both qualified and supplemental plans. Anadarko
also provides certain health care and life insurance benefits
for retired employees. Effective December 31, 2006,
Anadarko adopted SFAS 158, Employers Accounting
for Defined Benefit Pension and Other Postretirement
Plans An Amendment of FASB Statements No. 87,
88, 106 and 132(R), which requires the recognition of the
overfunded or underfunded status of a defined postretirement
plan in its balance sheet, measured as the difference between
the fair value of plan assets and the benefit obligation and the
recognition of changes in the funded status of a plan during the
reporting period as a component of accumulated other
comprehensive income.
Anadarko also sponsors, and the Predecessor participates in, an
employee defined contribution savings plan that matches a
portion of each employees contributions.
Pension, postretirement and employee savings plan costs included
in the management services fee charged to the Predecessor by
Anadarko were approximately $250,000, $200,000 and $125,000 for
2006, 2005 and 2004, respectively.
F-25
Western Gas
Partners Predecessor
Combined
statements of
income
|
|
|
|
|
|
|
|
|
|
|
Nine months ended
September 30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
(unaudited)
|
|
|
|
(in
thousands)
|
|
|
Revenues affiliates
|
|
|
|
|
|
|
|
|
Gathering and transportation of natural gas
|
|
$
|
69,311
|
|
|
$
|
46,546
|
|
Condensate
|
|
|
6,266
|
|
|
|
5,374
|
|
Natural gas and other
|
|
|
918
|
|
|
|
324
|
|
|
|
|
|
|
|
|
|
|
Total revenuesaffiliates
|
|
|
76,495
|
|
|
|
52,244
|
|
|
|
|
|
|
|
|
|
|
Revenues third parties
|
|
|
|
|
|
|
|
|
Gathering and transportation of natural gas
|
|
|
6,067
|
|
|
|
3,660
|
|
Condensate, natural gas and other
|
|
|
2,951
|
|
|
|
1,577
|
|
|
|
|
|
|
|
|
|
|
Total revenues third parties
|
|
|
9,018
|
|
|
|
5,237
|
|
|
|
|
|
|
|
|
|
|
Total Revenues
|
|
|
85,513
|
|
|
|
57,481
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses affiliates
|
|
|
|
|
|
|
|
|
Cost of product
|
|
|
4,439
|
|
|
|
4,196
|
|
General and administrative
|
|
|
2,370
|
|
|
|
2,394
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses affiliates
|
|
|
6,809
|
|
|
|
6,590
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses third parties
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
21,840
|
|
|
|
18,598
|
|
General and administrative
|
|
|
751
|
|
|
|
204
|
|
Property and other taxes
|
|
|
3,784
|
|
|
|
3,665
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses third parties
|
|
|
26,375
|
|
|
|
22,467
|
|
Depreciation
|
|
|
17,104
|
|
|
|
12,635
|
|
|
|
|
|
|
|
|
|
|
Total Operating Expenses
|
|
|
50,288
|
|
|
|
41,692
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
|
35,225
|
|
|
|
15,789
|
|
|
|
|
|
|
|
|
|
|
Interest expense affiliates
|
|
|
6,643
|
|
|
|
7,943
|
|
Other expense
|
|
|
|
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
Income Before Income Taxes
|
|
|
28,582
|
|
|
|
7,821
|
|
Income Tax Expense (Benefit)
|
|
|
10,469
|
|
|
|
1,740
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
18,113
|
|
|
$
|
6,081
|
|
|
|
|
|
|
|
|
|
|
See the accompanying notes to the unaudited combined financial
statements.
F-26
Western Gas
Partners Predecessor
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
(unaudited)
|
|
|
|
(in
thousands)
|
|
|
Current Assets
|
|
|
|
|
|
|
|
|
Cash
|
|
$
|
|
|
|
$
|
458
|
|
Accounts receivable
|
|
|
1,732
|
|
|
|
817
|
|
Natural gas imbalance receivables
|
|
|
820
|
|
|
|
673
|
|
Deferred tax asset
|
|
|
16
|
|
|
|
14,569
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
2,568
|
|
|
|
16,517
|
|
Other assets
|
|
|
47
|
|
|
|
57
|
|
Property, Plant and Equipment
|
|
|
|
|
|
|
|
|
Cost
|
|
|
477,251
|
|
|
|
417,951
|
|
Less accumulated depreciation
|
|
|
(123,957
|
)
|
|
|
(107,080
|
)
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
|
353,294
|
|
|
|
310,871
|
|
Goodwill
|
|
|
4,783
|
|
|
|
4,783
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
360,692
|
|
|
$
|
332,228
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
1,197
|
|
|
$
|
4,581
|
|
Natural gas imbalance payables
|
|
|
453
|
|
|
|
2,365
|
|
Accrued ad valorem taxes
|
|
|
3,498
|
|
|
|
975
|
|
Income taxes payable
|
|
|
3,406
|
|
|
|
|
|
Accrued liabilities
|
|
|
3,128
|
|
|
|
3,297
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
11,682
|
|
|
|
11,218
|
|
Long-term Liabilities
|
|
|
|
|
|
|
|
|
Deferred income taxes
|
|
|
68,176
|
|
|
|
75,665
|
|
Asset retirement obligations
|
|
|
7,327
|
|
|
|
6,814
|
|
|
|
|
|
|
|
|
|
|
Total long-term liabilities
|
|
|
75,503
|
|
|
|
82,479
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities
|
|
|
87,185
|
|
|
|
93,697
|
|
Parent Net Equity
|
|
|
273,507
|
|
|
|
238,531
|
|
Commitments and Contingencies (see Note 6)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Parent Net Equity
|
|
$
|
360,692
|
|
|
$
|
332,228
|
|
|
|
|
|
|
|
|
|
|
See the accompanying notes to the unaudited combined financial
statements.
F-27
Western Gas
Partners Predecessor
Combined
statements of cash flows
|
|
|
|
|
|
|
|
|
|
|
Nine months
ended
|
|
|
|
September 30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
(unaudited)
|
|
|
|
(in
thousands)
|
|
|
Cash Flow from Operating Activities
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
18,113
|
|
|
$
|
6,081
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
Depreciation
|
|
|
17,104
|
|
|
|
12,635
|
|
Deferred income taxes
|
|
|
7,063
|
|
|
|
1,740
|
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
(Increase) in accounts receivable
|
|
|
(915
|
)
|
|
|
(1,160
|
)
|
(Increase) in natural gas imbalance receivable
|
|
|
(147
|
)
|
|
|
(250
|
)
|
Increase (decrease) in accounts payable and accrued
expenses
|
|
|
580
|
|
|
|
(6,015
|
)
|
(Increase) decrease in other items, net
|
|
|
12
|
|
|
|
(90
|
)
|
|
|
|
|
|
|
|
|
|
Cash provided by operating activities
|
|
|
41,810
|
|
|
|
12,941
|
|
|
|
|
|
|
|
|
|
|
Cash Flow used in Investing Activities
|
|
|
|
|
|
|
|
|
Capital expenditures, net
|
|
|
(37,020
|
)
|
|
|
(27,709
|
)
|
Other investing activities
|
|
|
(227
|
)
|
|
|
(243
|
)
|
|
|
|
|
|
|
|
|
|
Cash used in investing activities
|
|
|
(37,247
|
)
|
|
|
(27,952
|
)
|
Cash Flow from Financing Activities
|
|
|
|
|
|
|
|
|
Increase (decrease) in parent investment
|
|
|
(5,021
|
)
|
|
|
15,007
|
|
|
|
|
|
|
|
|
|
|
Cash flow provided by (used in) financing activities
|
|
|
(5,021
|
)
|
|
|
15,007
|
|
|
|
|
|
|
|
|
|
|
Net Decrease in Cash
|
|
|
(458
|
)
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
|
Cash at Beginning of Year
|
|
|
458
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
Cash at End of Period
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Disclosures:
|
|
|
|
|
|
|
|
|
Significant non-cash investing and financing transactions:
|
|
|
|
|
|
|
|
|
Property, plant and equipment contributed by parent
|
|
$
|
21,884
|
|
|
$
|
|
|
Acquisition, net of cash received
|
|
$
|
|
|
|
$
|
52,390
|
|
See the accompanying notes to the unaudited combined financial
statements.
F-28
Western Gas
Partners Predecessor
Combined
statements of parent net equity
|
|
|
|
|
|
|
Parent net
|
|
|
|
equity
|
|
|
|
|
|
(unaudited)
|
|
|
|
(in
thousands)
|
|
|
Balance, December 31, 2005
|
|
$
|
160,585
|
|
Net income
|
|
|
6,081
|
|
Net advance from parent
|
|
|
15,007
|
|
Investment by parent
|
|
|
52,390
|
|
|
|
|
|
|
Balance, September 30, 2006
|
|
$
|
234,063
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2006
|
|
$
|
238,531
|
|
Net income
|
|
|
18,113
|
|
Net advance from parent
|
|
|
(5,021
|
)
|
Investment by parent
|
|
|
21,884
|
|
|
|
|
|
|
Balance, September 30, 2007
|
|
$
|
273,507
|
|
|
|
|
|
|
See the accompanying notes to the unaudited combined financial
statements.
F-29
Western Gas
Partners Predecessor
Notes
to unaudited combined financial statements
|
|
1.
|
DESCRIPTION OF
BUSINESS AND BASIS OF PRESENTATION
|
These financial statements of Western Gas Partners Predecessors
(the Predecessor) have been prepared in connection
with the proposed initial public offering of limited partner
units of Western Gas Partners, LP (the Partnership),
which was formed in Delaware on August 21, 2007 and is
expected to own the operations and assets of the Predecessor
upon closing. The Predecessor is comprised of Anadarko Gathering
Company (AGC) and Pinnacle Gas Treating, Inc.
(PGT), with MIGC, Inc. (MIGC) being
reported as an acquired business of the Predecessor. The assets
contributed to the Partnership include AGC, PGT and MIGC
(collectively the Contributed Assets). Each of AGC,
PGT, MIGC and the Partnership is an indirect subsidiary of
Anadarko. For purposes of these financial statements,
Anadarko refers to Anadarko Petroleum Corporation
and its consolidated subsidiaries.
The Predecessors assets consist of six gathering systems,
five natural gas treating facilities and one interstate
pipeline. The Predecessors assets are located in East
Texas, the Rocky Mountains (Utah and Wyoming), the Mid-Continent
(Kansas and Oklahoma) and West Texas. As part of the initial
public offering of limited partner units of the Partnership,
Western Gas Holdings LLC (Holdings GP) and WGR
Holdings LLC, both Anadarko affiliates, will collectively
contribute the Contributed Assets to the Partnership. Holdings
GP will serve as the general partner of the Partnership and
together with Anadarko will provide services to the Partnership
pursuant to an omnibus agreement and the service and secondment
agreement between the parties.
On August 23, 2006 Anadarko acquired Western Gas Resources,
Inc. (Western), including Westerns subsidiary,
MIGC, and, under the purchase method of accounting, Anadarko
allocated $52.4 million of the Western purchase price to
MIGC. These financial statements are prepared as if MIGC was
acquired by the Predecessor on August 23, 2006, the date of
Anadarkos acquisition of Western.
The combined financial statements of the Predecessor have been
prepared in accordance with accounting principles generally
accepted in the United States on the basis of Anadarkos
historical ownership of the Contributed Assets. These combined
financial statements have been prepared from the separate
records maintained by Anadarko and may not necessarily be
indicative of the actual results of operations that might have
occurred if the Predecessor had been operated separately during
the periods reported. Because a direct ownership relationship
did not exist among the businesses comprising the Predecessor,
the net investment in the Predecessor is shown as parent net
equity, in lieu of owners equity, in the combined
financial statements.
The Predecessors costs of doing business incurred by
Anadarko on behalf of the Predecessor have been reflected in the
accompanying financial statements. These costs include general
and administrative expenses charged as a management services fee
Anadarko to the Predecessor in exchange for:
|
|
Ø
|
business services, such as payroll, accounts payable and
facilities management;
|
|
Ø
|
corporate services, such as finance and accounting, legal, human
resources, investor relations and public and regulatory policy;
|
|
Ø
|
allocation of executive compensation, but not including
share-based compensation; and
|
|
Ø
|
pension and other post-retirement benefit costs.
|
These financial statements should be read in conjunction with
the Predecessors combined financial statements for the
year ended December 31, 2006. These financial statements
reflect all normal recurring adjustments that are, in the
opinion of management, necessary to fairly present the
Predecessors results of operations and financial position.
Amounts reported in the combined statement of operations are not
necessarily indicative of amounts expected for the respective
annual periods.
F-30
Notes to
unaudited combined financial statements of Western Gas Partners
Predecessor
|
|
2.
|
SUMMARY OF
SIGNIFICANT ACCOUNTING POLICIES
|
Use of
estimates
To conform to generally accepted accounting principles in the
United States, management makes estimates and assumptions that
affect the amounts reported in the combined financial statements
and the notes thereto. These estimates are evaluated on an
ongoing basis, utilizing historical experience, consultation
with outside advisers and other methods considered reasonable in
the particular circumstances. Although these estimates are based
on managements best available knowledge at the time,
actual results could differ. Effects on the Predecessors
business, financial position and results of operations resulting
from revisions to estimates are recognized when the facts that
give rise to the revision become known.
Income
taxes
Anadarko files various United States federal and state income
tax returns. Deferred federal and state income taxes are
provided on all temporary differences between the financial
statement carrying amounts of recognized assets and liabilities
and their respective tax bases as if the Predecessor filed tax
returns as a stand-alone entity.
New accounting
standards
The following new accounting standards were adopted by the
Predecessor during the periods subsequent to June 30, 2006,
and the impact of such adoption, if applicable, has been
presented in the accompanying combined financial statements when
appropriate:
FASB Interpretation No. 48 Accounting for
Uncertainty in Income Taxesan Interpretation of FASB
Statement No. 109. FIN 48 was issued in 2006
and became effective January 1, 2007 for the Predecessor.
FIN 48 defines the criteria an individual tax position must
meet for any part of the benefit of that position to be
recognized in the financial statements. FIN 48 also
provides guidance, among other things, on the measurement of the
income tax benefit associated with uncertain tax positions,
de-recognition, classification, interest and penalties and
financial statement disclosures. As of the date of adoption, the
Predecessor had no unrecognized tax benefits recorded. The
Predecessor has elected to classify income tax interest and
penalties as income tax expense.
Anadarko is in administrative appeals or under examination by
the Internal Revenue Service for the 2000-2006 United States tax
returns.
Recently issued
accounting standards not yet adopted
The following new accounting standards have been issued, but as
of September 30, 2007, had not yet been adopted by the
Predecessor:
SFAS No. 159 The Fair Value Option for
Financial Assets and Financial Liabilitiesincluding an
amendment of FAS 115. In February 2007, the FASB
issued SFAS 159, which allows entities to choose, at
specified election dates, to measure eligible financial assets
and liabilities at fair value. If a company elects the fair
value option for an eligible item, changes in that items
fair value in subsequent reporting periods must be recognized in
current earnings. SFAS 159 also establishes presentation
and disclosure requirements designed to draw comparison between
entities that elect different measurement attributes for similar
assets and liabilities. SFAS 159 is effective for the
Predecessor on January 1, 2008. The Predecessor is
currently evaluating the impact of SFAS 159 on our combined
results of operations, cash flows or financial position.
SFAS No. 157 Fair Value Measurements.
In September 2006, the FASB issued SFAS 157, which
defines fair value, establishes a framework for measuring fair
value in GAAP and expands disclosures
F-31
Notes to
unaudited combined financial statements of Western Gas Partners
Predecessor
about fair value measurements. SFAS 157 does not require
any new fair value measurements. However, in some cases, the
application of SFAS 157 may change the Predecessors
current practice for measuring and disclosing fair values under
other accounting pronouncements that require or permit fair
value measurements. For the Predecessor, SFAS 157 is
effective as of January 2008 and must be applied prospectively,
except in certain cases. The Predecessor is currently evaluating
the impact of adopting SFAS 157, and cannot currently
estimate the impact of SFAS 157 on its combined results of
operations, cash flows or financial position.
On August 23, 2006, Anadarko completed its acquisition of
Western. This transaction included MIGC, a subsidiary of
Western, which was allocated a fair value of $52.4 million
under the purchase method of accounting. MIGC will be
contributed to the Partnership upon the closing of this offering
and the Predecessors combined financial statements are
prepared as if MIGC was acquired by the Predecessor on
August 23, 2006, when Anadarko acquired Western.
The acquisition of MIGC is accounted for under the purchase
method of accounting. The assets and liabilities of MIGC are
recorded at their estimated fair value by the Predecessor as of
the date of Anadarkos acquisition of Western.
The following table presents the allocation of the purchase
price to the MIGC assets acquired and liabilities assumed in the
MIGC acquisition, as of the acquisition date:
|
|
|
|
|
|
|
Allocation of
|
|
|
|
purchase
price
|
|
|
|
|
|
(in
thousands)
|
|
|
Current assets
|
|
|
193
|
|
Other assets
|
|
|
27
|
|
Property and equipment
|
|
|
79,273
|
|
Goodwill
|
|
|
4,783
|
|
Current liabilities
|
|
|
(5,813
|
)
|
Deferred income taxes
|
|
|
(24,790
|
)
|
Asset retirement obligations
|
|
|
(1,283
|
)
|
|
|
|
|
|
Total purchase price
|
|
$
|
52,390
|
|
|
|
|
|
|
The purchase price allocation is based on an assessment of the
fair value of the MIGC assets acquired and liabilities assumed.
Other assets and liabilities were recorded at their historical
book values, which the Predecessor believes to represent the
best estimate of fair value at the date of acquisition. The
liabilities assumed included certain amounts associated with
contingencies, such as legal and environmental, the fair values
of which were estimated by management.
The following table presents selected pro forma results of
operations data for the Predecessor as if the MIGC acquisition
occurred on January 1, 2006:
|
|
|
|
|
|
Nine months
|
|
|
ended
|
|
|
September 30,
|
|
|
2006
|
|
|
|
(in
thousands)
|
|
Revenues
|
|
$
|
69,633
|
Operating income
|
|
$
|
22,343
|
Net income
|
|
$
|
10,456
|
F-32
Notes to
unaudited combined financial statements of Western Gas Partners
Predecessor
The pro forma information set forth above is presented for
illustration purposes only and in accordance with the
assumptions set forth below. The pro forma information is not
necessarily indicative of the operating results that would have
occurred had the acquisition been completed at the assumed date,
nor is it necessarily indicative of future operating results of
the combined enterprise. The pro forma adjustments include
estimates and assumptions based on currently available
information. Management believes that the estimates and
assumptions are reasonable and that the significant effects of
the transaction are properly reflected.
The pro forma information for 2006 is a result of combining the
income statements of the Predecessor with the pre-acquisition
results from January 1, 2006 of MIGC adjusted for
(1) depreciation expense for MIGC property, plant and
equipment, calculated by reference to the adjusted basis of the
properties acquired, and (2) the related income tax effects
of these adjustments based on the applicable effective rates.
For the third quarter of 2006, the Predecessor recognized
goodwill of $4.8 million in connection with the acquisition
of MIGC. None of the Predecessors goodwill is deductible
for income tax purposes.
|
|
5.
|
TRANSACTIONS WITH
AFFILIATES
|
Affiliate
transactions
The Predecessor provides natural gas gathering, compression,
treating and transportation services to Anadarko resulting in
affiliate transactions. The Predecessors expenditures are
paid through Anadarko in the form of a management services fee,
which also results in affiliate transactions. Unlike
transactions with third parties that settle in cash, settlement
of these affiliate transactions occurs on a net basis through an
adjustment to parent net equity. Anadarko also charges the
Predecessor interest on the amounts settled through parent net
equity. Interest is computed based on an interest rate equal to
Anadarkos weighted average cost of capital.
Centralized cash
management
Anadarko operates a cash management system whereby excess cash
from most of its various subsidiaries, held in separate bank
accounts, is swept to a centralized account. Sales and purchases
related to third-party transactions are settled in cash but are
received or paid by Anadarko within the centralized cash
management system and are deemed to have occurred through parent
net equity.
Allocation of
costs
The employees supporting the Predecessors operations are
employees of Anadarko. The combined financial statements of the
Predecessor include costs allocated by Anadarko in the form of a
management fee and related to: (i) various business
services, including, but not limited to, payroll, accounts
payable and facilities management, (ii) various corporate
services, including, but not limited to, legal, accounting,
treasury, information technology and human resources and
(iii) compensation, benefit, and pension and
post-retirement costs. Costs were allocated to the Predecessor
based on its proportionate share of Anadarkos assets and
revenues. Management believes these allocation methodologies are
reasonable.
F-33
Notes to
unaudited combined financial statements of Western Gas Partners
Predecessor
The following table summarizes the affiliate transactions and
other payments made to or received from Anadarko which are
settled through parent net equity:
|
|
|
|
|
|
|
|
|
|
|
Nine months
ended
|
|
|
|
September 30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
(in
thousands)
|
|
|
Revenues affiliates
|
|
$
|
(76,495
|
)
|
|
$
|
(52,244
|
)
|
Operating expense affiliates
|
|
|
6,809
|
|
|
|
6,590
|
|
Interest expense affiliates
|
|
|
6,643
|
|
|
|
7,943
|
|
|
|
|
|
|
|
|
|
|
Affiliate transactions
|
|
|
(63,043
|
)
|
|
|
(37,711
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash used in investing activities
|
|
|
37,247
|
|
|
|
27,952
|
|
Other third-party payments
|
|
|
20,775
|
|
|
|
24,766
|
|
|
|
|
|
|
|
|
|
|
Third-party transactions
|
|
|
58,022
|
|
|
|
52,718
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net advance from (to) parent
|
|
$
|
(5,021
|
)
|
|
$
|
15,007
|
|
|
|
|
|
|
|
|
|
|
|
|
6.
|
COMMITMENTS AND
CONTINGENCIES
|
Environmental
The Predecessor is subject to federal, state and local
regulations regarding air and water quality, hazardous and solid
waste disposal and other environmental matters. Management
believes there are no such matters that are expected to have a
material adverse effect on the Predecessors results of
operations, cash flows or financial position.
Litigation and
legal proceedings
From time to time, the Predecessor is involved in legal, tax,
regulatory and other proceedings in various forums regarding
performance, contracts and other matters that arise in the
ordinary course of business. Management is not aware of any such
proceeding for which a final disposition could have a material
adverse effect on the Predecessors results of operations,
cash flows or financial position.
7. PENSION
PLANS, OTHER POSTRETIREMENT AND EMPLOYEE SAVINGS PLANS
The Predecessor does not sponsor any pension, postretirement or
employee savings plans. However, the Predecessor participates in
certain plans sponsored by Anadarko, including Anadarkos
qualified and supplemental non-contributory defined benefit
pension plans. In addition, Anadarko also provides certain
health care and life insurance benefits for retired employees.
Anadarko also sponsors, and the predecessor participates in, an
employee defined contribution savings plan that matches a
portion of each employees contribution.
Pension, postretirement and employee savings plan costs included
in the management services fee charged to the Predecessor by
Anadarko were approximately $175,000 and $175,000 for the nine
month periods ended September 30, 2007 and 2006,
respectively.
F-34
MIGC,
Inc.
Report
of independent registered public accounting firm
The Board of Directors
Anadarko Petroleum Corporation:
We have audited the accompanying balance sheet of MIGC, Inc.
(the Company) as of December 31, 2005, and the
related statements of income, parent net equity, and cash flows
for the period from January 1, 2006 through August 23,
2006 and for the year ended December 31, 2005. These
financial statements are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these combined financial statements based on our
audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial position
of the Company as of December 31, 2005, and its results of
operations and cash flows for the period from January 1,
2006 through August 23, 2006 and for the year ended
December 31, 2005, in conformity with U.S. generally
accepted accounting principles.
/s/ KPMG LLP
Denver, Colorado
October 11, 2007
F-35
MIGC,
Inc.
|
|
|
|
|
|
|
|
|
|
|
January 1,
|
|
|
|
|
|
|
2006
|
|
|
For the
|
|
|
|
through
|
|
|
year ended
|
|
|
|
August 23,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
(in
thousands)
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
Transportation of natural gas affiliates
|
|
$
|
7,583
|
|
|
$
|
11,887
|
|
Transportation of natural gas third parties
|
|
|
3,427
|
|
|
|
5,111
|
|
Sale of natural gas third parties
|
|
|
1,039
|
|
|
|
|
|
Other affiliates
|
|
|
103
|
|
|
|
161
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
12,152
|
|
|
|
17,159
|
|
|
|
|
|
|
|
|
|
|
Operating expenses third parties
|
|
|
|
|
|
|
|
|
Cost of product
|
|
|
|
|
|
|
703
|
|
Operation and maintenance
|
|
|
2,592
|
|
|
|
5,517
|
|
General and administrative
|
|
|
1,305
|
|
|
|
1,247
|
|
Depreciation
|
|
|
918
|
|
|
|
631
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
4,815
|
|
|
|
8,098
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
|
7,337
|
|
|
|
9,061
|
|
|
|
|
|
|
|
|
|
|
Interest (income) affiliates
|
|
|
(574
|
)
|
|
|
(526
|
)
|
Other expense
|
|
|
351
|
|
|
|
986
|
|
|
|
|
|
|
|
|
|
|
Income Before Income Taxes
|
|
|
7,560
|
|
|
|
8,601
|
|
Income Tax Expense
|
|
|
2,647
|
|
|
|
3,011
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
4,913
|
|
|
$
|
5,590
|
|
|
|
|
|
|
|
|
|
|
See the accompanying notes to the financial statements.
F-36
MIGC,
Inc.
|
|
|
|
|
|
|
December 31,
|
|
|
|
2005
|
|
|
|
|
|
(in
thousands)
|
|
|
Current Assets
|
|
|
|
|
Cash
|
|
$
|
|
|
Accounts receivable
|
|
|
523
|
|
Accounts receivable affiliates
|
|
|
42,659
|
|
|
|
|
|
|
Total current assets
|
|
|
43,182
|
|
Other assets
|
|
|
81
|
|
Property, Plant and Equipment
|
|
|
|
|
Cost
|
|
|
46,121
|
|
Less accumulated depreciation
|
|
|
(17,389
|
)
|
|
|
|
|
|
Net property, plant and equipment
|
|
|
28,732
|
|
|
|
|
|
|
Total Assets
|
|
$
|
71,995
|
|
|
|
|
|
|
Current Liabilities
|
|
|
|
|
Accounts payable
|
|
$
|
58
|
|
Natural gas imbalance payables
|
|
|
1,944
|
|
Natural gas imbalance payable affiliates
|
|
|
846
|
|
Accrued ad valorem taxes
|
|
|
318
|
|
Income taxes payable
|
|
|
3,118
|
|
Accrued expenses other
|
|
|
61
|
|
|
|
|
|
|
Total current liabilities
|
|
|
6,345
|
|
Long-term Liabilities
|
|
|
|
|
Deferred income taxes
|
|
|
3,643
|
|
Asset retirement obligations
|
|
|
1,233
|
|
|
|
|
|
|
Total long-term liabilities
|
|
|
4,876
|
|
|
|
|
|
|
Total Liabilities
|
|
|
11,221
|
|
Parent Net Equity
|
|
|
60,774
|
|
Commitments and Contingencies (see Note 8)
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Parent Net Equity
|
|
$
|
71,995
|
|
|
|
|
|
|
See the accompanying notes to the financial statements.
F-37
MIGC,
Inc.
|
|
|
|
|
|
|
|
|
|
|
January 1,
|
|
|
|
|
|
|
2006
|
|
|
For the year
|
|
|
|
through
|
|
|
ended
|
|
|
|
August 23,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
(in
thousands)
|
|
|
Cash Flow from Operating Activities
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
4,913
|
|
|
$
|
5,590
|
|
Adjustments to reconcile net income to net cash used in
operating activities:
|
|
|
|
|
|
|
|
|
Depreciation
|
|
|
918
|
|
|
|
631
|
|
Deferred income taxes
|
|
|
(67
|
)
|
|
|
(107
|
)
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
Decrease in accounts receivable
|
|
|
329
|
|
|
|
354
|
|
Increase in accounts receivable affiliates
|
|
|
(6,206
|
)
|
|
|
(14,749
|
)
|
Increase in accounts payable and accrued expenses
|
|
|
252
|
|
|
|
1,824
|
|
Increase (decrease) in natural gas
imbalances affiliates
|
|
|
(784
|
)
|
|
|
846
|
|
Increase in other items, net
|
|
|
104
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
Net cash used in operating activities
|
|
|
(541
|
)
|
|
|
(5,594
|
)
|
|
|
|
|
|
|
|
|
|
Cash Flow from Investing Activities
|
|
|
|
|
|
|
|
|
Retirements of property, plant and equipment, net
|
|
|
541
|
|
|
|
5,594
|
|
|
|
|
|
|
|
|
|
|
Cash provided by investing activities
|
|
|
541
|
|
|
|
5,594
|
|
|
|
|
|
|
|
|
|
|
Cash Flow from Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Change in Cash
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash at Beginning of Period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash at End of Period
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
See the accompanying notes to the financial statements.
F-38
MIGC,
Inc.
Statements
of parent net equity
|
|
|
|
|
|
Parent net
|
|
|
equity
|
|
|
|
(in
thousands)
|
|
Balance, January 1, 2005
|
|
$
|
55,184
|
|
|
|
|
Net income
|
|
|
5,590
|
|
|
|
|
Balance, December 31, 2005
|
|
|
60,774
|
|
|
|
|
Net income
|
|
|
4,913
|
|
|
|
|
Balance, August 23, 2006
|
|
$
|
65,687
|
|
|
|
|
See the accompanying notes to the financial statements.
F-39
MIGC,
Inc.
Notes to
financial statements
|
|
1.
|
DESCRIPTION OF
BUSINESS AND BASIS OF PRESENTATION
|
These financial statements of MIGC, Inc. (MIGC or
the Company) have been prepared in connection with
the proposed initial public offering of limited partner units of
Western Gas Partners, LP (the Partnership), which
was formed on August 21, 2007 and will own the operations
and assets of the Company upon the closing of this offering. On
August 23, 2006, Anadarko Petroleum Corporation acquired
Western Gas Resources, Inc. (Western). This
transaction included the assets of the Company. The Company was
a wholly owned subsidiary of Western for the periods presented
in these financial statements. For purposes of these financial
statements, Anadarko refers to Anadarko Petroleum
Corporation and its consolidated subsidiaries.
As part of the initial public offering of limited partnership
units of the Partnership, Western Gas Holdings, LLC
(Holdings GP) and WGR Holdings, LLC, both Anadarko
affiliates, will collectively contribute MIGC, along with
certain other assets, to the Partnership. Holdings GP will serve
as the general partner of the Partnership and together with
Anadarko will provide services to the Partnership pursuant to an
omnibus agreement and a services and secondment agreement
between the parties.
MIGC owns a
264-mile
natural gas interstate pipeline located in the Powder River
Basin of Wyoming. MIGC charges a Federal Energy Regulatory
Commission (FERC) approved tariff and earns revenues
through firm contracts that obligate its customers to pay a
monthly reservation or demand charge, which is a fixed charge
applied to firm contract capacity and owed by a customer
regardless of the pipeline capacity used by that customer. When
a customer uses the capacity it has reserved under these
contracts, MIGC is entitled to collect an additional commodity
usage charge based on the actual volume of natural gas
transported. These usage charges are typically a small
percentage of the total revenues received from firm capacity
contracts. Revenues are also generated from interruptible
contracts pursuant to which a fee is charged by MIGC to the
customer based upon volumes transported through the pipeline.
Western maintained a centralized treasury function wherein
individual cash accounts maintained by the Company were swept to
a Western corporate account, creating an intercompany receivable
between Western and the Company. Therefore, the Companys
balance sheet reflects no cash balance.
The Companys financial statements have been prepared in
accordance with United States generally accepted accounting
principles on the basis of the Companys ownership of the
assets that will be contributed to the Partnership. These
financial statements have been prepared from the separate
records maintained by the Company and may not necessarily be
indicative of the actual results of operations that would have
occurred if the Company had been separately operated during
those periods. Net investment in the Company is shown as parent
net equity, in lieu of owners equity in the combined
financial statements.
The Companys costs of doing business have been reflected
in the financial statements of the Company for the periods
presented. These costs, which include direct costs and
allocations, were calculated and then directly charged to the
Company for:
|
|
Ø
|
business services, such as payroll, accounts payable and
facilities management; and
|
|
Ø
|
corporate services, such as finance and accounting, legal, human
resources, investor relations, public and regulatory policy and
senior executives.
|
Transactions between the Company and Western or Westerns
affiliates are described in the financial statements as
transactions between affiliates (see Note 3). In the
opinion of management, the assumptions underlying the financial
statements are reasonable.
F-40
Notes to
financial statements of MIGC, Inc.
|
|
2.
|
SUMMARY OF
SIGNIFICANT ACCOUNTING POLICIES
|
Use of
estimates
To conform to generally accepted accounting principles in the
United States, management makes estimates and assumptions that
affect the amounts reported in the financial statements and the
notes thereto. These estimates are evaluated on an ongoing
basis, utilizing historic experience, consultation with outside
advisers and other methods considered reasonable under certain
circumstances. Although these estimates are based on
managements best available knowledge at the time, actual
results could differ. Effects on the Companys business,
financial position or results of operations resulting from
revisions to estimates are recognized when the facts that give
rise to the revision become known.
Property, plant
and equipment
Property, plant and equipment are stated at the lower of
historical cost, less accumulated depreciation or fair value, if
impaired. The Company capitalizes all construction-related
direct labor and material costs. The cost of renewals and
betterments that extend the useful life of property, plant and
equipment is also capitalized. The cost of repairs, replacements
and major maintenance projects, which do not extend the useful
life or increase the expected output of property, plant and
equipment, is expensed as incurred. Depreciation is generally
computed over the assets estimated useful life using the
straight-line method.
Asset retirement
obligations
The Company recognizes a liability based on estimated costs of
retiring tangible long-lived assets. The liability is recognized
at the fair value of the asset retirement obligation when the
obligation is incurred, which generally is when the asset is
acquired or constructed. The carrying amount of the associated
asset is increased commensurate with the liability recognized.
Subsequent to the initial recognition, the liability is adjusted
for any changes in the expected value of the retirement
obligation (with corresponding adjustments to property, plant
and equipment) and for accretion of the liability due to the
passage of time, until the obligation is settled.
Long-lived asset
impairment
The Company evaluates whether long-lived assets have been
impaired when circumstances indicate the carrying amount of
those assets may not be recoverable. For such long-lived assets,
impairment exists when the carrying amount exceeds estimates of
the undiscounted cash flows expected to result from the use and
eventual disposition of the asset. When alternative courses of
action to recover the carrying amount of a long-lived asset are
under consideration, estimates of future undiscounted cash flows
take into account possible outcomes and probabilities of their
occurrence. If the carrying amount of the long-lived asset is
not recoverable, based on the estimated future undiscounted cash
flows, the impairment loss is measured as the excess of the
assets carrying amount over its fair value, such that the
assets carrying amount is adjusted to its estimated fair
value.
Management assesses the fair value of long-lived assets using
commonly accepted techniques, and may use more than one source
in making such a determination. Sources used to determine fair
value include, but are not limited to, recent third-party
comparable sales, internally developed discounted cash flow
analysis and analysis from outside advisors. Significant changes
in market conditions resulting from events such as changes in
commodity prices or the condition of an asset or a change in
managements intent to utilize the asset would generally
require management to re-assess the cash flows related to the
long-lived assets.
F-41
Notes to
financial statements of MIGC, Inc.
Natural gas
imbalances
The Companys balance sheet includes a natural gas
imbalance payable as a result of differences in gas volumes
received and delivered for customers. Natural gas volumes owed
to or by the Company are subject to FERC tariffs, valued at
market index prices as of the balance sheet date and subject to
cash settlement procedures.
Environmental
expenditures
The Company expenses environmental expenditures related to
conditions caused by past operations that do not generate
current or future revenues. Environmental expenditures related
to operations that generate current or future revenues are
expensed or capitalized, as appropriate. Liabilities are
recorded when the necessity for environmental remediation
becomes probable and the costs can be reasonably estimated, or
when other potential environmental liabilities are probable and
may be reasonably estimated.
Revenue
recognition
Revenues for the transportation of natural gas are recognized
when the service is provided. From time to time, certain
revenues may be subject to refund pending the outcome of rate
matters before FERC and reserves are established where
appropriate. During the periods presented herein, there were no
pending rate cases, and no related reserves have been
established.
Income
taxes
The Company files a United States federal tax return. Deferred
federal income taxes are provided on all temporary differences
between the financial statement carrying amounts of recognized
assets and liabilities and their respective tax bases.
New accounting
standards
The following new accounting standard was adopted by the Company
for the period from January 1, 2006 through August 23,
2006:
FASB Interpretation No. 47 Accounting for
Conditional Asset Retirement Obligations. In March
2005, the FASB issued FIN 47, which clarifies the
accounting for conditional asset retirement obligations as used
in SFAS 143. A conditional asset retirement obligation is
an unconditional legal obligation to perform an asset retirement
activity in which the timing
and/or
method of settlement are conditional on a future event that may
or may not be within the control of the entity. Therefore, an
entity is required to recognize a liability for the fair value
of a conditional asset retirement obligation under SFAS 143
if the fair value of the liability can be reasonably estimated.
The adoption of FIN 47 did not have an impact on the
Companys results of operations, cash flows or financial
position.
Recently issued
accounting standards not yet adopted
FASB Interpretation No. 48 Accounting for
Uncertainty in Income Taxesan Interpretation of FASB
Statement No. 109. FIN 48 was issued in 2006
and became effective January 1, 2007 for the Company.
FIN 48 defines the criteria an individual tax position must
meet for any part of the benefit of that position to be
recognized in the financial statements. FIN 48 also
provides guidance on the measurement of the income tax benefit
associated with uncertain tax positions, de-recognition,
classification, interest and penalties and financial statement
disclosures. The Company does not expect the adoption of
FIN 48 to have a material impact on its financial
statements.
F-42
Notes to
financial statements of MIGC, Inc.
|
|
3.
|
TRANSACTIONS WITH
AFFILIATES
|
The Company provides natural gas transportation services to
Western and its affiliates. The Companys costs of doing
business have been reflected in the financial statements of the
Company for the periods presented. These costs include, but are
not limited to, legal, accounting, treasury, information
technology and human resources. These costs were calculated
based on the cost of actual services provided and directly
charged to the Company. Management believes the allocations upon
which these charges are based to be reasonable; however, these
estimates and allocations may not represent the amounts that
would have been incurred had the Company operated as a separate
entity and contracted with third parties for these services.
It is the Companys policy that all transactions entered
into between the Company and its affiliates be carried out in
the ordinary course of business and on terms comparable to terms
that could reasonably be obtained from third parties.
Advances made by or to the Company are carried as
interest-bearing accounts receivable or accounts payable and are
classified as current assets and current liabilities,
respectively. Increases in advances to the Company generally
result from advances made by Western to the Company in
connection with funding for operations and capital expenditures.
Decreases in advances to the Company generally result from
crediting, against advances made by Western to the Company,
(1) amounts owed by Western to the Company for services
rendered, and (2) the amount of cash which is swept from
the Companys bank account to a Western corporate account,
in accordance with Westerns cash management policy.
Components of income tax expense are as follows:
|
|
|
|
|
|
|
|
|
|
|
January 1,
|
|
|
|
|
|
|
2006
|
|
|
|
|
|
|
through
|
|
|
Year ended
|
|
|
|
August 23,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
(in
thousands)
|
|
|
Current income taxes
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
2,714
|
|
|
$
|
3,118
|
|
|
|
|
|
|
|
|
|
|
Total current income taxes
|
|
|
2,714
|
|
|
|
3,118
|
|
|
|
|
|
|
|
|
|
|
Deferred income taxes
|
|
|
|
|
|
|
|
|
Federal
|
|
|
(67
|
)
|
|
|
(107
|
)
|
|
|
|
|
|
|
|
|
|
Total deferred income taxes
|
|
|
(67
|
)
|
|
|
(107
|
)
|
|
|
|
|
|
|
|
|
|
Total income tax expense
|
|
$
|
2,647
|
|
|
$
|
3,011
|
|
|
|
|
|
|
|
|
|
|
F-43
Notes to
financial statements of MIGC, Inc.
Total income taxes differed from the amounts computed by
applying the statutory income tax rate to Income before
income taxes. The sources of these differences are as
follows:
|
|
|
|
|
|
|
|
|
|
|
January 1,
|
|
|
|
|
|
|
2006
|
|
|
|
|
|
|
through
|
|
|
Year ended
|
|
|
|
August 23,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
(in
thousands)
|
|
|
Income before income taxes
|
|
$
|
7,560
|
|
|
$
|
8,601
|
|
Income tax expense, computed at the statutory rate of 35%
|
|
|
2,646
|
|
|
|
3,010
|
|
Adjustments resulting from:
|
|
|
|
|
|
|
|
|
Other items
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense
|
|
$
|
2,647
|
|
|
$
|
3,011
|
|
|
|
|
|
|
|
|
|
|
Effective tax rate
|
|
|
35.01
|
%
|
|
|
35.01
|
%
|
|
|
|
|
|
|
|
|
|
The tax effects of temporary differences that give rise to the
deferred tax liability at December 31, 2005 is as follows:
|
|
|
|
|
|
|
December 31,
|
|
|
|
2005
|
|
|
|
|
|
(in
thousands)
|
|
|
Depreciable properties
|
|
$
|
(3,643
|
)
|
|
|
|
|
|
Total deferred income tax liability
|
|
$
|
(3,643
|
)
|
|
|
|
|
|
|
|
5.
|
CONCENTRATION OF
CREDIT RISK
|
The customers that individually accounted for 10% or more of
revenues for the period from January 1, 2006 through
August 23, 2006 and year ended December 31, 2005, are
as follows:
|
|
|
|
|
|
|
|
|
Percent of
revenues
|
|
|
January 1,
|
|
|
|
|
2006
|
|
|
|
|
through
|
|
Year ended
|
|
|
August 23,
|
|
December 31,
|
Customer
|
|
2006
|
|
2005
|
|
|
Western
|
|
|
63%
|
|
|
70%
|
Williams Production RMT Company
|
|
|
27%
|
|
|
30%
|
Other
|
|
|
10%
|
|
|
%
|
|
|
|
|
|
|
|
Total
|
|
|
100%
|
|
|
100%
|
|
|
|
|
|
|
|
Total revenues were approximately $12.2 million and
$17.2 million for the period from January 1, 2006
through August 23, 2006 and for the year ended
December 31, 2005, respectively. Western, an affiliate of
the Company, and Williams Production RMT Co., a non-affiliate of
the Company, were the only customers that separately accounted
for greater than 10% of the Companys revenues for the
period from January 1, 2006 through August 23, 2006
and for the year ended December 31, 2005.
Financial instruments, which potentially subject the Company to
concentrations of credit risk, consist principally of accounts
receivable. Where exposed to credit risk, the Company
(1) analyzes the
F-44
Notes to
financial statements of MIGC, Inc.
counterparties financial condition prior to entering into
an agreement, (2) establishes credit limits and
(3) monitors the appropriateness of those credit limits on
an ongoing basis. The Company maintains no credit policy with
respect to Western and its subsidiaries.
|
|
6.
|
PROPERTY, PLANT
AND EQUIPMENT
|
A summary of the historical cost of the Companys property,
plant and equipment is as follows:
|
|
|
|
|
|
|
|
|
|
Estimated
|
|
|
|
|
|
useful life
|
|
December 31,
|
|
|
|
(years)
|
|
2005
|
|
|
|
|
|
(in thousands,
except for estimated useful life)
|
|
|
Pipeline and equipment
|
|
|
33 to 49
|
|
$
|
45,651
|
|
General plant and other
|
|
|
3 to 10
|
|
|
470
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment
|
|
|
|
|
|
46,121
|
|
Total accumulated depreciation
|
|
|
|
|
|
(17,389
|
)
|
|
|
|
|
|
|
|
|
Total net property, plant and equipment
|
|
|
|
|
$
|
28,732
|
|
|
|
|
|
|
|
|
|
The Company generally calculates depreciation using the
straight-line method, based on estimated useful lives and
salvage values of assets. Uncertainties that impact these
estimates include changes in laws and regulations relating to
restoration and abandonment requirements, economic conditions
and supply and demand in the area. When assets are placed into
service, the Company makes estimates with respect to estimated
useful lives and salvage values that it believes to be
reasonable. However, subsequent events may cause a change in
estimate, thereby impacting the future depreciation amounts.
|
|
7.
|
ASSET RETIREMENT
OBLIGATIONS
|
The Companys asset retirement obligations are related to
the capping and dismantling of its pipeline and equipment. The
liability for asset retirement obligations is initially recorded
at estimated fair value, with an offsetting increase to
properties and equipment. Accretion expense is recognized over
the estimated productive life of the related assets, increasing
the liability to its expected settlement value. If the fair
value of the estimated asset retirement obligation changes, an
adjustment is recorded for both the asset retirement obligation
and the asset retirement cost.
The following table provides a rollforward of the Companys
asset retirement obligations. Liabilities settled include, among
other things, asset retirement obligations that were assumed by
purchasers of divested properties.
|
|
|
|
|
|
|
Year ended
|
|
|
|
December 31,
|
|
|
|
2005
|
|
|
|
|
|
(in
thousands)
|
|
|
Carrying amount of asset retirement obligations at beginning of
year
|
|
$
|
1,204
|
|
Liabilities transferred
|
|
|
(45
|
)
|
Accretion expense
|
|
|
74
|
|
|
|
|
|
|
Carrying amount of asset retirement obligations at end of year
|
|
$
|
1,233
|
|
|
|
|
|
|
F-45
Notes to
financial statements of MIGC, Inc.
|
|
8.
|
COMMITMENTS AND
CONTINGENCIES
|
Environmental
The Company is subject to federal, state and local regulations
governing air and water quality, hazardous and solid waste
disposal and other environmental matters. Management believes
there are no such matters that are expected to have a material
adverse effect on the Companys results of operations, cash
flows or financial position.
Litigation and
legal proceedings
From time to time, the Company is involved in legal, tax,
regulatory and other proceedings in various forums regarding
performance, contracts and other matters that arise in the
ordinary course of business. Management is not aware of any such
proceeding for which a final disposition could have a material
adverse effect on the Companys results of operations, cash
flows or financial position.
Obligations and
commitments
The following is a summary of the Companys future payment
obligations as of December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Obligations by
Period
|
|
|
|
|
2-3
|
|
4-5
|
|
Later
|
|
|
|
|
1 Year
|
|
Years
|
|
Years
|
|
Years
|
|
Total
|
|
|
|
(in
thousands)
|
|
Operating leases
|
|
$
|
170
|
|
$
|
120
|
|
$
|
|
|
$
|
|
|
$
|
290
|
Transportation agreements
|
|
|
5,678
|
|
|
3,782
|
|
|
|
|
|
|
|
|
9,460
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5,848
|
|
$
|
3,902
|
|
$
|
|
|
$
|
|
|
$
|
9,750
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
leases
The Company entered into various agreements to obtain access to
compressors. Rent expense related to compressor equipment leases
was $99,919 and $367,359 for the period from January 1,
2006 through August 23, 2006 and the year ended
December 31, 2005, respectively. There are no future
minimum lease obligations or payments beyond December 31,
2008.
Transportation
agreements
The Company entered into various transportation agreements with
interstate pipeline companies in order to access downstream
markets. Rent expense for leased capacity on third-party
pipelines was $26,226 and $36,000 for the period from
January 1, 2006 through August 23, 2006 and the year
ended December 31, 2005, respectively. The table above
includes future payments under these transportation commitments
of $9.46 million for all future years beyond 2005.
F-46
Western Gas
Partners, LP
Report
of independent registered public accounting firm
The Board of Directors
Anadarko Petroleum Corporation:
We have audited the accompanying balance sheet of Western Gas
Partners, LP (the Partnership) as of August 21,
2007. This financial statement is the responsibility of the
Partnerships management. Our responsibility is to express
an opinion on this financial statement based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the balance sheet is free of
material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the
balance sheet. An audit also includes assessing the accounting
principles used and significant estimates made by management, as
well as evaluating the overall balance sheet presentation. We
believe that our audit provides a reasonable basis for our
opinion.
In our opinion, the financial statement referred to above
presents fairly, in all material respects, the financial
position of the Partnership as of August 21, 2007, in
conformity with U.S. generally accepted accounting principles.
/s/ KPMG LLP
Houston, Texas
October 11, 2007
F-47
Western Gas
Partners, LP
|
|
|
|
|
|
|
August 21,
2007
|
|
|
|
|
Assets
|
|
|
|
|
Total Assets
|
|
$
|
|
|
|
|
|
|
|
Partners Equity
|
|
|
|
|
Limited partner equity
|
|
$
|
2,940
|
|
General partner equity
|
|
|
60
|
|
Less receivables from WGR Asset Holding Company, LLC and Western
Gas Holdings, LLC
|
|
|
(3,000
|
)
|
|
|
|
|
|
Total Partners Equity
|
|
$
|
|
|
|
|
|
|
|
See the accompanying note to the balance sheet.
F-48
Western Gas
Partners, LP
Note to
the balance sheet
Western Gas Partners, LP (the Partnership) is a
Delaware limited partnership formed on August 21, 2007 and
will acquire the assets owned by Anadarko Gathering Company,
Pinnacle Gas Treating, Inc. and MIGC, Inc.
Western Gas Holdings, LLC (Holdings GP), as general
partner, contributed $60 and WGR Asset Holding Company, LLC
(WGR Asset Holdings) contributed $2,940, all in the
form of receivables, to the Partnership on August 21, 2007.
The receivables from Holdings GP and WGR Asset Holdings have
been reflected as a reduction to Partners Equity on the
accompanying balance sheet.
On September 11, 2007, WGR Asset Holdings transferred 100%
of its interest in the Partnership to WGR Holdings, LLC
(Holdings LP). There have been no other transactions
involving the Partnership.
The Partnership will issue common and subordinated units, each
representing limited partner interests in the Partnership, to
Holdings LP and has issued a 2.0% general partner interest in
the Partnership to Holdings GP. The Partnership also
intends to issue and sell common units to the public in
connection with its initial public offering.
F-49
Western Gas
Holdings, LLC
Report
of independent registered public accounting firm
The Board of Directors
Anadarko Petroleum Corporation:
We have audited the accompanying balance sheet of Western Gas
Holdings, LLC (the Company) as of August 21,
2007. This financial statement is the responsibility of the
Companys management. Our responsibility is to express an
opinion on this financial statement based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the balance sheet is free of
material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the
balance sheet. An audit also includes assessing the accounting
principles used and significant estimates made by management, as
well as evaluating the overall balance sheet presentation. We
believe that our audit provides a reasonable basis for our
opinion.
In our opinion, the financial statement referred to above
presents fairly, in all material respects, the financial
position of the Company as of August 21, 2007, in
conformity with U.S. generally accepted accounting principles.
/s/ KPMG LLP
Houston, Texas
October 11, 2007
F-50
Western Gas
Holdings, LLC
|
|
|
|
|
|
|
August 21,
2007
|
|
|
|
|
Assets
|
|
|
|
|
Investment in Western Gas Partners, LP
|
|
$
|
60
|
|
|
|
|
|
|
Total Assets
|
|
$
|
60
|
|
|
|
|
|
|
Liabilities and Members Equity
|
|
|
|
|
Payable to Western Gas Partners, LP
|
|
$
|
60
|
|
Members Equity
|
|
|
|
|
Member equity
|
|
|
1,000
|
|
Less receivable from WGR Asset Holding Company, LLC
|
|
|
(1,000
|
)
|
|
|
|
|
|
Total member equity
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Members Equity
|
|
$
|
60
|
|
|
|
|
|
|
See the accompanying note to the balance sheet.
F-51
Western Gas
Holdings, LLC
Note to
the balance sheet
Western Gas Holdings, LLC (the Company), is a
limited liability company formed on August 21, 2007 to
become the general partner of Western Gas Partners, LP (the
Partnership). The Company owns a 2.0% general
partner interest in the Partnership.
WGR Asset Holding Company, LLC (WGR Asset Holdings),
as sole member, contributed $1,000, in the form of a receivable,
to the Company on August 21, 2007 in exchange for a 100%
membership interest. On August 21, 2007, the Company
contributed $60, in the form of a receivable, to the Partnership
in exchange for a 2.0% general partner interest in the
Partnership.
The receivable from WGR Asset Holdings has been reflected as a
reduction of Member Equity on the accompanying balance sheet.
There have been no other transactions involving the Company.
F-52
Amended
and restated
agreement of limited partnership
of Western Gas Partners, LP
A-1
adjusted operating surplus: For any
period, operating surplus generated during that period is
adjusted to:
(a) increase operating surplus by any net decreases
made in subsequent periods in cash reserves for operating
expenditures initially established with respect to such period;
(b) decrease operating surplus by any net reduction
in cash reserves for operating expenditures during that period
not relating to an operating expenditure made during that
period; and
(c) increase operating surplus by any net increase in
cash reserves for operating expenditures during that period
required by any debt instrument for the repayment of principal,
interest or premium.
Adjusted operating surplus does not include the portion of
operating surplus described in subpart (a)(2) of the definition
of operating surplus in this Appendix B.
available cash: For any quarter ending
prior to liquidation:
(a) the sum of:
(1) all cash and cash equivalents of Western Gas
Partners, LP and its subsidiaries on hand at the end of that
quarter; and
(2) if our general partner so determines all or a
portion of any additional cash or cash equivalents of Western
Gas Partners, LP and its subsidiaries on hand on the date of
determination of available cash for that quarter;
(b) less the amount of cash reserves established by
our general partner to:
(1) provide for the proper conduct of the business of
Western Gas Partners, LP and its subsidiaries (including
reserves for future capital expenditures and for future credit
needs of Western Gas Partners, LP and its subsidiaries) after
that quarter;
(2) comply with applicable law or any debt instrument
or other agreement or obligation to which Western Gas Partners,
LP or any of its subsidiaries is a party or its assets are
subject; and
(3) provide funds for minimum quarterly distributions
and cumulative common unit arrearages for any one or more of the
next four quarters;
provided, however, that our general partner may not
establish cash reserves pursuant to clause (b)(3) immediately
above unless our general partner has determined that the
establishment of reserves will not prevent us from distributing
the minimum quarterly distribution on all common units and any
cumulative common unit arrearages thereon for that quarter; and
provided, further, that disbursements made by us or any
of our subsidiaries or cash reserves established, increased or
reduced after the end of that quarter but on or before the date
of determination of available cash for that quarter shall be
deemed to have been made, established, increased or reduced, for
purposes of determining available cash, within that quarter if
our general partner so determines.
backhaul: Refers to pipeline
transportation service in which the nominated gas flow from
receipt point to delivery point is in the opposite direction as
the pipelines physical gas flow.
Bbls: Barrels.
Bcf/d: One billion cubic feet per day.
capital account: The capital account
maintained for a partner under the partnership agreement. The
capital account of a partner for a common unit, a subordinated
unit, an incentive distribution right or any other partnership
interest will be the amount which that capital account would be
if that common
B-1
Glossary of
terms
unit, subordinated unit, incentive distribution right or other
partnership interest were the only interest in Western Gas
Partners, LP held by a partner.
capital surplus: All available cash
distributed by us on any date from any source will be treated as
distributed from operating surplus until the sum of all
available cash distributed since the closing of the initial
public offering equals the operating surplus from the closing of
the initial public offering through the end of the quarter
immediately preceding that distribution. Any excess available
cash distributed by us on that date will be deemed to be capital
surplus.
closing price: The last sale price on a
day, regular way, or in case no sale takes place on that day,
the average of the closing bid and asked prices on that day,
regular way, in either case, as reported in the principal
consolidated transaction reporting system for securities listed
or admitted to trading on the principal national securities
exchange on which the units of that class are listed or admitted
to trading. If the units of that class are not listed or
admitted to trading on any national securities exchange, the
last quoted price on that day. If no quoted price exists, the
average of the high bid and low asked prices on that day in the
over-the-counter market, as reported by the New York Stock
Exchange or any other system then in use. If on any day the
units of that class are not quoted by any organization of that
type, the average of the closing bid and asked prices on that
day as furnished by a professional market maker making a market
in the units of the class selected by the our board of
directors. If on that day no market maker is making a market in
the units of that class, the fair value of the units on that day
as determined reasonably and in good faith by our board of
directors.
condensate: A natural gas liquid with a
low vapor pressure, mainly composed of propane, butane, pentane
and heavier hydrocarbon fractions.
cumulative common unit arrearage: The
amount by which the minimum quarterly distribution for a quarter
during the subordination period exceeds the distribution of
available cash from operating surplus actually made for that
quarter on a common unit, cumulative for that quarter and all
prior quarters during the subordination period.
current market price: For any class of
units listed or admitted to trading on any national securities
exchange as of any date, the average of the daily closing prices
for the 20 consecutive trading days immediately prior to that
date.
drilling location inventory: The
estimated number of potential drilling locations within a given
exploration area.
dry gas: A gas primarily composed of
methane and ethane where heavy hydrocarbons and water either do
not exist or have been removed through processing.
end-use markets: The ultimate
users/consumers of transported energy products.
forward-haul: Refers to pipeline
transportation service in which the nominated gas flow from
receipt point to delivery point is in the same direction as the
pipelines physical gas flow.
interim capital transactions: The
following transactions if they occur prior to liquidation:
(a) borrowings, refinancings or refundings of
indebtedness and sales of debt securities (other than for items
purchased on open account in the ordinary course of business) by
Western Gas Partners, LP or any of its subsidiaries;
(b) sales of equity interests by Western Gas
Partners, LP or any of its subsidiaries;
(c) sales or other voluntary or involuntary
dispositions of any assets of Western Gas Partners, LP or any of
its subsidiaries (other than sales or other dispositions of
inventory, accounts receivable and other assets in the ordinary
course of business, and sales or other dispositions of assets as
a part of normal retirements or replacements);
(d) the termination of interest rate swap agreements;
B-2
Glossary of
terms
(e) capital contributions; and
(f) corporate reorganizations or restructurings.
long ton: A British unit of weight
equivalent to 2,240 pounds.
LTD: One long ton per day.
MMBtu: One million British Thermal
Units.
MMBtu/d: One million British Thermal
Units per day.
MMcf: One million cubic feet of natural
gas.
MMcf/d: One
million cubic feet per day.
NGLs: Natural gas liquids. The
combination of ethane, propane, butane and natural gasolines
that when removed from natural gas become liquid under various
levels of higher pressure and lower temperature.
operating expenditures: All of our cash
expenditures, including, but not limited to, taxes,
reimbursement of expenses to our general partner, reimbursement
of expenses to Anadarko for services pursuant to the omnibus
agreement or personnel provided to us under the services and
secondment agreement, payments made in the ordinary course of
business under interest rate swap agreements or commodity hedge
contracts, manager and officer compensation, repayment of
working capital borrowings, debt service payments and estimated
maintenance capital expenditures, provided that operating
expenditures will not include:
|
|
|
|
|
repayment of working capital borrowings deducted from operating
surplus pursuant to the last bullet point of the definition of
operating surplus below when such repayment actually occurs;
|
|
|
|
|
|
payments (including prepayments and prepayment penalties) of
principal of and premium on indebtedness, other than working
capital borrowings;
|
|
|
|
|
|
expansion capital expenditures;
|
|
|
|
|
|
actual maintenance capital expenditures;
|
|
|
|
|
|
investment capital expenditures;
|
|
|
|
|
|
payment of transaction expenses relating to interim capital
transactions;
|
|
|
|
|
|
distributions to our partners (including distributions in
respect of Class B units and our incentive distribution
rights); or
|
|
|
|
|
|
non-pro rata purchases of units of any class made with the
proceeds of a substantially concurrent equity issuance.
|
operating surplus: Operating surplus consists of:
|
|
|
|
|
$27.1 million (as described below); plus
|
|
|
|
|
|
all of our cash receipts after the closing of this offering,
excluding cash from the following:
|
|
|
|
|
|
borrowings that are not working capital borrowings and sales of
debt securities,
|
|
|
|
|
|
sales of equity securities,
|
|
|
|
|
|
sales or other dispositions of assets outside the ordinary
course of business,
|
|
|
|
|
|
the termination of interest rate swap agreements or commodity
hedge contracts prior to the termination date specified herein,
|
|
|
|
|
|
capital contributions received, and
|
|
|
|
|
|
corporate reorganizations or restructurings; plus
|
B-3
Glossary of
terms
|
|
|
|
|
working capital borrowings made after the end of a quarter but
before the date of determination of operating surplus for the
quarter; plus
|
|
|
|
|
|
cash distributions paid on equity issued to finance all or a
portion of the construction, improvement or replacement of a
capital improvement or capital asset (such as equipment or
facilities) during the period beginning on the date that we
enter into a binding obligation to commence the construction,
acquisition or improvement of a capital improvement or
replacement of a capital asset and ending on the earlier to
occur of the date the capital improvement or capital asset
commences commercial service or the date that it is abandoned or
disposed of; less
|
|
|
|
|
|
our operating expenditures (as defined above) after the closing
of this offering; less
|
|
|
|
|
|
the amount of cash reserves established by our general partner
to provide funds for future operating expenditures; less
|
|
|
|
|
|
all working capital borrowings not repaid within twelve months
after having been incurred.
|
play: A proven geological formation
that contains commercial amounts of petroleum and/or natural gas.
psia: Pounds per square inch, absolute.
receipt point: The point where
production is received by or into a gathering system or
transportation pipeline.
residue gas: The natural gas remaining
after being processed or treated.
sour gas: Gas containing more than four
parts per million of hydrogen sulfide.
tailgate: Refers to the point at which
processed natural gas and/or natural gas liquids leave a
processing facility for end-use markets.
Tcf: One trillion cubic feet of natural
gas.
wellhead: The equipment at the surface
of a well used to control the wells pressure; the point at
which the hydrocarbons and water exit the ground.
B-4
Through and
including ,
2008 (the
25th
day after the date of this prospectus), federal securities law
may require all dealers that effect transactions in these
securities, whether or not participating in this offering, to
deliver a prospectus, This requirement is in addition to the
dealers obligation to deliver a prospectus when acting as
underwriters and with respect to their unsold allotments or
subscriptions.
Part II
Information required
in the registration statement
|
|
ITEM 13.
|
OTHER EXPENSES OF
ISSUANCE AND DISTRIBUTION.
|
Set forth below are the expenses (other than underwriting
discounts) expected to be incurred in connection with the
issuance and distribution of the securities registered hereby.
With the exception of the Securities and Exchange Commission
registration fee, the FINRA filing fee and the amounts set forth
below are estimates.
|
|
|
|
|
SEC registration fee
|
|
$
|
13,920
|
|
FINRA filing fee
|
|
|
45,781
|
|
Printing and engraving expenses
|
|
|
|
|
Fees and expenses of legal counsel
|
|
|
|
|
Accounting fees and expenses
|
|
|
|
|
Transfer agent and registrar fees
|
|
|
|
|
New York Stock Exchange listing fee
|
|
|
|
|
Miscellaneous
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
3,000,000
|
|
|
|
|
|
|
|
|
ITEM 14.
|
INDEMNIFICATION
OF OFFICERS AND MEMBERS OF OUR BOARD OF DIRECTORS.
|
The section of the prospectus entitled The partnership
agreementIndemnification discloses that we will
generally indemnify officers, directors and affiliates of the
general partner to the fullest extent permitted by the law
against all losses, claims, damages or similar events and is
incorporated herein by this reference. Reference is also made to
Section
of the underwriting agreement to be filed as an exhibit to this
registration statement in which we and our general partner will
agree to indemnify the underwriters against certain liabilities,
including liabilities under the Securities Act of 1933, as
amended, and to contribute to payments that may be required to
be made in respect of these liabilities. Subject to any terms,
conditions or restrictions set forth in the partnership
agreement,
Section 17-108
of the Delaware Revised Uniform Limited Partnership Act empowers
a Delaware limited partnership to indemnify and hold harmless
any partner or other persons from and against all claims and
demands whatsoever.
|
|
ITEM 15.
|
RECENT SALES OF
UNREGISTERED SECURITIES.
|
On August 21, 2007, in connection with the formation of
Western Gas Partners, LP (the Partnership), the
Partnership issued to (i) its general partner the 2.0%
general partner interest in the Partnership for $60 and
(ii) WGR Asset Holding Company LLC the 98.0% limited
partner interest in the Partnership for $2,940. The 98.0%
limited partner in trust was subsequently contributed to WGR
Holdings, LLC on September 11, 2007. The issuance and
contribution were exempt from registration under
Section 4(2) of the Securities Act. There have been no
other sales of unregistered securities within the past three
years.
II-1
Part II
The following documents are filed as exhibits to this
registration statement:
|
|
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
number
|
|
|
|
Description
|
|
|
|
1
|
.1*
|
|
|
|
|
|
Form of Underwriting Agreement
|
|
3
|
.1**
|
|
|
|
|
|
Certificate of Limited Partnership of Western Gas Partners, LP
|
|
3
|
.2*
|
|
|
|
|
|
Amended and Restated Limited Partnership Agreement of Western
Gas Partners, LP (included as Appendix A in the prospectus
included in this Registration Statement)
|
|
3
|
.3**
|
|
|
|
|
|
Certificate of Formation of Western Gas Holdings, LLC
|
|
3
|
.4*
|
|
|
|
|
|
Amended and Restated Limited Liability Company Agreement of
Western Gas Holdings, LLC
|
|
5
|
.1*
|
|
|
|
|
|
Opinion of Vinson & Elkins L.L.P. as to the legality
of the securities being registered
|
|
8
|
.1*
|
|
|
|
|
|
Opinion of Vinson & Elkins L.L.P. relating to tax
matters
|
|
10
|
.1*
|
|
|
|
|
|
Form of Credit Agreement
|
|
10
|
.2*
|
|
|
|
|
|
Form of Omnibus Agreement
|
|
10
|
.3*
|
|
|
|
|
|
Form of Services and Secondment Agreement
|
|
10
|
.4
|
|
|
|
|
|
Dew Gas Gathering Agreement between Anadarko Gathering Company
LLC and Anadarko Petroleum Corporation
|
|
10
|
.5
|
|
|
|
|
|
Haley Gas Gathering Agreement between Anadarko Gathering Company
LLC and Anadarko Petroleum Corporation
|
|
10
|
.6
|
|
|
|
|
|
Hugoton Gas Gathering Agreement between Anadarko Gathering
Company LLC and Anadarko Petroleum Corporation
|
|
10
|
.7
|
|
|
|
|
|
Pinnacle Gas Gathering Agreement between Pinnacle Gas Treating
LLC and Anadarko Petroleum Corporation
|
|
10
|
.8*
|
|
|
|
|
|
Form of Working Capital Facility
|
|
10
|
.9*
|
|
|
|
|
|
Form of Contribution, Conveyance and Assumption Agreement
|
|
10
|
.10*
|
|
|
|
|
|
Form of Indemnification Agreement by and between Western Gas
Holdings, LLC, its Officers and Directors
|
|
10
|
.11*
|
|
|
|
|
|
Long-Term Incentive Plan
|
|
10
|
.12*
|
|
|
|
|
|
Form of Tax Sharing Agreement
|
|
10
|
.13
|
|
|
|
|
|
Revolving Credit Agreement, dated as of September 1, 2004, by
and among Anadarko Petroleum Corporation, Anadarko Canada
Corporation, JPMorgan Chase Bank, JPMorgan Chase Bank, Toronto
Branch, ABN AMRO Bank N.V. and Deutsche Bank AG New York Branch,
Harris Nesbitt Financing, Inc. and Credit Suisse First Boston,
and each of the Lenders named therein.
|
|
10
|
.14
|
|
|
|
|
|
First Amendment to Revolving Credit Agreement, dated as of
August 31, 2006, by and among Anadarko Petroleum Corporation,
Anadarko Canada Corporation, JPMorgan Chase Bank, N.A., JPMorgan
Chase Bank, N.A., Toronto Branch, ABN AMRO Bank N.V. and
Deutsche Bank AG New York Branch, BMO Capital Markets Financing,
Inc. and Credit Suisse, Cayman Islands Branch, and each of the
Lenders named therein.
|
|
10
|
.15
|
|
|
|
|
|
Second Amendment to Revolving Credit Agreement, dated as of
December 14, 2007, by and among Anadarko Petroleum Corporation,
Western Gas Partners LP, JPMorgan Chase Bank, N.A., ABN AMRO
Bank N.V. and Deutsche Bank AG New York Branch, BMO Capital
Markets Financing, Inc., and Credit Suisse, Cayman Islands
Branch, and each of the Lenders named therein.
|
|
21
|
.1*
|
|
|
|
|
|
List of Subsidiaries of Western Gas Partners, LP
|
II-2
Part II
|
|
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
number
|
|
|
|
Description
|
|
|
|
23
|
.1
|
|
|
|
|
|
Consent of KPMG LLP
|
|
23
|
.2
|
|
|
|
|
|
Consent of KPMG LLP
|
|
23
|
.3
|
|
|
|
|
|
Consent of KPMG LLP
|
|
23
|
.4*
|
|
|
|
|
|
Consent of Vinson & Elkins L.L.P. (contained in
Exhibit 5.1)
|
|
23
|
.5*
|
|
|
|
|
|
Consent of Vinson & Elkins L.L.P. (contained in
Exhibit 8.1)
|
|
24
|
.1**
|
|
|
|
|
|
Powers of Attorney
|
|
|
|
* |
|
To be filed by amendment. |
|
|
|
|
|
Portions of this exhibit have been omitted pursuant to a
request for confidential treatment. |
The undersigned registrant hereby undertakes to provide to the
underwriters at the closing specified in the underwriting
agreement certificates in such denominations and registered in
such names as required by the underwriters to permit prompt
delivery to each purchaser.
Insofar as indemnification for liabilities arising under the
Securities Act may be permitted to directors, officers and
controlling persons of the registrant pursuant to the foregoing
provisions, or otherwise, the registrant has been advised that
in the opinion of the Securities and Exchange Commission such
indemnification is against public policy as expressed in the
Securities Act and is, therefore, unenforceable. In the event
that a claim for indemnification against such liabilities (other
than the payment by the registrant of expenses incurred or paid
by a director, officer or controlling person of the registrant
in the successful defense of any action, suit or proceeding) is
asserted by such director, officer or controlling person in
connection with the securities being registered, the registrant
will, unless in the opinion of its counsel the matter has been
settled by controlling precedent, submit to a court of
appropriate jurisdiction the question whether such
indemnification by it is against public policy as expressed in
the Securities Act and will be governed by the final
adjudication of such issue.
The undersigned registrant hereby undertakes that:
(1) For purposes of determining any liability under
the Securities Act, the information omitted from the form of
prospectus filed as part of this registration statement in
reliance upon Rule 430A and contained in a form of
prospectus filed by the registrant pursuant to
Rule 424(b)(1) or (4) or 497(h) under the Securities
Act shall be deemed to be part of this registration statement as
of the time it was declared effective.
(2) For the purpose of determining any liability
under the Securities Act, each post-effective amendment that
contains a form of prospectus shall be deemed to be a new
registration statement relating to the securities offered
therein, and the offering of such securities at that time shall
be deemed to be the initial bona fide offering thereof.
The undersigned registrant undertakes to send to each common
unitholder, at least on an annual basis, a detailed statement of
any transactions with Anadarko or its subsidiaries, and of fees,
commissions, compensation and other benefits paid, or accrued to
Anadarko or its subsidiaries for the fiscal year completed,
showing the amount paid or accrued to each recipient and the
services performed.
The registrant undertakes to provide to the common unitholders
the financial statements required by
Form 10-K
for the first full fiscal year of operations of the company.
II-3
Signatures
Pursuant to the requirements of the Securities Act of 1933, as
amended, the registrant has duly caused this amendment to the
Registration Statement to be signed on its behalf by the
undersigned, thereunto duly authorized, in the City of Houston,
State of Texas, on December 26, 2007.
WESTERN GAS PARTNERS, LP
|
|
|
|
By:
|
Western Gas Holdings, LLC,
its general partner
|
Name: Robert G. Gwin
|
|
|
|
Title:
|
President, Chief Executive Officer and Director
|
Pursuant to the requirements of the Securities Act of 1933, as
amended, this Registration Statement has been signed below by
the following persons in the capacities and the dates indicated.
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
/s/ Robert
G. Gwin
Robert
G. Gwin
|
|
President, Chief Executive Officer and Director
|
|
December 26, 2007
|
|
|
|
|
|
*
Danny
J. Rea
|
|
Senior Vice President, Chief Operating Officer and Director
|
|
December 26, 2007
|
|
|
|
|
|
/s/ Michael
C. Pearl
Michael
C. Pearl
|
|
Senior Vice President, Chief Financial Officer and Chief
Accounting Officer
|
|
December 26, 2007
|
|
|
|
|
|
*
R.
A. Walker
|
|
Chairman of the Board and Director
|
|
December 26, 2007
|
|
|
|
|
|
*
Karl
F. Kurz
|
|
Director
|
|
December 26, 2007
|
|
|
|
|
|
*
Robert
K. Reeves
|
|
Director
|
|
December 26, 2007
|
|
|
|
|
|
|
|
*By:
|
|
/s/ Robert
G. Gwin
Robert
G. GwinAttorney-in-fact
|
|
|
|
|
II-4
Exhibit index
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
number
|
|
|
|
Description
|
|
|
|
1
|
.1*
|
|
|
|
Form of Underwriting Agreement
|
|
3
|
.1**
|
|
|
|
Certificate of Limited Partnership of Western Gas Partners, LP
|
|
3
|
.2*
|
|
|
|
Amended and Restated Limited Partnership Agreement of Western
Gas Partners, LP (included as Appendix A in the prospectus
included in this Registration Statement)
|
|
3
|
.3**
|
|
|
|
Certificate of Formation of Western Gas Holdings, LLC
|
|
3
|
.4*
|
|
|
|
Amended and Restated Limited Liability Company Agreement of
Western Gas Holdings, LLC
|
|
5
|
.1*
|
|
|
|
Opinion of Vinson & Elkins L.L.P. as to the legality
of the securities being registered
|
|
8
|
.1*
|
|
|
|
Opinion of Vinson & Elkins L.L.P. relating to tax
matters
|
|
10
|
.1*
|
|
|
|
Form of Credit Agreement
|
|
10
|
.2*
|
|
|
|
Form of Omnibus Agreement
|
|
10
|
.3*
|
|
|
|
Form of Services and Secondment Agreement
|
|
10
|
.4
|
|
|
|
Dew Gas Gathering Agreement between Anadarko Gathering Company
LLC and Anadarko Petroleum Corporation
|
|
10
|
.5
|
|
|
|
Haley Gas Gathering Agreement between Anadarko Gathering Company
LLC and Anadarko Petroleum Corporation
|
|
10
|
.6
|
|
|
|
Hugoton Gas Gathering Agreement between Anadarko Gathering
Company LLC and Anadarko Petroleum Corporation
|
|
10
|
.7
|
|
|
|
Pinnacle Gas Gathering Agreement between Pinnacle Gas Treating
LLC and Anadarko Petroleum Corporation
|
|
10
|
.8*
|
|
|
|
Form of Working Capital Facility
|
|
10
|
.9*
|
|
|
|
Form of Contribution, Conveyance and Assumption Agreement
|
|
10
|
.10*
|
|
|
|
Form of Indemnification Agreement by and between Western Gas
Holdings, LLC, its Officers and Directors
|
|
10
|
.11*
|
|
|
|
Long-Term Incentive Plan
|
|
10
|
.12*
|
|
|
|
Form of Tax Sharing Agreement
|
|
10
|
.13
|
|
|
|
Revolving Credit Agreement, dated as of September 1, 2004, by
and among Anadarko Petroleum Corporation, Anadarko Canada
Corporation, JPMorgan Chase Bank, JPMorgan Chase Bank, Toronto
Branch, ABN AMRO Bank N.V. and Deutsche Bank AG New York Branch,
Harris Nesbitt Financing, Inc. and Credit Suisse First Boston,
and each of the Lenders named therein.
|
|
10
|
.14
|
|
|
|
First Amendment to Revolving Credit Agreement, dated as of
August 31, 2006, by and among Anadarko Petroleum Corporation,
Anadarko Canada Corporation, JPMorgan Chase Bank, N.A., JPMorgan
Chase Bank, N.A., Toronto Branch, ABN AMRO Bank N.V. and
Deutsche Bank AG New York Branch, BMO Capital Markets Financing,
Inc. and Credit Suisse, Cayman Islands Branch, and each of the
Lenders named therein.
|
|
10
|
.15
|
|
|
|
Second Amendment to Revolving Credit Agreement, dated as of
December 14, 2007, by and among Anadarko Petroleum Corporation,
Western Gas Partners LP, JPMorgan Chase Bank, N.A., ABN AMRO
Bank N.V. and Deutsche Bank AG New York Branch, BMO Capital
Markets Financing, Inc., and Credit Suisse, Cayman Islands
Branch, and each of the Lenders named therein.
|
|
21
|
.1*
|
|
|
|
List of Subsidiaries of Western Gas Partners, LP
|
|
23
|
.1
|
|
|
|
Consent of KPMG LLP
|
|
23
|
.2
|
|
|
|
Consent of KPMG LLP
|
|
23
|
.3
|
|
|
|
Consent of KPMG LLP
|
|
23
|
.4*
|
|
|
|
Consent of Vinson & Elkins L.L.P. (contained in
Exhibit 5.1)
|
|
23
|
.5*
|
|
|
|
Consent of Vinson & Elkins L.L.P. (contained in
Exhibit 8.1)
|
|
24
|
.1**
|
|
|
|
Powers of Attorney
|
|
|
|
* |
|
To be filed by amendment. |
|
|
|
|
|
Portions of this exhibit have been omitted pursuant to a
request for confidential treatment. |
II-5