sv1za
As filed with the Securities and Exchange Commission on
May 22, 2006
Registration
No. 333-133065
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
Williams Partners L.P.
(Exact name of registrant as specified in its charter)
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Delaware |
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4922 |
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20-2485124 |
(State or other jurisdiction of |
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(Primary Standard Industrial |
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(I.R.S. Employer |
incorporation or organization) |
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Classification Code Number) |
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Identification Number) |
One Williams Center
Tulsa, Oklahoma 74172-0172
(918) 573-2000
(Address, including zip code, and telephone number, including
area code, of registrants principal executive offices)
James J. Bender
One Williams Center
Tulsa, Oklahoma 74172-0172
(918) 573-2000
(Name, address, including zip code, and telephone number,
including area code, of agent for service)
Copies to:
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Robert V. Jewell |
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Dan A. Fleckman |
William J. Cooper |
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Vinson & Elkins L.L.P. |
Andrews Kurth LLP |
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First City Tower |
600 Travis, Suite 4200 |
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1001 Fannin, Suite 2300 |
Houston, Texas 77002 |
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Houston, Texas 77002 |
(713) 220-4200 |
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(713) 758-2222 |
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,
please check the following box and list the Securities Act
registration statement number of the earlier effective
registration statement for the same
offering. o
If this Form is a post-effective amendment filed pursuant to
Rule 462(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
CALCULATION OF REGISTRATION FEE
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Proposed maximum |
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Proposed maximum |
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Title of Each Class of |
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offering price |
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aggregate offering |
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Amount of | |
Securities to be Registered |
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be registered(1) |
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per unit(2) |
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price(2) |
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Registration Fee | |
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Common units representing limited partnership interests
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7,590,000 |
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$33.97 |
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$257,832,300 |
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$27,588.06 |
(3) |
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(1) |
Includes 990,000 common units which may be sold upon exercise of
the underwriters over-allotment option. |
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(2) |
Calculated in accordance with Rule 457(c) on the basis of
the average of the high and low sales price of the common units
on May 16, 2006. |
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(3) |
The registrant previously paid registration fees of $28,028.33. |
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The Registrant hereby amends this Registration Statement on
such date or dates as may be necessary to delay its effective
date until the Registrant shall file a further amendment which
specifically states that this Registration Statement shall
thereafter become effective in accordance with Section 8(a)
of the Securities Act of 1933 or until the Registration
Statement shall become effective on such date as the Securities
and Exchange Commission, acting pursuant to said
Section 8(a), may determine.
The information
in this prospectus is not complete and may be changed. We may
not sell these securities until the registration statement filed
with the Securities and Exchange Commission is effective. This
prospectus is not an offer to sell these securities and is not
soliciting an offer to buy these securities in any state where
the offer or sale is not
permitted.
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Subject to Completion, dated May 22,
2006
PROSPECTUS
6,600,000 Common Units
Representing Limited Partner Interests
We are offering to sell 6,600,000 common units representing
limited partner interests in Williams Partners L.P. Our common
units are listed on the New York Stock Exchange under the symbol
WPZ. The last reported sales price of our common
units on the New York Stock Exchange on May 18, 2006, was
$35.10 per common unit.
Investing in our common units involves risks. Please read
Risk Factors beginning on page 23.
These risks include the following:
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We may not have sufficient cash from operations to enable us to
pay the minimum quarterly distribution following establishment
of cash reserves and payment of fees and expenses, including
payments to our general partner. |
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Because of the natural decline in production from existing wells
and competitive factors, the success of our gathering and
transportation businesses depends on our ability to connect new
sources of natural gas supply, which is dependent on factors
beyond our control. Any decrease in supplies of natural gas
could adversely affect our business and operating results. |
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Our processing, fractionation and storage businesses could be
affected by any decrease in the price of natural gas liquids or
a change in the price of natural gas liquids relative to the
price of natural gas. |
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Williams credit agreement and Williams public
indentures contain financial and operating restrictions that may
limit our access to credit. In addition, our ability to obtain
credit in the future will be affected by Williams credit
ratings. |
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Our general partner and its affiliates have conflicts of
interest and limited fiduciary duties, which may permit them to
favor their own interests to the detriment of our unitholders. |
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Even if unitholders are dissatisfied, they cannot currently
remove our general partner without its consent. |
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You may be required to pay taxes on your share of our income
even if you do not receive any cash distributions from us. |
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Per Common Unit |
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Public offering price
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Underwriting discount
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Proceeds to Williams Partners L.P. (before expenses)
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We have granted the underwriters a
30-day option to
purchase up to an additional 990,000 common units from us on the
same terms and conditions as set forth above if the underwriters
sell more than 6,600,000 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.
Lehman Brothers, on behalf of the underwriters, expects to
deliver the common units on or
about ,
2006.
Joint Book-Running Managers
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Lehman Brothers |
Citigroup |
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A.G. Edwards |
Merrill Lynch & Co. |
Wachovia Securities |
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RBC Capital Markets |
Raymond James |
,
2006
TABLE OF CONTENTS
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OF OPERATIONS
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iii
You should rely only on the information contained in this
prospectus. We have not, and the underwriters have not,
authorized anyone to provide you with different information. If
anyone provides you with different or inconsistent information,
you should not rely on it. We are not, and the underwriters are
not, making an offer to sell these securities in any
jurisdiction where an offer or sale is not permitted. You should
assume that the information appearing in this prospectus is
accurate as of the date on the front cover of this prospectus.
Our business, financial condition, results of operations and
prospects may have changed since that date.
References in this prospectus to Williams Partners
L.P., we, our, us or
like terms, when used in the present tense, prospectively or for
historical periods since August 23, 2005, refer to Williams
Partners L.P. and its subsidiaries. References to our
predecessor, or to we, our,
us or like terms for historical periods prior to
August 23, 2005, refer to the assets of The Williams
Companies, Inc. and its subsidiaries, which were contributed to
us at the closing of our initial public offering on
August 23, 2005. In either case, unless the context clearly
indicates otherwise, references to we,
our and us generally include the
operations of Discovery Producer Services LLC, in which we own a
40% interest, but does not include Williams Four Corners LLC, in
which we will own a 25.1% interest upon consummation of the
transactions discussed in this prospectus. When we refer to
Discovery and Four Corners by name, we are referring exclusively
to their respective businesses and operations.
iv
PROSPECTUS SUMMARY
This summary highlights information contained elsewhere in
this prospectus. It does not contain all of the information that
you should consider before investing in the common units. You
should read the entire prospectus carefully, including the
historical and pro forma financial statements and the notes to
those financial statements. The information presented in this
prospectus assumes that the underwriters option to
purchase additional units is not exercised. You should read
Williams Partners L.P. Summary of
Risk Factors and Risk Factors for information
about important factors to consider before buying the common
units. We include a glossary of some of the terms used in this
prospectus as Appendix A.
Williams Partners L.P.
We are a Delaware limited partnership formed by The Williams
Companies, Inc., or Williams, in February 2005, to own, operate
and acquire a diversified portfolio of complementary energy
assets. We are principally engaged in the business of gathering,
transporting and processing natural gas and fractionating and
storing natural gas liquids. Fractionation is the process by
which a mixed stream of natural gas liquids is separated into
its constituent products, such as ethane, propane and butane.
These natural gas liquids result from natural gas processing and
crude oil refining and are used as petrochemical feedstocks,
heating fuels and gasoline additives, among other applications.
On April 6, 2006, we entered into an agreement to acquire a
25.1% membership interest in Williams Four Corners LLC, or Four
Corners, from affiliates of Williams. Four Corners owns a
3,500-mile natural gas
gathering system, including three natural gas processing plants
and two natural gas treating plants, located in the
San Juan Basin in Colorado and New Mexico. Please read
Acquisition of Interest in Four Corners.
This is our first acquisition since our initial public offering
in August 2005. We intend to acquire additional assets in the
future and have a management team dedicated to a growth strategy.
Our current asset portfolio consists of:
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a 40% interest in Discovery Producer Services LLC, or Discovery,
which owns an integrated natural gas gathering and
transportation pipeline system extending from offshore in the
Gulf of Mexico to a natural gas processing facility and a
natural gas liquids fractionator in Louisiana; |
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the Carbonate Trend natural gas gathering pipeline off the coast
of Alabama; and |
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three integrated natural gas liquids storage facilities and a
50% interest in a natural gas liquids fractionator near Conway,
Kansas. |
Discovery provides integrated wellhead to market
services to natural gas producers operating in the shallow and
deep waters of the Gulf of Mexico off the coast of Louisiana.
Discovery consists of a
105-mile mainline,
168 miles of lateral gathering pipelines, a natural gas
processing plant and a natural gas liquids fractionation
facility. Discovery has interconnections with five natural gas
pipeline systems, which allow producers to benefit from flexible
and diversified access to a variety of natural gas markets. The
Discovery mainline was placed into service in 1998 and has a
design capacity of 600 million cubic feet per day.
Our Carbonate Trend gathering pipeline is a
34-mile pipeline that
gathers sour gas production from the Carbonate Trend area off
the coast of Alabama. Sour gas is natural gas that
has relatively high concentrations of acidic gases, such as
hydrogen sulfide and carbon dioxide, that exceed normal gas
transportation specifications. The pipeline was built and placed
into service in 2000 and has a maximum design capacity of
120 million cubic feet per day.
We are also engaged in the storage and fractionation of natural
gas liquids near Conway, Kansas, which is the principal natural
gas liquids market hub for the Mid-Continent region of the
United States. We believe our integrated natural gas liquids
storage facility at Conway is one of the largest in the
Mid-Continent region. These storage facilities consist of a
network of interconnected underground caverns that hold large
volumes of natural gas liquids and other hydrocarbons and have
an aggregate capacity of approximately 20 million barrels.
Our Conway storage facilities connect directly with the
Mid-America, or MAPL, and Kinder Morgan
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natural gas liquids pipeline systems and indirectly with three
other large interstate natural gas liquids pipelines. We also
own a 50% undivided interest in the Conway natural gas liquids
fractionation facility, which is strategically located at the
junction of the south, east and west legs of MAPL. This
fractionation facility also benefits from its proximity to other
natural gas liquids pipelines in the Conway area, and from its
proximity to our Conway storage facility. Our share of the
fractionators capacity is approximately
53,500 barrels per day.
We account for our 40% interest in Discovery as an equity
investment, and therefore do not consolidate its financial
results. Please read Summary Historical and
Pro Forma Financial and Operating Data for information
regarding our and Discoverys financial and operating
results.
Business Strategies
Our primary business objectives are to generate stable cash
flows sufficient to make quarterly cash distributions to our
unitholders and to increase quarterly cash distributions over
time by executing the following strategies:
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grow through accretive acquisitions of complementary energy
assets from third parties, Williams or both, such as our
proposed acquisition of a 25.1% interest in Four Corners; |
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capitalize on expected long-term increases in natural gas
production in proximity to Discoverys pipelines in the
Gulf of Mexico; |
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optimize the benefits of our scale, strategic location and
pipeline connectivity serving the Mid- Continent natural gas
liquids market; |
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leverage the scale and competitive position of Four
Corners standing as a leading provider of natural gas
gathering, processing and treating services in the San Juan
Basin; and |
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manage our existing and future asset portfolio to minimize the
volatility of our cash flows. |
Competitive Strengths
We believe we are well positioned to execute our business
strategies successfully because of the following competitive
strengths:
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our ability to grow through acquisitions is enhanced by our
affiliation with Williams, and we expect this relationship to
provide us access to attractive acquisition opportunities, such
as our proposed acquisition of a 25.1% interest in Four Corners; |
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our assets are strategically located in areas with high demand
for our services; |
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our assets are diversified geographically and encompass
important aspects of the midstream natural gas and natural gas
liquids businesses; |
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the senior management team and board of directors of our general
partner have extensive industry experience and include the most
senior officers of Williams; and |
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Williams has established a reputation in the midstream natural
gas and natural gas liquids industry as a reliable and
cost-effective operator, and we believe that we and our
customers will benefit from Williams scale and operational
expertise as well as our access to the broad array of midstream
services that Williams offers. |
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Recent Events
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Acquisition of Interest in Four Corners |
On April 6, 2006, we entered into a purchase and sale
agreement with our general partner and certain subsidiaries of
Williams, pursuant to which they will contribute to us a 25.1%
membership interest in Four Corners in exchange for aggregate
consideration of $360 million.
Four Corners owns:
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a 3,500-mile natural
gas gathering system in the San Juan Basin in New Mexico
and Colorado with capacity of two billion cubic feet per day; |
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the Ignacio natural gas processing plant in Colorado and the
Kutz and Lybrook natural gas processing plants in New Mexico,
which have a combined processing capacity of 760 million
cubic feet per day; and |
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the Milagro and Esperanza natural gas treating plants in New
Mexico, which have a combined carbon dioxide treating capacity
of 750 million cubic feet per day. |
Four Corners customers are primarily natural gas producers
in the San Juan Basin. Four Corners provides its customers
with a full range of gathering, processing and treating services.
The Four Corners pipeline system gathers approximately 37% of
the natural gas produced in the San Juan Basin and connects
with the five pipeline systems that transport natural gas to end
markets from the basin. Approximately 40% of the supply
connected to the Four Corners pipeline system in the
San Juan Basin is produced from conventional reservoirs
with approximately 60% coming from coal bed reservoirs. Four
Corners is currently the only company in the basin that owns and
operates both major conventional and coal bed natural gas
gathering, processing and treating facilities. Despite the
topographically challenging terrain, Four Corners has gathering
pipelines throughout most of the San Juan Basin.
Consistent with our growth strategy, our proposed acquisition of
the interest in Four Corners will allow us to expand our asset
base with an ownership position in an integrated business that
complements our existing portfolio of midstream assets. Our
interest in Four Corners will expand our customer base and
diversify our geographic footprint by providing a presence in
the San Juan Basin. We expect that this transaction will be
accretive on a per unit basis. For a more detailed discussion of
this transaction, please read Acquisition of Interest in
Four Corners.
The closing of our acquisition of the interest in Four Corners
is subject to the satisfaction of a number of conditions,
including our ability to obtain financing, which will consist of
the net proceeds of this offering and the net proceeds from our
concurrent private placement of senior notes.
We will account for the 25.1% interest in Four Corners as an
equity investment, and therefore will not consolidate its
financial results. For the year ended December 31, 2005 and
the three months ended March 31, 2006, a 25.1% interest in
Four Corners generated:
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net income plus interest (income) expense, depreciation,
amortization and accretion, referred to as Adjusted EBITDA, of
approximately $38.4 million and $10.9 million,
respectively; and |
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net income plus depreciation, amortization and accretion and
less maintenance capital expenditures, referred to as
Distributable Cash Flow, or DCF, of approximately
$35.4 million and $9.5 million, respectively. |
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For a reconciliation of each of Adjusted EBITDA and DCF to its
most directly comparable financial measure calculated and
presented in accordance with United States generally accepted
accounting principles, or GAAP, please read
Summary Historical and Pro Forma Financial and
Operating Data Non-GAAP Financial Measures.
Please read Summary Historical and Pro Forma
Financial and Operating Data Four Corners for
information regarding Four Corners financial and operating
results.
3
Lehman Brothers Inc. is serving as Williams financial
advisor in connection with our acquisition of the 25.1% interest
in Four Corners. See Underwriting
Relationships.
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Conflicts Committee Approval |
The conflicts committee of the board of directors of Williams
Partners GP LLC, our general partner, recommended approval of
the acquisition of the interest in Four Corners. The committee
retained independent legal and financial advisors to assist it
in evaluating and negotiating the transaction. In recommending
approval of the transaction, the committee based its decision in
part on an opinion from the committees independent
financial advisor that the consideration to be paid by us to
Williams is fair, from a financial point of view, to us and our
public unitholders.
We intend to finance our acquisition of the interest in Four
Corners with:
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the net proceeds of this offering; and |
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the net proceeds from a private placement of our senior notes to
qualified institutional investors and to
non-U.S. persons
in offshore transactions. |
Concurrently with this offering, we are offering
$150 million in aggregate principal amount of senior notes
in a private placement. The senior notes are being offered only
to qualified institutional investors in reliance on
Rule 144A under the Securities Act and to
non-U.S. persons
in offshore transactions in reliance on Regulation S under
the Securities Act and initially will not be guaranteed by any
of our subsidiaries. In the future in certain instances, some or
all of our subsidiaries may be required to guarantee our senior
notes. This prospectus shall not be deemed to be an offer to
sell or a solicitation of an offer to buy any senior notes
offered in the private placement. We cannot assure you that this
private placement will be completed or, if it is completed, that
it will be completed for the amount contemplated.
This offering is conditioned upon the consummation of the
private placement of senior notes, and the private placement of
senior notes is conditioned upon the consummation of this
offering.
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Increase in Quarterly Cash Distribution |
On May 15, 2006, we paid a quarterly cash distribution of
$0.38 per unit for the first quarter of 2006, or
$1.52 per unit on an annualized basis, to unitholders of
record as of May 8, 2006. The distribution for the first
quarter of 2006 represents an 8.6% increase over the
distribution for the fourth quarter of 2005 of $0.35 per
unit.
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New Williams Credit Agreement |
In May 2006, Williams replaced its $1.275 billion secured
credit facility with a $1.5 billion unsecured credit
agreement. The new facility contains substantially similar terms
and covenants applicable to us as were contained in the prior
facility. The new credit agreement is available for borrowings
and letters of credit and will continue to allow us to borrow up
to $75 million for general partnership purposes, including
acquisitions, but only to the extent that sufficient amounts
remain unborrowed by Williams and its other subsidiaries. Please
read Managements Discussion and Analysis of
Financial Conditions and Results of Operations
Financial Condition and Liquidity Credit
Facilities for more information.
Our Relationship with Williams
One of our principal attributes is our relationship with
Williams, an integrated energy company with 2005 revenues in
excess of $12.5 billion that trades on the New York Stock
Exchange, or NYSE, under the symbol WMB. Williams
operates in a number of segments of the energy industry,
including natural gas exploration and production, interstate
natural gas transportation and midstream services. Williams has
been in the midstream natural gas and natural gas liquids
industry for more than 20 years.
4
Williams has a long history of successfully pursuing and
consummating energy acquisitions and intends to use our
partnership as a growth vehicle for its midstream, natural gas,
natural gas liquids and other complementary energy businesses.
Although we expect to have the opportunity to make additional
acquisitions directly from Williams in the future, we cannot say
with any certainty which, if any, of these acquisition
opportunities may be made available to us or if we will choose
to pursue any such opportunity. In addition, through our
relationship with Williams, we will have access to a significant
pool of management talent and strong commercial relationships
throughout the energy industry. While our relationship with
Williams and its subsidiaries is a significant attribute, it is
also a source of potential conflicts. For example, Williams is
not restricted from competing with us. Williams may acquire,
construct or dispose of midstream or other assets in the future
without any obligation to offer us the opportunity to purchase
or construct those assets. Please read Conflicts of
Interest and Fiduciary Duties.
Following this offering, Williams will have a significant
interest in our partnership through its ownership of a 39.2%
limited partner interest and all of our 2% general partner
interest. Additionally, subsidiaries of Williams market
substantially all of the natural gas liquids to which Discovery
and Four Corners take title and affiliates of Williams have
contracts with Four Corners related to processing natural gas
and providing waste heat from the Milagro co-generation plant to
assist in the operation of the Milagro treating plant. Please
read Certain Relationships and Related Transactions.
Summary of Risk Factors
An investment in our common units involves risks associated with
our business, our partnership structure and the tax
characteristics of our common units. These risks are described
under the caption Risk Factors and include:
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Risks Inherent in Our Business |
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We may not have sufficient cash from operations to enable us to
pay the minimum quarterly distribution following establishment
of cash reserves and payment of fees and expenses, including
payments to our general partner. |
|
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|
Because of the natural decline in production from existing wells
and competitive factors, the success of our gathering and
transportation businesses depends on our ability to connect new
sources of natural gas supply, which is dependent on factors
beyond our control. Any decrease in supplies of natural gas
could adversely affect our business and operating results. |
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|
Lower natural gas and oil prices could adversely affect our
fractionation and storage businesses. |
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|
Our processing, fractionation and storage businesses could be
affected by any decrease in the price of natural gas liquids or
a change in the price of natural gas liquids relative to the
price of natural gas. |
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|
We depend on certain key customers and producers for a
significant portion of our revenues and supply of natural gas
and natural gas liquids. The loss of any of these key customers
or producers could result in a decline in our revenues and cash
available to pay distributions. |
|
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|
If third-party pipelines and other facilities interconnected to
our pipelines and facilities become unavailable to transport
natural gas and natural gas liquids or to treat natural gas, our
revenues and cash available to pay distributions could be
adversely affected. |
|
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|
Our future financial and operating flexibility may be adversely
affected by restrictions in our indenture and by our leverage. |
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|
Williams credit agreement and Williams public
indentures contain financial and operating restrictions that may
limit our access to credit. In addition, our ability to obtain
credit in the future will be affected by Williams credit
ratings. |
|
5
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Risks Inherent in an Investment in Us |
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Our general partner and its affiliates have conflicts of
interest and limited fiduciary duties, which may permit them to
favor their own interests to the detriment of our unitholders. |
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Our partnership agreement limits our general partners
fiduciary duties to our unitholders and restricts the remedies
available to unitholders for actions taken by our general
partner that might otherwise constitute breaches of fiduciary
duty. |
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|
Even if unitholders are dissatisfied, they cannot currently
remove our general partner without its consent. |
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The control of our general partner may be transferred to a third
party without unitholder consent. |
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Increases in interest rates may cause the market price of our
common units to decline. |
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We may issue additional common units without your approval,
which would dilute your ownership interests. |
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Williams and its affiliates may compete directly with us and
have no obligation to present business opportunities to us. |
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Our tax treatment depends on our status as a partnership for
federal income tax purposes, as well as our not being subject to
entity-level taxation by states. If the IRS were to treat us as
a corporation or if we were to become subject to entity-level
taxation for state tax purposes, then our cash available to pay
distributions to you would be substantially reduced. |
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A successful IRS contest of the federal income tax positions we
take may adversely impact the market for our common units, and
the costs of any contest will be borne by our unitholders and
our general partner. |
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You may be required to pay taxes on your share of our income
even if you do not receive any cash distributions from us. |
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The tax gain or loss on the disposition of our common units
could be different than expected. |
Partnership Structure and Management
Management of Williams Partners L.P.
Our general partner manages our operations and activities. Some
of the executive officers and directors of Williams also serve
as executive officers and directors of our general partner. For
more information about these individuals, please read
Management Directors and Executive Officers of
Our General Partner. Our general partner will not receive
any management fee or other compensation in connection with the
management of our business or this offering, but it is entitled
to reimbursement of all direct and indirect expenses incurred on
our behalf, subject to a partial credit for general and
administrative expenses. Our general partner is also entitled to
distributions on its general partner interest and, if specified
requirements are met, on its incentive distribution rights.
Please read How We Make Cash Distributions,
Management Executive Compensation and
Certain Relationships and Related Transactions.
Unlike shareholders in a publicly traded corporation, our
unitholders are not entitled to elect our general partner or its
directors.
Principal Executive Offices and Internet Address
Our principal executive offices are located at One Williams
Center, Tulsa, Oklahoma 74172-0172, and our telephone number is
(918) 573-2000. Our website is located at
http://www.williamslp.com. We make our
6
periodic reports and other information filed with or furnished
to the SEC available, free of charge, through our website, as
soon as reasonably practicable after those reports and other
information are electronically filed with or furnished to the
SEC. Information on our website or any other website is not
incorporated by reference into this prospectus and does not
constitute a part of this prospectus.
Summary of Conflicts of Interest and Fiduciary Duties
Our general partner has a legal duty to manage us in a manner
beneficial to our unitholders. This legal duty originates in
statutes and judicial decisions and is commonly referred to as a
fiduciary duty. However, because our general partner
is wholly owned by Williams, the officers and directors of our
general partner have fiduciary duties to manage the business of
our general partner in a manner beneficial to Williams. As a
result of this relationship, conflicts of interest may arise in
the future between us and our unitholders, on the one hand, and
our general partner and its affiliates, on the other hand. For a
more detailed description of the conflicts of interest of our
general partner, please read Risk Factors
Risks Inherent in an Investment in Us and Conflicts
of Interest and Fiduciary Duties Conflicts of
Interest.
Our partnership agreement limits the liability and reduces the
fiduciary duties of our general partner to our unitholders. Our
partnership agreement also restricts the remedies available to
unitholders for actions that might otherwise constitute a breach
of our general partners fiduciary duties owed to
unitholders. By purchasing a common unit, you are treated as
having consented to various actions contemplated in the
partnership agreement and conflicts of interest that might
otherwise be considered a breach of fiduciary or other duties
under applicable state law. Please read Conflicts of
Interest and Fiduciary Duties Fiduciary Duties
for a description of the fiduciary duties imposed on our general
partner by Delaware law, the material modifications of these
duties contained in our partnership agreement and certain legal
rights and remedies available to unitholders.
For a description of our other relationships with our
affiliates, please read Certain Relationships and Related
Transactions.
Organizational Structure After the Transactions
Immediately upon the closing of this common unit offering, and
subject to the conditions described above under
Acquisition of Interest in Four
Corners Financing:
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|
we will issue $150 million aggregate principal amount of
senior notes, which initially will not be guaranteed by any of
our subsidiaries, in a private placement to institutional
investors and
non-U.S. persons
in offshore transactions. In the future in certain instances,
some or all of our subsidiaries may be required to guarantee our
senior notes; and |
|
|
|
an affiliate of Williams will contribute the interest in Four
Corners to us in exchange for aggregate consideration of
$360 million. |
The following diagram depicts our organizational structure after
giving effect to this offering, our private placement of senior
notes and our acquisition of a 25.1% interest in Four Corners.
7
Ownership of Williams Partners L.P.
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|
Public Common Units
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|
58.8 |
% |
The Williams Companies, Inc. and Affiliates Common and
Subordinated Units
|
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39.2 |
% |
General Partner Interest
|
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2.0 |
% |
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|
|
|
Total
|
|
|
100.0 |
% |
|
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|
|
8
The Offering
|
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|
|
Common units offered by us |
|
6,600,000 common units. |
|
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|
|
7,590,000 common units if the underwriters exercise their option
to purchase additional units in full. |
|
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|
Units outstanding after this offering |
|
13,606,146 common units and 7,000,000 subordinated units. |
|
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|
|
14,596,146 common units and 7,000,000 subordinated units if the
underwriters exercise their option to purchase additional units
in full. |
|
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|
Use of proceeds |
|
We estimate the net proceeds from this offering will be
approximately $221.9 million assuming an offering price of
$35.10 per common unit and after deducting underwriting
discounts but before estimated offering expenses. We intend to
use the net proceeds of this offering, together with the net
proceeds from our private placement of $150 million
aggregate principal amount of senior notes: |
|
|
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|
to pay the aggregate consideration of
$360.0 million (or approximately $355.3 million net of
our general partners capital contribution related to this
offering) in exchange for the 25.1% interest in Four Corners; |
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|
|
to pay approximately $5.4 million of estimated
expenses associated with this offering, our private placement of
senior notes and the acquisition of the interest in Four
Corners; and |
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|
for general partnership purposes. |
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|
Please read Use of Proceeds. |
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|
If the underwriters exercise their option to purchase additional
units, we will use the net proceeds, together with the related
capital contribution of our general partner, for general
partnership purposes. |
|
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|
Cash distributions |
|
We paid a quarterly cash distribution of $0.38 per unit for
the first quarter of 2006, or $1.52 per unit on an
annualized basis, on May 15, 2006 to unitholders of record
as of May 8, 2006. In general, we will pay any cash
distributions we make each quarter in the following manner: |
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|
first, 98% to the holders of common units and
2% to our general partner, until each common unit has received a
minimum quarterly distribution of $0.35 plus any arrearages from
prior quarters; |
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|
second, 98% to the holders of subordinated
units and 2% to our general partner, until each subordinated
unit has received a minimum quarterly distribution of $0.35; and |
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|
third, 98% to all unitholders, pro rata, and
2% to our general partner, until each unit has received a
distribution of $0.4025. |
|
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|
If cash distributions exceed $0.4025 per unit in a quarter,
our general partner will receive increasing percentages, up to
50%, of the cash we distribute in excess of that amount. We
refer to these distributions as incentive
distributions. |
9
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|
We must distribute all of our cash on hand at the end of each
quarter, less reserves established by our general partner in its
discretion to provide for the proper conduct of our business, to
comply with any applicable debt instruments or to provide funds
for future distributions. We refer to this cash as
available cash, and we define its meaning in our
partnership agreement and in the glossary of terms attached as
Appendix A. The amount of available cash may be greater
than or less than the minimum quarterly distribution to be
distributed on all units. |
|
Subordination period |
|
During 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. The subordination period will
end once we meet the financial tests in the partnership
agreement. Except as described below, it generally cannot end
before June 30, 2008. |
|
|
|
When the subordination period ends, all subordinated units will
convert into common units on a one-for-one basis, and the common
units will no longer be entitled to arrearages. |
|
Early termination of subordination period |
|
If we have earned and paid an amount that equals or exceeds
$2.10 (150% of the annualized minimum quarterly distribution) on
each outstanding unit for any four-quarter period, the
subordination period will automatically terminate and all of the
subordinated units will convert into common units. Please read
How We Make Cash Distributions Subordination
Period. |
|
Issuance of additional units |
|
We can issue an unlimited number of common units without the
consent of unitholders, subject to the limitations imposed by
the New York Stock Exchange. Please read Units Eligible
for Future Sale and The Partnership
Agreement Issuance of Additional Securities. |
|
|
Voting rights |
|
Our general partner manages and operates us. Unlike the holders
of common stock in a corporation, you have only limited voting
rights on matters affecting our business. You have no right to
elect our general partner or the directors of our general
partner. Our general partner may not be removed except by a vote
of the holders of at least
662/3
% of the outstanding units, including any units owned by
our general partner and its affiliates, voting together as a
single class. Upon consummation of this offering, our general
partner and its affiliates will own an aggregate of
approximately 40.0% of our common and subordinated units. This
gives our general partner the practical ability to prevent its
involuntary removal. |
|
|
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, but not
less than all, of the remaining common units at a price not less
than the then-current market price of the common units. Our
general partner is not obligated to obtain a fairness opinion
regarding the value of the common units to be repurchased by it
upon exercise of this limited call right. |
10
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|
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, 2008, you will be allocated, on
a cumulative basis, an amount of federal taxable income for that
period that will be less than 20% of the cash distributed to you
with respect to that period. Please read Material Tax
Consequences Tax Consequences of Unit
Ownership for the basis of this estimate. |
|
|
Material tax consequences |
|
For a discussion of other material federal income tax
consequences that may be relevant to prospective unitholders who
are individual citizens or residents of the United States,
please read Material Tax Consequences. |
|
New York Stock Exchange symbol |
|
WPZ. |
11
Summary Historical and Pro Forma
Financial and Operating Data
Williams Partners L.P.
The following table shows summary historical financial and
operating data of Williams Partners L.P., summary pro forma
financial data of Williams Partners L.P., summary historical
financial and operating data of Discovery Producer Services LLC
and summary historical financial and operating data for Williams
Four Corners Predecessor for the periods and as of the dates
indicated. The summary historical financial data of Williams
Partners L.P. as of December 31, 2004 and 2005 and for the
years ended December 31, 2003, 2004 and 2005 are derived
from the audited consolidated financial statements of Williams
Partners L.P. appearing elsewhere in this prospectus. The
summary historical financial data of Williams Partners L.P. as
of March 31, 2006 and for the three months ended
March 31, 2005 and 2006 are derived from the unaudited
consolidated financial statements of Williams Partners L.P.
appearing elsewhere in this prospectus. All other historical
financial data are derived from our financial records. The
results of operations for the three months ended March 31,
2006 are not necessarily indicative of the operating results for
the entire year or any future period.
The summary pro forma financial data of Williams Partners L.P.
as of March 31, 2006 and for the year ended
December 31, 2005 and three months ended March 31,
2006 are derived from the unaudited pro forma consolidated
financial statements of Williams Partners L.P. included
elsewhere in this prospectus. These pro forma consolidated
financial statements show the pro forma effect of:
|
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|
|
this offering, including our use of the anticipated net proceeds; |
|
|
|
the proposed private placement of $150 million aggregate
principal amount of our senior notes to certain institutional
investors and to
non-U.S. persons
in offshore transactions, including our use of the anticipated
net proceeds of that private placement; |
|
|
|
our acquisition of a 25.1% interest in Four Corners; |
|
|
|
the forgiveness by Williams of advances to our predecessor in
connection with our initial public offering; and |
|
|
|
the payment of estimated underwriters commissions and
other offering expenses. |
The summary pro forma balance sheet data assumes that the items
listed above occurred as of March 31, 2006, and the summary
pro forma income statement data assumes that the items listed
above occurred on January 1, 2005.
The summary historical financial data of Discovery Producer
Services LLC for the years ended December 31, 2003, 2004
and 2005 are derived from the audited consolidated financial
statements of Discovery Producer Services LLC appearing
elsewhere in this prospectus. The summary historical financial
data of Discovery Producer Services LLC as of March 31,
2006 and for the three months ended March 31, 2005 and 2006
are derived from the unaudited consolidated financial statements
of Discovery Producer Services LLC appearing elsewhere in this
prospectus. All other historical financial data are derived from
our financial records. The results of operations for the three
months ended March 31, 2006 are not necessarily indicative
of the operating results for the entire year or any future
period.
The summary historical financial data of Williams Four Corners
Predecessor for the years ended December 31, 2003, 2004 and
2005 are derived from the audited financial statements of
Williams Four Corners Predecessor appearing elsewhere in this
prospectus. The summary historical financial data of Williams
Four Corners Predecessor as of March 31, 2006 and for the
three months ended March 31, 2005 and 2006 are derived from
the unaudited financial statements of Williams Four Corners
Predecessor appearing elsewhere in this prospectus. All other
historical financial data are derived from our financial
records. The results of operations for the three months ended
March 31, 2006 are not necessarily indicative of the
operating results for the entire year or any future period.
12
The following table includes these non-GAAP financial measures:
|
|
|
|
|
Adjusted EBITDA Excluding Equity Investments for Williams
Partners L.P.; |
|
|
|
Adjusted EBITDA for both our interest in Discovery and the 25.1%
interest in Four Corners that we expect to acquire; |
|
|
|
|
Distributable Cash Flow Excluding Equity Investments for
Williams Partners L.P.; and |
|
|
|
|
Distributable Cash Flow for both our interest in Discovery and
the 25.1% interest in Four Corners that we expect to acquire. |
These measures are presented because such information is
relevant and is used by management, industry analysts,
investors, lenders and rating agencies to assess the financial
performance and operating results of our fundamental business
activities. Our 40% ownership interest in Discovery is not and
our 25.1% ownership interest in Four Corners will not be,
consolidated in our financial results; rather we account or will
account for them using the equity method of accounting. In order
to evaluate EBITDA for the impact of our investment in Discovery
and Four Corners on our results, we calculate Adjusted EBITDA
Excluding Equity Investments and Distributable Cash Flow
Excluding Equity Investments separately for Williams Partners
L.P. and Adjusted EBITDA and Distributable Cash Flow for both
our interest in Discovery and the interest in Four Corners that
we expect to acquire. We expect distributions we receive from
Discovery and Four Corners to represent a significant portion of
the cash we distribute to our unitholders. Discoverys
limited liability company agreement provides for quarterly
distributions of available cash to its members. Four
Corners limited liability company agreement, as amended to
be effective as of the closing of this offering, will provide
for distributions of available cash at least quarterly to its
members. Please read How We Make Cash
Distributions General Discoverys
Cash Distribution Policy and
General Four Corners Cash
Distribution Policy.
For Williams Partners L.P., we define Adjusted EBITDA Excluding
Equity Investments as net income (loss) plus interest (income)
expense, depreciation and accretion and the amortization of a
natural gas contract, less our equity earnings in Discovery and
Four Corners. We also adjust for certain non-cash, non-recurring
items.
For Discovery and Four Corners we define Adjusted EBITDA as net
income plus interest (income) expense, depreciation,
amortization and accretion. We also adjust for certain non-cash,
non-recurring items. Our equity share of Discoverys
Adjusted EBITDA is 40%, and our equity share of Four
Corners Adjusted EBITDA will be 25.1%.
For Williams Partners L.P., we define Distributable Cash Flow
Excluding Equity Investments as net income (loss) plus the
non-cash affiliate interest expense associated with the advances
from affiliate to our predecessor that were forgiven by
Williams, depreciation and accretion, the amortization of a
natural gas contract, and reimbursements from Williams under our
omnibus agreement, less our equity earnings in Discovery and
Four Corners and maintenance capital expenditures. We also
adjust for certain non-cash, non-recurring items.
For Discovery and Four Corners, we define Distributable Cash
Flow as net income (loss) plus depreciation, amortization and
accretion and less maintenance capital expenditures. Our equity
share of Discoverys Distributable Cash Flow is 40%, and
our equity share of Four Corners Distributable Cash Flow
will be 25.1%.
For a reconciliation of these measures to their most directly
comparable financial measure calculated and presented in
accordance with GAAP, please read Non-GAAP
Financial Measures.
13
We derived the information in the following table from, and that
information should be read together with, and is qualified in
its entirety by reference to, the historical and pro forma
financial statements and the accompanying notes included
elsewhere in this prospectus. The table should also be read
together with Managements Discussion and Analysis of
Financial Condition and Results of Operations.
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|
Williams Partners L.P.(a) | |
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| |
|
|
Historical | |
|
Pro Forma | |
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| |
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| |
|
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|
|
Three Months | |
|
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|
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|
|
Ended | |
|
|
|
Three Months | |
|
|
Year Ended December 31, | |
|
March 31, | |
|
Year Ended | |
|
Ended | |
|
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| |
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| |
|
December 31, | |
|
March 31, | |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
2005 | |
|
2006 | |
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| |
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| |
|
| |
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| |
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| |
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| |
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| |
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|
($ in thousands, except per unit data) | |
Statement of Income Data:
|
|
|
|
|
|
|
|
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
28,294 |
|
|
$ |
40,976 |
|
|
$ |
51,769 |
|
|
$ |
11,369 |
|
|
$ |
17,063 |
|
|
$ |
51,769 |
|
|
$ |
17,063 |
|
Costs and expenses
|
|
|
21,250 |
|
|
|
32,935 |
|
|
|
46,568 |
|
|
|
10,266 |
|
|
|
16,469 |
|
|
|
46,568 |
|
|
|
16,469 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
7,044 |
|
|
|
8,041 |
|
|
|
5,201 |
|
|
|
1,103 |
|
|
|
594 |
|
|
|
5,201 |
|
|
|
594 |
|
Equity earnings Four Corners
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
28,668 |
|
|
|
8,387 |
|
Equity earnings Discovery
|
|
|
3,447 |
|
|
|
4,495 |
|
|
|
8,331 |
|
|
|
2,212 |
|
|
|
3,781 |
|
|
|
8,331 |
|
|
|
3,781 |
|
Impairment of investment in Discovery
|
|
|
|
|
|
|
(13,484 |
)(b) |
|
|
|
|
|
|
|
|
|
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|
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|
|
|
|
|
|
|
|
Interest expense net
|
|
|
(4,176 |
) |
|
|
(12,476 |
) |
|
|
(8,073 |
) |
|
|
(3,004 |
) |
|
|
(166 |
) |
|
|
(12,472 |
) |
|
|
(3,072 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before cumulative effect of change in accounting
principle
|
|
|
6,315 |
|
|
|
(13,424 |
) |
|
|
5,459 |
|
|
|
311 |
|
|
|
4,209 |
|
|
$ |
29,728 |
|
|
$ |
9,690 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of change in accounting principle
|
|
|
(1,099 |
) |
|
|
|
|
|
|
(628 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)(c)
|
|
$ |
5,216 |
|
|
$ |
(13,424 |
) |
|
$ |
4,831 |
|
|
$ |
311 |
|
|
$ |
4,209 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle
|
|
|
|
|
|
|
|
|
|
$ |
0.49 |
|
|
|
|
|
|
$ |
0.35 |
|
|
$ |
1.48 |
|
|
$ |
0.49 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of change in accounting principle
|
|
|
|
|
|
|
|
|
|
|
(0.05 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
$ |
0.44 |
|
|
|
|
|
|
$ |
0.35 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Data (at period end):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$ |
230,150 |
(d) |
|
$ |
219,361 |
|
|
$ |
240,941 |
|
|
$ |
220,293 |
|
|
$ |
235,528 |
|
|
|
|
|
|
$ |
403,033 |
|
Property, plant and equipment, net
|
|
|
69,695 |
|
|
|
67,793 |
|
|
|
67,931 |
|
|
|
67,146 |
|
|
|
68,239 |
|
|
|
|
|
|
|
68,239 |
|
Investment in Four Corners
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
153,309 |
|
Investment in Discovery
|
|
|
156,269 |
(d) |
|
|
147,281 |
(b) |
|
|
150,260 |
|
|
|
149,493 |
|
|
|
149,641 |
|
|
|
|
|
|
|
149,641 |
|
Advances from affiliate
|
|
|
187,193 |
(d) |
|
|
186,024 |
|
|
|
|
|
|
|
190,291 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Partners capital
|
|
|
30,092 |
|
|
|
16,668 |
|
|
|
221,655 |
|
|
|
16,979 |
|
|
|
222,214 |
|
|
|
|
|
|
|
239,719 |
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners L.P.:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA Excluding Equity Investments
|
|
$ |
10,751 |
|
|
$ |
11,727 |
|
|
$ |
10,853 |
|
|
$ |
2,008 |
|
|
$ |
2,848 |
|
|
$ |
10,853 |
|
|
$ |
2,848 |
|
|
Distributable Cash Flow Excluding Equity Investments
|
|
|
9,575 |
|
|
|
9,609 |
|
|
|
8,165 |
|
|
|
1,597 |
|
|
|
2,765 |
|
|
|
(3,673 |
) |
|
|
(141 |
) |
Four Corners our 25.1%:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
|
32,705 |
|
|
|
34,445 |
|
|
|
38,447 |
|
|
|
8,941 |
|
|
|
10,850 |
|
|
|
|
|
|
|
|
|
|
Distributable Cash Flow
|
|
|
30,677 |
|
|
|
31,900 |
|
|
|
35,391 |
|
|
|
8,303 |
|
|
|
9,539 |
|
|
|
|
|
|
|
|
|
Discovery our 40%:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
|
16,614 |
|
|
|
13,566 |
|
|
|
17,575 |
|
|
|
4,544 |
|
|
|
6,082 |
|
|
|
|
|
|
|
|
|
|
Distributable Cash Flow
|
|
|
11,641 |
|
|
|
13,448 |
|
|
|
17,235 |
|
|
|
3,911 |
|
|
|
6,126 |
|
|
|
|
|
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners L.P.(a) | |
|
|
| |
|
|
Historical | |
|
|
| |
|
|
|
|
Three Months Ended | |
|
|
Year Ended December 31, | |
|
March 31, | |
|
|
| |
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
($ in thousands, except per unit data) | |
Operating Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners L.P.:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conway storage revenues
|
|
$ |
11,649 |
|
|
$ |
15,318 |
|
|
$ |
20,290 |
|
|
$ |
4,388 |
|
|
$ |
5,105 |
|
|
Conway fractionation volumes (bpd) our 50%
|
|
|
34,989 |
|
|
|
39,062 |
|
|
|
39,965 |
|
|
|
41,296 |
|
|
|
46,042 |
|
|
Carbonate Trend gathered volumes (MMBtu/d)
|
|
|
67,638 |
|
|
|
49,981 |
|
|
|
35,605 |
|
|
|
41,567 |
|
|
|
33,407 |
|
Four Corners 100%:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathered volumes (MMBtu/d)
|
|
|
1,577,181 |
|
|
|
1,559,940 |
|
|
|
1,521,507 |
|
|
|
1,512,489 |
|
|
|
1,511,867 |
|
|
Processed volumes (MMBtu/d)
|
|
|
900,356 |
|
|
|
900,194 |
|
|
|
863,693 |
|
|
|
857,867 |
|
|
|
868,200 |
|
|
Net liquids margin (cents/gallon)(e)
|
|
|
17 |
¢ |
|
|
29 |
¢ |
|
|
37 |
¢ |
|
|
32 |
¢ |
|
|
37 |
¢ |
Discovery 100%:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathered volumes (MMBtu/d)
|
|
|
378,745 |
|
|
|
348,142 |
|
|
|
345,098 |
|
|
|
335,727 |
|
|
|
581,788 |
|
|
Gross processing margin (¢/ MMBtu)(f)
|
|
|
17 |
¢ |
|
|
17 |
¢ |
|
|
19 |
¢ |
|
|
21 |
¢ |
|
|
16 |
¢ |
|
|
(a) |
Williams Partners L.P. is the successor to Williams Partners
Predecessor. Results of operations and balance sheet data prior
to August 23, 2005 represent historical results of the
Williams Partners Predecessor. |
|
|
(b) |
The $13.5 million impairment of our equity investment in
Discovery in 2004 reduced the investment balance. See
Note 6 of the Notes to Consolidated Financial Statements. |
|
|
(c) |
Our operations are treated as a partnership with each member
being separately taxed on its ratable share of our taxable
income. Therefore, we have excluded income tax expense from this
financial information. |
|
|
(d) |
In December 2003, our predecessor made a $101.6 million
capital contribution to Discovery, which Discovery subsequently
used to repay maturing debt. Our predecessor funded this
contribution with an advance from Williams. |
|
|
(e) |
Please read Managements Discussion and Analysis of
Financial Condition and Results of Operations Four
Corners How We Evaluate Four Corners Net
Liquids Margin for a discussion of net liquids margin. |
|
|
(f) |
Please read Managements Discussion and Analysis of
Financial Condition and Results of Operations How We
Evaluate Our Operations Gross Processing
Margins for a discussion of gross processing margin. |
15
Four Corners
The following table shows summary historical financial and
operating data of Williams Four Corners Predecessor for the
periods and as of the dates indicated. The summary historical
financial data of Williams Four Corners Predecessor as of
December 31, 2004 and 2005 and for the years ended
December 31, 2003, 2004 and 2005 are derived from the
audited financial statements of Williams Four Corners
Predecessor appearing elsewhere in this prospectus. The summary
historical financial data of Williams Four Corners Predecessor
as of March 31, 2006 and for the three months ended
March 31, 2005 and 2006 are derived from the unaudited
financial statements of Williams Four Corners Predecessor
appearing elsewhere in this prospectus. All other historical
financial data are derived from our financial records. The
results of operations for the three months ended March 31,
2006 are not necessarily indicative of the operating results for
the entire year or any future period. The table should be read
together with, and is qualified in its entirety by reference to,
the historical financial statements and the accompanying notes
included elsewhere in this prospectus. The table should also be
read together with Managements Discussion and
Analysis of Financial Condition and Results of Operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Four Corners Predecessor | |
|
|
| |
|
|
|
|
Three Months Ended | |
|
|
Year Ended December 31, | |
|
March 31, | |
|
|
| |
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
($ in thousands) | |
Statement of Income Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
354,134 |
|
|
$ |
428,223 |
|
|
$ |
463,203 |
|
|
$ |
107,903 |
|
|
$ |
115,672 |
|
Costs and expenses
|
|
|
265,387 |
|
|
|
331,667 |
|
|
|
348,988 |
|
|
|
82,008 |
|
|
|
82,257 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle
|
|
|
88,747 |
|
|
|
96,556 |
|
|
|
114,215 |
|
|
|
25,895 |
|
|
|
33,415 |
|
Cumulative effect of change in accounting principle
|
|
|
(330 |
) |
|
|
|
|
|
|
(694 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
88,417 |
|
|
$ |
96,556 |
|
|
$ |
113,521 |
|
|
$ |
25,895 |
|
|
$ |
33,415 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Data (at period end):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$ |
666,589 |
|
|
$ |
645,294 |
|
|
$ |
635,094 |
|
|
$ |
631,162 |
|
|
$ |
630,238 |
|
Property, plant and equipment, net
|
|
|
635,905 |
|
|
|
601,710 |
|
|
|
591,034 |
|
|
|
594,887 |
|
|
|
585,470 |
|
Total owners equity
|
|
|
644,441 |
|
|
|
620,530 |
|
|
|
605,590 |
|
|
|
611,938 |
|
|
|
610,791 |
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$ |
130,299 |
|
|
$ |
137,231 |
|
|
$ |
153,175 |
|
|
$ |
35,621 |
|
|
$ |
43,229 |
|
|
Distributable Cash Flow
|
|
|
122,220 |
|
|
|
127,093 |
|
|
|
141,000 |
|
|
|
33,081 |
|
|
|
38,003 |
|
Operating Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathered volumes (MMBtu/d)
|
|
|
1,577,181 |
|
|
|
1,559,940 |
|
|
|
1,521,507 |
|
|
|
1,512,489 |
|
|
|
1,511,867 |
|
|
Processed volumes (MMBtu/d)
|
|
|
900,356 |
|
|
|
900,194 |
|
|
|
863,693 |
|
|
|
857,867 |
|
|
|
868,200 |
|
|
Net liquids margin (cents/gallon)(a)
|
|
|
17 |
¢ |
|
|
29 |
¢ |
|
|
37 |
¢ |
|
|
32 |
¢ |
|
|
37 |
¢ |
|
|
(a) |
Please read Managements Discussion and Analysis of
Financial Condition and Results of Operations Four
Corners How We Evaluate Four Corners Net
Liquids Margin for a discussion of net liquids margin. |
16
Discovery
The following table shows summary historical financial and
operating data of Discovery Producer Services LLC for the
periods and as of the dates indicated. The summary historical
financial data of Discovery Producer Services LLC as of
December 31, 2004 and 2005 and for the years ended
December 31, 2003, 2004 and 2005 are derived from the
audited consolidated financial statements of Discovery Producer
Services LLC appearing elsewhere in this prospectus. The summary
historical financial data of Discovery Producer Services LLC as
of March 31, 2006 and for the three months ended
March 31, 2005 and 2006 are derived from the unaudited
consolidated financial statements of Discovery Producer Services
LLC appearing elsewhere in this prospectus. All other historical
financial data are derived from our financial records. The
results of operations for the three months ended March 31,
2006 are not necessarily indicative of the results for the
entire period or any future period. The table should be read
together with, and is qualified in its entirety by reference to,
the historical financial statements and the accompanying notes
included elsewhere in this prospectus. The table should also be
read together with Managements Discussion and
Analysis of Financial Condition and Results of Operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discovery Producer Services LLC | |
|
|
| |
|
|
|
|
Three Months Ended | |
|
|
Year Ended December 31, | |
|
March 31, | |
|
|
| |
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
($ in thousands) | |
Statement of Income Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
103,178 |
|
|
$ |
99,876 |
|
|
$ |
122,745 |
|
|
$ |
27,289 |
|
|
$ |
62,120 |
|
Costs and expenses
|
|
|
84,519 |
|
|
|
88,756 |
|
|
|
102,597 |
|
|
|
22,042 |
|
|
|
52,867 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
18,659 |
|
|
|
11,120 |
|
|
|
20,148 |
|
|
|
5,247 |
|
|
|
9,253 |
|
Interest (expense) income and other
|
|
|
(9,611 |
) |
|
|
550 |
|
|
|
680 |
|
|
|
284 |
|
|
|
199 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle
|
|
|
9,048 |
|
|
|
11,670 |
|
|
|
20,828 |
|
|
|
5,531 |
|
|
|
9,452 |
|
Cumulative effect of change in accounting principle
|
|
|
(267 |
) |
|
|
|
|
|
|
(176 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
8,781 |
|
|
$ |
11,670 |
|
|
$ |
20,652 |
|
|
$ |
5,531 |
|
|
$ |
9,452 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Data (at period end):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$ |
401,525 |
|
|
$ |
423,919 |
|
|
$ |
459,827 |
|
|
$ |
426,327 |
|
|
$ |
445,494 |
|
Property, plant and equipment, net
|
|
|
332,398 |
|
|
|
356,385 |
|
|
|
344,743 |
|
|
|
353,932 |
|
|
|
340,935 |
|
Total Members capital
|
|
|
379,975 |
|
|
|
391,645 |
|
|
|
413,636 |
|
|
|
397,176 |
|
|
|
416,873 |
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$ |
41,534 |
|
|
$ |
33,915 |
|
|
$ |
43,937 |
|
|
$ |
11,360 |
|
|
$ |
15,205 |
|
|
Distributable Cash Flow
|
|
|
29,103 |
|
|
|
33,620 |
|
|
|
43,088 |
|
|
|
9,778 |
|
|
|
15,315 |
|
Operating Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathered Volumes (MMBtu/d)
|
|
|
378,745 |
|
|
|
348,142 |
|
|
|
345,098 |
|
|
|
335,727 |
|
|
|
581,788 |
|
|
Gross processing margin (MMBtu)(a)
|
|
|
17 |
¢ |
|
|
17 |
¢ |
|
|
19 |
¢ |
|
|
21 |
¢ |
|
|
16 |
¢ |
|
|
(a) |
Please read Managements Discussion and Analysis of
Financial Condition and Results of Operations How We
Evaluate Our Operations Gross Processing
Margins for a discussion of gross processing margin. |
17
Non-GAAP Financial Measures
Adjusted EBITDA Excluding Equity Investments and Distributable
Cash Flow Excluding Equity Investments, in our case, and
Adjusted EBITDA and Distributable Cash Flow, in Discoverys
and Four Corners cases, are used as supplemental financial
measures by management and by external users of our financial
statements, such as investors and commercial banks, to assess:
|
|
|
|
|
the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis; |
|
|
|
the ability of our assets to generate cash sufficient to pay
interest on our indebtedness and to make distributions to our
partners; and |
|
|
|
our operating performance and return on invested capital as
compared to those of other publicly traded limited partnerships
that own energy infrastructure assets, without regard to their
financing methods and capital structure. |
Our Adjusted EBITDA Excluding Equity Investments and
Distributable Cash Flow Excluding Equity Investments,
Discoverys Adjusted EBITDA and Distributable Cash Flow and
Four Corners Adjusted EBITDA and Distributable Cash Flow
should not be considered alternatives to net income, operating
income, cash flow from operating activities or any other measure
of financial performance or liquidity presented in accordance
with GAAP. Our Adjusted EBITDA Excluding Equity Investments and
Distributable Cash Flow Excluding Equity Investments,
Discoverys Adjusted EBITDA and Distributable Cash Flow and
Four Corners Adjusted EBITDA and Distributable Cash Flow
exclude some, but not all, items that affect net income and
operating income, and these measures may vary among other
companies. Therefore, our Adjusted EBITDA Excluding Equity
Investments and Distributable Cash Flow Excluding Equity
Investments, Discoverys Adjusted EBITDA and Distributable
Cash Flow and Four Corners Adjusted EBITDA and
Distributable Cash Flow as presented may not be comparable to
similarly titled measures of other companies. Furthermore, while
Distributable Cash Flow is a measure we use to assess our
ability to make distributions to our partners, Distributable
Cash Flow should not be viewed as indicative of the actual
amount of cash that we have available for distributions or that
we plan to distribute for a given period.
18
The following tables present a reconciliation of the non-GAAP
financial measures, our Adjusted EBITDA Excluding Equity
Investments and Distributable Cash Flow Excluding Equity
Investments, Discoverys Adjusted EBITDA and Distributable
Cash Flow and Four Corners Adjusted EBITDA and
Distributable Cash Flow, to the GAAP financial measures of net
income (loss) and of net cash provided (used) by operating
activities, on a historical basis and on a pro forma basis, as
adjusted for this offering, the proposed private placement of
our senior notes, the application of the net proceeds from each
offering, our acquisition of the interest in Four Corners, and
the forgiveness of advances from affiliate to our predecessor in
connection with our initial public offering.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners L.P.(a) | |
|
|
| |
|
|
Historical | |
|
Pro Forma | |
|
|
| |
|
| |
|
|
|
|
Three Months | |
|
|
|
|
|
|
Ended | |
|
|
|
Three Months | |
|
|
Year Ended December 31, | |
|
March 31, | |
|
Year Ended | |
|
Ended | |
|
|
| |
|
| |
|
December 31, | |
|
March 31, | |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
($ in thousands) | |
Williams Partners L.P.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Non-GAAP Adjusted EBITDA Excluding
Equity Investments to GAAP Net income
(loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$ |
5,216 |
|
|
$ |
(13,424 |
) |
|
$ |
4,831 |
|
|
$ |
311 |
|
|
$ |
4,209 |
|
|
$ |
28,926 |
|
|
$ |
9,690 |
|
Interest expense, net of interest income
|
|
|
4,176 |
|
|
|
12,476 |
|
|
|
8,073 |
|
|
|
3,004 |
|
|
|
166 |
|
|
|
12,472 |
|
|
|
3,072 |
|
Depreciation and accretion
|
|
|
3,707 |
|
|
|
3,686 |
|
|
|
3,619 |
|
|
|
905 |
|
|
|
900 |
|
|
|
3,619 |
|
|
|
900 |
|
Amortization of natural gas purchase contract
|
|
|
|
|
|
|
|
|
|
|
2,033 |
|
|
|
|
|
|
|
1,354 |
|
|
|
2,033 |
|
|
|
1,354 |
|
Impairment of investment in Discovery Producer Services
|
|
|
|
|
|
|
13,484 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings Discovery Producer Services
|
|
|
(3,447 |
) |
|
|
(4,495 |
) |
|
|
(8,331 |
) |
|
|
(2,212 |
) |
|
|
(3,781 |
) |
|
|
(8,331 |
) |
|
|
(3,781 |
) |
Equity earnings Four Corners
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(28,668 |
) |
|
|
(8,387 |
) |
Cumulative effect of change in accounting principle
|
|
|
1,099 |
|
|
|
|
|
|
|
628 |
|
|
|
|
|
|
|
|
|
|
|
802 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA Excluding Equity Investments
|
|
$ |
10,751 |
|
|
$ |
11,727 |
|
|
$ |
10,853 |
|
|
$ |
2,008 |
|
|
$ |
2,848 |
|
|
$ |
10,853 |
|
|
$ |
2,848 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Non-GAAP Adjusted EBITDA Excluding
Equity Investments to GAAP Net cash provided
(used) by operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by operating activities
|
|
$ |
6,644 |
|
|
$ |
2,703 |
|
|
$ |
1,893 |
|
|
$ |
(4,055 |
) |
|
$ |
2,395 |
|
|
$ |
(2,506 |
) |
|
$ |
(511 |
) |
Interest expense, net of interest income
|
|
|
4,176 |
|
|
|
12,476 |
|
|
|
8,073 |
|
|
|
3,004 |
|
|
|
166 |
|
|
|
12,472 |
|
|
|
3,072 |
|
Distributed earnings from equity investments
|
|
|
|
|
|
|
|
|
|
|
(1,280 |
) |
|
|
|
|
|
|
(4,400 |
) |
|
|
(1,280 |
) |
|
|
(4,400 |
) |
Changes in operating working capital:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
850 |
|
|
|
(261 |
) |
|
|
3,045 |
|
|
|
(678 |
) |
|
|
(996 |
) |
|
|
3,045 |
|
|
|
(996 |
) |
|
Other current assets
|
|
|
187 |
|
|
|
362 |
|
|
|
384 |
|
|
|
45 |
|
|
|
237 |
|
|
|
384 |
|
|
|
237 |
|
|
Accounts payable
|
|
|
274 |
|
|
|
(2,711 |
) |
|
|
(4,215 |
) |
|
|
1,495 |
|
|
|
3,028 |
|
|
|
(4,215 |
) |
|
|
3,028 |
|
|
Accrued liabilities
|
|
|
320 |
|
|
|
417 |
|
|
|
737 |
|
|
|
209 |
|
|
|
(345 |
) |
|
|
737 |
|
|
|
(345 |
) |
|
Deferred revenue
|
|
|
(1,108 |
) |
|
|
(775 |
) |
|
|
(247 |
) |
|
|
3,200 |
|
|
|
3,330 |
|
|
|
(247 |
) |
|
|
3,330 |
|
Other, including changes in noncurrent assets and liabilities
|
|
|
(592 |
) |
|
|
(484 |
) |
|
|
2,463 |
|
|
|
(1,212 |
) |
|
|
(567 |
) |
|
|
2,463 |
|
|
|
(567 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA Excluding Equity Investments
|
|
$ |
10,751 |
|
|
$ |
11,727 |
|
|
$ |
10,853 |
|
|
$ |
2,008 |
|
|
$ |
2,848 |
|
|
$ |
10,853 |
|
|
$ |
2,848 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners L.P.(a) | |
|
|
| |
|
|
Historical | |
|
Pro Forma | |
|
|
| |
|
| |
|
|
|
|
Three Months | |
|
|
|
|
|
|
Ended | |
|
|
|
Three Months | |
|
|
Year Ended December 31, | |
|
March 31, | |
|
Year Ended | |
|
Ended | |
|
|
| |
|
| |
|
December 31, | |
|
March 31, | |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
($ in thousands) | |
Williams Partners L.P.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Non-GAAP Distributable Cash Flow
Excluding Equity Investments to GAAP Net income
(loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$ |
5,216 |
|
|
$ |
(13,424 |
) |
|
$ |
4,831 |
|
|
$ |
311 |
|
|
$ |
4,209 |
|
|
$ |
28,926 |
|
|
$ |
9,690 |
|
Affiliate interest expense(b)
|
|
|
4,176 |
|
|
|
11,980 |
|
|
|
7,439 |
|
|
|
2,805 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and accretion
|
|
|
3,707 |
|
|
|
3,686 |
|
|
|
3,619 |
|
|
|
905 |
|
|
|
900 |
|
|
|
3,619 |
|
|
|
900 |
|
Amortization of natural gas purchase contract
|
|
|
|
|
|
|
|
|
|
|
2,033 |
|
|
|
|
|
|
|
1,354 |
|
|
|
2,033 |
|
|
|
1,354 |
|
Reimbursements from Williams under an omnibus agreement
|
|
|
|
|
|
|
|
|
|
|
1,610 |
|
|
|
|
|
|
|
1,248 |
|
|
|
1,610 |
|
|
|
1,248 |
|
Impairment of investment in Discovery Producer Services
|
|
|
|
|
|
|
13,484 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of change in accounting principle
|
|
|
1,099 |
|
|
|
|
|
|
|
628 |
|
|
|
|
|
|
|
|
|
|
|
802 |
|
|
|
|
|
Equity earnings Discovery Producer Services
|
|
|
(3,447 |
) |
|
|
(4,495 |
) |
|
|
(8,331 |
) |
|
|
(2,212 |
) |
|
|
(3,781 |
) |
|
|
(8,331 |
) |
|
|
(3,781 |
) |
Equity earnings Four Corners
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(28,668 |
) |
|
|
(8,387 |
) |
Maintenance capital expenditures
|
|
|
(1,176 |
) |
|
|
(1,622 |
) |
|
|
(3,664 |
) |
|
|
(212 |
) |
|
|
(1,165 |
) |
|
|
(3,664 |
) |
|
|
(1,165 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable Cash Flow Excluding Equity Investments
|
|
$ |
9,575 |
|
|
$ |
9,609 |
|
|
$ |
8,165 |
|
|
$ |
1,597 |
|
|
$ |
2,765 |
|
|
$ |
(3,673 |
) |
|
$ |
(141 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Non-GAAP Distributable Cash Flow
Excluding Equity Investments to GAAP Net cash
provided (used) by operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by operating activities
|
|
$ |
6,644 |
|
|
$ |
2,703 |
|
|
$ |
1,893 |
|
|
$ |
(4,055 |
) |
|
$ |
2,395 |
|
|
$ |
(2,506 |
) |
|
$ |
(511 |
) |
Affiliate interest expense(b)
|
|
|
4,176 |
|
|
|
11,980 |
|
|
|
7,439 |
|
|
|
2,805 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions from equity investments
|
|
|
|
|
|
|
|
|
|
|
(1,280 |
) |
|
|
|
|
|
|
(4,400 |
) |
|
|
(1,280 |
) |
|
|
(4,400 |
) |
Changes in operating working capital:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
850 |
|
|
|
(261 |
) |
|
|
3,045 |
|
|
|
(678 |
) |
|
|
(996 |
) |
|
|
3,045 |
|
|
|
(996 |
) |
|
Other current assets
|
|
|
187 |
|
|
|
362 |
|
|
|
384 |
|
|
|
45 |
|
|
|
237 |
|
|
|
384 |
|
|
|
237 |
|
|
Accounts payable
|
|
|
274 |
|
|
|
(2,711 |
) |
|
|
(4,215 |
) |
|
|
1,495 |
|
|
|
3,028 |
|
|
|
(4,215 |
) |
|
|
3,028 |
|
|
Accrued liabilities
|
|
|
320 |
|
|
|
417 |
|
|
|
737 |
|
|
|
209 |
|
|
|
(345 |
) |
|
|
737 |
|
|
|
(345 |
) |
|
Deferred revenue
|
|
|
(1,108 |
) |
|
|
(775 |
) |
|
|
(247 |
) |
|
|
3,200 |
|
|
|
3,330 |
|
|
|
(247 |
) |
|
|
3,330 |
|
Other, including changes in noncurrent assets and liabilities
|
|
|
(592 |
) |
|
|
(484 |
) |
|
|
2,463 |
|
|
|
(1,212 |
) |
|
|
(567 |
) |
|
|
2,463 |
|
|
|
(567 |
) |
Reimbursements from Williams under an omnibus agreement
|
|
|
|
|
|
|
|
|
|
|
1,610 |
|
|
|
|
|
|
|
1,248 |
|
|
|
1,610 |
|
|
|
1,248 |
|
Maintenance capital expenditures
|
|
|
(1,176 |
) |
|
|
(1,622 |
) |
|
|
(3,664 |
) |
|
|
(212 |
) |
|
|
(1,165 |
) |
|
|
(3,664 |
) |
|
|
(1,165 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable Cash Flow Excluding Equity Investments
|
|
$ |
9,575 |
|
|
$ |
9,609 |
|
|
$ |
8,165 |
|
|
$ |
1,597 |
|
|
$ |
2,765 |
|
|
$ |
(3,673 |
) |
|
$ |
(141 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Williams Partners L.P. is the successor to Williams Partners
Predecessor. Results of operations data prior to August 23,
2005 represent historical results of the Williams Partners
Predecessor. |
|
(b) |
|
Represents affiliate interest expense associated with the
advances from affiliate to our predecessor that were forgiven by
Williams in connection with our initial public offering. |
20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Four Corners Predecessor | |
|
|
| |
|
|
|
|
Three Months Ended | |
|
|
Year Ended December 31, | |
|
March 31, | |
|
|
| |
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
($ in thousands) | |
Williams Four Corners Predecessor
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Non-GAAP Adjusted EBITDA to
GAAP Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
88,417 |
|
|
$ |
96,556 |
|
|
$ |
113,521 |
|
|
$ |
25,895 |
|
|
$ |
33,415 |
|
Depreciation and amortization
|
|
|
41,552 |
|
|
|
40,675 |
|
|
|
38,960 |
|
|
|
9,726 |
|
|
|
9,814 |
|
Cumulative effect of change in accounting principle
|
|
|
330 |
|
|
|
|
|
|
|
694 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA 100%
|
|
$ |
130,299 |
|
|
$ |
137,231 |
|
|
$ |
153,175 |
|
|
$ |
35,621 |
|
|
$ |
43,229 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA our 25.1% interest
|
|
$ |
32,705 |
|
|
$ |
34,445 |
|
|
$ |
38,447 |
|
|
$ |
8,941 |
|
|
$ |
10,850 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Non-GAAP Adjusted EBITDA to
GAAP Net cash provided by operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$ |
122,266 |
|
|
$ |
134,387 |
|
|
$ |
156,039 |
|
|
$ |
37,027 |
|
|
$ |
29,464 |
|
Provision for loss on property, plant and equipment
|
|
|
(7,598 |
) |
|
|
(7,636 |
) |
|
|
(917 |
) |
|
|
|
|
|
|
|
|
Gain (loss) on sale of property, plant and equipment
|
|
|
1,151 |
|
|
|
(1,258 |
) |
|
|
|
|
|
|
|
|
|
|
3,319 |
|
Changes in operating working capital:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
279 |
|
|
|
(1,298 |
) |
|
|
1,374 |
|
|
|
(2,463 |
) |
|
|
516 |
|
|
Prepaid expenses
|
|
|
1,530 |
|
|
|
|
|
|
|
79 |
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
|
3,266 |
|
|
|
(9,435 |
) |
|
|
(4,586 |
) |
|
|
5,758 |
|
|
|
7,724 |
|
|
Produce imbalance
|
|
|
4,447 |
|
|
|
7,983 |
|
|
|
(10,073 |
) |
|
|
(4,483 |
) |
|
|
2,377 |
|
|
Accrued liabilities
|
|
|
(61 |
) |
|
|
5,047 |
|
|
|
3,271 |
|
|
|
(514 |
) |
|
|
(451 |
) |
|
Other, including changes in other noncurrent assets and
liabilities
|
|
|
5,019 |
|
|
|
9,441 |
|
|
|
7,988 |
|
|
|
296 |
|
|
|
280 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA 100%
|
|
$ |
130,299 |
|
|
$ |
137,231 |
|
|
$ |
153,175 |
|
|
$ |
35,621 |
|
|
$ |
43,229 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Non-GAAP Distributable Cash
Flow to GAAP Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
88,417 |
|
|
$ |
96,556 |
|
|
$ |
113,521 |
|
|
$ |
25,895 |
|
|
$ |
33,415 |
|
Depreciation and amortization
|
|
|
41,552 |
|
|
|
40,675 |
|
|
|
38,960 |
|
|
|
9,726 |
|
|
|
9,814 |
|
Cumulative effect of change in accounting principle
|
|
|
330 |
|
|
|
|
|
|
|
694 |
|
|
|
|
|
|
|
|
|
Maintenance capital expenditures(a)
|
|
|
(8,079 |
) |
|
|
(10,138 |
) |
|
|
(12,175 |
) |
|
|
(2,540 |
) |
|
|
(5,226 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable Cash Flow 100%
|
|
$ |
122,220 |
|
|
$ |
127,093 |
|
|
$ |
141,000 |
|
|
$ |
33,081 |
|
|
$ |
38,003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable Cash Flow our 25.1% interest
|
|
$ |
30,677 |
|
|
$ |
31,900 |
|
|
$ |
35,391 |
|
|
$ |
8,303 |
|
|
$ |
9,539 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
Maintenance capital expenditures for Williams Four Corners
Predecessor includes well connection capital. |
21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discovery Producer Services LLC | |
|
|
| |
|
|
|
|
Three Months Ended | |
|
|
Year Ended December 31, | |
|
March 31, | |
|
|
| |
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
($ in thousands) | |
Discovery Producer Services LLC
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Non-GAAP Adjusted EBITDA to
GAAP Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
8,781 |
|
|
$ |
11,670 |
|
|
$ |
20,652 |
|
|
$ |
5,531 |
|
|
$ |
9,452 |
|
Interest (income) expense, net
|
|
|
9,611 |
|
|
|
(550 |
) |
|
|
(1,685 |
) |
|
|
(284 |
) |
|
|
(626 |
) |
Depreciation and accretion
|
|
|
22,875 |
|
|
|
22,795 |
|
|
|
24,794 |
|
|
|
6,113 |
|
|
|
6,379 |
|
Cumulative effect of change in accounting principle
|
|
|
267 |
|
|
|
|
|
|
|
176 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA 100%
|
|
$ |
41,534 |
|
|
$ |
33,915 |
|
|
$ |
43,937 |
|
|
$ |
11,360 |
|
|
$ |
15,205 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA our 40% interest
|
|
$ |
16,614 |
|
|
$ |
13,566 |
|
|
$ |
17,575 |
|
|
$ |
4,544 |
|
|
$ |
6,082 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Non-GAAP Adjusted EBITDA to
GAAP Net cash provided by operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$ |
44,025 |
|
|
$ |
35,623 |
|
|
$ |
30,814 |
|
|
$ |
7,981 |
|
|
$ |
18,515 |
|
Interest (income) expense, net
|
|
|
9,611 |
|
|
|
(550 |
) |
|
|
(1,685 |
) |
|
|
(284 |
) |
|
|
(626 |
) |
Changes in operating working capital:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(7,860 |
) |
|
|
1,658 |
|
|
|
35,739 |
|
|
|
4,057 |
|
|
|
(20,201 |
) |
|
Inventory
|
|
|
229 |
|
|
|
240 |
|
|
|
84 |
|
|
|
138 |
|
|
|
(57 |
) |
|
Other current assets
|
|
|
761 |
|
|
|
1 |
|
|
|
1,012 |
|
|
|
(218 |
) |
|
|
(475 |
) |
|
Accounts payable
|
|
|
1,415 |
|
|
|
(1,256 |
) |
|
|
(29,355 |
) |
|
|
713 |
|
|
|
19,153 |
|
|
Other current liabilities
|
|
|
(2,223 |
) |
|
|
668 |
|
|
|
(664 |
) |
|
|
(443 |
) |
|
|
(583 |
) |
|
Accrued liabilities
|
|
|
(4,424 |
) |
|
|
(2,469 |
) |
|
|
7,992 |
|
|
|
(584 |
) |
|
|
(521 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA 100%
|
|
$ |
41,534 |
|
|
$ |
33,915 |
|
|
$ |
43,937 |
|
|
$ |
11,360 |
|
|
$ |
15,205 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Non-GAAP Distributable Cash
Flow to GAAP Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
8,781 |
|
|
$ |
11,670 |
|
|
$ |
20,652 |
|
|
$ |
5,531 |
|
|
$ |
9,452 |
|
Depreciation and accretion
|
|
|
22,875 |
|
|
|
22,795 |
|
|
|
24,794 |
|
|
|
6,113 |
|
|
|
6,379 |
|
Cumulative effect of change in accounting principle
|
|
|
267 |
|
|
|
|
|
|
|
176 |
|
|
|
|
|
|
|
|
|
Maintenance capital expenditures
|
|
|
(2,820 |
) |
|
|
(845 |
) |
|
|
(2,534 |
) |
|
|
(1,866 |
) |
|
|
(516 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable cash flow 100%
|
|
$ |
29,103 |
|
|
$ |
33,620 |
|
|
$ |
43,088 |
|
|
$ |
9,778 |
|
|
$ |
15,315 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable cash flow our 40% interest
|
|
$ |
11,641 |
|
|
$ |
13,448 |
|
|
$ |
17,235 |
|
|
$ |
3,911 |
|
|
$ |
6,126 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22
RISK FACTORS
Limited partner interests are inherently different from the
capital stock of a corporation, although many of the business
risks to which we are subject are similar to those that would be
faced by a corporation engaged in a similar business. You should
carefully consider the following risk factors together with all
of the other information included in this prospectus when
evaluating an investment in our common units.
If any of the following risks were actually to occur, our
business, results of operations and financial condition could be
materially adversely affected. In that case, we might not be
able to pay distributions on our common units, the trading price
of our common units could decline, and you could lose all or
part of your investment.
Risks Inherent in Our Business
We may not have sufficient cash from operations to enable
us to pay the minimum quarterly distribution following
establishment of cash reserves and payment of fees and expenses,
including payments to our general partner.
We may not have sufficient available cash each quarter to pay
the minimum quarterly distribution. The amount of cash we can
distribute on our common units principally depends upon the
amount of cash we generate from our operations, which will
fluctuate from quarter to quarter based on, among other things:
|
|
|
|
|
the prices we obtain for our services; |
|
|
|
the prices of, level of production of, and demand for, natural
gas and NGLs; |
|
|
|
the volumes of natural gas we gather, transport and process and
the volumes of NGLs we fractionate and store; |
|
|
|
the level of our operating costs, including payments to our
general partner; and |
|
|
|
prevailing economic conditions. |
In addition, the actual amount of cash we will have available
for distribution will depend on other factors such as:
|
|
|
|
|
the level of capital expenditures we make; |
|
|
|
the restrictions contained in our and Williams debt
agreements and our debt service requirements; |
|
|
|
the cost of acquisitions, if any; |
|
|
|
fluctuations in our working capital needs; |
|
|
|
our ability to borrow for working capital or other purposes; |
|
|
|
the amount, if any, of cash reserves established by our general
partner; |
|
|
|
the amount of cash that each of Discovery and Four Corners
distributes to us; and |
|
|
|
reimbursement payments to us by, and credits from, Williams
under the omnibus agreement. |
You should be aware that the amount of cash we have available
for distribution depends primarily on our cash flow, including
cash reserves and working capital or other borrowings, and not
solely on profitability, which will be affected by non-cash
items. As a result, we may make cash distributions during
periods when we record losses, and we may not make cash
distributions during periods when we record net income.
23
Because of the natural decline in production from existing
wells and competitive factors, the success of our gathering and
transportation businesses depends on our ability to connect new
sources of natural gas supply, which is dependent on factors
beyond our control. Any decrease in supplies of natural gas
could adversely affect our business and operating
results.
Our and Discoverys pipelines receive natural gas directly
from offshore producers. The Four Corners gathering system
receives natural gas directly from producers in the
San Juan Basin. The production from existing wells
connected to these pipelines and the Four Corners
gathering system will naturally decline over time, which means
that our cash flows associated with these wells will also
decline over time. We do not produce an aggregate reserve report
on a regular basis or regularly obtain or update independent
reserve evaluations. The amount of natural gas reserves
underlying these wells may be less than we anticipate, and the
rate at which production will decline from these reserves may be
greater than we anticipate. Accordingly, to maintain or increase
throughput levels on these pipelines and the utilization rate of
Discoverys natural gas processing plant and fractionator
and Four Corners processing plants and treating plants,
we, Discovery and Four Corners must continually connect new
supplies of natural gas. The primary factors affecting our
ability to connect new supplies of natural gas and attract new
customers to our pipelines include: (1) the level of
successful drilling activity near these pipelines; (2) our
ability to compete for volumes from successful new wells and
existing wells connected to third parties; and (3) our,
Discoverys and Four Corners ability to successfully
complete lateral expansion projects to connect to new wells.
Neither we nor Four Corners has any current significant lateral
expansion projects planned and Discovery has only one currently
planned significant lateral expansion project. Discovery signed
definitive agreements with Chevron, Shell and Statoil to
construct an approximate
35-mile gathering
pipeline lateral to connect Discoverys existing pipeline
system to these producers production facilities for the
Tahiti prospect in the deepwater region of the Gulf of Mexico.
Initial production is expected in April 2008.
The level of drilling activity in the fields served by our and
Discoverys pipelines and Four Corners gathering
system is dependent on economic and business factors beyond our
control. The primary factors that impact drilling decisions are
oil and natural gas prices. A sustained decline in oil and
natural gas prices could result in a decrease in exploration and
development activities in these fields, which would lead to
reduced throughput levels on our pipelines and gathering system.
Other factors that impact production decisions include
producers capital budget limitations, the ability of
producers to obtain necessary drilling and other governmental
permits, the availability of qualified personnel and equipment,
the quality of drilling prospects in the area and regulatory
changes. Because of these factors, even if new oil or natural
gas reserves are discovered in areas served by our pipelines and
gathering system, producers may choose not to develop those
reserves. If we were not able to connect new supplies of natural
gas to replace the natural decline in volumes from existing
wells, due to reductions in drilling activity, competition, or
difficulties in completing lateral expansion projects to connect
to new supplies of natural gas, throughput on our pipelines and
gathering system and the utilization rates of Discoverys
natural gas processing plant and fractionator and Four
Corners processing plants and treating plants would
decline, which could have a material adverse effect on our
business, results of operations, financial condition and ability
to make cash distributions to you.
Lower natural gas and oil prices could adversely affect
our fractionation and storage businesses.
Lower natural gas and oil prices could result in a decline in
the production of natural gas and NGLs resulting in reduced
throughput on our pipelines and Four Corners gathering
system. Any such decline would reduce the amount of NGLs we
fractionate and store, which could have a material adverse
effect on our business, results of operations, financial
condition and our ability to make cash distributions to you.
In general terms, the prices of natural gas, NGLs and other
hydrocarbon products fluctuate in response to changes in supply,
changes in demand, market uncertainty and a variety of
additional factors that are impossible to control. These factors
include:
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worldwide economic conditions; |
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weather conditions and seasonal trends; |
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the levels of domestic production and consumer demand; |
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the availability of imported natural gas and NGLs; |
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the availability of transportation systems with adequate
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the price and availability of alternative fuels; |
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the effect of energy conservation measures; |
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the nature and extent of governmental regulation and
taxation; and |
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the anticipated future prices of natural gas, NGLs and other
commodities. |
Our processing, fractionation and storage businesses could
be affected by any decrease in NGL prices or a change in NGL
prices relative to the price of natural gas.
Lower NGL prices would reduce the revenues we generate from the
sale of NGLs for our own account. Under certain gas processing
contracts, referred to as
percent-of-liquids
and keep whole contracts, Discovery and Four Corners
both receive NGLs removed from the natural gas stream during
processing. Discovery and Four Corners can then choose to either
fractionate and sell the NGLs or to sell the NGLs directly. In
addition, product optimization at our Conway fractionator
generally leaves us with excess propane, an NGL, which we sell.
We also sell excess storage volumes resulting from measurement
variances at our Conway storage facilities.
The relationship between natural gas prices and NGL prices may
also affect our profitability. When natural gas prices are low
relative to NGL prices, it is more profitable for Discovery,
Four Corners and their customers to process natural gas. When
natural gas prices are high relative to NGL prices, it is less
profitable to process natural gas both because of the higher
value of natural gas and of the increased cost (principally that
of natural gas as a feedstock and a fuel) of separating the
mixed NGLs from the natural gas. As a result, Discovery and Four
Corners may experience periods in which higher natural gas
prices reduce the volumes of NGLs removed at their processing
plants, which would reduce their margins. Finally, higher
natural gas prices relative to NGL prices could also reduce
volumes of gas processed generally, reducing the volumes of
mixed NGLs available for fractionation.
We depend on certain key customers and producers for a
significant portion of our revenues and supply of natural gas
and NGLs. The loss of any of these key customers or producers
could result in a decline in our revenues and cash available to
pay distributions.
We rely on a limited number of customers for a significant
portion of our revenues. Our three largest customers for the
year ended December 31, 2005 and the three months ended
March 31, 2006, other than a subsidiary of Williams that
markets NGLs for Conway, were BP Products North America, Inc.,
SemStream, L.P. and Enterprise Products Partners, all customers
of our Conway facilities. These customers accounted for
approximately 45% and 40% of our revenues for the year ended
December 31, 2005 and the three months ended March 31,
2006, respectively. Four Corners three largest customers
for the year ended December 31, 2005 and the three months
ended March 31, 2006, respectively, other than a subsidiary
of Williams that markets NGLs for Four Corners and Williams
Production Company, LLC, were ConocoPhillips, Burlington
Resources and BP America Production Company, which
accounted for approximately 30% and 29% of Four Corners
revenues for the year ended December 31, 2005 and the three
months ended March 31, 2006, respectively. On
March 31, 2006, ConocoPhillips acquired Burlington
Resources.
In addition, although some of these customers are subject to
long-term contracts, we may be unable to negotiate extensions or
replacements of these contracts, on favorable terms, if at all.
For example, Four Corners is in active negotiations with several
customers to renew gathering, processing and treating contracts
that are in evergreen status and that represent approximately
14% of Four Corners revenues for each of the year ended
December 31, 2005 and the three months ended March 31,
2006. The negotiations may not result in any extended
commitments from these customers. The loss of all or even a
portion of the volumes of natural gas or NGLs, as applicable,
supplied by these customers, as a result of competition or
otherwise,
25
could have a material adverse effect on our business, results of
operations, financial condition and our ability to make cash
distributions to you, unless we are able to acquire comparable
volumes from other sources.
If third-party pipelines and other facilities
interconnected to our pipelines and facilities become
unavailable to transport natural gas and NGLs or to treat
natural gas, our revenues and cash available to pay
distributions could be adversely affected.
We depend upon third party pipelines and other facilities that
provide delivery options to and from our pipelines and
facilities for the benefit of our customers. For example, MAPL
delivers its customers mixed NGLs to our Conway
fractionator and provides access to multiple end markets for NGL
products of our storage customers. If MAPL were to become
temporarily or permanently unavailable for any reason, or if
throughput were reduced because of testing, line repair, damage
to pipelines, reduced operating pressures, lack of capacity or
other causes, our customers would be unable to store or deliver
NGL products and we would be unable to receive deliveries of
mixed NGLs at our Conway fractionator. This would have an
immediate adverse impact on our ability to enter into short-term
storage contracts and our ability to fractionate sufficient
volumes of mixed NGLs at Conway.
MAPL also provides the only liquids pipeline access to multiple
end markets for NGL products that are recovered from Four
Corners processing plants. If MAPL were to become
temporarily or permanently unavailable for any reason, or if
throughput were reduced because of testing, line repair, damage
to pipelines, reduced operating pressures, lack of capacity or
other causes, Four Corners would be unable to deliver a
substantial portion of the NGLs recovered at its processing
plants. This would have an immediate impact on Four
Corners ability to sell or deliver NGL products recovered
at its processing plants. In addition, the five pipeline systems
that move natural gas to end markets from the San Juan
Basin connect to Four Corners treating and processing
facilities, including the El Paso Natural Gas,
Transwestern, Williams Northwest Pipeline, PNM and
Southern Trails systems. Some of these natural gas pipeline
systems have minimal excess capacity. If any of these pipeline
systems were to become temporarily or permanently unavailable
for any reason, or if throughput were reduced because of
testing, line repair, damage to pipelines, reduced operating
pressures, lack of capacity or other causes, Four Corners
customers would be unable to deliver natural gas to end markets.
This would reduce the volumes of natural gas processed or
treated at Four Corners treating and processing
facilities. Either of such events could materially and adversely
affect our business results of operations, financial condition
and ability to make distributions to you.
As another example, Shells Yellowhammer sour gas treating
facility in Coden, Alabama is the only sour gas treating
facility currently connected to our Carbonate Trend pipeline.
Natural gas produced from the Carbonate Trend area must pass
through a Shell-owned pipeline and Shells Yellowhammer
sour gas treating facility before delivery to end markets. If
the Shell-owned pipeline or the Yellowhammer facility were to
become unavailable for current or future volumes of natural gas
delivered to it through the Carbonate Trend pipeline due to
repairs, damages to the facility, lack of capacity or any other
reason, our Carbonate Trend customers would be unable to
continue shipping natural gas to end markets. Since we generally
receive revenues for volumes shipped on the Carbonate Trend
pipeline, this would reduce our revenues.
Any temporary or permanent interruption in operations at MAPL,
Yellowhammer or any other third party pipelines or facilities
that would cause a material reduction in volumes transported on
our pipelines or our gathering systems or processed,
fractionated, treated or stored at our facilities could have a
material adverse effect on our business, results of operations,
financial condition and our ability to make cash distributions
to you.
Our future financial and operating flexibility may be
adversely affected by restrictions in our indenture and by our
leverage.
In connection with the closing of this offering and our
acquisition of the interest in Four Corners, we will issue
$150 million of senior notes, which will cause our leverage
to increase. After giving effect to this offering and the
private placement of our senior notes, our total outstanding
debt will be $150 million,
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representing approximately 39% of our total book capitalization.
Immediately prior to this offering and the private placement of
our senior notes, we had no outstanding debt.
Debt service obligations and restrictive covenants in the
indenture governing the senior notes resulting from this
leverage may adversely affect our ability to finance future
operations, pursue acquisitions, fund other capital needs and
pay cash distributions to unitholders, and may make our results
of operations more susceptible to adverse economic or operating
conditions. Our ability to repay, extend or refinance our
existing debt obligations and to obtain future credit will
depend primarily on our operating performance, which will be
affected by general economic, financial, competitive,
legislative, regulatory, business and other factors, many of
which are beyond our control.
Williams credit agreement and Williams public
indentures contain financial and operating restrictions that may
limit our access to credit. In addition, our ability to obtain
credit in the future will be affected by Williams credit
ratings.
We have the ability to incur up to $75 million of
indebtedness under Williams $1.5 billion credit
agreement. However, this $75 million of borrowing capacity
will only be available to us to the extent that sufficient
amounts remain unborrowed by Williams and its other
subsidiaries. As a result, borrowings by Williams or its other
subsidiaries could restrict our access to credit. As of
May 1, 2006, letters of credit totaling approximately
$235 million had been issued on behalf of Williams and its
other subsidiaries by the participating institutions under the
facility and we did not have any revolving credit loans
outstanding. In addition, Williams public indentures
contain covenants that restrict Williams and our ability
to incur liens to support indebtedness. As a result, if Williams
were not in compliance with these covenants, we could be unable
to make any borrowings under our $75 million borrowing
limit, even if capacity were otherwise available. These
covenants could adversely affect our ability to finance our
future operations or capital needs or engage in, expand or
pursue our business activities and prevent us from engaging in
certain transactions that might otherwise be considered
beneficial to us.
Williams ability to comply with the covenants contained in
its debt instruments may be affected by events beyond our
control, including prevailing economic, financial and industry
conditions. If market or other economic conditions deteriorate,
Williams ability to comply with these covenants may be
impaired. While we are not individually subject to any financial
covenants or ratios under Williams credit agreement,
Williams and its subsidiaries as a whole are subject to these
tests. Accordingly, any breach of these or other covenants,
ratios or tests, would terminate our and Williams and its
other subsidiaries ability to make additional borrowings
under the credit facility and, as a result, could limit our
ability to finance our operations, make acquisitions or pay
distributions to unitholders. In addition, a breach of these
covenants by Williams could cause the acceleration of
Williams and, in some cases, our outstanding borrowings
under the facility. In the event of acceleration of
indebtedness, Williams, the other borrowers or we might not
have, or be able to obtain, sufficient funds to make required
repayments of the accelerated indebtedness. For more information
regarding our debt agreements, please read
Managements Discussion and Analysis of Financial
Condition and Results of Operations Financial
Condition and Liquidity.
Due to our relationship with Williams, our ability to obtain
credit will be affected by Williams credit ratings. If we
obtain our own credit rating, any future down grading of a
Williams credit rating would likely also result in a down
grading of our credit rating. Regardless of whether we have our
own credit rating, a down grading of a Williams credit
rating could limit our ability to obtain financing in the future
upon favorable terms, if at all.
Neither Four Corners nor Discovery is prohibited from
incurring indebtedness, which may affect our ability to make
distributions to you.
Neither Four Corners nor Discovery is prohibited by the terms of
their respective limited liability company agreements from
incurring indebtedness. At the closing of this offering and our
acquisition of an interest in Four Corners, Four Corners will
enter into a $20 million revolving credit facility with
Williams as the lender. Please read Managements
Discussion and Analysis of Financial Condition and Results of
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Operations Financial Condition and
Liquidity Credit Facilities. If either Four
Corners or Discovery were to incur significant amounts of
indebtedness, it may inhibit their ability to make distributions
to us. An inability by either Four Corners or Discovery to make
distributions to us would materially and adversely affect our
ability to make distributions to you because we expect
distributions we receive from Discovery and Four Corners to
represent a significant portion of the cash we distribute to our
unitholders.
We do not own all of the interests in the Conway
fractionator, in Discovery or in Four Corners, which could
adversely affect our ability to operate and control these assets
in a manner beneficial to us.
Because we do not wholly own the Conway fractionator, Discovery
or Four Corners, we may have limited flexibility to control the
operation of, dispose of, encumber or receive cash from these
assets. Any future disagreements with the other co-owners of
these assets could adversely affect our ability to respond to
changing economic or industry conditions, which could have a
material adverse effect on our business, results of operations,
financial condition and ability to make cash distributions to
you.
Discovery and Four Corners may reduce their cash
distributions to us in some situations
Discoverys limited liability company agreement provides
that Discovery will distribute its available cash to its members
on a quarterly basis. Four Corners limited liability
company agreement, as amended to be effective at the closing of
our acquisition of the interest in Four Corners, will provide
that Four Corners will distribute its available cash to its
members at least quarterly. Both Discoverys and Four
Corners available cash includes cash on hand less any
reserves that may be appropriate for operating its business. As
a result, reserves established by Discovery and Four Corners,
including those for working capital, will reduce the amount of
available cash. The amount of Discoverys and Four
Corners quarterly distributions, including the amount of
cash reserves not distributed, are to be determined by the
members of their respective management committees representing a
majority-in-interest in
such entity.
We own a 40% interest in Discovery and an affiliate of Williams
owns a 20% interest in Discovery. In addition, to the extent
Discovery requires working capital in excess of applicable
reserves, the Williams member must make working capital advances
to Discovery of up to the amount of Discoverys two most
recent prior quarterly distributions of available cash, but
Discovery must repay any such advances before it can make future
distributions to its members. As a result, the repayment of
advances could reduce the amount of cash distributions we would
otherwise receive from Discovery. In addition, if the Williams
member cannot advance working capital to Discovery as described
above, Discoverys business and financial condition may be
adversely affected.
We do not operate all of our assets. This reliance on
others to operate our assets and to provide other services could
adversely affect our business and operating results.
Williams operates all of our assets, other than the Carbonate
Trend pipeline, which is operated by Chevron, and our Conway
fractionator and storage facilities, which we operate. Williams
also operates the major plants and all of the plant compression
for Four Corners, while Hanover operates approximately 85% of
Four Corners field compression. We have a limited ability
to control our operations or the associated costs of these
operations. The success of these operations is therefore
dependent upon a number of factors that are outside our control,
including the competence and financial resources of the
operators.
We also rely on Williams for services necessary for us to be
able to conduct our business. Williams may outsource some or all
of these services to third parties, and a failure of all or part
of Williams relationships with its outsourcing providers
could lead to delays in or interruptions of these services. Our
reliance on Williams as an operator and on Williams
outsourcing relationships, our reliance on Chevron, Four
Corners reliance on Hanover and Williams and our limited
ability to control certain costs could have a material adverse
effect on our business, results of operations, financial
condition and ability to make cash distributions to you.
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Our industry is highly competitive, and increased
competitive pressure could adversely affect our business and
operating results.
We compete with similar enterprises in our respective areas of
operation. Some of our competitors are large oil, natural gas
and petrochemical companies that have greater financial
resources and access to supplies of natural gas and NGLs than we
do.
Discovery competes with other natural gas gathering and
transportation and processing facilities and other NGL
fractionation facilities located in south Louisiana, offshore in
the Gulf of Mexico and along the Gulf Coast, including the Manta
Ray/ Nautilus systems, the Trunkline pipeline and the Venice
Gathering System and the processing and fractionation facilities
that are connected to these pipelines.
Our Conway fractionation facility competes for volumes of mixed
NGLs with a fractionator located in each of Hutchinson, Kansas,
Medford, Oklahoma, and Bushton, Kansas owned by ONEOK Partners,
L.P., the other joint owners of the Conway fractionation
facility and, to a lesser extent, with fractionation facilities
on the Gulf Coast. In April 2006, ONEOK, Inc. transferred its
entire gathering and processing, natural gas liquids, and
pipelines and storage segments to ONEOK Partners, L.P. (formerly
known as Northern Border Partners L.P.), or ONEOK. Our Conway
storage facilities compete with ONEOK-owned storage facilities
in Bushton, Kansas and in Conway, Kansas, an NCRA-owned facility
in Conway, Kansas, a ONEOK-owned facility in Hutchinson, Kansas
and an Enterprise Products Partners-owned facility in
Hutchinson, Kansas and, to a lesser extent, with storage
facilities on the Gulf Coast and in Canada.
Four Corners competes with other natural gas gathering,
processing and treating facilities in the San Juan Basin,
including Enterprise, Red Cedar and TEPPCO. In addition, our
customers who are significant producers of gas or consumers of
NGLs may develop their own gathering, processing, fractionation
and storage facilities in lieu of using ours.
Also, competitors may establish new connections with pipeline
systems that would create additional competition for services we
provide to our customers. For example, other than the producer
gathering lines that connect to the Carbonate Trend pipeline,
there are no other sour gas pipelines near our Carbonate Trend
pipeline, but the producers that are currently our customers
could construct or commission such pipelines in the future.
Our ability to renew or replace existing contracts with our
customers at rates sufficient to maintain current revenues and
cash flows could be adversely affected by the activities of our
competitors. 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 results of storage and fractionation operations are
dependent upon the demand for propane and other NGLs. A
substantial decrease in this demand could adversely affect our
business and operating results.
Our Conway storage and fractionation operations are impacted by
demand for propane more than any other NGLs. Conway, Kansas is
one of the two major trading hubs for propane and other NGLs in
the continental United States. Demand for propane at Conway is
principally driven by demand for its use as a heating fuel.
However, propane is also used as an engine and industrial fuel
and as a petrochemical feedstock in the production of ethylene
and propylene. Demand for propane as a heating fuel is
significantly affected by weather conditions and the
availability of alternative heating fuels such as natural gas.
Weather-related demand is subject to normal seasonal
fluctuations, but an unusually warm winter could cause demand
for propane as a heating fuel to decline significantly. Demand
for other NGLs, which include ethane, butane, isobutane and
natural gasoline, could be adversely impacted by general
economic conditions, a reduction in demand by customers for
plastics and other end products made from NGLs, an increase in
competition from petroleum-based products, government
regulations or other reasons. Any decline in demand for propane
or other NGLs could cause a reduction in demand for our Conway
storage and fractionation services.
When prices for the future delivery of propane and other NGLs
that we store at our Conway facilities fall below current
prices, customers are less likely to store these products, which
could reduce our storage revenues. This market condition is
commonly referred to as backwardation. When the
market for propane
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and other NGLs is in backwardation, the demand for storage
capacity at our Conway facilities may decrease. While this would
not impact our long-term capacity leases, customers could become
less likely to enter into short-term storage contracts.
We may not be able to grow or effectively manage our
growth.
A principal focus of our strategy is to continue to grow by
expanding our business. Our future growth will depend upon a
number of factors, some of which we can control and some of
which we cannot. These factors include our ability to:
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identify businesses engaged in managing, operating or owning
pipeline, processing, fractionation and storage assets, or other
midstream assets for acquisitions, joint ventures and
construction projects; |
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control costs associated with acquisitions, joint ventures or
construction projects; |
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consummate acquisitions, including the acquisition of the
interest in Four Corners, or joint ventures and complete
construction projects, including Discoverys Tahiti lateral
expansion project; |
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integrate any acquired or constructed business or assets
successfully with our existing operations and into our operating
and financial systems and controls; |
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hire, train and retain qualified personnel to manage and operate
our growing business; and |
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obtain required financing for our existing and new operations. |
A failure to achieve any of these factors would adversely affect
our ability to achieve anticipated growth in the level of cash
flows or realize anticipated benefits. Furthermore, competition
from other buyers could reduce our acquisition opportunities or
cause us to pay a higher price than we might otherwise pay. In
addition, Williams is not restricted from competing with us.
Williams may acquire, construct or dispose of midstream or other
assets in the future without any obligation to offer us the
opportunity to purchase or construct those assets.
We may acquire new facilities or expand our existing facilities
to capture anticipated future growth in natural gas production
that does not ultimately materialize. As a result, our new or
expanded facilities may not achieve profitability. In addition,
the process of integrating newly acquired or constructed assets
into our operations may result in unforeseen operating
difficulties, may absorb significant management attention and
may require financial resources that would otherwise be
available for the ongoing development and expansion of our
existing operations. Future acquisitions or construction
projects could result in the incurrence of indebtedness and
additional liabilities and excessive costs that could have a
material adverse effect on our business, results of operations,
financial condition and ability to make cash distributions to
you. For example, in connection with our proposed acquisition of
the interest in Four Corners, we will issue $150 million
aggregate principal amount of senior notes. Further, if we issue
additional common units in connection with future acquisitions,
your interest in the partnership will be diluted and
distributions to you may be reduced.
Discoverys interstate tariff rates are subject to
review and possible adjustment by federal regulators, which
could have a material adverse effect on our business and
operating results. Moreover, because Discovery is a
non-corporate entity, it may be disadvantaged in calculating its
cost of service for rate-making purposes.
The Federal Energy Regulatory Commission, or FERC, pursuant to
the Natural Gas Act, regulates Discoverys interstate
pipeline transportation service. Under the Natural Gas Act,
interstate transportation rates must be just and reasonable and
not unduly discriminatory. If the tariff rates Discovery is
permitted to charge its customers are lowered by FERC, on its
own initiative, or as a result of challenges raised by
Discoverys customers or third parties, FERC could require
refunds of amounts collected under rates which it finds
unlawful. An adverse decision by FERC in approving
Discoverys regulated rates could adversely affect our cash
flows. Although FERC generally does not regulate the natural gas
gathering operations of Discovery under the Natural Gas Act,
federal regulation influences the parties that gather natural
gas on the Discovery gas gathering system.
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Discoverys maximum regulated rate for mainline
transportation is scheduled to decrease in 2008. At that time,
Discovery may be required to reduce its mainline transportation
rate on all of its contracts that have rates above the new
maximum rate. This could reduce the revenues generated by
Discovery. Discovery may elect to file a rate case with FERC
seeking to alter this scheduled maximum rate reduction. However,
if filed, a rate case may not be successful in even partially
preventing the rate reduction. If Discovery makes such a filing,
all aspects of Discoverys cost of service and rate design
could be reviewed, which could result in additional reductions
to its regulated rates.
In July 2004, the United States Court of Appeals for the
District of Columbia Circuit, or the D.C. Circuit, issued its
opinion in BP West Coast Products, LLC v. FERC,
which upheld, among other things, FERCs determination that
certain rates of an interstate petroleum products pipeline,
SFPP, L.P., or SFPP, were grandfathered rates under the Energy
Policy Act of 1992 and that SFPPs shippers had not
demonstrated substantially changed circumstances that would
justify modification of those rates. The court also vacated the
portion of FERCs decision applying the Lakehead
policy. In the Lakehead decision, FERC allowed an oil
pipeline publicly traded partnership to include in its
cost-of-service an
income tax allowance to the extent that its unitholders were
corporations subject to income tax. In May and June 2005, FERC
issued a statement of general policy, as well as an order on
remand of BP West Coast, respectively, in which FERC
stated it will permit pipelines to include in
cost-of-service a tax
allowance to reflect actual or potential tax liability on their
public utility income attributable to all partnership or limited
liability company interests, if the ultimate owner of the
interest has an actual or potential income tax liability on such
income. Whether a pipelines owners have such actual or
potential income tax liability will be reviewed by FERC on a
case-by-case basis. Although the new policy is generally
favorable for pipelines that are organized as pass-through
entities, it still entails rate risk due to the case-by-case
review requirement. In December 2005, FERC issued its first
case-specific oil pipeline review of the income tax allowance
issue in the SFPP proceeding, reaffirming its new income tax
allowance policy and directing SFPP to provide certain evidence
necessary for the pipeline to determine its income tax
allowance. FERCs BP West Coast remand decision and
the new tax allowance policy have been appealed to the D.C.
Circuit. The FERC has not issued an order determining the income
tax allowance for SFPP. As a result, the ultimate outcome of
these proceedings is not certain and could result in changes to
FERCs treatment of income tax allowances in
cost-of-service. If
Discovery were to file a rate case, as discussed above, it would
be required to prove pursuant to the new policys standard
that the inclusion of an income tax allowance in
Discoverys
cost-of-service was
permitted. If FERC were to disallow a substantial portion of
Discoverys income tax allowance, it may be more difficult
for Discovery to justify its rates.
The only pipeline that provides NGL transportation
capacity in the San Juan Basin has filed at FERC to
increase certain of its tariff rates. If the requested increase
is granted, Four Corners operating costs would increase,
which could have an adverse effect on our business and operating
results.
MAPL, the only pipeline in the San Juan Basin that provides
NGL transportation capacity, has filed at FERC to increase
certain of its tariff rates. If FERC grants this request to
increase those tariff rates, we estimate that Four Corners
cost of transporting NGLs to certain markets would increase by
approximately $1.5 million per year, which could have an
adverse effect on our business, results of operations, financial
condition and ability to make cash distributions to us.
Our operations are subject to operational hazards and
unforeseen interruptions for which we may not be adequately
insured.
There are operational risks associated with the gathering,
transporting and processing of natural gas and the fractionation
and storage of NGLs, including:
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hurricanes, tornadoes, floods, fires, extreme weather conditions
and other natural disasters and acts of terrorism; |
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damages to pipelines and pipeline blockages; |
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leakage of natural gas (including sour gas), NGLs, brine or
industrial chemicals; |
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collapse of NGL storage caverns; |
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operator error; |
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pollution; |
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fires, explosions and blowouts; |
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risks related to truck and rail loading and unloading; and |
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risks related to operating in a marine environment. |
Any of these or any other similar occurrences could result in
the disruption of our operations, substantial repair costs,
personal injury or loss of life, property damage, damage to the
environment or other significant exposure to liability. For
example, in 2004 we experienced a temporary interruption of
service on one of our pipelines due to an influx of seawater
while connecting a new lateral. In addition, the Carbonate Trend
pipeline is scheduled to be temporarily shut down in the second
half of 2006 in connection with restoration activities due to
the partial erosion of the pipeline overburden caused by
Hurricane Ivan in September 2004. We believe the cost of these
restoration activities will be between $3.4 and
$4.6 million and that the scheduled shut down could reduce
our cash flows from operations.
In addition, in anticipation of Hurricane Katrina, the Discovery
and Carbonate Trend assets were temporarily shut down on
August 27, 2005. The Carbonate Trend assets were off-line
for ten days and then experienced a gradual return to
pre-hurricane throughput rates by September 19, 2005. In
anticipation of Hurricane Rita, the Discovery assets, which were
already at reduced throughput from Hurricane Katrina, were
temporarily shut down on September 21, 2005. The Discovery
assets were off-line for seven days and then continued to
experience lower throughput rates through the end of the year
and into 2006. We estimate the unfavorable impact of these
hurricanes on our 2005 net income was approximately
$1.5 million due primarily to the impact of these
hurricanes on Discoverys results. Discoverys net
income was unfavorably impacted by an approximate loss of
$2.3 million in revenue and $1.0 million in uninsured
expenses. In 2005, Discovery sustained damages from Hurricane
Katrina that exceeded the $1.0 million deductible per
occurrence under its property insurance policy. Please read
Managements Discussion and Analysis of Financial
Condition and Results of Operations Recent
Events for additional information.
Insurance may be inadequate, and in some instances, we may be
unable to obtain insurance on commercially reasonable terms, if
at all. A significant disruption in operations or a significant
liability for which we were not fully insured could have a
material adverse effect on our business, results of operations
and financial condition and our ability to make cash
distributions to you.
Pipeline integrity programs and repairs may impose
significant costs and liabilities on us.
In December 2003, the U.S. Department of Transportation
issued a final rule requiring pipeline operators to develop
integrity management programs for gas transportation pipelines
located where a leak or rupture could do the most harm in
high consequence areas. The final rule requires
operators to:
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perform ongoing assessments of pipeline integrity; |
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identify and characterize applicable threats to pipeline
segments that could impact a high consequence area; |
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improve data collection, integration and analysis; |
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repair and remediate the pipeline as necessary; and |
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implement preventive and mitigating actions. |
The final rule incorporates the requirements of the Pipeline
Safety Improvement Act of 2002. The final rule became effective
on January 14, 2004. In response to this new Department of
Transportation rule, we have initiated pipeline integrity
testing programs that are intended to assess pipeline integrity.
In addition, we have voluntarily initiated a testing program to
assess the integrity of the brine pipelines of our Conway storage
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facilities. In 2005, Conway replaced two sections of brine
systems at a cost of $0.2 million. This work is in
anticipation of integrity testing scheduled to begin in 2006.
The results of these testing programs could cause us to incur
significant capital and operating expenditures in response to
any repair, remediation, preventative or mitigating actions that
are determined to be necessary.
Additionally, the transportation of sour gas in our Carbonate
Trend pipeline necessitates a corrosion control program in order
to protect the integrity of the pipeline and prolong its life.
Our corrosion control program may not be successful and the sour
gas could compromise pipeline integrity. Our inability to reduce
corrosion on our Carbonate Trend pipeline to acceptable levels
could significantly reduce the service life of the pipeline and
could have a material adverse effect on our business, results of
operations, financial condition and ability to make cash
distributions to you. Please read Business
Gathering and Processing The Carbonate Trend
Pipeline General for additional information on
our corrosion control program.
The State of New Mexico recently enacted rule changes that
permit the pressure in gathering pipelines to be reduced below
atmospheric levels. In response to these rule changes, Four
Corners may reduce the pressures in its gathering lines below
atmospheric levels. With Four Corners concurrence,
producers may also reduce pressures below atmospheric levels
prior to delivery to Four Corners. All of the gathering lines
owned by Four Corners in the San Juan Basin are made of
steel. Reduced pressures below atmospheric levels may introduce
increasing amounts of oxygen into those pipelines, which could
cause an acceleration of the corrosion.
We do not own all of the land on which our pipelines and
facilities are located, which could disrupt our
operations.
We do not own all of the land on which our pipelines and
facilities have been constructed, and we are therefore subject
to the possibility of increased costs to retain necessary land
use. We obtain the rights to construct and operate our pipelines
and gathering systems on land owned by third parties and
governmental agencies for a specific period of time. For
example, portions of the Four Corners gathering system are
located on Native American
right-of-ways. Four
Corners is currently in discussions with the Jicarilla Apache
Nation regarding
rights-of-way that
expire at the end of 2006 for a small segment of the gathering
system. 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 and financial condition and our
ability to make cash distributions to you.
Our operations are subject to governmental laws and
regulations relating to the protection of the environment, which
may expose us to significant costs and liabilities.
The risk of substantial environmental costs and liabilities is
inherent in natural gas gathering, transportation and
processing, and in the fractionation and storage of NGLs, and we
may incur substantial environmental costs and liabilities in the
performance of these types of operations. Our operations are
subject to stringent federal, state and local laws and
regulations relating to protection of the public and the
environment. These laws include, for example:
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the Federal Clean Air Act and analogous state laws, which impose
obligations related to air emissions; |
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the Federal Water Pollution Control Act of 1972, as renamed and
amended as the Clean Water Act, or CWA, and analogous state
laws, which regulate discharge of wastewaters from our
facilities to state and federal waters; |
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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 have been released at properties currently
or previously owned or operated by us or locations to which we
have sent wastes for disposal; and |
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the federal Resource Conservation and Recovery Act, also known
as RCRA, and analogous state laws that impose requirements for
the handling and discharge of solid and hazardous waste from our
facilities. |
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Various governmental authorities, including the
U.S. Environmental Protection Agency, or EPA, have the
power to enforce compliance with these laws and regulations and
the permits issued under them, and violators are subject to
administrative, civil and criminal penalties, including civil
fines, injunctions or both. Joint and several, strict liability
may be incurred without regard to fault under CERCLA, RCRA and
analogous state laws for the remediation of contaminated areas.
There is inherent risk of the incurrence of environmental costs
and liabilities in our business due to our handling of the
products we gather, transport, process, fractionate and store,
air emissions related to our operations, historical industry
operations, waste disposal practices, and the prior use of flow
meters containing mercury, some of which may be material.
Private parties, including the owners of properties through
which our pipeline and gathering systems pass, may 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 arising
from our operations. Some sites we operate are located near
current or former third party hydrocarbon storage and processing
operations and there is a risk that contamination has migrated
from those sites to ours. In addition, increasingly strict laws,
regulations and enforcement policies could significantly
increase our compliance costs and the cost of any remediation
that may become necessary, some of which may be material.
For example, the Kansas Department of Health and Environment, or
the KDHE, regulates the storage of NGLs and natural gas in the
state of Kansas. This agency also regulates the construction,
operation and closure of brine ponds associated with such
storage facilities. In response to a significant incident at a
third party facility, the KDHE recently promulgated more
stringent regulations regarding safety and integrity of brine
ponds and storage caverns. These regulations are subject to
interpretation and the costs associated with compliance with
these regulations could vary significantly depending upon the
interpretation of these regulations. Additionally, incidents
similar to the incident at a third party facility that prompted
the recent KDHE regulations could prompt the issuance of even
stricter regulations.
There is increasing pressure in New Mexico from environmental
groups and area residents to reduce the noise from midstream
operations through regulatory means. If these groups are
successful, Four Corners may have to make capital expenditures
to muffle noise from its facilities or to ensure adequate
barriers or distance to mitigate noise concerns.
Our insurance may not cover all environmental risks and costs or
may not provide sufficient coverage in the event an
environmental claim is made against us. Our business may be
adversely affected by increased costs due to stricter pollution
control requirements or liabilities resulting from
non-compliance with required operating or other regulatory
permits. Also, new environmental regulations might adversely
affect our products and activities, including processing,
fractionation, storage and transportation, as well as waste
management and air emissions. Federal and state agencies also
could impose additional safety requirements, any of which could
affect our profitability.
The natural gas gathering operations in the San Juan
Basin may be subjected to regulation by the state of New Mexico,
which could negatively affect Four Corners.
The New Mexico state legislature has called for hearings to take
place to examine the regulation of natural gas gathering systems
in the state. It is unclear when these hearings will occur, but
they could result in gathering regulation that would affect the
fees that Four Corners could collect for gathering services.
This type of regulation could adversely impact Four
Corners revenues and cash flow.
Potential changes in accounting standards might cause us
to revise our financial results and disclosure in the
future.
Recently-discovered accounting irregularities in various
industries have forced regulators and legislators to take a
renewed look at accounting practices, financial disclosure, the
relationships between companies and their independent auditors,
and retirement plan practices. It remains unclear what new laws
or regulations will be adopted, and we cannot predict the
ultimate impact that any such new laws or regulations could
have. In addition, the Financial Accounting Standards Board or
the SEC could enact new accounting standards that
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might impact how we are required to record revenues, expenses,
assets and liabilities. Any significant change in accounting
standards or disclosure requirements could have a material
adverse effect on our business, results of operations, financial
condition and ability to make cash distributions to you.
Terrorist attacks have resulted in increased costs, and
attacks directed at our facilities or those of our suppliers and
customers could disrupt our operations.
On September 11, 2001, the United States was the target of
terrorist attacks of unprecedented scale. Since the September 11
attacks, the United States government has issued warnings that
energy assets may be the future target of terrorist
organizations. These developments have subjected our operations
to increased risks and costs. The long-term impact that
terrorist attacks and the threat of terrorist attacks may have
on our industry in general, and on us in particular, is not
known at this time. Uncertainty surrounding continued
hostilities in the Middle East or other sustained military
campaigns may affect our operations in unpredictable ways. In
addition, uncertainty regarding future attacks and war cause
global energy markets to become more volatile. Any terrorist
attack on our facilities or those of our suppliers or customers
could have a material adverse effect on our business, results of
operations, financial condition and ability to make cash
distributions to you.
Changes in the insurance markets attributable to terrorists
attacks may make certain types of insurance more difficult for
us to obtain. Moreover, the insurance that may be available to
us may be significantly more expensive than our existing
insurance coverage. Instability in financial markets as a result
of terrorism or war could also affect our ability to raise
capital.
We are exposed to the credit risk of our customers and our
credit risk management may not be adequate to protect against
such risk.
We are subject to the risk of loss resulting from nonpayment
and/or nonperformance by our customers. Our credit procedures
and policies may not be adequate to fully eliminate customer
credit risk. If we fail to adequately assess the
creditworthiness of existing or future customers, unanticipated
deterioration in their creditworthiness and any resulting
increase in nonpayment and/or nonperformance by them could have
a material adverse effect on our business, results of
operations, financial condition and ability to make cash
distributions to you.
Risks Inherent in an Investment in Us
Our general partner and its affiliates have conflicts of
interest and limited fiduciary duties, which may permit them to
favor their own interests to your detriment.
Following this offering, Williams will own a 2% general partner
interest and a 39.2% limited partner interest in us and will own
and control our general partner. Although our general partner
has a fiduciary duty to manage us in a manner beneficial to us
and our unitholders, the directors and executive officers of our
general partner have a fiduciary duty to manage our general
partner in a manner beneficial to its owner, Williams. Conflicts
of interest may arise between our general partner and its
affiliates, on the one hand, and us and our unitholders, on the
other hand. In resolving these conflicts, our general partner
may favor its own interests and the interests of its affiliates
over the interests of our unitholders. These conflicts include,
among others, the following situations:
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neither our partnership agreement nor any other agreement
requires Williams or its affiliates to pursue a business
strategy that favors us; |
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our general partner is allowed to take into account the
interests of parties other than us, such as Williams, in
resolving conflicts of interest, which has the effect of
limiting its fiduciary duty to you; |
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Williams and its affiliates may engage in competition with us; |
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our general partner has limited its liability and reduced its
fiduciary duties, and has also restricted the remedies available
to our unitholders for actions that, without the limitations,
might constitute breaches of fiduciary duty; |
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our general partner determines the amount and timing of our cash
reserves, asset purchases and sales, capital expenditures,
borrowings and issuances of additional partnership securities,
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, as well as whether a capital expenditure
is a maintenance capital expenditure, which reduces operating
surplus, or an expansion capital expenditure, which does not,
which determination can affect the amount of cash that is
distributed to our unitholders and the ability of the
subordinated units to convert to common units; |
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in some instances, 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 general partner determines which costs incurred by it and
its affiliates are reimbursable by us; |
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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 limited right to call and
purchase common units if it and its affiliates own more than 80%
of the common units; |
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our general partner controls the enforcement of obligations owed
to us by it and its affiliates; and |
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our general partner decides whether to retain separate counsel,
accountants or others to perform services for us. |
Please read Certain Relationships and Related
Transactions Omnibus Agreement and
Conflicts of Interest and Fiduciary Duties.
Our partnership agreement limits our general
partners fiduciary duties to you and restricts the
remedies available to you for actions taken by our general
partner that might otherwise constitute breaches of fiduciary
duty.
Our partnership agreement contains provisions that reduce the
standards to which our general partner would otherwise be held
by state fiduciary duty law. For example, our partnership
agreement:
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permits our general partner to make a number of decisions in its
individual capacity, as opposed to in its capacity as our
general partner. This entitles our general partner to consider
only the interests and factors that it desires, and it has no
duty or obligation to give any consideration to any interest of,
or factors affecting, us, our affiliates or any limited partner.
Examples include the exercise of its 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; |
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provides that our general partner will not have any liability to
us or our unitholders for decisions made in its capacity as a
general partner so long as it acted in good faith, meaning it
believed the decision was in the best interests of our
partnership; |
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provides that resolutions of conflicts of interest not approved
by the conflicts committee of the board of directors of our
general partner and not involving a vote of unitholders must be
on terms no less favorable to us than those generally being
provided to or available from unrelated third parties or be
fair and reasonable to us, as determined by our
general partner in good faith, and that, in determining whether
a transaction or resolution is fair and reasonable,
our general partner may |
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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, its affiliates and their
officers and directors will not be liable for monetary damages
to us or our limited partners for any acts or omissions unless
there has been a final and non-appealable judgment entered by a
court of competent jurisdiction determining that our general
partner or those other persons acted in bad faith or engaged in
fraud or willful misconduct. |
By purchasing a common unit, a common unitholder will be bound
by the provisions in the partnership agreement, including the
provisions discussed above. Please read Conflicts of
Interest and Fiduciary Duties Fiduciary Duties.
Even if you are dissatisfied, you cannot currently remove
our general partner without its consent.
Unlike the holders of common stock in a corporation, you have
only limited voting rights on matters affecting our business
and, therefore, limited ability to influence managements
decisions regarding our business. You will have no right to
elect our general partner or its board of directors on an annual
or other continuing basis. The board of directors of our general
partner is chosen by Williams. As a result of these limitations,
the price at which our common units will trade could be
diminished because of the absence or reduction of a takeover
premium in the trading price.
Furthermore, if you are dissatisfied with the performance of our
general partner, you will have little ability to remove our
general partner. The vote of the holders of at least
662/3
% of all outstanding common and subordinated units voting
together as a single class is required to remove our general
partner. Accordingly, our unitholders are currently unable to
remove our general partner without its consent because
affiliates of our general partner own sufficient units to be
able to prevent the general partners removal. 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 be converted
into common units and any existing arrearages on the common
units will be extinguished. A removal of our general partner
under these circumstances would adversely affect the common
units by prematurely eliminating their distribution and
liquidation preference over the subordinated units, which would
otherwise have continued until we had met certain distribution
and performance tests.
Cause is narrowly defined in our partnership agreement 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.
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 the members of our general partner from transferring
their member interest in our general partner to a third party.
The new members of our general partner would then be in a
position to replace the board of directors and officers of the
general partner with their own choices and to control the
decisions taken by the board of directors and officers of the
general partner. In addition, pursuant to the omnibus agreement
with Williams, any new owner of the general partner would be
required to change our name so that there would be no further
reference to Williams.
Increases in interest rates may cause the market price of
our common units to decline.
An increase in interest rates may cause a corresponding decline
in demand for equity investments in general, and in particular
for yield-based equity investments such as our common units. Any
such increase in
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interest rates or reduction in demand for our common units
resulting from other more attractive investment opportunities
may cause the trading price of our common units to decline.
We may issue additional common units without your
approval, which would dilute your ownership interests.
Our general partner, without the approval of our unitholders,
may cause us to issue an unlimited number of additional units,
subject to the limitations imposed by the New York Stock
Exchange. The issuance by us of additional common units or other
equity securities of equal or senior rank will have the
following effects:
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our unitholders proportionate ownership interest in us
will decrease; |
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the amount of cash available to pay distributions on each unit
may decrease; |
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because a lower percentage of total outstanding units will be
subordinated units, the risk that a shortfall in the payment of
the minimum quarterly distribution will be borne by our common
unitholders will increase; |
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the relative voting strength of each previously outstanding unit
may be diminished; and |
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the market price of the common units may decline. |
Williams and its affiliates may compete directly with us
and have no obligation to present business opportunities to
us.
The omnibus agreement does not prohibit Williams and its
affiliates from owning assets or engaging in businesses that
compete directly or indirectly with us. Williams 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. In addition, under
our partnership agreement, the doctrine of corporate
opportunity, or any analogous doctrine, will not apply to
Williams and its affiliates. As a result, neither Williams nor
any of its affiliates has any obligation to present business
opportunities to us. Please read Certain Relationships and
Related Transactions Omnibus Agreement and
Conflicts of Interest and Fiduciary Duties.
Our general partner has a limited call right that may
require you to sell your common units at an undesirable time or
price.
If at any time our general partner and its affiliates own more
than 80% of the common units, our general partner will have the
right, but not the obligation, which it may assign to any of its
affiliates or to us, to acquire all, but not less than all, of
the common units held by unaffiliated persons at a price not
less than their then-current market price. As a result, you may
be required to sell your common units at an undesirable time or
price and may not receive any return on your investment. You may
also incur a tax liability upon a sale of your units. Our
general partner is not obligated to obtain a fairness opinion
regarding the value of the common units to be repurchased by it
upon exercise of the limited call right. There is no restriction
in our partnership agreement that prevents our general partner
from issuing additional common units and exercising its call
right. If our general partner exercised its limited call right,
the effect would be to take us private and, if the units were
subsequently deregistered, we would not longer be subject to the
reporting requirements of the Securities Exchange Act of 1934.
For additional information about this call right, please read
The Partnership Agreement Limited Call
Right.
Our partnership agreement restricts the voting rights of
unitholders owning 20% or more of our common units.
Our partnership agreement restricts unitholders voting
rights by providing that any units held by a person that owns
20% or more of any class of units then outstanding, other than
our general partner and 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. The partnership agreement also contains provisions
limiting the ability of unitholders to call meetings or to
acquire information about our operations,
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as well as other provisions limiting the unitholders ability to
influence the manner or direction of management.
Cost reimbursements due our general partner and its
affiliates will reduce cash available to pay distributions to
you.
Prior to making any distribution on the common units, we will
reimburse our general partner and its affiliates for all
expenses they incur on our behalf, which will be determined by
our general partner. These expenses will include all costs
incurred by the general partner and its affiliates in managing
and operating us, including costs for rendering corporate staff
and support services to us. Please read Certain
Relationships and Related Transactions and Conflicts
of Interest and Fiduciary Duties Conflicts of
Interest. The reimbursement of expenses and payment of
fees, if any, to our general partner and its affiliates could
adversely affect our ability to pay cash distributions to you.
You may not have limited liability if a court finds that
unitholder action constitutes control of our business. You may
also have liability to repay distributions.
As a limited partner in a partnership organized under Delaware
law, you could be held liable for our obligations to the same
extent as a general partner if you participate in the
control of our business. Our general partner
generally has unlimited liability for the obligations of the
partnership, such as its debts and environmental liabilities,
except for those contractual obligations of the partnership that
are expressly made without recourse to our general partner. In
addition, Section 17-607 of the Delaware Revised Uniform
Limited Partnership Act provides that, under some circumstances,
a unitholder may be liable to us for the amount of a
distribution for a period of three years from the date of the
distribution. 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. Please read The
Partnership Agreement Limited Liability for a
discussion of the implications of the limitations of liability
on a unitholder.
Common units held by affiliates of Williams eligible for
future sale may have adverse effects on the price of our common
units.
As of May 15, 2006, affiliates of Williams held 1,250,000
common units and 7,000,000 subordinated units, representing a
39.2% limited partnership interest in us after giving effect to
this offering. The affiliates of Williams may, from time to
time, sell all or a portion of their common units or
subordinated units. Sales of substantial amounts of their common
units or subordinated units, or the anticipation of such sales,
could lower the market price of our common units and may make it
more difficult for us to sell our equity securities in the
future at a time and at a price that we deem appropriate.
Our common units have a limited trading history and a
limited trading volume compared to other units representing
limited partner interests.
Our common units are traded publicly on the New York Stock
Exchange under the symbol WPZ. However, our common
units have a limited trading history and daily trading volumes
for our common units are, and may continue to be, relatively
small compared to many other units representing limited partner
interests quoted on the New York Stock Exchange. This offering
may not increase the trading volume for our common units, and
the price of our common units may, therefore, be volatile.
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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our quarterly distributions; |
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our quarterly or annual earnings or those of other companies in
our industry; |
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loss of a large customer; |
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announcements by us or our competitors of significant contracts
or acquisitions; |
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changes in accounting standards, policies, guidance,
interpretations or principles; |
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general economic conditions; |
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the failure of securities analysts to cover our common units
after this offering or changes in financial estimates by
analysts; |
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future sales of our common units; and |
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the other factors described in these Risk Factors. |
Tax Risks
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 entity-level taxation by states. If the IRS were to
treat us as a corporation or if we were to become subject to
entity-level taxation for state tax purposes, then our cash
available to pay distributions to you would be substantially
reduced.
The anticipated after-tax benefit of an investment in the common
units depends largely on our being treated as a partnership for
federal income tax purposes. We have not requested, and do not
plan to request, a ruling from the IRS on this or any other
matter affecting us.
If we were treated as a corporation for federal income tax
purposes, we would pay federal income tax on our income at the
corporate tax rate, which is currently a maximum of 35%, 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 to pay
distributions to you would be substantially reduced. Thus,
treatment of us as a corporation would result in a material
reduction in the anticipated cash flow and after-tax return to
you, likely causing a substantial reduction in the value of the
common units.
Current law may change, causing us to be treated as a
corporation for federal income tax purposes or otherwise
subjecting us to entity-level taxation. For example, because of
widespread state budget deficits, several states are evaluating
ways to subject partnerships to entity-level taxation through
the imposition of state income, franchise or other forms of
taxation. If any state were to impose a tax upon us as an
entity, the cash available to pay distributions to you would be
reduced. The partnership agreement provides that if a law is
enacted or existing law is modified or interpreted in a manner
that subjects us to taxation as a corporation or otherwise
subjects us to entity-level taxation for federal, state or local
income tax purposes, then the minimum quarterly distribution
amount and the target distribution amounts will be adjusted to
reflect the impact of that law on us.
A successful IRS contest of the federal income tax
positions we take may adversely impact the market for our common
units, and the costs of any contest will be borne by our
unitholders and our general partner.
We have not requested any ruling from the IRS with respect to
our treatment as a partnership for federal income tax purposes
or any other matter affecting us. The IRS may adopt positions
that differ from our counsels conclusions expressed in
this prospectus. 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
the positions we take. Any contest with the IRS may materially
and adversely impact the market for our common units and the
price at which they trade. In addition, the costs of any contest
with the IRS will result in a reduction in cash available to pay
distributions to our unitholders and our general partner and
thus will be borne indirectly by our unitholders and our general
partner.
40
You may be required to pay taxes on your share of our
income even if you do not receive any cash distributions from
us.
You will be required to pay federal income taxes and, in some
cases, state and local income taxes on your share of our taxable
income, whether or not you receive cash distributions from us.
You may not receive cash distributions from us equal to your
share of our taxable income or even equal to the actual tax
liability that results from your share of our taxable income.
The tax gain or loss on the disposition of our common
units could be different than expected.
If you sell your common units, you will recognize gain or loss
equal to the difference between the amount realized and your tax
basis in those common units. Prior distributions to you in
excess of the total net taxable income you were allocated for a
common unit, which decreased your tax basis in that common unit,
will, in effect, become taxable income to you if the common unit
is sold at a price greater than your tax basis in that common
unit, even if the price you receive is less than your original
cost. A substantial portion of the amount realized, whether or
not representing gain, may be ordinary income to you. In
addition, if you sell your units, you may incur a tax liability
in excess of the amount of cash you receive from the sale.
Tax-exempt entities and foreign persons face unique tax
issues from owning common units that may result in adverse tax
consequences to them.
Investment in common units by tax-exempt entities, such as
individual retirement accounts (known as IRAs), regulated
investment companies (known as mutual funds), and
non-U.S. persons
raises issues unique to them. For example, virtually all of our
income allocated to organizations exempt from federal income
tax, including individual retirement accounts and other
retirement plans, will be unrelated business taxable income and
will be taxable to them. Distributions to
non-U.S. persons
will be reduced by withholding taxes at the highest applicable
effective tax rate, and
non-U.S. persons
will be required to file United States federal income tax
returns and pay tax on their share of our taxable income.
We will treat each purchaser of units as having the same
tax benefits without regard to the units purchased. The IRS may
challenge this treatment, which could adversely affect the value
of the common units.
Because we cannot match transferors and transferees of common
units, we will adopt depreciation and amortization positions
that may not conform with all aspects of existing Treasury
Regulations. A successful IRS challenge to those positions could
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
Consequences Uniformity of Units for a further
discussion of the effect of the depreciation and amortization
positions we will adopt.
The sale or exchange of 50% or more of our capital and
profits interests during any
12-month period will
result in the termination of our partnership for federal income
tax purposes.
We will be considered to have terminated for federal income tax
purposes if there is a sale or exchange of 50% or more of the
total interests in our capital and profits within a
12-month period. Our
termination would, among other things, result in the closing of
our taxable year for all unitholders and could result in a
deferral of depreciation deductions allowable in computing our
taxable income. Please read Material Tax
Consequences Disposition of Common Units
Constructive Termination for a discussion of the
consequences of our termination for federal income tax purposes.
41
You will likely be subject to state and local taxes and
return filing requirements as a result of investing in our
common units.
In addition to federal income taxes, you will likely be subject
to other taxes, such as state and local income taxes,
unincorporated business taxes and estate, inheritance, or
intangible taxes that are imposed by the various jurisdictions
in which we do business or own property. You will likely be
required to file state and local income tax returns and pay
state and local income taxes in some or all of these various
jurisdictions. Further, you may be subject to penalties for
failure to comply with those requirements. We own property and
conduct business in Kansas, Louisiana and Alabama. We may own
property or conduct business in other states or foreign
countries in the future, including Colorado and New Mexico upon
the consummation of the acquisition of the interest in Four
Corners. It is your responsibility to file all federal, state
and local tax returns. Our counsel has not rendered an opinion
on the state and local tax consequences of an investment in our
common units.
42
ACQUISITION OF INTEREST IN FOUR CORNERS
Overview of San Juan Basin
The San Juan Basin, measuring approximately
7,500 square miles, is located in southwest Colorado and
northwest New Mexico and is one of North Americas largest
natural gas fields. In 2002, the U.S. Geological Survey
estimated there were 50.6 trillion cubic feet of undiscovered
natural gas in the San Juan Basin. The U.S. Bureau of
Land Management also estimates that more than 12,500 undrilled
locations remain in the New Mexico portion of the San Juan
Basin. Lippman Consulting Inc., an independent natural gas
consultant for North America with significant experience in the
San Juan Basin, believes wellhead production of natural gas
in the San Juan Basin will remain stable at four Bcf/d for
at least the next ten years. In addition, we anticipate the
level of development in the San Juan Basin to continue at
current levels in response to approval from the states of
Colorado and New Mexico for increased drilling activity in the
basin.
Natural gas in the San Juan Basin is produced from two
reservoir types conventional and coal bed.
Conventional natural gas generally contains NGLs and
comparatively less carbon dioxide while natural gas from coal
beds, or coal bed methane, typically contains few, if any,
extractable NGLs and has a high concentration of carbon dioxide.
As a result, conventional natural gas generally requires
processing, and coal bed methane generally requires treating for
excess carbon dioxide, before the natural gas can be transported
on long-haul interstate pipelines. Five pipeline systems
transport natural gas to end markets from the San Juan
Basin, allowing producers to benefit from diversified access to
a variety of natural gas markets throughout the western United
States.
General
On April 6, 2006, we entered into a purchase and sale
agreement with our general partner and certain subsidiaries of
Williams, pursuant to which they will contribute to us a 25.1%
membership interest in Four Corners in exchange for aggregate
consideration of $360 million.
Four Corners owns:
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a 3,500-mile natural
gas gathering system in the San Juan Basin in New Mexico
and Colorado with a capacity of two Bcf/d; |
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the Ignacio natural gas processing plant in Colorado and the
Kutz and Lybrook natural gas processing plants in New Mexico,
which have a combined processing capacity of
760 MMcf/d; and |
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the Milagro and Esperanza natural gas treating plants in New
Mexico, which have a combined carbon dioxide treating capacity
of 750 MMcf/d. |
Four Corners customers are primarily natural gas producers
in the San Juan Basin. Four Corners provides its customers
with a full range of gathering, processing and treating
services. Fee-based gathering, processing and treating services
accounted for approximately 62% and 61% of Four Corners
revenue, excluding NGL sales resulting from marketing services,
for the year ended December 31, 2005 and the three months
ended March 31, 2006, respectively. The excluded NGL sales
result from marketing services we provide producers for a fee in
accordance with their contracts. These NGL sales have an
offsetting cost, which results in no margin for Four Corners on
these NGL sales. The remaining 38% and 39% of Four Corners
revenue for the year ended December 31, 2005 and the three
months ended March 31, 2006, respectively, was derived from
the sale of NGLs received by Four Corners as consideration for
processing services.
The Four Corners pipeline system gathers approximately 37% of
the natural gas produced in the San Juan Basin and connects
with the five pipeline systems that transport natural gas to end
markets from the basin. Approximately 40% of the supply
connected to the Four Corners pipeline system in the
San Juan Basin is produced from conventional reservoirs
with approximately 60% coming from coal bed reservoirs. Four
Corners is currently the only company in the basin that is the
owner and operator of both major conventional natural gas and
coal bed methane gathering, processing and treating facilities
in the San Juan Basin. Despite the
43
topographically challenging terrain, Four Corners has gathering
pipelines throughout most of the San Juan Basin.
The following map shows the locations of Four Corners
gathering lines, the Ignacio, Kutz and Lybrook natural gas
processing plants and the Milagro and Esperanza natural gas
treating plants:
Consistent with our growth strategy, our proposed acquisition of
the interest in Four Corners will allow us to expand our asset
base with an ownership position in an integrated business that
complements our existing portfolio of midstream assets. Our
interest in Four Corners will expand our customer base and
diversify our geographic footprint by providing a presence in
the San Juan Basin. We expect that this transaction will be
accretive on a per unit basis.
The closing of our acquisition of the interest in Four Corners
is subject to the satisfaction of a number of conditions,
including our ability to obtain financing, which will consist of
the net proceeds of this offering and the net proceeds from our
concurrent private placement of senior notes.
We will account for the 25.1% interest in Four Corners as an
equity investment, and therefore will not consolidate its
financial results. For the year ended December 31, 2005 and
the three months ended March 31, 2006, this 25.1% interest
in Four Corners generated Adjusted EBITDA of approximately
$38.4 million and $10.9 million, respectively, and DCF
of approximately $35.4 million and $9.5 million,
respectively. For a reconciliation of each of Adjusted EBITDA
and DCF to its most directly comparable financial measure
calculated and presented in accordance with GAAP, please read
Prospectus Summary Summary Historical and Pro
Forma Financial and Operating Data Non-GAAP
Financial Measures. Please
44
read Prospectus Summary Summary Historical and
Pro Forma Financial and Operating Data Four
Corners for information regarding Four Corners
financial and operating results.
Lehman Brothers Inc. is serving as Williams financial
advisor in connection with our acquisition of the 25.1% interest
in Four Corners. See Underwriting
Relationships.
Four Corners Management
Upon the consummation of the proposed transactions, Four Corners
will be managed by a two-member management committee consisting
of representatives of the two owners, Williams and us. The
members of the management committee will have voting power that
corresponds to the ownership interest of the owner they
represent. Except for certain significant matters that are
specified in the Four Corners limited liability company
agreement, all actions and decisions relating to Four Corners
require the approval of the management committee members
representing a majority interest. Through Williams 74.9%
ownership interest in Four Corners, it will have the ability to
control Four Corners. Four Corners is required under its limited
liability company agreement to make distributions of available
cash (generally, cash from operations less required and
discretionary reserves) at least quarterly to its owners. The
management committee, by majority approval, will determine the
amount of such distributions. Williams will operate the natural
gas gathering pipeline system in accordance with the Four
Corners limited liability company agreement.
Both members of Four Corners will be subject to reciprocal
rights of first offer under the Four Corners limited liability
company agreement. Accordingly, prior to selling all or a
portion of its respective interest in Four Corners, that member
will be required to first offer its membership interest to the
other member.
Four Corners Natural Gas Gathering System
The Four Corners natural gas gathering pipeline system consists
of:
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3,500 miles of
2-inch to
30-inch diameter
natural gas gathering pipelines with capacity of two Bcf/d and
approximately 6,400 receipt points; and |
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90 field compression units leased from Hanover Compression, Inc.
and an additional 108 compression units owned by Four Corners,
providing an aggregate of approximately 290,000 horsepower of
field compression. Approximately 85% of this field compression
is operated by Hanover Compression. |
Additionally, Four Corners owns and operates approximately
110,000 horsepower of compression at pipeline stations and
plants, giving the Four Corners gathering system an
aggregate of approximately 400,000 horsepower of total
compression deployed.
Four Corners generally charges a fee on the volume of natural
gas gathered on its pipeline system. Four Corners does not,
however, take title to the natural gas that it gathers other
than natural gas it retains for fuel and purchases for shrinkage.
Four Corners Processing and Treating Plants
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Natural Gas Processing Plants |
Four Corners owns and operates three natural gas processing
plants with a combined processing capacity of 760 MMcf/d
and combined NGL production capacity of 41,000 bpd.
The Ignacio natural gas processing plant was constructed in 1956
and is located near Durango, Colorado. Williams acquired the
plant in 1983 in connection with its acquisition of Northwest
Energy. The primary processing components of the Ignacio plant
were installed in 1984 and were subsequently upgraded and
expanded in 1999. The Ignacio plant has one cryogenic train with
55,000 horsepower of compression and processing capacity of
450 MMcf/d. The Ignacio plant has outlet connections to the
El Paso Natural Gas, Transwestern and Williams
Northwest Pipeline systems. These pipelines serve markets
throughout most of the western United States. The plant has an
NGL production capacity of 22,000 bpd. Most of the NGLs are
shipped via the MAPL pipeline system to Gulf Coast markets, but
some NGLs retained by Four Corners are
45
fractionated at Ignacio and distributed locally via trucks.
Ignacio also produces liquefied natural gas, which is
distributed via truck. The Ignacio plant is able to recover
approximately 95% of the ethane contained in the natural gas
stream and nearly all of the propane and heavier NGLs.
The Kutz and Lybrook gas processing plants, located in
Bloomfield and Lybrook, New Mexico, respectively, have a
combined processing capacity of 310 MMcf/d. These plants
have an aggregate 67,000 horsepower of compression and have
a combined NGL production capacity of 19,000 bpd. The NGLs
are shipped via the MAPL pipeline system to Gulf Coast markets,
but some liquids retained by Four Corners are fractionated at
Lybrook and distributed locally via truck. The Kutz plant has
gas outlets to the El Paso Natural Gas, PNM and
Transwestern pipeline systems. The Lybrook plant connects to the
PNM pipeline. The Kutz and Lybrook plants are able to recover
approximately 55% and 80%, respectively, of the ethane contained
in the natural gas stream.
Four Corners has a portfolio of natural gas processing
agreements that includes the following types of contracts:
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Keep-whole. Under keep-whole contracts, Four Corners (1)
processes natural gas produced by customers, (2) retains
some or all of the extracted NGLs as compensation for its
services, (3) replaces the Btu content of the retained NGLs
that were separated during processing with natural gas it
purchases, also known as shrink replacement gas, and
(4) delivers an equivalent Btu content of natural gas to
customers at the plant outlet. Four Corners, in turn, sells the
retained NGLs to a subsidiary of Williams, which serves as a
marketer for those NGLs at market prices. For the year ended
December 31, 2005 and the three months ended March 31,
2006, 38% and 36%, respectively, of Four Corners
processing volumes were under keep-whole contracts. |
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Percent-of-liquids.
Under
percent-of-liquids
processing contracts, Four Corners (1) processes natural
gas produced by customers, (2) delivers to customers an
agreed-upon percentage of the extracted NGLs, (3) retains a
portion of the extracted NGLs as compensation for its services
and (4) delivers natural gas to customers at the plant
outlet. Under this type of contract, there is no requirement for
Four Corners to replace the Btu content of the retained NGLs
that were extracted during processing. Four Corners sells the
retained NGLs to a subsidiary of Williams, which serves as a
marketer for those NGLs at market prices. For the year ended
December 31, 2005 and the three months ended March 31,
2006, 14% and 13%, respectively, of Four Corners
processing volumes were under
percent-of-liquids
contracts. |
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Fee-based. Under fee-based contracts, Four Corners
receives revenue based on the volume of natural gas processed
and the per-unit fee charged, and Four Corners retains none of
the extracted NGLs. For the year ended December 31, 2005
and the three months ended March 31, 2006, 13% and 14%,
respectively, of Four Corners processing volumes were
under fee-based contracts. |
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Fee-based and keep-whole. These contracts have both a
per-unit fee component and a keep-whole component. The relative
proportions of the fee component and the keep-whole component
vary from contract to contract, with the keep-whole component
never consisting of more than 50% of the total extracted NGLs.
For the year ended December 31, 2005 and the three months
ended March 31, 2006, 35% and 37%, respectively, of Four
Corners processing volumes were under these fee-based and
keep-whole contracts. |
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Coal bed methane sources typically contain high levels of carbon
dioxide and must be treated before it can be transported through
pipelines to end markets. Four Corners owns and operates two
natural gas treating plants, the Milagro and Esperanza plants,
with a combined carbon dioxide treating capacity of
750 MMcf/d. The Milagro treating plant can deliver natural
gas to the El Paso Natural Gas, Transwestern, Southern
Trails and PNM pipelines.
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Four Corners charges a fee for the volume of natural gas treated
at its facilities and does not take gas as payment for its
treating services, other than for the reimbursement of gas used
or lost during the treating of natural gas.
Four Corners Customers and Contracts
Three producer customers, ConocoPhillips, Burlington Resources
and BP America Production Company, accounted for
approximately 30% and 29% of Four Corners total revenues
for the year ended December 31, 2005 and the three months
ended March 31, 2006, respectively. In addition, on
March 31, 2006, ConocoPhillips acquired Burlington
Resources. No other customer accounted for over 10% of Four
Corners total revenues for the year ended
December 31, 2005 or the three months ended March 31,
2006. Additionally, a subsidiary of Williams, to which Four
Corners sells substantially all of the NGLs Four Corners retains
under its keep-whole and
percent-of-liquids
contracts, accounted for approximately 48% and 45% of Four
Corners total revenues for the year ended
December 31, 2005 and the three months ended March 31,
2006, respectively. We provide natural gas gathering, treating
and processing services to another affiliate of Williams, which
services accounted for less than 10% of Four Corners total
revenues for each of the year ended December 31, 2005 and
the three months ended March 31, 2006.
Four Corners provides its customers with a full range of
gathering, processing and treating services. These services are
usually provided to each customer under a single long-term
contract with applicable acreage dedications, reserve
dedications, or both, for the life of the contract.
Competition
The Four Corners pipeline system competes with other delivery
options available to producers in the San Juan Basin. Four
Corners generally competes with other gathering systems and
interconnecting gas processing and treating facilities, some of
which may have the same owner. The Enterprise system, comprised
of 5,500 miles of gathering lines and one processing plant,
gathers approximately 27% of the natural gas produced in the
San Juan Basin. Enterprise owns and operates primarily
conventional natural gas gathering and processing facilities in
the San Juan Basin. The Red Cedar system, consisting of
900 miles of gathering lines, is a joint venture between
the Southern Ute Indian tribe and Kinder Morgan Energy Partners.
The Red Cedar system gathers approximately 12% of the natural
gas produced in the San Juan Basin. The TEPPCO system
consists of 400 miles of gathering lines and gathers
approximately 12% of the natural gas produced in the
San Juan Basin. Red Cedar and TEPPCO own and operate
primarily coal bed methane gathering and treating facilities in
the San Juan Basin.
The Four Corners pipeline system gathers approximately 37% of
the natural gas produced in the San Juan Basin and connects
with the five pipeline systems that transport natural gas to end
markets from the San Juan Basin.
Gas Supply
All of Four Corners contracts with major customers contain
certain production dedications whereby natural gas produced from
a particular area and/or group of receipt points may only flow
to Four Corners assets for the life of the contract. Those
contracts also contain provisions requiring the connection of
newly drilled wells within dedicated areas to Four Corners. From
1999 to 2005, an average of 220 wells were connected each
year and, according to tentative customer drilling plans shared
with Williams, may grow to as many as 280 wells annually.
We anticipate that these additional well connects, together with
sustained drilling activity, other expansion opportunities and
production enhancement activities by producers, will offset
substantially the impact of normal decline in gathered and
processed volumes. Four Corners has on occasion successfully
pursued customers connected to competing gathering systems when
the customers contract with the competing gathering system
expired.
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Environmental Matters
Current federal regulations require that certain unlined liquid
containment pits located near named rivers and catchment areas
be taken out of use, and current state regulations required all
unlined, earthen pits to be either permitted or closed by
December 31, 2005. Operating under a New Mexico Oil
Conservation Division-approved workplan, Four Corners has
physically closed all of its pits that were slated for closure
under those regulations. Four Corners is presently awaiting
agency approval of the closures for 40 to 50 of those pits.
Four Corners is also a participant in environmental activities
associated with groundwater contamination at certain well sites
in New Mexico. Of nine remaining active sites, product removal
is ongoing at seven and groundwater monitoring is ongoing at
each site. As groundwater concentrations reach and sustain
closure criteria levels and state regulator approval is
received, the sites will be properly abandoned. Four Corners
expects the remaining sites will be closed within four to eight
years.
At March 31, 2006, Four Corners had accrued liabilities
totaling $603,000 for these environmental activities. It is
reasonably possible that Four Corners will incur losses in
excess of its accrual for these matters. However, a reasonable
estimate of such amounts cannot be determined at this time
because actual costs incurred will depend on the actual number
of contaminated sites identified, the amount and extent of
contamination discovered, the final cleanup standards mandated
by governmental authorities and other factors.
Four Corners is subject to extensive federal, state and local
environmental laws and regulations that affect its operations
related to the construction and operation of its facilities.
Appropriate governmental authorities may enforce these laws and
regulations with a variety of civil and criminal enforcement
measures, including monetary penalties, assessment and
remediation requirements and injunctions as to future
compliance. Four Corners has not been notified and is not
currently aware of any material noncompliance under the various
applicable environmental laws and regulations. Please read
Risk Factors Risks Inherent in Our
Business Our operations are subject to governmental
laws and regulations relating to the protection of the
environment which may expose us to significant costs and
liabilities and Business Environmental
Regulation.
Litigation
In 2001, Four Corners predecessor was named, along with
other subsidiaries of Williams, as defendants in a nationwide
class action lawsuit in Kansas state court that had been pending
against other defendants, generally pipeline and gathering
companies, since 2000. The plaintiffs alleged that the
defendants have engaged in mismeasurement techniques that
distort the heating content of natural gas, resulting in an
alleged underpayment of royalties to the class of producer
plaintiffs and sought an unspecified amount of damages. The
defendants have opposed class certification and a hearing on
plaintiffs second motion to certify the class was held on
April 1, 2005. Four Corners is awaiting a decision from the
court.
In 1998, the Department of Justice informed Williams that Jack
Grynberg, an individual, had filed claims on behalf of himself
and the federal government, in the United States District Court
for the District of Colorado under the False Claims Act against
Williams and certain of its wholly owned subsidiaries, including
Four Corners predecessor. The claims sought an unspecified
amount of royalties allegedly not paid to the federal
government, treble damages, a civil penalty, attorneys
fees, and costs. Grynberg has also filed claims against
approximately 300 other energy companies alleging that the
defendants violated the False Claims Act in connection with the
measurement, royalty valuation and purchase of hydrocarbons. In
1999, the Department of Justice announced that it was declining
to intervene in any of the Grynberg cases, including the action
filed in federal court in Colorado against Four Corners
predecessor. Also in 1999, the Panel on Multi-District
Litigation transferred all of these cases, including those filed
against Four Corners predecessor, to the federal court in
Wyoming for pre-trial purposes. Grynbergs measurement
claims remain pending
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against Four Corners predecessor and the other defendants;
the court previously dismissed Grynbergs royalty valuation
claims. In May 2005, the court-appointed special master entered
a report which recommended that the claims against certain
Williams subsidiaries, including Four Corners
predecessor, be dismissed. The District Court is considering
whether to affirm or reject the special masters
recommendations and heard oral arguments in December 2005.
Conflicts Committee Approval
The conflicts committee of the board of directors of our general
partner recommended approval of the acquisition of the interest
in Four Corners. The committee retained independent legal and
financial advisors to assist it in evaluating and negotiating
the transaction. In recommending approval of the transaction,
the committee based its decision in part on an opinion from the
committees independent financial advisor that the
consideration to be paid by us to Williams is fair, from a
financial point of view, to us and our public unitholders.
Financing
We intend to finance our acquisition of the interest in Four
Corners with:
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the net proceeds of this offering; and |
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the net proceeds from a private placement of our senior notes to
qualified institutional investors and to
non-U.S. persons
in offshore transactions. |
Concurrently with this offering, we are offering
$150 million in aggregate principal amount of senior notes
in a private placement. The senior notes are being offered only
to qualified institutional investors in reliance on
Rule 144A under the Securities Act and to
non-U.S. persons
in offshore transactions in reliance on Regulation S under
the Securities Act and initially will not be guaranteed by any
of our subsidiaries. In the future in certain instances, some or
all of our subsidiaries may be required to guarantee our senior
notes. This prospectus shall not be deemed to be an offer to
sell or a solicitation of an offer to buy any senior notes
offered in the private placement. We cannot assure you that this
private placement will be completed or, if it is completed, that
it will be completed for the amount contemplated.
This offering is conditioned upon the consummation of the
private placement of senior notes, and the private placement of
senior notes is conditioned upon the consummation of this
offering.
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USE OF PROCEEDS
We expect to receive net proceeds of approximately
$221.9 million from the sale of 6,600,000 common units
offered by this prospectus, after deducting estimated
underwriting discounts but before estimated offering expenses.
We base this amount on the public offering price of $35.10 per
common unit, the last reported sales price of our common units
on the NYSE on May 18, 2006.
We intend to use the net proceeds of this offering, together
with the net proceeds from our private placement of
$150 million of senior notes:
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to pay the aggregate consideration of $360.0 million
(approximately $355.3 million net of our general
partners capital contribution related to this offering) in
exchange for acquiring the 25.1% interest in Four Corners from
affiliates of Williams; |
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to pay approximately $5.4 million of estimated expenses
associated with this offering, our private placement of senior
notes and the acquisition of the interest in Four
Corners; and |
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for general partnership purposes. |
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Please read Acquisition of Interest in Four Corners
for information on our acquisition of the interest in Four
Corners and a description of Four Corners business.
If the underwriters exercise their option to purchase additional
units, we will use the net proceeds, together with the related
capital contribution of our general partner, for general
partnership purposes.
An increase or decrease in the public offering price by
$1.00 per common unit would cause the net proceeds from
this offering, after deducting estimated underwriting discounts
and estimated offering expenses, to increase or decrease by
approximately $6.3 million (or approximately
$7.3 million assuming full exercise of the
underwriters option to purchase additional common units).
If the public offering price were to exceed $35.10 per common
unit or if we were to increase the number of common units in
this offering, the additional proceeds, together with the
related capital contribution of our general partner, would be
used for general partnership purposes. If the net proceeds are
reduced, the amount used for general partnership purposes would
be reduced. If the net proceeds of this offering are reduced to
an amount that, together with the net proceeds from our private
placement of $150 million of senior notes, is less than the
aggregate consideration for the interest in Four Corners, we
will fund the shortfall by borrowing under Williams credit
agreement.
This offering is conditioned upon the consummation of the
private placement of senior notes, and the private placement of
senior notes is conditioned upon the consummation of this
offering.
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CAPITALIZATION
The following table shows:
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our historical capitalization as of March 31, 2006; and |
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our pro forma capitalization as of March 31, 2006, as
adjusted to reflect: |
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this common unit offering; |
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the private placement of our senior notes; |
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the application of the net proceeds of this common unit offering
and the notes offering as described under Use of
Proceeds; and |
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our acquisition of the interest in Four Corners. |
This table is derived from and should be read together with our
historical and unaudited pro forma consolidated financial
statements and the accompanying notes included elsewhere in this
prospectus. You should also read this table in conjunction with
Managements Discussion and Analysis of Financial
Condition and Results of Operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
As of March 31, 2006 | |
|
|
| |
|
|
|
|
Pro Forma | |
|
|
Actual | |
|
As Adjusted | |
|
|
| |
|
| |
|
|
($ in thousands) | |
Cash and cash equivalents
|
|
$ |
4,315 |
|
|
$ |
15,511 |
|
|
|
|
|
|
|
|
Long-term debt, including current portion:
|
|
|
|
|
|
|
|
|
|
Our borrowings under Williams credit agreement
|
|
$ |
|
|
|
$ |
|
|
|
Working capital facility with Williams
|
|
|
|
|
|
|
|
|
|
Senior Notes
|
|
|
|
|
|
|
150,000 |
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
|
|
|
|
|
150,000 |
|
|
|
|
|
|
|
|
Partners capital:
|
|
|
|
|
|
|
|
|
|
Held by public:
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
|
89,246 |
|
|
|
297,949 |
|
|
Held by the general partner and its affiliates:
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
|
19,381 |
|
|
|
30,142 |
|
|
|
Subordinated units
|
|
|
108,490 |
|
|
|
108,490 |
|
|
|
General partner interest
|
|
|
5,097 |
|
|
|
(196,862 |
) |
|
|
|
|
|
|
|
|
|
Total partners capital
|
|
|
222,214 |
|
|
|
239,719 |
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
$ |
222,214 |
|
|
$ |
389,719 |
|
|
|
|
|
|
|
|
51
PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS
As of May 15, 2006, there were 7,006,146 common units
outstanding, held by approximately 4,170 holders, including
common units held in street name and by affiliates of Williams.
Our common units are traded on the NYSE under the symbol
WPZ.
As of May 15, 2006, there were 7,000,000 subordinated units
outstanding held by four subsidiaries of Williams. The
subordinated units are not publicly traded.
The following table sets forth, for the periods indicated, the
high and low sales prices for our common units, as reported on
the NYSE Composite Transactions Tape, and quarterly cash
distributions paid to our unitholders. The last reported sales
price of common units on the New York Stock Exchange on
May 18, 2006 was $35.10 per common unit.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price Ranges | |
|
|
|
|
| |
|
Cash Distribution | |
|
|
High | |
|
Low | |
|
Per Unit (1) | |
|
|
| |
|
| |
|
| |
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Third Quarter (2)
|
|
$ |
32.75 |
|
|
$ |
24.89 |
|
|
$ |
0.1484 |
(3) |
|
Fourth Quarter
|
|
|
34.46 |
|
|
|
29.75 |
|
|
|
0.3500 |
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$ |
33.92 |
|
|
$ |
31.00 |
|
|
$ |
0.3800 |
|
|
Second Quarter (through May 19, 2006)
|
|
|
35.55 |
|
|
|
30.30 |
|
|
|
N/A |
|
|
|
|
(1) |
Represents cash distributions attributable to the quarter and
declared and paid or to be paid within 45 days after
quarter end. We paid total cash distributions to our general
partner with respect to its 2% general partner interest of
$142,400 for the period from August 23, 2005 through
December 31, 2005 and $108,571 for the period from
January 1, 2006 through March 31, 2006. |
|
|
|
(2) |
For the period from August 18, 2005 through
September 30, 2005. |
|
|
(3) |
The distribution for the third quarter of 2005 represents a
pro-rated distribution of $0.35 per common and subordinated
unit for the period from August 23, 2005, the date of the
closing of our initial public offering of common units, through
September 30, 2005. |
Distributions of Available Cash
Please read How We Make Cash Distributions for
information on our cash distribution policy.
52
SELECTED HISTORICAL AND PRO FORMA
FINANCIAL AND OPERATING DATA
The following table shows selected historical financial and
operating data of Williams Partners L.P., selected pro forma
financial data of Williams Partners L.P., selected historical
financial and operating data of Discovery Producer Services LLC
and selected historical financial and operating data for
Williams Four Corners Predecessor for the periods and as of the
dates indicated. The selected historical financial data of
Williams Partners L.P. as of December 31, 2004 and 2005 and
for the years ended December 31, 2003, 2004 and 2005 are
derived from the audited consolidated financial statements of
Williams Partners L.P. appearing elsewhere in this prospectus.
The selected historical financial data of Williams Partners L.P.
as of March 31, 2006 and for the three months ended
March 31, 2005 and 2006 are derived from the unaudited
consolidated financial statements of Williams Partners L.P.
appearing elsewhere in this prospectus. All other historical
financial data are derived from our financial records. The
results of operations for the three months ended March 31,
2006 are not necessarily indicative of the operating results for
the entire year or any future period.
The selected pro forma financial data of Williams Partners L.P.
as of March 31, 2006 and for the year ended
December 31, 2005 and three months ended March 31,
2006 are derived from the unaudited pro forma consolidated
financial statements of Williams Partners L.P. included
elsewhere in this prospectus. These pro forma consolidated
financial statements show the pro forma effect of:
|
|
|
|
|
this offering, including our use of the anticipated net proceeds; |
|
|
|
the proposed private placement of $150 million aggregate
principal amount of our senior notes to certain institutional
investors and to
non-U.S. persons
in offshore transactions, including our use of the anticipated
net proceeds of that private placement; |
|
|
|
our acquisition of a 25.1% interest in Four Corners; |
|
|
|
the forgiveness by Williams of advances to our predecessor in
connection with our initial public offering; and |
|
|
|
the payment of estimated underwriters commission and other
offering expenses. |
The selected pro forma balance sheet data assumes that the items
listed above occurred as of March 31, 2006, and the
selected pro forma income statement data assumes that the items
listed above occurred on January 1, 2005.
The selected historical financial data of Discovery Producer
Services LLC for the years ended December 31, 2003, 2004
and 2005 are derived from the audited consolidated financial
statements of Discovery Producer Services LLC appearing
elsewhere in this prospectus. The selected historical financial
data of Discovery Producer Services LLC for the three months
ended March 31, 2005 and 2006 are derived from the
unaudited consolidated financial statements of Discovery
Producer Services LLC appearing elsewhere in this prospectus.
All other historical financial data are derived from our
financial records. The results of operations from the three
months ended March 31, 2006 are not necessarily indicative
of the operating results for the entire year or any future
period.
The selected historical financial data of Williams Four Corners
Predecessor for the years ended December 31, 2003, 2004 and
2005 are derived from the audited financial statements of
Williams Four Corners Predecessor appearing elsewhere in this
prospectus. The selected historical financial data of Williams
Four Corners Predecessor for the three months ended
March 31, 2005 and 2006 are derived from the unaudited
financial statements of Williams Four Corners Predecessor
appearing elsewhere in this prospectus. All other historical
financial data are derived from our financial records. The
results of operations from the three months ended March 31,
2006 are not necessarily indicative of the operating results for
the entire year or any future period.
The following table includes Adjusted EBITDA Excluding Equity
Investments, a non-GAAP financial measure, for Williams Partners
L.P. and Adjusted EBITDA for both our interest in Discovery and
the interest in Four Corners that we expect to acquire. These
measures are presented because such information is relevant
53
and is used by management, industry analysts, investors, lenders
and rating agencies to assess the financial performance and
operating results of our fundamental business activities. Our
40% ownership interest in Discovery is not and our 25.1%
ownership interest in Four Corners will not be, consolidated in
our financial results; rather we account or will account for
them using the equity method of accounting. In order to evaluate
EBITDA for the impact of our investment of Discovery and Four
Corners on our results, we calculate Adjusted EBITDA Excluding
Equity Investments separately for Williams Partners L.P. and
Adjusted EBITDA for both our interest in Discovery and our
interest in Four Corners that we expect to acquire. We expect
distributions we receive from Discovery and Four Corners to
represent a significant portion of the cash we distribute to our
unitholders. Discoverys limited liability company
agreement provides for quarterly distributions of available cash
to its members. Four Corners limited liability company
agreement, as amended effective as of the closing of this
offering, will provide for distributions of available cash at
least quarterly to its members. Please read How We Make
Cash Distributions General
Discoverys Cash Distribution Policy and
General Four Corners Cash
Distribution Policy.
For Williams Partners L.P., we define Adjusted EBITDA Excluding
Equity Investments as net income (loss) plus interest (income)
expense, depreciation and accretion and the amortization of a
natural gas contract, less our equity earnings in Discovery and
Four Corners. We also adjust for certain non-cash, non-recurring
items.
For Discovery and Four Corners, we define Adjusted EBITDA as net
income plus interest (income) expense, depreciation,
amortization and accretion. We also adjust for certain non-cash,
non-recurring items. Our equity share of Discoverys
Adjusted EBITDA is 40%, and our equity share of Four
Corners Adjusted EBITDA will be 25.1%.
For a reconciliation of these measures to their most directly
comparable financial measure calculated and presented in
accordance with GAAP, please read Non-GAAP
Financial Measures.
We derived the information in the following table from, and that
information should be read together with, and is qualified in
its entirety by reference to, the historical and pro forma
financial statements and the accompanying notes included
elsewhere in this prospectus. The table should also be read
together with Managements Discussion and Analysis of
Financial Condition and Results of Operations.
54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners L.P.(a) | |
|
|
| |
|
|
Historical | |
|
Pro Forma | |
|
|
| |
|
| |
|
|
|
|
Three Months | |
|
|
|
|
|
|
Ended | |
|
|
|
Three Months | |
|
|
Year Ended December 31, | |
|
March 31, | |
|
Year Ended | |
|
Ended | |
|
|
| |
|
| |
|
December 31, | |
|
March 31, | |
|
|
2001 | |
|
2002 | |
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
($ in thousands, except per unit data) | |
Statement of Income Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
29,164 |
|
|
$ |
25,725 |
|
|
$ |
28,294 |
|
|
$ |
40,976 |
|
|
$ |
51,769 |
|
|
$ |
11,369 |
|
|
$ |
17,063 |
|
|
$ |
51,769 |
|
|
$ |
17,063 |
|
Costs and expenses
|
|
|
23,692 |
|
|
|
16,542 |
|
|
|
21,250 |
|
|
|
32,935 |
|
|
|
46,568 |
|
|
|
10,266 |
|
|
|
16,469 |
|
|
|
46,568 |
|
|
|
16,469 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
5,472 |
|
|
|
9,183 |
|
|
|
7,044 |
|
|
|
8,041 |
|
|
|
5,201 |
|
|
|
1,103 |
|
|
|
594 |
|
|
|
5,201 |
|
|
|
594 |
|
Equity earnings Four Corners
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
28,668 |
|
|
|
8,387 |
|
Equity earnings (loss) Discovery
|
|
|
(13,401 |
) |
|
|
2,026 |
|
|
|
3,447 |
|
|
|
4,495 |
|
|
|
8,331 |
|
|
|
2,212 |
|
|
|
3,781 |
|
|
|
8,331 |
|
|
|
3,781 |
|
Impairment of investment in Discovery
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(13,484 |
)(b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
(4,173 |
) |
|
|
(3,414 |
) |
|
|
(4,176 |
) |
|
|
(12,476 |
) |
|
|
(8,073 |
) |
|
|
(3,004 |
) |
|
|
(166 |
) |
|
|
(12,472 |
) |
|
|
(3,072 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before cumulative effect of change in accounting
principle
|
|
|
(12,102 |
) |
|
|
7,795 |
|
|
|
6,315 |
|
|
|
(13,424 |
) |
|
|
5,459 |
|
|
|
311 |
|
|
|
4,209 |
|
|
$ |
29,728 |
|
|
$ |
9,690 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of change in accounting principle
|
|
|
|
|
|
|
|
|
|
|
(1,099 |
) |
|
|
|
|
|
|
(628 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)(c)
|
|
$ |
(12,102 |
) |
|
$ |
7,795 |
|
|
$ |
5,216 |
|
|
$ |
(13,424 |
) |
|
$ |
4,831 |
|
|
$ |
311 |
|
|
$ |
4,209 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before cumulative effect of change in accounting
principle
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
0.49 |
|
|
|
|
|
|
$ |
0.35 |
|
|
$ |
1.48 |
|
|
$ |
0.49 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of change in accounting principle
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(0.05 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
0.44 |
|
|
|
|
|
|
$ |
0.35 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Data (at period end):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$ |
122,239 |
|
|
$ |
125,069 |
|
|
$ |
230,150 |
(d) |
|
$ |
219,361 |
|
|
$ |
240,941 |
|
|
$ |
220,293 |
|
|
$ |
235,528 |
|
|
|
|
|
|
$ |
403,033 |
|
Property, plant and equipment, net
|
|
|
75,269 |
|
|
|
72,062 |
|
|
|
69,695 |
|
|
|
67,793 |
|
|
|
67,931 |
|
|
|
67,146 |
|
|
|
68,239 |
|
|
|
|
|
|
|
68,239 |
|
Investment in Four Corners
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
153,309 |
|
Investment in Discovery
|
|
|
44,499 |
|
|
|
49,323 |
|
|
|
156,269 |
(d) |
|
|
147,281 |
(b) |
|
|
150,260 |
|
|
|
149,493 |
|
|
|
149,641 |
|
|
|
|
|
|
|
149,641 |
|
Advances from affiliate
|
|
|
95,535 |
|
|
|
90,996 |
|
|
|
187,193 |
(d) |
|
|
186,024 |
|
|
|
|
|
|
|
190,291 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total partners capital
|
|
|
15,236 |
|
|
|
22,914 |
|
|
|
30,092 |
|
|
|
16,668 |
|
|
|
221,655 |
|
|
|
16,979 |
|
|
|
222,214 |
|
|
|
|
|
|
|
239,719 |
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners L.P.:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA Excluding Equity Investments
|
|
$ |
8,849 |
|
|
$ |
12,758 |
|
|
$ |
10,751 |
|
|
$ |
11,727 |
|
|
$ |
10,853 |
|
|
$ |
2,008 |
|
|
$ |
2,848 |
|
|
$ |
10,853 |
|
|
$ |
2,848 |
|
|
Maintenance capital expenditures(e)
|
|
|
4,269 |
|
|
|
295 |
|
|
|
1,176 |
|
|
|
1,622 |
|
|
|
3,664 |
|
|
|
212 |
|
|
|
1,165 |
|
|
|
3,664 |
|
|
|
1,165 |
|
Four Corners our 25.1%:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
|
|
|
|
|
|
|
|
|
32,705 |
|
|
|
34,445 |
|
|
|
38,447 |
|
|
|
8,941 |
|
|
|
10,850 |
|
|
|
|
|
|
|
|
|
|
Maintenance capital expenditures(e)
|
|
|
|
|
|
|
|
|
|
|
512 |
|
|
|
286 |
|
|
|
797 |
|
|
|
638 |
|
|
|
1,312 |
|
|
|
|
|
|
|
|
|
Discovery our 40%:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
|
1,284 |
|
|
|
15,314 |
|
|
|
16,614 |
|
|
|
13,566 |
|
|
|
17,575 |
|
|
|
4,544 |
|
|
|
6,082 |
|
|
|
|
|
|
|
|
|
|
Maintenance capital expenditures(e)
|
|
|
N/A |
|
|
|
1,131 |
|
|
|
1,128 |
|
|
|
338 |
|
|
|
1,014 |
|
|
|
746 |
|
|
|
206 |
|
|
|
|
|
|
|
|
|
Operating Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners L.P.:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conway storage revenues
|
|
$ |
11,134 |
|
|
$ |
10,854 |
|
|
$ |
11,649 |
|
|
$ |
15,318 |
|
|
$ |
20,290 |
|
|
$ |
4,388 |
|
|
$ |
5,105 |
|
|
|
|
|
|
|
|
|
|
Conway fractionation volumes (bpd) our 50%
|
|
|
40,713 |
|
|
|
38,234 |
|
|
|
34,989 |
|
|
|
39,062 |
|
|
|
39,965 |
|
|
|
41,296 |
|
|
|
46,042 |
|
|
|
|
|
|
|
|
|
|
Carbonate Trend gathered volumes (MMBtu/d)
|
|
|
55,746 |
|
|
|
57,060 |
|
|
|
67,638 |
|
|
|
49,981 |
|
|
|
35,605 |
|
|
|
41,567 |
|
|
|
33,407 |
|
|
|
|
|
|
|
|
|
Four Corners 100%:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathered volumes (MMBtu/d)
|
|
|
|
|
|
|
|
|
|
|
1,577,181 |
|
|
|
1,559,940 |
|
|
|
1,521,507 |
|
|
|
1,512,489 |
|
|
|
1,511,867 |
|
|
|
|
|
|
|
|
|
|
Processed volumes (MMBtu/d)
|
|
|
|
|
|
|
|
|
|
|
900,356 |
|
|
|
900,194 |
|
|
|
863,693 |
|
|
|
857,867 |
|
|
|
868,200 |
|
|
|
|
|
|
|
|
|
|
Net liquids margin (cents/gallon)(f)
|
|
|
|
|
|
|
|
|
|
|
17 |
¢ |
|
|
29 |
¢ |
|
|
37 |
¢ |
|
|
32 |
¢ |
|
|
37 |
¢ |
|
|
|
|
|
|
|
|
Discovery 100%:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathered volumes (MMBtu/d)
|
|
|
226,820 |
|
|
|
425,388 |
|
|
|
378,745 |
|
|
|
348,142 |
|
|
|
345,098 |
|
|
|
335,727 |
|
|
|
581,788 |
|
|
|
|
|
|
|
|
|
|
Gross processing margin (¢/MMBtu)(g)
|
|
|
N/A |
|
|
|
12 |
¢ |
|
|
17 |
¢ |
|
|
17 |
¢ |
|
|
19 |
¢ |
|
|
21 |
¢ |
|
|
16 |
¢ |
|
|
|
|
|
|
|
|
55
|
|
|
(a) |
|
Williams Partners L.P. is the successor to Williams Partners
Predecessor. Results of operations and balance sheet data prior
to August 23, 2005 represent historical results of the
Williams Partners Predecessor. |
|
(b) |
|
The $13.5 million impairment of our equity investment in
Discovery in 2004 reduced the investment balance. See
Note 6 of the Notes to Consolidated Financial Statements. |
|
(c) |
|
Our operations are treated as a partnership with each member
being separately taxed on its ratable share of our taxable
income. Therefore, we have excluded income tax expense from this
financial information. |
|
(d) |
|
In December 2003, our predecessor made a $101.6 million
capital contribution to Discovery, which Discovery subsequently
used to repay maturing debt. Our predecessor funded this
contribution with an advance from Williams. |
|
(e) |
|
Please read Managements Discussion and Analysis of
Financial Condition and Results of Operations
Financial Condition and Liquidity Capital
Requirements for a definition of maintenance capital
expenditures. Information for 2001 is not available as Williams
was not the operator of Discovery. |
|
(f) |
|
Please read Managements Discussion and Analysis of
Financial Condition and Results of Operations Four
Corners How We Evaluate Four Corners Net
Liquids Margin for a discussion of net liquids margin. |
|
(g) |
|
Please read Managements Discussion and Analysis of
Financial Condition and Results of Operations How We
Evaluate Our Operations Gross Processing
Margins for a discussion of gross processing margin. Gross
processing margin information for 2001 is not available because
Williams was not the operator of Discovery. |
Non-GAAP Financial Measures
Adjusted EBITDA Excluding Equity Investments, in our case, and,
Adjusted EBITDA in Discoverys and Four Corners
cases, are used as a supplemental financial measures by
management and by external users of our financial statements,
such as investors and commercial banks, to assess:
|
|
|
|
|
the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis; |
|
|
|
the ability of our assets to generate cash sufficient to pay
interest on our indebtedness and to make distributions to our
partners; and |
|
|
|
our operating performance and return on invested capital as
compared to those of other publicly traded limited partnerships
that own energy infrastructure assets, without regard to their
financing methods and capital structure. |
Our Adjusted EBITDA Excluding Equity Investments,
Discoverys Adjusted EBITDA and Four Corners Adjusted
EBITDA should not be considered alternatives to net income,
operating income, cash flow from operating activities or any
other measure of financial performance or liquidity presented in
accordance with GAAP. Our Adjusted EBITDA Excluding Equity
Investments, Discoverys Adjusted EBITDA and Four
Corners Adjusted EBITDA exclude some, but not all, items
that affect net income and operating income, and these measures
may vary among other companies. Therefore, our Adjusted EBITDA
Excluding Equity Investments, Discoverys Adjusted EBITDA
and Four Corners Adjusted EBITDA as presented may not be
comparable to similarly titled measures of other companies.
Furthermore, while Distributable Cash Flow is a measure we use
to assess our ability to make distributions to our partners,
Distributable Cash Flow should not be viewed as indicative of
the actual amount of cash that we have available for
distributions or that we plan to distribute for a given period.
56
The following tables present a reconciliation of the non-GAAP
financial measures, our Adjusted EBITDA Excluding Equity
Investments, Discoverys Adjusted EBITDA and Four
Corners Adjusted EBITDA, to the GAAP financial measures of
net income (loss) and of net cash provided (used) by
operating activities, on a historical basis and on a pro forma
basis, as adjusted for this offering, the proposed private
placement of our senior notes, the application of the net
proceeds from each offering, our acquisition of the interest in
Four Corners, and the forgiveness of advances from affiliate to
our predecessor in connection with our initial public offering.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners L.P.(a) | |
|
|
| |
|
|
Historical | |
|
Pro Forma | |
|
|
| |
|
| |
|
|
|
|
Three Months | |
|
|
|
|
|
|
Ended | |
|
|
|
Three Months | |
|
|
Year Ended December 31, | |
|
March 31, | |
|
Year Ended | |
|
Ended | |
|
|
| |
|
| |
|
December 31, | |
|
March 31, | |
|
|
2001 | |
|
2002 | |
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
($ in thousands) | |
Williams Partners L.P.:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Non-GAAP Adjusted EBITDA Excluding
Equity Investments to GAAP Net income
(loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$ |
(12,102 |
) |
|
$ |
7,795 |
|
|
$ |
5,216 |
|
|
$ |
(13,424 |
) |
|
$ |
4,831 |
|
|
$ |
311 |
|
|
$ |
4,209 |
|
|
$ |
28,926 |
|
|
$ |
9,690 |
|
Interest expense, net of interest income
|
|
|
4,173 |
|
|
|
3,414 |
|
|
|
4,176 |
|
|
|
12,476 |
|
|
|
8,073 |
|
|
|
3,004 |
|
|
|
166 |
|
|
|
12,472 |
|
|
|
3,072 |
|
Depreciation and accretion
|
|
|
3,377 |
|
|
|
3,575 |
|
|
|
3,707 |
|
|
|
3,686 |
|
|
|
3,619 |
|
|
|
905 |
|
|
|
900 |
|
|
|
3,619 |
|
|
|
900 |
|
Amortization of natural gas purchase contract
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,033 |
|
|
|
|
|
|
|
1,354 |
|
|
|
2,033 |
|
|
|
1,354 |
|
Impairment of investment in Discovery Producer Services
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,484 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity (earnings) loss Discovery Producer
Services
|
|
|
13,401 |
|
|
|
(2,026 |
) |
|
|
(3,447 |
) |
|
|
(4,495 |
) |
|
|
(8,331 |
) |
|
|
(2,212 |
) |
|
|
(3,781 |
) |
|
|
(8,331 |
) |
|
|
(3,781 |
) |
Equity earnings Four Corners
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(28,668 |
) |
|
|
(8,387 |
) |
Cumulative effect of change in accounting principle
|
|
|
|
|
|
|
|
|
|
|
1,099 |
|
|
|
|
|
|
|
628 |
|
|
|
|
|
|
|
|
|
|
|
802 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA Excluding Equity Investments
|
|
$ |
8,849 |
|
|
$ |
12,758 |
|
|
$ |
10,751 |
|
|
$ |
11,727 |
|
|
$ |
10,853 |
|
|
$ |
2,008 |
|
|
$ |
2,848 |
|
|
$ |
10,853 |
|
|
$ |
2,848 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Non-GAAP Adjusted EBITDA Excluding
Equity Investments to GAAP Net cash provided (used)
by operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by operating activities
|
|
|
|
|
|
$ |
8,144 |
|
|
$ |
6,644 |
|
|
$ |
2,703 |
|
|
$ |
1,893 |
|
|
$ |
(4,055 |
) |
|
$ |
2,395 |
|
|
$ |
(2,506 |
) |
|
$ |
(511 |
) |
Interest expense, net of interest income
|
|
|
|
|
|
|
3,414 |
|
|
|
4,176 |
|
|
|
12,476 |
|
|
|
8,073 |
|
|
|
3,004 |
|
|
|
166 |
|
|
|
12,472 |
|
|
|
3,072 |
|
Distributed earnings from equity investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,280 |
) |
|
|
|
|
|
|
(4,400 |
) |
|
|
(1,280 |
) |
|
|
(4,400 |
) |
Changes in operating working capital:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
|
|
|
|
958 |
|
|
|
850 |
|
|
|
(261 |
) |
|
|
3,045 |
|
|
|
(678 |
) |
|
|
(996 |
) |
|
|
3,045 |
|
|
|
(996 |
) |
|
Other current assets
|
|
|
|
|
|
|
185 |
|
|
|
187 |
|
|
|
362 |
|
|
|
384 |
|
|
|
45 |
|
|
|
237 |
|
|
|
384 |
|
|
|
237 |
|
|
Accounts payable
|
|
|
|
|
|
|
(593 |
) |
|
|
274 |
|
|
|
(2,711 |
) |
|
|
(4,215 |
) |
|
|
1,495 |
|
|
|
3,028 |
|
|
|
(4,215 |
) |
|
|
3,028 |
|
|
Accrued liabilities
|
|
|
|
|
|
|
1,218 |
|
|
|
320 |
|
|
|
417 |
|
|
|
737 |
|
|
|
209 |
|
|
|
(345 |
) |
|
|
737 |
|
|
|
(345 |
) |
|
Deferred revenue
|
|
|
|
|
|
|
765 |
|
|
|
(1,108 |
) |
|
|
(775 |
) |
|
|
(247 |
) |
|
|
3,200 |
|
|
|
3,330 |
|
|
|
(247 |
) |
|
|
3,330 |
|
Other, including changes in noncurrent assets and liabilities
|
|
|
|
|
|
|
(1,333 |
) |
|
|
(592 |
) |
|
|
(484 |
) |
|
|
2,463 |
|
|
|
(1,212 |
) |
|
|
(567 |
) |
|
|
2,463 |
|
|
|
(567 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA Excluding Equity Investments
|
|
|
|
|
|
$ |
12,758 |
|
|
$ |
10,751 |
|
|
$ |
11,727 |
|
|
$ |
10,853 |
|
|
$ |
2,008 |
|
|
$ |
2,848 |
|
|
$ |
10,853 |
|
|
$ |
2,848 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Williams Partners L.P. is the successor to Williams Partners
Predecessor. Results of operations data prior to August 23,
2005 represent historical results of the Williams Partners
Predecessor. |
57
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Four Corners Predecessor | |
|
|
| |
|
|
|
|
Three Months Ended | |
|
|
Year Ended December 31, | |
|
March 31, | |
|
|
| |
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
($ in thousands) | |
Williams Four Corners Predecessor:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Non-GAAP Adjusted EBITDA to
GAAP Net income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
88,417 |
|
|
$ |
96,556 |
|
|
$ |
113,521 |
|
|
$ |
25,895 |
|
|
$ |
33,415 |
|
Depreciation and amortization
|
|
|
41,552 |
|
|
|
40,675 |
|
|
|
38,960 |
|
|
|
9,726 |
|
|
|
9,814 |
|
Cumulative effect of change in accounting principle
|
|
|
330 |
|
|
|
|
|
|
|
694 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA 100%
|
|
$ |
130,299 |
|
|
$ |
137,231 |
|
|
$ |
153,175 |
|
|
$ |
35,621 |
|
|
$ |
43,229 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA our 25.1% interest
|
|
$ |
32,705 |
|
|
$ |
34,445 |
|
|
$ |
38,447 |
|
|
$ |
8,941 |
|
|
$ |
10,850 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Non-GAAP Adjusted EBITDA to
GAAP Net cash provided by operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$ |
122,266 |
|
|
$ |
134,387 |
|
|
$ |
156,039 |
|
|
$ |
37,027 |
|
|
$ |
29,464 |
|
Provision for loss on property, plant and equipment
|
|
|
(7,598 |
) |
|
|
(7,636 |
) |
|
|
(917 |
) |
|
|
|
|
|
|
|
|
Gain (loss) on sale of property, plant and equipment
|
|
|
1,151 |
|
|
|
(1,258 |
) |
|
|
|
|
|
|
|
|
|
|
3,319 |
|
Changes in operating working capital:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
279 |
|
|
|
(1,298 |
) |
|
|
1,374 |
|
|
|
(2,463 |
) |
|
|
516 |
|
|
Prepaid expenses
|
|
|
1,530 |
|
|
|
|
|
|
|
79 |
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
|
3,266 |
|
|
|
(9,435 |
) |
|
|
(4,586 |
) |
|
|
5,758 |
|
|
|
7,724 |
|
|
Product imbalance
|
|
|
4,447 |
|
|
|
7,983 |
|
|
|
(10,073 |
) |
|
|
(4,483 |
) |
|
|
2,377 |
|
|
Accrued liabilities
|
|
|
(61 |
) |
|
|
5,047 |
|
|
|
3,271 |
|
|
|
(514 |
) |
|
|
(451 |
) |
|
Other, including changes in other noncurrent assets and
liabilities
|
|
|
5,019 |
|
|
|
9,441 |
|
|
|
7,988 |
|
|
|
296 |
|
|
|
280 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA 100%
|
|
$ |
130,299 |
|
|
$ |
137,231 |
|
|
$ |
153,175 |
|
|
$ |
35,621 |
|
|
$ |
43,229 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discovery Producer Services LLC | |
|
|
| |
|
|
|
|
Three Months Ended | |
|
|
Year Ended December 31, | |
|
March 31, | |
|
|
| |
|
| |
|
|
2001 | |
|
2002 | |
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
($ in thousands) | |
Discovery Producer Services LLC:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Non-GAAP Adjusted EBITDA to
GAAP Net income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$ |
(33,069 |
) |
|
$ |
5,498 |
|
|
$ |
8,781 |
|
|
$ |
11,670 |
|
|
$ |
20,652 |
|
|
$ |
5,531 |
|
|
$ |
9,452 |
|
Interest (income) expense, net
|
|
|
14,283 |
|
|
|
10,851 |
|
|
|
9,611 |
|
|
|
(550 |
) |
|
|
(1,685 |
) |
|
|
(284 |
) |
|
|
(626 |
) |
Depreciation and accretion
|
|
|
21,996 |
|
|
|
21,935 |
|
|
|
22,875 |
|
|
|
22,795 |
|
|
|
24,794 |
|
|
|
6,113 |
|
|
|
6,379 |
|
Cumulative effect of change in accounting principle
|
|
|
|
|
|
|
|
|
|
|
267 |
|
|
|
|
|
|
|
176 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA 100%
|
|
$ |
3,210 |
|
|
$ |
38,284 |
|
|
$ |
41,534 |
|
|
$ |
33,915 |
|
|
$ |
43,937 |
|
|
$ |
11,360 |
|
|
$ |
15,205 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA our 40% interest
|
|
$ |
1,284 |
|
|
$ |
15,314 |
|
|
$ |
16,614 |
|
|
$ |
13,566 |
|
|
$ |
17,575 |
|
|
$ |
4,544 |
|
|
$ |
6,082 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Non-GAAP Adjusted EBITDA to
GAAP Net cash provided by operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
|
|
|
$ |
19,572 |
|
|
$ |
44,025 |
|
|
$ |
35,623 |
|
|
$ |
30,814 |
|
|
$ |
7,981 |
|
|
$ |
18,515 |
|
Interest (income) expense, net
|
|
|
|
|
|
|
10,851 |
|
|
|
9,611 |
|
|
|
(550 |
) |
|
|
(1,685 |
) |
|
|
(284 |
) |
|
|
(626 |
) |
Loss on disposal of equipment
|
|
|
|
|
|
|
(1,913 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in operating working capital:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
|
|
|
|
6,008 |
|
|
|
(7,860 |
) |
|
|
1,658 |
|
|
|
35,739 |
|
|
|
4,057 |
|
|
|
(20,201 |
) |
|
Inventory
|
|
|
|
|
|
|
122 |
|
|
|
229 |
|
|
|
240 |
|
|
|
84 |
|
|
|
138 |
|
|
|
(57 |
) |
|
Other current assets
|
|
|
|
|
|
|
330 |
|
|
|
761 |
|
|
|
1 |
|
|
|
1,012 |
|
|
|
(218 |
) |
|
|
(475 |
) |
|
Accounts payable
|
|
|
|
|
|
|
7,538 |
|
|
|
1,415 |
|
|
|
(1,256 |
) |
|
|
(29,355 |
) |
|
|
713 |
|
|
|
19,153 |
|
|
Other current liabilities
|
|
|
|
|
|
|
1,163 |
|
|
|
(2,223 |
) |
|
|
668 |
|
|
|
(664 |
) |
|
|
(443 |
) |
|
|
(583 |
) |
|
Accrued liabilities
|
|
|
|
|
|
|
(5,387 |
) |
|
|
(4,424 |
) |
|
|
(2,469 |
) |
|
|
7,992 |
|
|
|
(584 |
) |
|
|
(521 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA 100%
|
|
|
|
|
|
$ |
38,284 |
|
|
$ |
41,534 |
|
|
$ |
33,915 |
|
|
$ |
43,937 |
|
|
$ |
11,360 |
|
|
$ |
15,205 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
59
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
You should read the following discussion of our financial
condition and results of operations in conjunction with our
historical consolidated financial statements and notes and our
pro forma financial statements included elsewhere in this
prospectus.
Because of the significance of our investment in Discovery,
we include separate consolidated financial statements and notes
of Discovery in this prospectus as well as an analysis of its
financial condition and results of operations presented below.
You should read this analysis in conjunction with the historical
consolidated financial statements of Discovery and the notes to
those financial statements found elsewhere in this
prospectus.
We have recently entered into an agreement to acquire a 25.1%
membership interest in Four Corners. Because of the significance
of this investment to us in the future, we include separate
financial statements and notes of Four Corners in this
prospectus as well as an analysis of its financial condition and
results of operations presented below. You should read this
analysis in conjunction with the historical financial statements
of Four Corners and the notes to those financial statements
found elsewhere in this prospectus.
General
We are a Delaware limited partnership formed in February 2005 by
Williams to own, operate and acquire a diversified portfolio of
complementary energy assets. On August 23, 2005, we
completed our initial public offering of 5,000,000 common units
at a price of $21.50 per unit. We used net proceeds from
the sale of the units totaling $100.2 million to:
|
|
|
|
|
distribute $58.8 million to affiliates of Williams, in part
to reimburse Williams for capital expenditures relating to the
assets, including a gas purchase contract, contributed to us; |
|
|
|
provide $24.4 million to make a capital contribution to
Discovery to fund an escrow account required in connection with
the Tahiti pipeline lateral expansion project; |
|
|
|
provide $12.7 million of additional working
capital; and |
|
|
|
pay $4.3 million of expenses associated with our initial
public offering and related formation transactions. |
Additionally, at the closing of our initial public offering, the
underwriters fully exercised their option to
purchase 750,000 common units at the initial public
offering price of $21.50 per unit from certain affiliates
of Williams.
We have recently executed an agreement to acquire a 25.1%
membership interest in Four Corners from subsidiaries of
Williams. Please read Acquisition of Interest in Four
Corners. Prior to the closing of our initial public
offering, our assets were held by wholly owned subsidiaries of
Williams. Upon the closing of our initial public offering, these
Williams subsidiaries transferred the assets and the
related liabilities to us. The following discussion includes the
historical period prior to the closing of our initial public
offering and analyzes the financial condition and results of
operations for our assets, excluding the interest in Four
Corners. A discussion of Four Corners financial condition
and the results of operations is presented separately.
Business Overview
We are principally engaged in the business of gathering,
transporting and processing natural gas and fractionating and
storing NGLs. For an overview of these industries, please read
Business Industry Overview. We manage
our business and analyze our results of operations on a segment
basis. Our operations are divided into two business segments:
|
|
|
|
|
Gathering and Processing. Our Gathering and Processing
segment includes (1) our 40% ownership interest in
Discovery and (2) the Carbonate Trend gathering pipeline off the
coast of Alabama. |
60
|
|
|
|
|
Discovery owns an integrated natural gas gathering and
transportation pipeline system extending from offshore in the
Gulf of Mexico to a natural gas processing facility and an NGL
fractionator in Louisiana. These assets generate revenues by
providing natural gas gathering, transporting and processing
services and integrated NGL fractionating services to customers
under a range of contractual arrangements. Although Discovery
includes fractionation operations, which would normally fall
within the NGL Services segment, it is primarily engaged in
gathering and processing and is managed as such. |
|
|
|
NGL Services. Our NGL Services segment includes three
integrated NGL storage facilities and a 50% undivided interest
in a fractionator near Conway, Kansas. These assets generate
revenues by providing stand-alone NGL fractionation and storage
services using various fee-based contractual arrangements where
we receive a fee or fees based on actual or contracted
volumetric measures. |
Executive Summary
Overall our 2005 results of operations met our expectations for
these assets, although we faced unusual operating conditions
during the last few months of 2005. Discovery and Carbonate
Trend were impacted by Hurricanes Dennis, Katrina and Rita, and
Conway saw an impact from a delay in the peak usage of retail
propane due to an unusually moderate winter. The hurricanes
created an unfavorable impact for our traditional natural gas
supplies but also provided an opportunity for Discovery to
assist other producers and processors with stranded gas by
offering available firm transportation capacity to them through
two open seasons held in October 2005. New supplies of natural
gas attributable to these open seasons resulted in increased
volumes on Discovery through the first quarter of 2006, but we
expect that these new volumes will decrease beginning in the
second quarter of 2006. For more information, please read the
discussion of these open seasons below in
Recent Events. In addition, we continue
to monitor the longer-term effects these hurricanes had on
Discoverys traditional sources of natural gas, which might
cause lower than expected gathered volumes from these sources in
2006. Conway experienced an increased demand for propane storage
services as a result of warm early-winter temperatures. Our
results were negatively impacted by unfavorable commodity price
movements on operating supply inventory we held at Conway and by
higher general and administrative costs. Our liquidity continues
to meet our expectations. We have had no borrowings under our
revolving credit facilities and have successfully met our
minimum quarterly distributions. Our capitalization and
relationship with Williams has us well-positioned to grow our
partnership through both internal projects, including
Discoverys Tahiti lateral expansion, and acquisition
transactions with Williams and other third parties.
Recent Events
In July 2005, Discovery executed an agreement with three
producers to construct an approximate
35-mile gathering
pipeline lateral to connect Discoverys existing pipeline
system to these producers production facilities for the
Tahiti prospect in the deepwater region of the Gulf of Mexico.
The Tahiti pipeline lateral expansion will have a design
capacity of approximately 200 MMcf/d, and its anticipated
completion date is May 2007 with initial production expected in
April 2008. We expect the total construction cost of the Tahiti
pipeline lateral expansion project to be approximately
$69.5 million, of which our 40% share will be approximately
$27.8 million. In September 2005, we made a
$24.4 million contribution to Discovery to cover a
substantial portion of the total expenditures attributable to
our share of these costs. We funded this contribution with
proceeds from our initial public offering. The omnibus agreement
with Williams, executed in connection with our initial public
offering, provides that Williams will reimburse us for up to
$3.4 million in additional costs once the initial escrow
funds established for this project have been exhausted.
On July 8, 2005, the Discovery and Carbonate Trend assets
were temporarily shut down in anticipation of Hurricane Dennis.
The Discovery and Carbonate Trend assets were off-line for four
and five days, respectively. We estimate the unfavorable impact
of this hurricane on our 2005 net income was approximately
$150,000 in lost revenue.
61
On August 29, 2005, Hurricane Katrina struck the Gulf Coast
area. In anticipation of this hurricane, the Discovery and
Carbonate Trend assets were temporarily shut down on
August 27, 2005. The Discovery assets were off-line for six
days and then continued to experience lower throughput rates
until being temporarily shut down for Hurricane Rita. The
Carbonate Trend assets were off-line for ten days and then
experienced a gradual return to pre-hurricane throughput rates
by September 19, 2005. On September 24, 2005,
Hurricane Rita struck the Gulf Coast area. In anticipation of
this hurricane, the Discovery assets, which were already at
reduced throughput from Hurricane Katrina, were temporarily shut
down on September 21, 2005. The Discovery assets were
off-line for seven days and then continued to experience lower
throughput rates through the end of the third quarter.
Discoverys net income was unfavorably impacted by an
approximate loss of $2.3 million in revenue and
$1.0 million in uninsured expenses. Discoverys
property insurance policy includes a $1.0 million
deductible per occurrence. We estimate the unfavorable impact of
Hurricanes Katrina and Rita on our 2005 net income was
approximately $1.5 million due primarily to the impact of
these hurricanes on Discoverys results.
In October 2005, Discovery conducted two expedited FERC open
seasons for firm transportation to provide outlets for natural
gas that was stranded following damage to third-party facilities
during hurricanes Katrina and Rita. Both of these open seasons
were for up to 250,000 MMBtu/d. The first of these included
Discoverys construction of a new receipt point at Texas
Eastern Transmission Companys, or TETCOs, Larose
compressor station in Lafourche Parish, Louisiana. The second
was via an existing interconnection to Tennessee Gas
Pipelines, or TGPs, Line 500 in Terrebonne Parish,
Louisiana. We began receiving additional incremental volumes
from these receipt points in November and December 2005 through
the first quarter of 2006. Shippers reimbursed Discovery for a
majority of the capital necessary to establish these
connections. Throughput volumes from TETCOs open season
ended on March 14, 2006, and throughput volumes from
TGPs open season have substantially decreased and may
cease soon.
On April 6, 2006, we entered into a Purchase and Sale
Agreement, or the Purchase Agreement, with Williams Energy
Services, LLC, or WES, Williams Field Services Group, LLC, or
WFSG, Williams Field Services Company, LLC, or WFSC, Williams
Partners GP LLC, our general partner, and Williams Partners
Operating LLC, our operating subsidiary, or Williams Partners
Operating. Pursuant to the Purchase Agreement, WES, WFSG, WFSC
and our general partner will contribute to us a 25.1% membership
interest in Four Corners for aggregate consideration of
$360 million. Prior to or at closing, WFSC will contribute
to Four Corners its natural gas gathering, processing and
treating assets in the San Juan Basin in New Mexico and
Colorado. The closing of the Purchase Agreement is subject to
the satisfaction of a number of conditions, including our
ability to obtain financing, which will consist of the net
proceeds of this offering and the net proceeds from our
concurrent private placement of senior notes, and the receipt of
all necessary consents.
In May 2006, Williams replaced its $1.275 billion secured
credit facility with a $1.5 billion unsecured credit
agreement. The new facility contains substantially similar terms
and covenants as the prior facility. The new credit agreement is
available for borrowings and letters of credit and will continue
to allow us to borrow up to $75 million for general
partnership purposes, including acquisitions, but only to the
extent that sufficient amounts remain unborrowed by Williams and
its other subsidiaries. Please read Financial
Condition and Liquidity Credit Facilities for
more information.
How We Evaluate Our Operations
Our management uses a variety of financial and operational
measures to analyze our segment performance, including the
performance of Discovery. These measurements include:
|
|
|
|
|
pipeline throughput volumes; |
|
|
|
gross processing margins; |
|
|
|
fractionation volumes; |
|
|
|
storage revenues; and |
|
|
|
operating and maintenance expenses. |
62
Pipeline Throughput Volumes. We view throughput volumes
on Discoverys pipeline system and our Carbonate Trend
pipeline as an important component of maximizing our
profitability. We gather and transport natural gas under
fee-based contracts. Revenue from these contracts is derived by
applying the rates stipulated to the volumes transported.
Pipeline throughput volumes from existing wells connected to our
pipelines will naturally decline over time. Accordingly, to
maintain or increase throughput levels on these pipelines and
the utilization rate of Discoverys natural gas processing
plant and fractionator, we and Discovery must continually
connect new supplies of natural gas. Our ability to maintain
existing supplies of natural gas and connect new supplies are
impacted by (1) the level of workovers or recompletions of
existing connected wells and successful drilling activity in
areas currently dedicated to our pipelines and (2) our
ability to compete for volumes from successful new wells in
other areas. We routinely monitor producer activity in the areas
served by Discovery and Carbonate Trend and pursue opportunities
to connect new wells to these pipelines.
Gross Processing Margins. We view total gross processing
margins as an important measure of Discoverys ability to
maximize the profitability of its processing operations. Gross
processing margins include revenue derived from:
|
|
|
|
|
the rates stipulated under fee-based contracts multiplied by the
actual MMBtu volumes; |
|
|
|
sales of NGL volumes received under
percent-of-liquids
contracts for Discoverys account; and |
|
|
|
sales of natural gas volumes that are in excess of operational
needs. |
The associated costs, primarily shrink replacement gas and fuel
gas, are deducted from these revenues to determine processing
gross margin. Shrink replacement gas refers to natural gas that
is required to replace the Btu content lost when NGLs are
extracted from the natural gas stream. In certain prior years,
such as 2003, we generated significant revenues from the sale of
excess natural gas volumes. However, in response to a final rule
issued by FERC in 2004, we expect that Discovery will generate
only minimal revenues from the sale of excess natural gas in the
future.
Discoverys mix of processing contract types and its
operation and contract optimization activities are determinants
in processing revenues and gross margins. Please read
Our Operations Gathering and
Processing Segment.
Fractionation Volumes. We view the volumes that we
fractionate at the Conway fractionator as an important measure
of our ability to maximize the profitability of this facility.
We provide fractionation services at Conway under fee-based
contracts. Revenue from these contracts is derived by applying
the rates stipulated to the volumes fractionated.
Storage Revenues. Our storage revenues are derived by
applying the average demand charge per barrel to the total
volume of storage capacity under contract. Given the nature of
our operations, our storage facilities have a relatively higher
degree of fixed verses variable costs. Consequently, we view
total storage revenues, rather than contracted capacity or
average pricing per barrel, as the appropriate measure of our
ability to maximize the profitability of our storage assets and
contracts. Total storage revenues include the monthly
recognition of fees received for the storage contract year and
shorter-term storage transactions.
Operating and Maintenance Expenses. Operating and
maintenance expenses are costs associated with the operations of
a specific asset. Direct labor, fuel, utilities, contract
services, materials, supplies and insurance comprise the most
significant portion of operating and maintenance expenses. Other
than fuel, these expenses generally remain relatively stable
across broad ranges of throughput volumes but can fluctuate
depending on the activities performed during a specific period.
For example, plant overhauls and turnarounds result in increased
expenses in the periods during which they are performed. We
include fuel cost in our operating and maintenance expense,
although it is generally recoverable from our customers in our
NGL Services segment. As noted above, fuel costs in our
Gathering and Processing segment are a component in assessing
our gross processing margins.
In addition to the foregoing measures, we also review our
general and administrative expenditures, substantially all of
which are incurred through Williams. In an omnibus agreement,
executed in connection with our initial public offering,
Williams agreed to provide a five-year partial credit for
general and
63
administrative expenses incurred on our behalf. The annualized
amount of this credit in 2005 was $3.9 million, which was
pro rated for the period from the closing of our initial public
offering in August 2005 through year end. The pro rated amount
totaled $1.4 million. The amount of the credit will be
$3.2 million in 2006 and will decrease by approximately
$800,000 in each subsequent year.
We record total general and administrative costs, including
those costs that are subject to the credit by Williams, as an
expense, and we record the credit as a capital contribution by
our general partner. Accordingly, our net income does not
reflect the benefit of the credit received from Williams.
However, the cost subject to this credit is allocated entirely
to our general partner. As a result, the net income allocated to
limited partners on a per-unit basis reflects the benefit of
this credit.
Our Operations
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Gathering and Processing Segment |
Our Gathering and Processing segment consists of our interest in
Discovery and our Carbonate Trend Pipeline. These assets
generate revenues by providing natural gas gathering,
transporting and processing services and NGL fractionating
services to customers under a range of contractual arrangements.
Although Discovery includes fractionation operations, which
would normally fall within the NGL Services segment, it is
primarily engaged in gathering and processing and is managed as
such. As a result, this equity investment, which can only be
presented in one segment, is considered part of the Gathering
and Processing segment. For additional information on these
activities, and the assets and activities described below,
please read Business Gathering and
Processing The Discovery Assets and
Business Gathering and Processing
The Carbonate Trend Pipeline.
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Gathering and Transportation Contracts |
We generate gathering and transportation revenues by applying
the set tariff or contracted rate to the contractually-defined
volumes of gas gathered or transported. Discoverys
mainline and its FERC-regulated laterals generate revenues
through two types of arrangements firm
transportation service and traditional interruptible
transportation service. Under the firm transportation
arrangement, producers are required to dedicate reserves for the
life of the lease, but pay no reservation fees for firm
capacity. Under the interruptible transportation arrangement, no
reserve dedication is required. Customers with firm
transportation arrangements are entitled to a higher priority of
service, in the case of a full pipeline, than customers who
contract for interruptible transportation service. Firm
transportation services represent the majority of the revenues
from Discoverys FERC-regulated business. Discovery also
offers a third type of arrangement, traditional firm service
with reservation fees, but none of Discoverys customers
currently contract for this type of transportation service.
Discoverys maximum regulated rate for mainline
transportation is scheduled to decrease in 2008. At that time,
Discovery may be required to reduce its mainline transportation
rate on all of its contracts that have rates above the new
reduced rate. This could reduce the revenues generated by
Discovery. Discovery may elect to file a rate case with FERC
seeking to alter this scheduled reduction. However, if filed, we
cannot assure you that a rate case would be successful in even
partially preventing the rate reduction. Please read Risk
Factors Risks Inherent in Our Business
Discoverys interstate tariff rates are subject to review
and possible adjustment by federal regulators, which could have
a material adverse effect on our business and operating results.
Moreover, because Discovery is a non-corporate entity, it may be
disadvantaged in calculating its cost of service for rate-making
purposes and Business FERC
Regulation.
Carbonate Trends three contracts have terms tied to the
life of the customers lease. The actual terms of these
contracts will vary depending on the productive life of the
natural gas reserves underlying these leases. However, the
per-unit gathering fee associated with two of our three
Carbonate Trend gathering contracts was negotiated on a bundled
basis that includes transportation along a segment of
Transcontinental Gas Pipe Line Company, or Transco, a wholly
owned subsidiary of Williams. The gathering fees we receive are
dependent upon whether our customer elects to utilize this
Transco capacity. If a customer elects to use the Transco
capacity, our gathering fee is determined by subtracting the
Transco tariff from the total negotiated fee and
64
generally results in a rate lower than would be realized if the
customer elects not to utilize Transcos capacity. The rate
associated with Transco capacity is based on a FERC tariff that
is subject to change. Accordingly, if the Transco rate
increases, our gathering fees will be reduced. The customers
with these bundled contracts must make an annual election to
receive this capacity. Both customers elected to use this
capacity during 2004 and only one elected to use this capacity
in 2005 and 2006.
The gathering and transportation revenues that we generate under
fee-based contracts are not directly affected by changing
commodity prices. However, to the extent a sustained decline in
commodity prices realized by our customers results in a decline
in the producers future drilling and development
activities, our revenues from these contracts could be reduced
in the long term.
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Processing and Fractionation Contracts |
Fee-based contracts. Discovery generates fee-based
fractionation revenues based on the volumes of mixed NGLs
fractionated and the per-unit fee charged, which is subject to
adjustment for changes in certain fractionation expenses,
including natural gas fuel and labor costs. Some of
Discoverys natural gas processing contracts are also
fee-based contracts under which revenues are generated based on
the volumes of natural gas processed at its natural gas
processing plant. As discussed below, Discovery also processes
natural gas under
percent-of-liquids
contracts.
The processing revenues that Discovery generates under fee-based
contracts are not directly affected by changing commodity
prices. However, to the extent a sustained decline in commodity
prices realized by our customers results in a decline in the
producers future drilling and development activities, our
revenues from these contracts could be reduced due to long-term
development declines.
Percent-of-liquids
contracts. Under
percent-of-liquids
contracts, Discovery (1) processes natural gas for
customers, (2) delivers to customers an agreed-upon
percentage of the NGLs extracted in processing and
(3) retains a portion of the extracted NGLs. Discovery
generates revenue by selling these retained NGLs to other
parties at market prices. Some of Discoverys
percent-of-liquids
contracts have a bypass option. Under this option,
customers may elect not to process, or bypass, their natural gas
on a monthly basis, in which case, Discovery retains a portion
of the customers natural gas in lieu of NGLs as a fee.
Discovery uses its retained natural gas to partially offset the
amount of natural gas Discovery must purchase in the market for
shrink replacement gas and natural gas consumed as fuel.
Discovery may choose to process natural gas that a customer has
elected to bypass, but it then must deliver natural gas with an
equivalent Btu content to the customer. Discovery would not
elect to process bypassed gas if market conditions posed the
risk of negative processing margins. Please read
Operation and Contract Optimization.
Under Discoverys
percent-of-liquids
contracts, revenues either increase or decrease as a result of a
corresponding change in the market prices of NGLs. For contracts
with a bypass option, and depending upon whether the customer
elects the bypass election, Discoverys revenues would
either increase or decrease as a result of a corresponding
change in the relative market prices of NGLs and natural gas.
Discovery is also a party to a small number of
keep-whole gas processing arrangements. Under these
arrangements, a processor retains NGLs removed from a
customers natural gas stream but must deliver gas with an
equivalent Btu content to the customer, either from the
processors inventory or through open market purchases. A
rise in natural gas prices as compared to NGL prices can cause
the processor to suffer negative margins on keep-whole
arrangements. The natural gas associated with Discoverys
keep-whole arrangements has a low NGL content. As a result, this
gas does not require processing to be shipped on downstream
pipelines. Consequently, under unfavorable market conditions,
Discovery may earn little or no margin on these arrangements,
but is not exposed to negative processing margins. Discovery
does not intend to enter into additional keep-whole arrangements
in the future that would represent a material amount of
processing volumes.
Substantially all of Discoverys gas gathering,
transportation, processing and fractionation contracts have
terms that expire at the end of the customers natural
resource lease. The actual terms of these contracts will vary
depending on life of the natural gas reserves underlying these
leases. As a result of Discoverys current
65
contract mix, Discovery takes title to approximately one-half of
the mixed NGL volumes leaving its natural gas processing plant.
A Williams subsidiary serves as a marketer for these NGLs and,
under the terms of its agreement with Discovery, purchases
substantially all of Discoverys NGLs for resale to end
users. As a result, a significant portion of Discoverys
revenues are reported as affiliate revenues even though Williams
is not a producer that supplies the Discovery pipeline system
with any volumes of natural gas. If the arrangement with the
Williams subsidiary were terminated, we believe that Discovery
could contract with a third party marketer or perform its own
marketing services.
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Operation and Contract Optimization |
Long-haul natural gas pipelines, generally interstate pipelines
that serve end markets, publish specifications for the maximum
NGL content of the natural gas that they will transport.
Normally, NGLs must be removed from the natural gas stream at a
gas processing facility in order to meet these pipeline
specifications. Please read Business Industry
Overview Midstream Industry. It is common
industry practice, however, to blend some unprocessed gas with
processed gas to the extent that the combined gas stream is
still able to meet the pipeline specifications at the point of
injection into the long-haul pipeline.
Although it is typically profitable for producers to separate
NGLs from their natural gas streams, there can be periods of
time in which the relative value of NGL market prices to natural
gas market prices may result in negative processing margins and,
as a result, lack of profit from NGL extraction. Because of this
margin risk, producers are often willing to pay for the right to
bypass the gas processing facility if the circumstances permit.
Owners of gas processing facilities may often allow producers to
bypass their facilities if they are paid a bypass
fee. The bypass fee helps to compensate the gas processing
facility for the loss of processing volumes.
Under Discoverys contracts that include a bypass option,
Discoverys customers may exercise their option to bypass
the gas processing plant. Producers with these contracts notify
Discovery of their decision to bypass prior to the beginning of
each month. For the natural gas volumes that producers have
chosen to bypass, Discovery evaluates current commodity prices
and then decides whether it will process the gas for its own
account and retain the separated NGLs for sale to third parties.
The customer pays a bypass fee regardless of whether or not
Discovery decides to process the gas for its own account.
Discoverys decision is determined by the value of the NGLs
it will separate during the month compared to the cost of the
replacement volume of natural gas it must purchase to keep the
producer whole.
By providing flexibility to both producers and gas processors,
bypass options can enhance both parties profitability.
Discovery manages its operations given its contract portfolio,
which contains a proportion of contracts with this option that
is appropriate given current and expected future commodity
market conditions.
We generate revenues by providing NGL fractionation and storage
services at our facilities near Conway, Kansas, using various
fee based contractual arrangements where we receive a fee or
fees based on actual or contracted volumetric measures.
The fee-based fractionation contracts at our Conway facility
generate revenues based on the volumes of mixed NGLs
fractionated and the per-unit fee charged. The per-unit fee is
generally subject to adjustment for changes in certain operating
expenses, including natural gas, electricity and labor costs,
which are the principal variable costs in NGL fractionation. As
a result, we are generally able to pass through increases in
those operating expenses to our customers. However, under one of
our fractionation contracts, there is a cap on the per-unit fee
and, under current natural gas market conditions, we are not
able to pass through the full amount of increases in variable
expenses to this customer. In order to mitigate the fuel price
risk with respect to our purchases of natural gas needed to
perform under this contract, upon the closing of our initial
public offering in August 2005, Williams transferred to us a
contract for the purchase of a sufficient quantity of natural
gas from a wholly owned subsidiary of Williams at a fixed price
to satisfy our fuel requirements
66
under this fractionation contract. Williams paid the full costs
associated with entering into this contract prior to assigning
the contract to us upon closing of our initial public offering.
The fair value of this gas purchase contract was recorded as an
equity contribution to us by Williams. This gas purchase
contract will terminate on December 31, 2007 to correspond
with the expected termination of the related fractionation
agreement. Pursuant to the terms of this agreement we provided
notice of termination to this customer in July 2005. If we are
unable to negotiate a new agreement with this customer upon such
termination, we believe that we could contract with other
potential customers to replace a significant portion of these
volumes.
Two contracts with remaining terms of approximately two and four
years account for most of our fractionation revenues. The
revenues we generate under fractionation contracts at our Conway
facility generally are not directly affected by changing
commodity prices. However, to the extent a sustained decline in
commodity prices received by our customers results in a decline
in their production volumes, our revenues from these contracts
could be reduced. One of our customers has the contractual
right, on a
month-to-month basis,
to deliver its mixed NGLs elsewhere. Its decision on whether to
ship its products to the Mid-Continent region or another region
depends on supply and demand in the respective regions and the
current price being paid for fractionated products in each
region.
Substantially all our storage contracts are on a firm basis,
pursuant to which our customers pay a demand charge for a
contracted volume of storage capacity, including injection and
withdrawal rights. The majority of our storage revenues are from
three contracts with remaining terms between three and
12 years. The terms of our remaining storage contracts are
typically one year or less. In addition, we also enter into
contracts for fungible product storage in increments of six
months, three months and one month.
For storage contracts of one year or less, we require our
customers to remit the full contract price at the time the
contract is signed, which reduces our overall credit risk. Most
of our contracts of one year or less are on a fixed price basis.
We base our longer-term contracts on a percentage of our
published price of storage in our Conway facilities and adjust
these prices annually.
We offer our customers four types of storage contracts: single
product fungible, two product fungible, multi-product fungible
and segregated product storage. In addition to the fees we
charge for contracted storage, we also receive fees for
overstorage. Overstorage is all barrels held in a
customers inventory in excess of that customers
contractual storage rights, calculated on a daily basis.
Because we typically contract for periods of one year or longer,
our business is less susceptible to seasonal variations.
However, spot and future NGL market prices can influence demand
for storage. When the market for propane and other NGLs is in
backwardation, the demand for storage capacity of our Conway
facilities may decrease. While this would not impact our
long-term leases of storage capacity, our customers could become
less likely to enter into short-term storage contracts.
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Operating Supply Management |
We also generate revenues by managing product imbalances at our
Conway facilities. In response to market conditions, we actively
manage the fractionation process to optimize the resulting mix
of products. Generally, this process leaves us with a surplus of
propane volumes and a deficit of ethane volumes. We sell the
surplus propane and make up the ethane deficit through
open-market purchases. We refer to these transactions as product
sales and product purchases. In addition, product imbalances may
arise due to measurement variances that occur during the routine
operation of a storage cavern. These imbalances are realized
when storage caverns are emptied. We are able to sell any excess
product volumes for our own account, but must make up product
deficits. The flexibility we enjoy as operator of the storage
facility allows us to manage the economic impact of deficit
volumes by settling deficit volumes either from our storage
inventory or through opportunistic open-market purchases.
67
Historically, we effected these product sales and purchases with
third parties. However, in December of 2004, we began to effect
these purchases and sales with a subsidiary of Williams. If this
arrangement with the Williams subsidiary were terminated, we
believe we could once again transact with third parties.
Critical Accounting Policies and Estimates
Our financial statements reflect the selection and application
of accounting policies that require management to make
significant estimates and assumptions. The selection of these
policies has been discussed with the Audit Committee of our
general partner. We believe that the following are the more
critical judgment areas in the application of our accounting
policies that currently affect our financial condition and
results of operations.
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Impairment of Long-Lived Assets and Investments |
We evaluate our long-lived assets and investments for impairment
when we believe events or changes in circumstances indicate that
we may not be able to recover the carrying value of certain
long-lived assets or that the decline in value of an investment
is other than temporary.
During 2004, an impairment review was performed of our 40%
equity investment in Discovery because of Williams planned
purchase of an additional interest in Discovery at an amount
below our current carrying value. We estimated the fair value of
our investment based on a probability-weighted analysis that
considered a range of expected future cash flows and earnings,
EBITDA multiples and the distribution yields for publicly-traded
partnerships. Based upon our analysis we concluded that our
investment in Discovery experienced an other-than-temporary
decline in value. As a result, we recorded an 8%, or
$13.5 million, impairment of this investment to its
estimated fair value at December 31, 2004. Please read
Note 6 of Notes to Consolidated Financial Statements. Our
computations were based upon judgments and assumptions in the
following areas:
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estimated future volumes and rates; |
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range of expected future cash flows; |
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potential proceeds from a sale to another publicly-traded
partnership based on an acquirers estimated distribution
and earnings impact; and |
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expected proceeds from our planned initial public offering. |
Our projections are highly sensitive to changes in the above
assumptions. The estimated values from the various scenarios
ranged from approximately $28.0 million above to
approximately $20.0 million below our estimated fair value
at December 31, 2004.
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Accounting for Asset Retirement Obligations |
We record asset retirement obligations for legal and contractual
obligations associated with the retirement of long-lived assets
that result from the acquisition, construction, development
and/or normal use of the asset in the period in which it is
incurred if a reasonable estimate of fair value can be made. At
December 31, 2005, we have an accrued asset retirement
obligation liability of $762,000 for estimated retirement costs
associated with the closure of our Conway underground storage
caverns and brine ponds in accordance with Kansas Department of
Health and Environment, or the KDHE, regulations. This estimate
is based on the assumption that the closure will occur in
50 years. If this assumption were changed to 30 years,
the recorded asset retirement obligation would increase by
approximately $2.6 million. Our estimate utilizes judgments
and assumptions regarding the costs and timing of closure.
Please read Note 7 of Notes to Consolidated Financial
Statements.
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Environmental Remediation Liabilities |
We record liabilities for estimated environmental remediation
liabilities when we assess that a loss is probable and the
amount of the loss can be reasonably estimated. At
March 31, 2006, we have an accrual for
68
estimated environmental remediation obligations of
$5.3 million. This remediation accrual is revised, and our
associated income is affected, during periods in which new or
different facts or information become known or circumstances
change that affect the previous assumptions with respect to the
likelihood or amount of loss. We base liabilities for
environmental remediation upon our assumptions and estimates
regarding what remediation work and post-remediation monitoring
will be required and the costs of those efforts, which we
develop from information obtained from outside consultants and
from discussions with the applicable governmental authorities.
As new developments occur or more information becomes available,
it is possible that our assumptions and estimates in these
matters will change. Changes in our assumptions and estimates or
outcomes different from our current assumptions and estimates
could materially affect future results of operations for any
particular quarter or annual period. During 2004, we purchased
an insurance policy covering some of our environmental
liabilities. Please read Environmental
and Note 13 of Notes to Consolidated Financial Statements
for further information.
Results of Operations
The following table and discussion is a summary of our
consolidated results of operations for the three years ended
December 31, 2005 and the three months ended
March 31, 2005 and 2006. The results of operations by
segment are discussed in further detail following this
consolidated overview discussion.
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Three Months Ended | |
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Years Ended December 31, | |
|
March 31, | |
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| |
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| |
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2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
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| |
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| |
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| |
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| |
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($ in thousands) | |
Revenues
|
|
$ |
28,294 |
|
|
$ |
40,976 |
|
|
$ |
51,769 |
|
|
$ |
11,369 |
|
|
$ |
17,063 |
|
Costs and expenses:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense
|
|
|
13,960 |
|
|
|
19,376 |
|
|
|
25,111 |
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|
|
5,728 |
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|
|
7,691 |
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|
Product cost
|
|
|
1,263 |
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|
|
6,635 |
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|
|
11,821 |
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|
|
2,735 |
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|
|
5,723 |
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|
Depreciation and accretion
|
|
|
3,707 |
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|
|
3,686 |
|
|
|
3,619 |
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|
|
905 |
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|
|
900 |
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General and administrative expense
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|
|
1,813 |
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|
|
2,613 |
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|
|
5,323 |
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|
|
706 |
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|
|
1,948 |
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Taxes other than income
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|
|
640 |
|
|
|
716 |
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|
|
700 |
|
|
|
192 |
|
|
|
207 |
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Other, net
|
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|
(133 |
) |
|
|
(91 |
) |
|
|
(6 |
) |
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|
|
|
|
|
|
|
|
|
|
|
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|
Total costs and expenses
|
|
|
21,250 |
|
|
|
32,935 |
|
|
|
46,568 |
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|
|
10,266 |
|
|
|
16,469 |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Operating income
|
|
|
7,044 |
|
|
|
8,041 |
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|
|
5,201 |
|
|
|
1,103 |
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|
|
594 |
|
Equity earnings Discovery
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|
|
3,447 |
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|
|
4,495 |
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|
|
8,331 |
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|
|
2,212 |
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|
|
3,781 |
|
Impairment of investment in Discovery
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|
|
|
|
|
(13,484 |
) |
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|
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|
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Interest expense
|
|
|
(4,176 |
) |
|
|
(12,476 |
) |
|
|
(8,238 |
) |
|
|
(3,004 |
) |
|
|
(236 |
) |
Interest income
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|
|
|
|
|
|
|
|
|
|
165 |
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|
|
|
|
|
|
70 |
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Income (loss) before cumulative effect of change in accounting
principle
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|
|
6,315 |
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|
|
(13,424 |
) |
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|
5,459 |
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|
|
311 |
|
|
|
4,209 |
|
Cumulative effect of change in accounting principle
|
|
|
(1,099 |
) |
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|
|
|
|
|
(628 |
) |
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|
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Net income (loss)
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$ |
5,216 |
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|
$ |
(13,424 |
) |
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$ |
4,831 |
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|
$ |
311 |
|
|
|
4,209 |
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|
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|
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Three Months Ended March 31, 2006 vs. Three Months Ended
March 31, 2005 |
Revenues increased $5.7 million, or 50%, due primarily to
higher revenues in our NGL Services segment reflecting higher
fractionation and storage revenues and increased product sales
volumes. These increases are discussed in detail in
Results of Operations NGL
Services.
69
Operating and maintenance expense increased $2.0 million,
or 34%, due primarily to our NGL Services segment where fuel and
power costs and the number of cavern workover projects
increased, partially offset by a decrease in product imbalance
adjustments.
Product cost increased $3.0 million, or 109%, directly
related to the increased product sales volumes discussed above.
General and administrative expense increased $1.2 million,
or 176%, due primarily to the increased costs of being a
publicly-traded partnership. These costs included
$0.4 million for audit, tax return preparation and director
fees, $0.3 million for charges allocated by Williams for
accounting, legal, and other support, and $0.3 million for
conflict committee activity associated with our proposed
acquisition of an interest in Four Corners.
Operating income decreased $0.5 million, or 46%, due
primarily to higher general and administrative expense and
higher operating and maintenance expense, partially offset by
higher fractionation and storage revenues from our NGL Services
segment.
Equity earnings from Discovery increased $1.6 million, or
71%. This increase is discussed in detail in
Results of Operations Gathering and Processing.
Interest expense decreased $2.8 million, or 92%, due to the
forgiveness of the advances from Williams to our predecessor in
conjunction with the closing of our initial public offering on
August 23, 2005, slightly offset by the commitment fees on
our $75 million borrowing capacity under Williams
credit agreement and our $20 million working capital
revolving credit facility with Williams.
|
|
|
Year Ended December 31, 2005 vs. Year Ended
December 31, 2004 |
Revenues increased $10.8 million, or 26%, due primarily to
higher revenues in our NGL Services segment reflecting increased
product sales volumes and higher storage revenues, slightly
offset by lower revenue in our Gathering and Processing segment
due to Hurricanes Katrina and Rita and the 2004 recognition of a
$950,000 settlement of a contractual volume deficiency provision.
Operating and maintenance expense increased $5.7 million,
or 30%, due primarily to larger product imbalance valuation
adjustments and higher fuel and power costs recognized by our
NGL Services segment in 2005 as compared to 2004.
Product cost increased $5.2 million, or 78%, directly
related to the increase in product sales volumes in our NGL
Services segment.
General and administrative expense increased $2.7 million,
or 104%, due primarily to the increased costs of being a
publicly traded partnership. These costs included
$1.1 million for audit fees, tax return preparation,
director fees, and registration and transfer agent fees,
$0.7 million for direct and specific charges allocated, by
Williams, for accounting, legal, and other support,
$0.6 million for business development, and
$0.3 million for other various expenses.
Operating income decreased $2.8 million, or 35%, due
primarily to higher operating and maintenance expense in our NGL
Services segment, higher general and administrative expenses and
lower revenues in our Gathering and Processing segment,
partially offset by higher storage revenues in our NGL Services
segment.
Equity earnings from Discovery increased $3.8 million. This
increase is discussed in detail below under
Results of Operations Gathering
and Processing.
The impairment of our investment in Discovery is the result of
our analysis pursuant to which we concluded that we had
experienced an other-than-temporary decline in the value of our
investment in Discovery as described above in
Critical Accounting Policies and
Estimates Impairment of Long-Lived Assets and
Investments.
Interest expense decreased $4.2 million, or 34%, due
primarily to the forgiveness of the advances from Williams to
our predecessor in conjunction with the closing of our initial
public offering on August 23, 2005.
70
The cumulative effect of change in accounting principle of
$0.6 million in 2005 relates to our December 31, 2005
adoption of Financial Accounting Standards Board Interpretation
(FIN) No. 47. Please read Note 7 of Notes
to Consolidated Financial Statements.
|
|
|
Year Ended December 31, 2004 vs. Year Ended
December 31, 2003 |
Revenues increased $12.7 million, or 45%, due mainly to
higher revenues in our NGL Services segment, reflecting higher
product sales volumes and storage rates.
Operating and maintenance expense increased $5.4 million,
or 39%, due primarily to increased costs to comply with KDHE
requirements at NGL Services Conway facilities. Product
costs increased $5.4 million, from $1.3 million, due
to the increase in product sales.
General and administrative expense increased $0.8 million,
or 44%, due primarily to an increase in allocated general and
administrative expenses from Williams reflecting increased
corporate overhead costs within the Williams organization. These
increased costs related to various corporate initiatives and
Sarbanes-Oxley Act compliance efforts within Williams.
The impairment of our investment in Discovery is the result of
our analysis pursuant to which we concluded that we had
experienced an other-than-temporary decline in the value of our
investment in Discovery as described above in
Critical Accounting Policies and
Estimates Impairment of Long-Lived Assets and
Investments.
Interest expense increased $8.3 million, from
$4.2 million, due primarily to the cash advanced by
Williams in December 2003 to fund our predecessors
$101.6 million share of a cash call by Discovery to repay
its outstanding debt.
The cumulative effect of change in accounting principle of
$1.1 million in 2003 relates to our January 1, 2003
adoption of Statement of Financial Accounting Standard, or SFAS,
No. 143, Accounting for Asset Retirement
Obligations. Please read Note 7 of Notes to
Consolidated Financial Statements.
Following the completion of the private placement of our senior
notes to partially finance the acquisition of the 25.1% interest
in Four Corners, our interest expense will increase by
approximately $11.6 million annually.
71
|
|
|
Results of Operations Gathering and
Processing |
The Gathering and Processing segment includes (1) the
Carbonate Trend gathering pipeline and (2) our 40%
ownership interest in Discovery.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months | |
|
|
|
|
Ended | |
|
|
Years Ended December 31, | |
|
March 31, | |
|
|
| |
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
($ in thousands) | |
Segment revenues
|
|
$ |
5,513 |
|
|
$ |
4,833 |
|
|
$ |
3,515 |
|
|
$ |
880 |
|
|
$ |
733 |
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense
|
|
|
379 |
|
|
|
572 |
|
|
|
714 |
|
|
|
107 |
|
|
|
242 |
|
|
Depreciation
|
|
|
1,200 |
|
|
|
1,200 |
|
|
|
1,200 |
|
|
|
300 |
|
|
|
300 |
|
|
General and administrative expense direct
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
1,579 |
|
|
|
1,772 |
|
|
|
1,916 |
|
|
|
407 |
|
|
|
544 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income
|
|
|
3,934 |
|
|
|
3,061 |
|
|
|
1,599 |
|
|
|
473 |
|
|
|
189 |
|
Equity earnings Discovery
|
|
|
3,447 |
|
|
|
4,495 |
|
|
|
8,331 |
|
|
|
2,212 |
|
|
|
3,781 |
|
Impairment of investment in Discovery
|
|
|
|
|
|
|
(13,484 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit (loss)
|
|
$ |
7,381 |
|
|
$ |
(5,928 |
) |
|
$ |
9,930 |
|
|
$ |
2,685 |
|
|
$ |
3,970 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2006 vs. Three Months Ended
March 31, 2005 |
Carbonate Trends revenues decreased $147,000, or 17%, due
primarily to a 20% decline in average daily gathered volumes
between 2006 and 2005 caused by normal reservoir depletion.
Operating and maintenance expense increased $135,000, or 126%,
due to $44,000 in increased costs for inhibitor chemicals and
internal pipeline corrosion inspection, and $91,000 related to
increased insurance costs.
Segment operating income decreased $284,000, or 60%, due
primarily to the items discussed above.
|
|
|
Year Ended December 31, 2005 vs. Year Ended
December 31, 2004 |
Carbonate Trends revenues decreased $1.3 million, or
27%, due primarily to a 29% decline in average daily gathered
volumes between 2005 and 2004 and the absence of $950,000 of
revenue resulting from the settlement of a contractual volume
deficiency payment recognized in 2004, partially offset by
$452,000 of revenue from the settlement of a contractual volume
deficiency payment recognized in 2005.
The decline in Carbonate Trends average daily gathered
volumes was caused by normal reservoir depletion, reduced
capacity experienced at a third-party onshore treating plant in
April 2005 and the temporary shutdowns for Hurricane Dennis in
July 2005 and Hurricane Katrina in August 2005. The overall
impact of this decline in gathered volumes on gathering revenue
was approximately $1.1 million. This decline in gathered
volumes was partially offset by a 11% higher average gathering
rate causing a $300,000 increase in gathering revenue. The
increase in the average gathering rate was due to a
customers annual election in 2005 under a bundled rate
provision within its contract.
Operating and maintenance expense increased $142,000, or 25%,
due to $72,000 increased costs for inhibitor chemicals and
internal pipeline corrosion inspection, and $70,000 related to
increased insurance costs. These increases were offset partially
by increased painting expense in 2004.
Segment operating income decreased $1.5 million, or 48%,
due primarily to the lower revenues discussed above.
72
|
|
|
Year Ended December 31, 2004 vs. Year Ended
December 31, 2003 |
Carbonate Trends revenues decreased $0.7 million, or
12%, due primarily to a 26% decline in gathering volumes in
2004, largely offset by the recognition in 2004 of a $950,000
settlement of a contractual volume deficiency provision.
Gathering volumes declined in 2004 due to lower production from
connected wells that was not offset by new production coming
online.
Operating and maintenance expense increased $0.2 million
due to additional costs for contractor services.
Discovery is accounted for using the equity method of
accounting. As such, our interest in Discoverys net
operating results is reflected as equity earnings in our
Consolidated Statement of Operations. Due to the significance of
Discoverys equity earnings to our results of operations,
the following discussion addresses in greater detail, the
results of operations for 100% of Discovery.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended | |
|
|
Years Ended December 31, | |
|
March 31, | |
|
|
| |
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
($ in thousands) | |
Revenues
|
|
$ |
103,178 |
|
|
$ |
99,876 |
|
|
$ |
122,745 |
|
|
$ |
27,289 |
|
|
$ |
62,120 |
|
Costs and expenses, including interest:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement
|
|
|
42,914 |
|
|
|
45,355 |
|
|
|
64,467 |
|
|
|
11,124 |
|
|
|
41,550 |
|
|
Operating and maintenance expense
|
|
|
15,829 |
|
|
|
17,854 |
|
|
|
10,165 |
|
|
|
3,993 |
|
|
|
4,822 |
|
|
General and administrative expense
|
|
|
1,400 |
|
|
|
1,424 |
|
|
|
2,053 |
|
|
|
500 |
|
|
|
690 |
|
|
Depreciation and accretion
|
|
|
22,875 |
|
|
|
22,795 |
|
|
|
24,794 |
|
|
|
6,113 |
|
|
|
6,379 |
|
|
Interest expense (income)
|
|
|
9,611 |
|
|
|
(550 |
) |
|
|
(1,685 |
) |
|
|
(284 |
) |
|
|
(626 |
) |
|
Other (income) expenses, net
|
|
|
1,501 |
|
|
|
1,328 |
|
|
|
2,123 |
|
|
|
312 |
|
|
|
(147 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses, including interest
|
|
|
94,130 |
|
|
|
88,206 |
|
|
|
101,917 |
|
|
|
21,758 |
|
|
|
52,668 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle
|
|
$ |
9,048 |
|
|
$ |
11,670 |
|
|
$ |
20,828 |
|
|
$ |
5,531 |
|
|
$ |
9,452 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners 40% interest
|
|
$ |
3,619 |
|
|
$ |
4,668 |
|
|
$ |
8,331 |
|
|
$ |
2,212 |
|
|
$ |
3,781 |
|
Capitalized interest amortization
|
|
|
(172 |
) |
|
|
(173 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings per our Consolidated Statement of Operations
|
|
$ |
3,447 |
|
|
$ |
4,495 |
|
|
$ |
8,331 |
|
|
$ |
2,212 |
|
|
$ |
3,781 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31, 2006 vs. Three Months Ended March 31,
2005
Revenues increased $34.8 million, or 128%, due primarily to
higher NGL product sales from the marketing of customers
NGLs. In addition, the Tennessee Gas Pipeline, or TGP, and Texas
Eastern Transmission Company, or TETCO, open seasons, which
began in the last quarter of 2005, accounted for
$9.9 million in revenues. Throughput volumes from
TETCOs open season ended on March 14, 2006, and
throughput volumes from TGPs open season have
substantially decreased and may cease soon. The significant
components of the revenue increase are addressed more fully
below.
|
|
|
|
|
|
Product sales increased $36.8 million for NGL sales related
to third-party processing customers elections to have
Discovery market their NGLs for a fee under an option in their
contracts. These sales were offset by higher associated product
costs of $36.8 million as discussed below. |
|
|
|
|
|
Processing and fractionation revenues increased
$5.6 million, including $6.7 million in additional
fee-based revenues related to the TGP and TETCO open seasons
discussed above and $0.8 million of increased volumes from
the Front Runner prospect, partially offset by normal reservoir
declines. |
|
73
|
|
|
|
|
Transportation revenue increased $2.1 million, including
$3.2 million in additional fee-based revenues related to
the TGP and TETCO open seasons discussed above, partially offset
by $1.0 million related to normal reservoir declines. |
Partially offsetting these increases were the following:
|
|
|
|
|
|
Product sales decreased approximately $8.5 million as a
result of 60% lower NGL sales following Hurricanes Katrina and
Rita, partially offset by a $1.8 million increase
associated with 32% higher average sales prices. |
|
|
|
|
|
Product sales also decreased $0.9 million due to the
absence of excess fuel and shrink replacement gas sales
in 2006. |
|
|
|
|
|
Gathering revenues decreased $2.1 million due primarily to
a $1.4 million deficiency payment received in the first
quarter of 2005. |
|
Product cost and shrink replacement increased
$30.4 million, from $11.1 million in 2005, due
primarily to $36.8 million of product purchase costs for
customers who elected to have Discovery market their NGLs and
$1.4 million from higher average per-unit natural gas
prices, partially offset by $6.3 million of lower costs
related to reduced processing activity in 2006.
Other operating and maintenance expense increased
$0.8 million, or 21%, due primarily to $0.6 million of
higher processing costs related to increased throughput volumes
and $0.2 million of higher property insurance costs in 2006
following the 2005 hurricanes.
General and administrative expense increased $0.2 million,
or 38%, due primarily to an increase in the management fee paid
to Williams related to Discoverys market expansion project
and additions of other facilities.
Depreciation and accretion expense increased $0.3 million,
or 4%, due primarily to the addition of market expansion assets.
Interest income increased $0.3 million due primarily to
interest earned on the restricted cash balance for the Tahiti
project.
Other (income) expense, net improved $0.5 million due
primarily to a non-cash foreign currency transaction gain from
the revaluation of restricted cash accounts denominated in
Euros. These restricted cash accounts were established from
contributions made by Discoverys members, including us,
for the construction of the Tahiti pipeline lateral expansion
project.
Net income increased $3.9 million, or 71%, due primarily to
the TGP and TETCO open seasons that contributed approximately
$8.2 million. This was largely offset by $1.1 million of
lower gross processing margins and $0.7 million of lower
gathering revenues related to lower volumes following the
hurricanes, the absence of a $1.4 million deficiency
payment received in 2005 and $1.1 million of higher
operating and maintenance and general and administrative
expenses.
Year Ended
December 31, 2005 vs. Year Ended December 31, 2004
Revenues increased $22.9 million, or 23%, due primarily to
higher NGL product sales from marketing of customers NGLs,
fractionation revenue, processing revenue and average per-unit
NGL sales prices, partially offset by lower NGL sales volumes.
The significant components of the revenue increase are addressed
more fully below:
|
|
|
|
|
Product sales increased $31.6 million for the NGL sales
related to third-party processing customers election to
have Discovery market their NGLs for a fee under an option in
their contracts. These sales were offset by higher associated
product costs of $31.6 million discussed below. |
|
|
|
Processing and fractionation revenues increased
$6.8 million including $3.9 million in additional
volumes related to the TGP and TETCO open seasons discussed
previously, $2.9 million related to an |
74
|
|
|
|
|
increase in the fractionation rate for increased natural gas
fuel cost pass through, and other increases related to new
volumes from the Front Runner prospect that came on line in the
first quarter of 2005. |
|
|
|
Gathering revenues increased $2.1 million due primarily to
a $1.4 million deficiency payment received in 2005 related
to a volume shortfall under a transportation contract,
$0.4 million related to an increase in volumes and
$0.3 million related to a 25% higher average gathering rate
associated with new volumes from the Front Runner prospect. |
Partially offsetting these increases were the following:
|
|
|
|
|
Product sales decreased $4.9 million as a result of lower
sales of excess fuel and shrink replacement gas in 2005. During
the first half of 2004, increased natural gas prices made it
more economical for Discoverys customers to bypass the
processing plant rather than process the gas, leaving Discovery
with higher levels of excess fuel and shrink replacement gas in
2004 than 2005. |
|
|
|
Product sales also decreased approximately $16.0 million as
a result of 36% lower NGL sales volumes following Hurricanes
Katrina and Rita, partially offset by a $5.0 million
increase associated with a 17% higher average sales prices. |
|
|
|
Transportation revenues decreased $0.6 million due
primarily to lower condensate transportation volumes. Higher
average natural gas transportation volumes were partially offset
by a lower average natural gas transmission rate. |
|
|
|
Other revenues declined $1.1 million due largely to lower
platform rental fees. |
Product cost and shrink replacement increased
$19.1 million, or 42%, due primarily to:
|
|
|
|
|
$31.6 million increased purchase costs for the two
processing customers who elected to have Discovery market their
NGLs; and |
|
|
|
$3.4 million resulting from higher average per-unit natural
gas prices. |
Partially offsetting these increases were the following:
|
|
|
|
|
$11.0 million lower costs related to reduced processing
activity in 2005; and |
|
|
|
$4.9 million lower cost associated with sales of excess
fuel and shrink replacement gas. |
Operating and maintenance expense decreased $7.7 million,
or 43%, due primarily to a $10.7 million credit related to
amounts previously deferred for net system gains from 2002
through 2004 that were reversed following the acceptance in 2005
of a filing with FERC, partially offset by $1.2 million
higher utility costs, $1.0 million of uninsured damages
caused by Hurricane Katrina, and $0.8 million other
miscellaneous operational costs.
General and administrative expense increased $0.6 million,
or 44%, due primarily to an increase in the management fee paid
to Williams related to Discoverys market expansion project
and additions of other facilities. For a discussion of
Discoverys recently completed market expansion project,
please read Business Gathering and
Processing The Discovery Assets
Discovery Natural Gas Pipeline System.
Depreciation and accretion expense increased $2.0 million,
or 9%, due primarily to the completion of a pipeline connection
to the Front Runner prospect in late 2004.
Interest income increased $1.1 million, due primarily to
increases in interest-bearing cash balances during early 2005
when cash flows from operations were being retained by Discovery.
Other expenses, net increased $0.8 million, or 60%, due
primarily to a non-cash foreign currency transaction loss from
the revaluation of restricted cash accounts denominated in
Euros. These restricted cash accounts were established from
contributions made by Discoverys members, including us,
for the construction of the Tahiti pipeline lateral expansion
project.
Net income increased $9.2 million, or 78%, due primarily to
the $10.7 million reversal of deferred net system gains,
$8.9 million increased revenue from gathering, processing
and fractionation services and
75
$1.1 million higher interest income, partially offset by
$3.5 million lower product sales margins, $3.0 million
higher other operating and maintenance expense,
$0.6 million higher general and administrative expense,
$2.0 million higher depreciation and accretion, and
$0.8 million of higher other expense including the foreign
currency transaction loss.
|
|
|
Year Ended December 31, 2004 vs. Year Ended
December 31, 2003 |
The $3.3 million, or 3%, decrease in revenues resulted
primarily from lower fuel and shrink replacement gas sales in
2004 and lower NGL sales volumes, partially offset by higher
average per-unit NGL sales prices. The significant components of
the revenue decrease are addressed more fully below:
|
|
|
|
|
Increasing gas prices during some months of 2003 made it more
economical for Discoverys customers to bypass the
processing plant rather than to process the gas, leaving
Discovery with higher levels of excess fuel and shrink
replacement gas in 2003 than 2004. This excess natural gas was
sold in the market in 2003, which resulted in $5.1 million
of lower revenues in 2004. |
|
|
|
Transportation volumes declined 6% due to production declines
and a temporary interruption of service because of an accidental
influx of seawater in a lateral while putting in place a subsea
connection to a wellhead. These lower volumes resulted in a
decrease in fee-based revenues, including $2.7 million from
gathering and transportation, $2.2 million from fee-based
processing and $0.2 million from fractionation, for a total
of $5.1 million. |
|
|
|
Other revenues decreased $1.5 million due to a
$0.9 million decrease in offshore platform production
handling fees related to lower natural gas production volumes
and $0.8 million received in connection with the resolution
of a condensate measurement and ownership allocation issue in
2003. |
|
|
|
NGL sales increased $8.5 million due to a 26% increase in
average sales prices, which were slightly offset by a 2%
decrease in sales volumes. |
Product cost and shrink replacement increased by
$2.4 million, or 6%, primarily due to higher average
natural gas prices. Operating and maintenance expense increased
$2.0 million, or 12%, from 2003 due primarily to
$1.2 million of costs for a routine compressor overhaul and
$1.3 million of costs to correct a non-routine temporary
interruption of service due to an accidental influx of seawater
in our offshore pipeline. These increases were partially offset
by lower miscellaneous operating expenses.
Interest expense decreased $9.6 million due to the
repayment of $253.7 million of outstanding debt in December
2003. Other expense, net decreased $0.7 million due
primarily to $0.6 million of income earned on the
short-term investing of excess cash.
Net income increased $2.6 million, or 29%, due primarily to
$9.6 million lower interest expense, $0.7 million
lower other expense, partially offset by $3.3 million lower
revenue, $2.4 million higher product cost and shrink
replacement expense and $2.0 million higher operating and
maintenance expense.
Following our acquisition of a 25.1% interest in Four Corners,
that investment would become part of the Gathering and
Processing segment. Please read Four
Corners for a discussion of the results of operations of
Four Corners.
Prior to our initial public offering, Williams incurred and paid
$965,000 of costs to assess property damage caused by Hurricane
Ivan in 2004 to the Carbonate Trend pipeline. This resulted in
an insurance receivable for Williams. Although Williams believes
these costs to be recoverable under its property damage
insurance, it has not received approval from its insurer and it
is possible that the insurer will deny some or all of this
claim. If Williams is unable to recover these costs from
insurance, we will recognize a loss for these costs as they
relate to the Carbonate Trend pipeline. This loss will be fully
allocated to our general partner.
Additionally, we currently estimate that we will incur
$3.4 million to $4.6 million of maintenance
expenditures for Carbonate Trend during 2006 and 2007 for
restoration activities related to the partial erosion
76
of the pipeline overburden caused by Hurricane Ivan in September
2004. Under an omnibus agreement, Williams agreed to reimburse
us for the cost of these restoration activities. In connection
with these restoration activities, the Carbonate Trend pipeline
may experience a temporary shut down. We estimate that such a
shut down could reduce our cash flows from operations, excluding
the maintenance expenditures, by approximately $200,000 to
$300,000.
Throughput volumes on Discoverys pipeline system and our
Carbonate Trend pipeline are an important component of
maximizing our profitability. Pipeline throughput volumes from
existing wells connected to our pipelines will naturally decline
over time. Accordingly, to maintain or increase throughput
levels on these pipelines and the utilization rate of
Discoverys natural gas plant and fractionator, we and
Discovery must continually obtain new supplies of natural gas.
|
|
|
|
|
|
In 2006, recompletions and workovers may not offset production
declines from the wells currently connected to the Carbonate
Trend pipeline. |
|
|
|
|
|
Throughput volumes for Discovery resulting from the TETCO open
season ended on March 14, 2006. Currently Discovery
continues to receive reduced throughput volumes from TGP.
Discovery is negotiating for the retention of some of this gas
on a long-term basis and will compete with several other natural
gas processing plants in the area for this business. |
|
|
|
|
|
We are beginning to see the recovery of gathered volumes from
Discoverys pre-hurricane sources. The 2005 hurricanes
caused a significant disruption in the normal operations of
Discoverys customers including critical recompletion and
drilling activity necessary to sustain and improve their
production levels. |
|
|
|
|
|
With the current oil and natural gas price environment, drilling
activity across the shelf and the deepwater of the Gulf of
Mexico has been robust. However, the limited availability of
specialized rigs necessary to drill in the deepwater areas, such
as those in and around Discoverys gathering areas, limits
the ability of producers to bring identified reserves to market
quickly. This will prolong the timeframe over which these
reserves will be developed. We expect Discovery to be successful
in competing for a portion of these new volumes. |
|
|
|
|
|
On March 31, 2006, Discovery connected a new well in ATP
Oil & Gas Corporations Gomez prospect, with initial
volumes of approximately 13,000 MMBtu/d, which ATP has
announced that it expects will increase. |
|
|
|
|
|
We anticipate a significant increase in Discoverys
property damage insurance premiums, which are due in October
2006. The expected increase is related to an overall increase in
premiums for property located in the Gulf Coast area following
the 2005 hurricanes. |
|
77
|
|
|
Results of Operations NGL Services |
The NGL Services segment includes our three NGL storage
facilities near Conway, Kansas and our undivided 50% interest in
the Conway fractionator.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months | |
|
|
Years Ended December 31, | |
|
Ended March 31, | |
|
|
| |
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
($ in thousands) | |
|
|
|
|
Segment revenues
|
|
$ |
22,781 |
|
|
$ |
36,143 |
|
|
$ |
48,254 |
|
|
$ |
10,489 |
|
|
$ |
16,330 |
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense
|
|
|
13,581 |
|
|
|
18,804 |
|
|
|
24,397 |
|
|
|
5,621 |
|
|
|
7,449 |
|
|
Product cost
|
|
|
1,263 |
|
|
|
6,635 |
|
|
|
11,821 |
|
|
|
2,735 |
|
|
|
5,723 |
|
|
Depreciation and accretion
|
|
|
2,507 |
|
|
|
2,486 |
|
|
|
2,419 |
|
|
|
605 |
|
|
|
600 |
|
|
General and administrative expense direct
|
|
|
421 |
|
|
|
535 |
|
|
|
1,068 |
|
|
|
203 |
|
|
|
301 |
|
|
Other, net
|
|
|
507 |
|
|
|
625 |
|
|
|
694 |
|
|
|
192 |
|
|
|
207 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
18,279 |
|
|
|
29,085 |
|
|
|
40,399 |
|
|
|
9,356 |
|
|
|
14,280 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$ |
4,502 |
|
|
$ |
7,058 |
|
|
$ |
7,855 |
|
|
$ |
1,133 |
|
|
$ |
2,050 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31, 2006 vs. Three months ended
March 31, 2005 |
Segment revenues increased $5.8 million, or 56%, due
primarily to higher product sales and higher fractionation and
storage revenues. The significant components of the revenue
increase are addressed more fully below:
|
|
|
|
|
|
Product sales were $3.2 million higher due primarily to the
increased sale of normal butane and propylene. The
$2.0 million increase in normal butane resulted from the
sale of product that was previously purchased for operating
supply at our storage facilities. The $1.1 million increase
in propylene sales resulted from product realized from a
standard loss allowance retained when we unload railcars. This
volume accumulated in 2004 and 2005. This increase was largely
offset by the related increase in product cost. |
|
|
|
|
|
Fractionation revenues increased $1.5 million due primarily
to a 35% increase in the average fractionation rate related to
the pass through to customers of increased fuel and power costs
and 21% higher volumes in the first three months of 2006
compared to the first three months of 2005. The increased
fractionation volumes are a result of increased customer
throughput in anticipation of a scheduled turnaround in April
2006 and the elimination of Conways backlogged product at
its storage facilities. |
|
|
|
|
|
Storage revenues increased $0.7 million due primarily to
higher average per-unit storage rates for the 2005-2006 term and
higher storage volumes from additional short-term storage leases
caused by the reduced demand for propane due to the unusually
warm temperatures in the early winter months of 2006. |
|
|
|
|
|
Other revenues increased $0.4 million due to increased
butane conversion revenue and increased terminaling revenue. |
|
78
The following table summarizes the major components of operating
and maintenance expense which are discussed in detail below.
|
|
|
|
|
|
|
|
|
|
|
|
Three Months | |
|
|
Ended March 31, | |
|
|
| |
|
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
|
($ in thousands) | |
Operating and maintenance expense:
|
|
|
|
|
|
|
|
|
|
Salaries and benefits
|
|
$ |
661 |
|
|
$ |
701 |
|
|
Outside services and other
|
|
|
1,555 |
|
|
|
3,492 |
|
|
Fuel and power
|
|
|
2,268 |
|
|
|
3,658 |
|
|
Product imbalance expense (income)
|
|
|
1,137 |
|
|
|
(402 |
) |
|
|
|
|
|
|
|
Total operating and maintenance expense
|
|
$ |
5,621 |
|
|
$ |
7,449 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outside services and other increased $1.9 million due
primarily to increased storage cavern workovers required to meet
KDHE requirements. |
|
|
|
|
|
Fuel and power costs increased $1.4 million due primarily
to: |
|
|
|
|
|
|
|
$0.5 million of higher average costs due to a 23% increase
in the price of natural gas; |
|
|
|
|
|
$0.4 million of higher average costs associated with a
long-term physical natural gas contract; and |
|
|
|
|
|
a $0.4 million increase due to a 19% increase in the
consumption of natural gas associated with higher fractionated
volumes. |
|
|
|
|
|
|
Product imbalance expense (income) had a favorable change of
$1.5 million due primarily to: |
|
|
|
|
|
|
$1.2 million of gains recognized from the management of the
fractionation process to optimize the resulting mix of products,
which typically results in surplus propane volumes and deficit
ethane volumes; and |
|
|
|
|
|
$0.8 million of lower product imbalance valuation
adjustments. |
|
Partially offsetting these increases are $0.6 million of
losses recognized as we emptied our caverns.
Product cost increased $3.0 million, or 109%, directly
related to the increased sales of surplus propylene and normal
butane volumes discussed above.
Segment profit increased $0.9 million, or 81%, due
primarily to the $2.2 million of higher storage and
fractionation revenues, $0.4 million of higher other
revenues and $0.3 million of higher product sales margins,
largely offset by $1.9 million of higher operating and
maintenance expense.
|
|
|
Year Ended December 31, 2005 vs. Year Ended
December 31, 2004 |
Segment revenues increased $12.1 million, or 34%, due
primarily to higher product sales, storage and fractionation
revenues. The significant components of the revenue increase are
addressed more fully below:
|
|
|
|
|
Product sales were $5.0 million higher due primarily to the
sale of surplus propane volumes created through our product
optimization activities. This increase was partially offset by
the related increase in product cost. |
|
|
|
Storage revenues increased $5.0 million due primarily to
higher average per-unit storage rates for 2005 and higher
storage volumes from additional short-term storage leases caused
by the reduced demand for propane due to unusually warm
temperatures in the early winter months of 2005 and an overall
increase in butane storage volumes. The published rate for
one-year storage contracts increased 67% on April 1, 2004,
primarily reflecting the pass through to customers of increased
costs to comply with KDHE regulations. The storage volumes in
the remaining quarters of 2004 initially declined due to these
higher storage rates. During 2005, the volumes returned to more
normal levels. |
79
|
|
|
|
|
Fractionation revenues increased $1.7 million due primarily
to a 17% increase in the average fractionation rate related to
the pass through to customers of increased fuel and power costs
and 4% higher volumes in 2005. |
|
|
|
Other revenues increased $0.4 million due to increased
railcar loadings in 2005. |
The following table summarizes the major components of operating
and maintenance expense that are discussed in detail below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, | |
|
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
|
| |
|
| |
|
| |
|
|
($ in thousands) | |
Operating and maintenance expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Salaries and benefits
|
|
$ |
2,762 |
|
|
$ |
2,740 |
|
|
$ |
2,773 |
|
|
Outside services and other
|
|
|
3,843 |
|
|
|
8,240 |
|
|
|
7,458 |
|
|
Fuel and power
|
|
|
7,608 |
|
|
|
8,565 |
|
|
|
12,538 |
|
|
Product imbalance expense (income)
|
|
|
(632 |
) |
|
|
(741 |
) |
|
|
1,628 |
|
|
|
|
|
|
|
|
|
|
|
Total operating and maintenance expense
|
|
$ |
13,581 |
|
|
$ |
18,804 |
|
|
$ |
24,397 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outside services and other decreased $0.8 million due to
fewer storage cavern workovers in 2005 as compared to 2004. Also
our estimated asset retirement obligation for the storage
caverns was adjusted in 2005, reducing our operating expense by
$0.5 million. |
|
|
|
Fuel and power costs increased $4.0 million due primarily
to a 33% increase in the average per-unit price for natural gas,
which we are generally able to pass through to our customers.
Fuel and power costs also include $2.0 million for the
amortization of a natural gas purchase contract contributed to
us by Williams at the closing of our initial public offering.
Please read Our Operations NGL
Services Segment Fractionation Contracts. |
|
|
|
Product imbalance expense increased $2.4 million due
primarily to $3.0 million of larger product imbalance
valuation adjustments, and $0.6 million other product
losses, partially offset by a $1.2 million increase in
product optimization gains due to a significantly higher spread
between propane and ethane prices in 2005. |
Product cost increased $5.2 million, or 78%, directly
related to increased sales of surplus propane volumes created
through our product optimization activities.
General and administrative expense direct increased
$0.5 million, or 100%, due primarily to increased
operational and technical support for these assets.
Segment profit increased $0.8 million, or 11%, due
primarily to the $6.7 million higher storage and
fractionation revenues and $0.4 million higher other
revenues for increased railcar loadings in 2005, partially
offset by $5.6 million higher operating and maintenance
expense, $0.5 million higher general and administrative
expense direct charges, and $0.2 million
decrease in product margin.
|
|
|
Year Ended December 31, 2004 vs. Year Ended
December 31, 2003 |
Revenues increased $13.4 million, or 59%, due primarily to
increased product sales and storage revenues. The significant
components of the revenue increase are addressed more fully
below:
|
|
|
|
|
Product sales were $6.9 million higher primarily due to the
sale of surplus propane volumes created through our product
optimization activities. Prior to 2003, the sale and purchase
activities and related inventory associated with product
optimization were conducted by another wholly owned subsidiary
of Williams that was sold in 2002. We made no sales of surplus
propane until 2004 as we transitioned to conducting these
activities and accumulated inventory. |
80
|
|
|
|
|
Storage revenues increased $3.7 million due to higher
average per-unit storage rates, slightly offset by lower
contracted storage volumes. The published rate for one-year
storage contracts increased 67% on April 1, 2004 and
primarily reflects the pass through of increased costs to comply
with KDHE regulations. |
|
|
|
During 2004 we began offering product upgrading services for
normal butane at our fractionator. This service contributed
$1.7 million of fee revenues in 2004. |
Product costs increased $5.4 million, from
$1.3 million, directly related to increased product sales.
Operating and maintenance expenses increased by
$5.2 million, or 38%, primarily from higher maintenance
expenses and fuel costs. The significant components are
addressed more fully below:
|
|
|
|
|
Outside services and other expenses increased $4.4 million
due to new storage cavern workover activity related to KDHE
requirements. |
|
|
|
Fuel expense increased $1.0 million due to an 18% increase
in the average price of natural gas. |
Segment profit increased $2.6 million, or 57%, due
primarily to higher storage and fractionation revenue of
$4.5 million, $1.5 million higher product sales
margins and $1.7 million higher other fee revenues,
partially offset by $5.2 million higher operating and
maintenance expense.
For the second quarter of 2006, fractionation volumes will
decrease due to scheduled maintenance activities necessary to
ensure the mechanical integrity of the fractionator. After this
maintenance is completed, we expect to average throughput of
approximately 42,000 bpd for the remainder of 2006. We also
expect to continue to produce income from the blending and
segregation of various products.
The early results of the 2006 storage season are positive.
During the first quarter of 2006, we received storage volume
nominations for the storage year beginning April 1, 2006
that would generate revenues equal to last years record
levels. There is still potential for additional short-term
storage contracts later in 2006.
We continue to have a high level of storage cavern workovers and
wellhead modifications to comply with KDHE regulatory
requirements. We expect outside service costs to continue at
high levels throughout 2006 and 2007 to ensure that we meet the
regulatory compliance requirement to complete cavern workovers
before the end of 2008. After the completion of the wellhead
modifications, maintenance expenditures should significantly
decrease. Please read Business Environmental
Regulation Kansas Department of Health and
Environment Obligations.
Four Corners
The Four Corners system gathers and processes approximately 37%
of the natural gas produced in the San Juan Basin and
connects with the five pipeline systems that transport natural
gas to end markets from the basin.
Approximately 40% of the supply connected to the Four Corners
system in the San Juan Basin is produced from conventional
reservoirs with approximately 60% coming from coal bed
reservoirs. Four Corners is currently the only company that owns
and operates both major conventional natural gas and coal bed
methane gathering, processing and treating facilities.
|
|
|
How We Evaluate Four Corners |
Our management uses a variety of financial and operational
measures to analyze Four Corners performance. These
measurements include:
|
|
|
|
|
gathering volumes; |
|
|
|
processing volumes; |
81
|
|
|
|
|
net liquids margin; and |
|
|
|
operating and maintenance expenses. |
Gathering Volumes. The gathering volumes on the Four
Corners system are an important component of maximizing Four
Corners profitability. Four Corners gathers approximately
37% of the San Juan Basins natural gas production at
approximately 6,400 receipt points under mostly fee-based
contracts.
Processing Volumes. The volumes processed at the Ignacio,
Kutz and Lybrook natural gas processing plants are an important
measure of Four Corners ability to maximize the
profitability of these facilities. Four Corners natural
gas processing plants generate revenues using the following
types of contracts:
|
|
|
|
|
|
Keep-whole. Under keep-whole contracts, Four Corners
(1) processes natural gas produced by customers,
(2) retains some or all of the extracted NGLs as
compensation for its services, (3) replaces the Btu content
of the retained NGLs that were separated during processing with
natural gas it purchases, also known as shrink replacement gas,
and (4) delivers an equivalent Btu content of natural gas
to customers at the plant outlet. Four Corners, in turn, sells
the retained NGLs to a subsidiary of Williams, which serves as a
marketer for those NGLs at market prices. For the year ended
December 31, 2005 and the three months ended March 31,
2006, 38% and 36%, respectively, of Four Corners
processing volumes were under keep-whole contracts. |
|
|
|
|
|
Percent-of-liquids.
Under
percent-of-liquids
processing contracts, Four Corners (1) processes natural
gas produced by customers, (2) delivers to customers an
agreed-upon percentage of the extracted NGLs, (3) retains a
portion of the extracted NGLs as compensation for its services
and (4) delivers natural gas to customers at the plant
outlet. Under this type of contract, there is no requirement for
Four Corners to replace the Btu content of the retained NGLs
that were extracted during processing. Four Corners sells the
retained NGLs to a subsidiary of Williams, which serves as a
marketer for those NGLs at market prices. For the year ended
December 31, 2005 and the three months ended March 31,
2006, 14% and 13%, respectively, of Four Corners
processing volumes were under
percent-of-liquids
contracts. |
|
|
|
|
|
Fee-based. Under fee-based contracts, Four Corners
receives revenue based on the volume of natural gas processed
and the per-unit fee charged, and Four Corners retains none of
the extracted NGLs. For the year ended December 31, 2005
and the three months ended March 31, 2006, 13% and 14%,
respectively, of Four Corners processing volumes were
under fee-based contracts. |
|
|
|
|
|
Fee-based and keep-whole. These contracts have both a
per-unit fee component and a keep-whole component. The relative
proportions of the fee component and the keep-whole component
vary from contract to contract, with the keep-whole component
never consisting of more than 50% of the total extracted NGLs.
For the year ended December 31, 2005 and the three months
ended March 31, 2006, 35% and 37%, respectively, of Four
Corners processing volumes were under combined these
fee-based and keep-whole contracts. |
|
Under Four Corners keep-whole and
percent-of-liquids
contracts, revenues either increase or decrease as a result of a
corresponding change in the market prices of NGLs. Four Corners
charges a fee for more than 95% of the gathering and treating
services it performs, as well as for approximately 48% of the
natural gas it processes. As a result, the majority of the
revenues generated by these services are not directly affected
by changing commodity prices. However, to the extent a sustained
decline in commodity prices realized by the customers of Four
Corners results in a decline in their future drilling and
development activities and the volumes of gas produced, Four
Corners revenues would be reduced.
Net Liquids Margin. The net liquids margin is an
important measure of Four Corners ability to maximize the
profitability of its processing operations. Liquids margin is
derived by deducting the cost of shrink replacement gas and fuel
from the revenue Four Corners receives from the sale of its
NGLs. The net liquids margin will either increase or decrease as
a result of a corresponding change in the relative market prices
of NGLs and natural gas.
82
Operating and Maintenance Expense. Operating and
maintenance expenses are costs associated with the operations of
a specific asset. Direct labor, contract services, materials,
supplies, rentals, leases and insurance comprise the most
significant portion of operating and maintenance expenses. These
expenses generally remain relatively stable across broad ranges
of throughput volumes but can fluctuate depending on the
activities performed during a specific period. For example,
plant overhauls and turnarounds result in increased expenses in
periods during which they are performed.
Product Imbalance Gains and Losses. Additionally, in the
course of providing gathering, processing and treating services
to its customers, Four Corners realizes over- and
under-deliveries of its customers products that are
reflected in operating and maintenance expense as product
imbalance gains and losses. Four Corners monitors these gains
and losses to determine whether they are within industry
standards and determine the impact of such gains and losses on
Four Corners results of operations.
Our interest in Four Corners will be accounted for using the
equity method of accounting. As such, our interest in Four
Corners net operating results will be reflected as equity
earnings in our consolidated statements of operations. Due to
the significance that Four Corners equity earnings will be
to our results of operations, the following discussion addresses
in greater detail the results of operations for 100% of the
Williams Four Corners Predecessor entity.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months | |
|
|
Years Ended December 31, | |
|
Ended March 31, | |
|
|
| |
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
($ in thousands) | |
Revenues
|
|
$ |
354,134 |
|
|
$ |
428,223 |
|
|
$ |
463,203 |
|
|
$ |
107,903 |
|
|
$ |
115,672 |
|
Costs and expenses, including interest:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost
|
|
|
91,328 |
|
|
|
146,328 |
|
|
|
165,706 |
|
|
|
36,434 |
|
|
|
38,277 |
|
|
Operating and maintenance
|
|
|
89,783 |
|
|
|
97,070 |
|
|
|
104,648 |
|
|
|
25,646 |
|
|
|
29,095 |
|
|
Depreciation and amortization
|
|
|
41,552 |
|
|
|
40,675 |
|
|
|
38,960 |
|
|
|
9,726 |
|
|
|
9,814 |
|
|
General and administrative
|
|
|
24,102 |
|
|
|
29,566 |
|
|
|
31,292 |
|
|
|
7,780 |
|
|
|
6,638 |
|
|
Taxes other than income
|
|
|
6,822 |
|
|
|
6,790 |
|
|
|
7,746 |
|
|
|
2,185 |
|
|
|
2,076 |
|
|
Other, net
|
|
|
11,800 |
|
|
|
11,238 |
|
|
|
636 |
|
|
|
237 |
|
|
|
(3,643 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
265,387 |
|
|
|
331,667 |
|
|
|
348,988 |
|
|
|
82,008 |
|
|
|
82,257 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle
|
|
|
88,747 |
|
|
|
96,556 |
|
|
|
114,215 |
|
|
|
25,895 |
|
|
|
33,415 |
|
Cumulative effect of change in accounting principle
|
|
|
(330 |
) |
|
|
|
|
|
|
(694 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
88,417 |
|
|
$ |
96,556 |
|
|
$ |
113,521 |
|
|
$ |
25,895 |
|
|
$ |
33,415 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2006 vs. Three Months Ended
March 31, 2005 |
Revenues increased $7.8 million, or 7%, due to higher
product sales and gathering and processing revenue.
Product sales revenues increased $3.1 million, or 6%, due
primarily to:
|
|
|
|
|
|
a $6.2 million increase related to a 24% increase in
average NGL sales prices realized on sales of NGLs Four Corners
received under its processing contracts; |
|
|
|
|
|
$0.9 million of higher condensate sales associated with
increased prices; and |
|
|
|
|
|
$1.5 million of higher LNG sales. |
|
83
These increases were partially offset by $3.8 million
related to a 13% decrease in NGL volumes received under Four
Corners processing contracts. In 2005, a customer
exercised an annual option to switch from a keep-whole contract
to a fee-based contract, which decreased the NGL volumes that
Four Corners retained. Additionally, product sales were
$1.7 million lower due to a decrease in the sale of liquids
on behalf of third parties. These NGL sales are made on behalf
of producers who have Four Corners market their NGLs for a fee
in accordance with their contracts. This decrease was offset by
lower associated product costs of $1.7 million discussed
below.
Fee-based gathering and processing revenues increased
$4.7 million due primarily to higher revenue from an 8%
increase in the average gathering and processing rates. The
average gathering and processing rates increased in 2006 largely
as a result of contractual escalation clauses. Most of Four
Corners gathering contracts include escalation clauses
that provide for an annual escalation based on an
inflation-sensitive index. One significant gathering agreement
is escalated based on changes in the average price of natural
gas.
Product cost, primarily shrink replacement gas, increased
$1.8 million, or 5%, due primarily to a 37% increase in the
average price of natural gas and $1.9 million related to
product cost associated with higher condensate and NGL sales.
These increases were partially offset by $3.0 million from
20% lower volumetric shrink requirements from Four Corners
keep-whole processing contracts as a result of a customer
exercising an annual option to switch from a keep-whole contract
to a fee-based contract and a $1.7 million decrease from
third party customers who elected to have Four Corners market
their NGLs.
Operating and maintenance expense increased $3.4 million,
or 13%, due primarily to $2.2 million of higher product
imbalance expense, including higher natural gas cost-related
fuel and system losses.
General and administrative expense decreased $1.1 million,
or 15%, due primarily to a decrease in allocated general and
administrative expense from Williams. Please read Note 4 of
Notes to the Williams Four Corners Predecessor Financial
Statements for information pertaining to the methodology used to
calculate these allocated general and administrative expenses.
Other expense, net improved $3.9 million due primarily to a
$3.3 million gain recognized on the sale of the LaMaquina
treating facility in the first quarter of 2006. The LaMaquina
treating facility was shut down in 2002, and impairments were
recorded in 2003 and 2004.
Net income increased $7.5 million, or 29%, due primarily to
$4.7 million of higher fee-based gathering and processing
revenues, $1.3 million from higher product sales margins
caused by increased per-unit margins on lower NGL sales volumes,
the $3.9 million improvement in other expense, and the
$1.1 million decrease in general and administrative
expense. These increases were partially offset by
$3.4 million of higher operating and maintenance expense.
|
|
|
Year Ended December 31, 2005 vs. Year Ended
December 31, 2004 |
Revenues increased $35.0 million, or 8%, due primarily to
higher product sales and gathering revenue.
Product sales revenues increased $26.4 million, or 13%, due
to:
|
|
|
|
|
a $21.5 million increase in the sale of liquids on behalf
of third parties. These NGL sales were made on behalf of
producers who have Four Corners market their NGLs for a fee in
accordance with their contracts. This increase was offset by
higher associated product costs of $21.5 million discussed
below; |
|
|
|
$21.1 million related to 21% higher average NGL sales
prices realized for the volumes Four Corners received under its
processing contracts; |
|
|
|
$3.0 million higher LNG sales; and |
|
|
|
$2.9 million higher condensate sales. |
84
These increases were partially offset by $22.1 million
related to 18% lower NGL volumes received under Four
Corners processing contracts. In 2005, a customer
exercised an annual option to switch from a keep-whole contract
to a fee-based contract, which decreased the NGL volumes that
Four Corners retained.
Fee-based gathering and processing revenues increased
$9.8 million due to $17.1 million higher revenue from
a 8% increase in the average gathering and processing rates,
partially offset by $7.3 million lower revenue from 3%
lower gathering volumes. The average gathering and processing
rates increased in 2005 largely as a result of contractual
escalation clauses. The volume decrease was driven by normal
reservoir declines, which were partially offset by new well
connects. The overall net decline is related primarily to the
slightly steeper decline rate associated with coal bed methane
production. Four Corners has historically offset substantially
the impact of production declines with new well connects.
Products cost, primarily shrink replacement gas, increased
$19.4 million, or 13%, due primarily to the
$21.5 million increase from third party customers who
elected to have Four Corners market their NGLs and
$15.1 million from a 30% increase in the average price of
natural gas, partially offset by $17.2 million from 26%
lower volumetric shrink requirements from Four Corners
keep-whole processing contracts resulting from a customer
exercising an annual option to switch from a keep-whole contract
to a fee-based contract.
Operating and maintenance expense increased $7.6 million,
or 8%, due primarily to:
|
|
|
|
|
|
$5.1 million higher materials and supplies and outside
services expense related to increased repair and maintenance
activity; |
|
|
|
|
|
$1.8 million of higher compressor costs from
inflation-indexed escalation clauses in operating and
maintenance agreements and additional rental units; and |
|
|
|
|
|
$2.7 million of higher natural gas cost related to fuel and
system gains and losses. |
|
These increases were partially offset by $2.0 million of
other various operating and maintenance expense decreases.
Depreciation and amortization expense decreased
$1.7 million, or 4%, due primarily to the absence of
depreciation on assets that were fully depreciated in 2004.
General and administrative expense increased $1.7 million,
or 6%, due primarily to an increase in allocated general and
administrative expense from Williams.
Taxes other than income increased $0.9 million, or 14%, due
primarily to increased processing taxes. The State of New
Mexicos average processing tax rate increased 39% between
2004 and 2005. Some, but not all, of Four Corners
contracts allow Four Corners to recoup these taxes.
Other expense decreased $10.6 million, from
$11.2 million in 2004, due primarily to the following 2004
charges that were not present in 2005:
|
|
|
|
|
$7.6 million impairment charge for the LaMaquina treating
facility in 2004. The LaMaquina treating facility shut down in
2002 and was sold in the first quarter of 2006. Please read
Note 5 of Notes to the Williams Four Corners Predecessor
Financial Statements for information pertaining to this
impairment; |
|
|
|
$1.2 million loss on asset dispositions; and |
|
|
|
$1.0 million for materials and supplies inventory
adjustments. |
The cumulative effect of change in accounting principle of
$0.7 million in 2005 related to Four Corners
December 31, 2005 adoption of FIN No. 47. Please
read Note 6 of Notes to the Williams Four Corners
Predecessor Financial Statements.
Net income increased $17.0 million, or 18%, due primarily
to higher gathering and processing revenues of $6.5 million
and $3.3 million, respectively, $7.0 million in higher
product sales margins on lower NGL sales volumes and lower other
expenses of $10.6 million, partially offset by
$7.6 million in higher operating and maintenance expenses
and $1.7 million higher general and administrative expenses.
85
|
|
|
Year Ended December 31, 2004 vs. Year Ended
December 31, 2003 |
Revenues increased $74.1 million, or 21%, due primarily to
higher product sales, partially offset by lower gathering and
processing revenues.
Product sales revenues increased $80.5 million, or 65%, due
to:
|
|
|
|
|
a $41.8 million increase in the sale of NGLs on behalf of
third parties. These NGL sales were made on behalf of producers
who have Four Corners market their NGLs for a fee in accordance
with their contracts. This increase was offset by higher
associated product costs of $41.8 million discussed below; |
|
|
|
$28.5 million related to 29% higher average NGL sales
prices realized for the volumes Four Corners received under its
processing contracts; |
|
|
|
$4.9 million related to 5% higher NGL volumes received
under Four Corners processing contracts; |
|
|
|
$4.0 million higher LNG sales; and |
|
|
|
$1.3 million higher condensate sales. |
Gathering and processing revenues decreased $5.9 million
due to $5.0 million lower revenue from a 2% decrease in the
average gathering and processing rates and $0.9 million
lower revenue from a 3% decrease in average gathered and
processed volumes. The decrease in the average rate in 2004 was
largely the result of a major new contract with a lower contract
rate, partially offset by other contractual escalation clauses.
Product cost, primarily shrink replacement gas, increased
$55.0 million, or 60%, due primarily to a
$41.8 million increase from third party customers who
elected to have Four Corners market their NGLs,
$10.2 million from an 18% increase in the average price of
natural gas and $4.5 million related to increased LNG and
condensate sales.
Operating and maintenance expense increased $7.3 million,
or 8%, due primarily to:
|
|
|
|
|
$4.4 million higher materials and supplies and outside
services expense related to increased repair and maintenance
activity; and |
|
|
|
$2.7 million higher natural gas cost related to fuel and
system gains and losses. |
Depreciation and amortization expense decreased
$0.9 million, or 2%, due primarily to the absence of
depreciation on assets that were fully depreciated in 2003.
General and administrative expense increased $5.5 million,
or 23%, due primarily to an increase in allocated general and
administrative expense from Williams reflecting increased
corporate overhead costs within the Williams organization. These
increased costs related to various corporate initiatives and
Sarbanes-Oxley Act compliance efforts within Williams.
Other expense, net in 2004 includes:
|
|
|
|
|
$7.6 million impairment charge for the LaMaquina treating
facility; |
|
|
|
$1.2 million loss on asset dispositions; and |
|
|
|
$1.0 million of materials and supplies inventory
adjustments. |
Other expense, net in 2003 includes:
|
|
|
|
|
$4.1 million impairment charge for the LaMaquina treating
facility; |
|
|
|
$3.5 million of other asset impairment; and |
|
|
|
$4.2 million of contractual settlement accruals. |
Please read Note 5 of Notes to the Williams Four Corners
Predecessor Financial Statements for information pertaining to
the asset impairments.
86
In 2003, the cumulative effect of change in accounting principle
of $0.3 million related to Four Corners
January 1, 2003 adoption of SFAS No. 143,
Accounting for Asset Retirement Obligations. Please
read Note 6 of Notes to the Williams Four Corners
Predecessor Financial Statements.
Net income increased $8.1 million, or 9%, due primarily to
a $25.5 million higher average product sales margins on
higher average NGL volumes, partially offset by lower gathering
revenue of $4.5 million, higher operating and maintenance
expense of $7.3 million and higher general and
administrative expense of $5.5 million.
|
|
|
|
|
We anticipate that sustained drilling activity, expansion
opportunities and production enhancement activities by producers
should be sufficient to substantially offset the historical
decline in gathered and processed volumes. |
|
|
|
|
Four Corners has realized above average margins at its gas
processing plants in recent years, despite volatile natural gas
and crude oil markets. We expect unit margins in 2006 will
remain strong in relation to historical averages. Additionally,
we anticipate that Four Corners contract mix and commodity
management activities will continue to allow it to realize
greater margins relative to industry averages. |
|
|
|
|
We anticipate that operating costs, excluding compression, will
increase slightly in 2006. Compression cost increases are
dependent upon the extent and amount of additional compression
needed to meet the needs of Four Corners customers. |
|
|
|
Four Corners has not planned any major capital projects for
2006. We estimate that capital expenditures will be
approximately $26.2 million for 2006 primarily for well
connections and maintenance. We expect Four Corners will fund
these capital expenditures with cash generated from operations
and capital contributions from its members. |
|
|
|
We anticipate that the natural gas fuel cost associated with the
operation of the Milagro treating plant will increase due to the
expiration, in October 2006, of a below-market natural gas
purchase contract with Williams. Please read Note 4 of
Notes to the Williams Four Corners Predecessor Financial
Statements for information pertaining to this contract. |
Financial Condition and Liquidity
Prior to our initial public offering in August 2005, our sources
of liquidity included cash generated from operations and funding
from Williams. Our cash receipts were deposited in
Williams bank accounts and all cash disbursements were
made from these accounts. Thus, historically our financial
statements have reflected no cash balances. Cash transactions
handled by Williams for us were reflected in intercompany
advances between Williams and us. Following our initial public
offering, we maintain our own bank accounts but continue to
utilize Williams personnel to manage our cash and
investments.
We believe we have, or have access, to the financial resources
and liquidity necessary to meet future requirements for working
capital, capital and investment expenditures, and quarterly cash
distributions. We anticipate our 2006 sources of liquidity will
include:
|
|
|
|
|
the issuance of common units contemplated by this offering; |
|
|
|
|
the issuance of senior notes in a private placement concurrently
with this offering; |
|
|
|
|
cash generated from operations; |
|
|
|
cash distributions from Discovery; |
|
|
|
cash distributions from Four Corners following our planned
acquisition of the 25.1% interest; |
87
|
|
|
|
|
capital contributions from Williams pursuant to the omnibus
agreement; and |
|
|
|
borrowings under our credit facilities, as needed. |
We anticipate our more significant 2006 capital requirements to
be:
|
|
|
|
|
acquisition of a 25.1% interest in Four Corners; |
|
|
|
maintenance capital expenditures for our Conway assets; |
|
|
|
|
capital contributions to Discovery for its capital expenditure
program; and |
|
|
|
|
|
minimum quarterly distributions to our unitholders. |
|
Prior to our initial public offering, cash distributions from
Discovery to its members required unanimous consent and no such
distributions were made. Discoverys limited liability
company agreement was amended to provide for quarterly
distributions of available cash. We expect future cash
requirements for Discovery relating to working capital and
maintenance capital expenditures to be funded from cash retained
by Discovery at the closing of our initial public offering and
from its own internally generated cash flows from operations.
Growth or expansion capital expenditures for Discovery will be
funded by either cash calls to its members, which requires
unanimous consent of the members except in limited
circumstances, or from internally generated funds.
Prospectively, Discovery expects to make quarterly distributions
of available cash to its members instead of retaining all cash
from operations. Accordingly, on April 28, 2006, pursuant
to the terms of its limited liability company agreement,
Discovery made a $9.0 million distribution of available
cash to its members. Our 40% share of this distribution was
$3.6 million.
In 2005, Discovery sustained damages from Hurricane Katrina that
exceeded its $1.0 million insurance deductible. Discovery
estimates the total cost for hurricane-related repairs will be
approximately $7.7 million, $6.7 million in excess of
its deductible. Discovery will fund these repairs with cash
flows from operations and then seek reimbursement from its
insurance carrier. The insurance receivable at March 31,
2006 was $3.9 million.
Historically, Four Corners sources of liquidity included
cash generated from operations and advances from Williams. Four
Corners limited liability company agreement, as amended
effective as of the closing of this offering, provides for the
distribution of available cash on at least a quarterly basis. We
expect future cash requirements for Four Corners relating to
working capital, maintenance capital expenditures and quarterly
cash distributions to members to be funded from cash flows
internally generated from its operations. Growth or expansion
capital expenditures for Four Corners will be funded by either
cash calls to its members, which requires unanimous consent of
the members except in limited circumstances, or from internally
generated funds.
|
|
|
Capital Contributions from Williams |
Capital contributions from Williams, including amounts required
under the omnibus agreement, consist of the following:
|
|
|
|
|
Indemnification of environmental and related expenditures for a
period of three years (for certain of those expenditures) up to
$14.0 million, which includes between $3.4 million and
$4.6 million for the restoration activities related to the
partial erosion of the Carbonate Trend pipeline overburden by
Hurricane Ivan, approximately $3.1 million for capital
expenditures related to KDHE-related cavern compliance at our
Conway storage facilities, and approximately $1.0 million
for our 40% share of Discoverys costs for marshland
restoration and repair or replacement of Paradis
emission-control flare. |
88
|
|
|
|
|
An annual credit for general and administrative expenses of
$3.9 million in 2005 ($1.4 million pro-rated for the
portion of the year from August 23 to December 31),
$3.2 million in 2006, $2.4 million in 2007,
$1.6 million in 2008 and $0.8 million in 2009. |
|
|
|
Up to $3.4 million to fund our 40% share of the expected
total cost of Discoverys Tahiti pipeline lateral expansion
project in excess of the $24.4 million we contributed
during September 2005. |
|
|
|
|
Capital contributions from Williams of approximately
$1.0 million for other KDHE-related compliance work at our
Conway storage facilities. |
|
On May 1, 2006 we entered into a three-year credit
agreement among Williams, Northwest Pipeline Corporation,
Transcontinental Gas Pipe Line Corporation, Citibank, N.A., as
administrative agent, and a group of lenders. This
$1.5 billion credit agreement is available for borrowings
and letters of credit and allows us to borrow up to
$75 million for general partnership purposes, including
acquisitions, but only to the extent that sufficient amounts
remain unborrowed by Williams and its other subsidiaries. At
May 1, 2006, letters of credit totaling $235 million
had been issued on behalf of Williams and its subsidiaries by
the participating institutions under this facility and no
revolving credit loans were outstanding. Our borrowings under
the credit agreement bear interest at a variable interest rate
based on either LIBOR or a base rate, in either case plus an
applicable margin that varies depending upon the rating of
Williams senior unsecured long-term debt.
The credit agreement contains a number of restrictions on the
borrowers business, including, but not limited to
restrictions on certain of the borrowers and their
subsidiaries ability, but not our ability, to:
(i) grant liens on assets, merge, consolidate, or sell,
lease or otherwise transfer assets; (ii) incur
indebtedness; (iii) engage in transactions with related
parties; and (iv) make distributions on equity interests.
In addition, Williams is required to maintain a minimum ratio of
consolidated EBITDA to interest expense in addition to other
financial covenants. The credit agreement also contains
affirmative covenants and events of default. If any borrower
breaches financial or certain other covenants or if an event of
default occurs, the lenders may cause the acceleration of the
borrowers indebtedness and may terminate lending to all
borrowers under the credit agreement. Additionally, if
(i) a borrower were to generally not pay its debts as such
debts come due or admit in writing its inability to pay its
debts generally, (ii) a borrower were to make a general
assignment for the benefit of its creditors or (iii)
proceedings relating to the bankruptcy or receivership of any
borrower were to remain unstayed or undismissed for
60 days, then all lending under the credit agreement would
terminate and all indebtedness outstanding under the credit
agreement would be accelerated. Williams guarantees our
indebtedness under this credit agreement. Please read Risk
Factors Risks Inherent in Our Business
Williams credit agreement and Williams public
indentures contain financial and operating restrictions that may
limit our access to credit. In addition, our ability to obtain
credit in the future will be affected by Williams credit
ratings for more information regarding the potential
impact on us of restrictions in Williams credit agreement
and in Williams public indentures.
Also on May 1, 2006, the $1.275 billion revolving
credit facility dated as of May 20, 2005 among us,
Williams, Northwest Pipeline Corporation, Transcontinental Gas
Pipe Line Corporation, Citibank, N.A., Bank of America, N.A.,
and Citicorp USA, INC., as administrative agent, was terminated.
We also have a $20 million revolving credit facility with
Williams as the lender. The facility is available exclusively to
fund working capital borrowings. Borrowings under the facility
will mature on May 3, 2007. Please read Note 11 of the
Notes to Consolidated Financial Statements for additional
information regarding the commitment fee we are required to pay
and the interest rate on borrowings under this credit facility.
We are required to reduce all borrowings under our working
capital credit facility to zero for a period of at least 15
consecutive days once each
12-month period prior
to the maturity date of the facility. As of March 31, 2006,
we had no borrowings outstanding under the working capital
credit facility.
89
At the closing of this offering, Four Corners will enter into a
$20 million revolving credit facility with Williams as the
lender. The facility is available to fund working capital
borrowings and for other purposes. Borrowings under the facility
will mature on the third anniversary of the closing of our
acquisition of the 25.1% interest in Four Corners. Four Corners
will pay a commitment fee to Williams on the unused portion of
the credit facility of 0.30% annually. Interest on any
borrowings under the Four Corners facility will be calculated
based on Four Corners choice of two methods: (i) a
fluctuating rate equal to the facilitating banks base rate
plus an applicable margin or (ii) a periodic fixed rate
equal to LIBOR plus an applicable margin.
Concurrently with this offering, we are offering
$150 million in aggregate principal amount of senior notes
in a private placement. The senior notes are being offered only
to qualified institutional investors and to
non-U.S. persons
in offshore transactions and initially will not be guaranteed by
any of our subsidiaries. In the future in certain instances,
some or all of our subsidiaries may be required to guarantee our
senior notes.
The natural gas gathering, processing and transportation and NGL
fractionation and storage businesses are capital-intensive,
requiring investment to upgrade or enhance existing operations
and comply with safety and environmental regulations. The
capital requirements of these businesses consist
primarily of:
|
|
|
|
|
|
Maintenance capital expenditures, which are capital expenditures
made to replace partially or fully depreciated assets in order
to maintain the existing operating capacity of our assets and to
extend their useful lives; and |
|
|
|
|
|
Expansion capital expenditures such as those to acquire
additional assets to grow our business, to expand and upgrade
plant or pipeline capacity and to construct new plants,
pipelines and storage facilities. |
|
We estimate that maintenance capital expenditures for the Conway
assets will be approximately $8.3 million for 2006. Of this
amount, approximately $2.3 million of expenditures will be
reimbursed by Williams subject to the omnibus agreement. This
omnibus agreement includes a three-year limitation from the
closing date of our initial public offering, and a limitation of
$14.0 million on environmental and related indemnities.
We estimate that maintenance capital expenditures for 100% of
Discovery will be approximately $2.3 million for 2006. We
expect Discovery will fund its maintenance capital expenditures
through its cash flows from operations.
We estimate that expansion capital expenditures for 100% of
Discovery will be approximately $30.8 million for 2006.
These expenditures are primarily for the ongoing construction of
the Tahiti pipeline lateral expansion project. Discovery will
fund these expenditures with amounts previously escrowed for
this project.
|
|
|
Working Capital Attributable to Deferred Revenues |
We require cash in order to continue providing services to our
storage customers who prepay their annual storage contracts in
April of each year. The storage year for a majority of customer
contracts at our Conway storage facility runs from April 1
of a year to March 31 of the following year. For most of
these agreements we receive payment for these one-year contracts
in advance in April after the beginning of the storage year and
recognize the associated revenue over the course of the storage
year. We reserve cash throughout the storage year to fund the
cost of providing these services. As of March 31, 2006, our
deferred storage revenue was $0.2 million.
90
|
|
|
Cash Distributions to Unitholders |
We paid a quarterly distribution of $5.0 million
($0.35 per unit) on February 14, 2006 and a quarterly
distribution of $5.4 million ($0.38 per unit) on
May 15, 2006 to common and subordinated unitholders and the
general partner interest.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended | |
|
|
Years Ended December 31, | |
|
March 31, | |
|
|
| |
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
($ in thousands) | |
Net cash provided (used) by operating activities
|
|
$ |
6,664 |
|
|
$ |
2,703 |
|
|
$ |
1,893 |
|
|
$ |
(4,055 |
) |
|
$ |
2,395 |
|
Net cash used by investing activities
|
|
|
(102,810 |
) |
|
|
(1,534 |
) |
|
|
(28,088 |
) |
|
$ |
(212 |
) |
|
$ |
(1,165 |
) |
Net cash provided (used) by financing activities
|
|
|
96,166 |
|
|
|
(1,169 |
) |
|
|
33,034 |
|
|
$ |
4,267 |
|
|
$ |
(3,754 |
) |
The $6.5 million increase in net cash provided by operating
activities for the first three months of 2006 as compared to the
first three months of 2005 is due primarily to:
|
|
|
|
|
|
a $4.4 million increase in distributed earnings from
Discovery; and |
|
|
|
|
|
$2.8 million in lower interest expenses due to the
forgiveness by Williams of advances to us at the closing of our
initial public offering. |
|
The $0.8 million decrease in net cash provided by operating
activities in 2005 as compared to 2004 is due primarily to:
|
|
|
|
|
|
$2.6 million related to trade accounts receivable at
August 22, 2005 that were not included in the contribution
of net assets to us; |
|
|
|
|
|
$2.5 million related to decreases in the Conway product
imbalance liability largely resulting from settlement activity
in the fourth quarter of 2005; and |
|
|
|
|
$1.0 million lower operating income, adjusted for non-cash
expenses. |
These decreases were largely offset by:
|
|
|
|
|
$4.2 million in lower interest expense due to the
forgiveness by Williams of advances to our predecessor at the
closing of our initial public offering; and |
|
|
|
a $1.3 million increase in distributed earnings from
Discovery. |
The decrease of $3.9 million in net cash provided by
operating activities in 2004 as compared to 2003 reflects an
increase of $8.3 million in interest expense in 2004
related primarily to the funding of our $101.6 million
share of a Discovery cash call discussed below. This decrease in
net cash provided by operating activities was partially offset
by changes in working capital, including a $2.7 million
increase in accounts payable. The increase in accounts payable
was due to a $1.6 million accrual for spot ethane purchases
in December 2004 and a $1.0 million higher accrual for
power costs at the end of 2004 as compared to 2003.
Net cash used by investing activities includes maintenance
capital expenditures in our NGL Services segment, including the
installation of cavern liners and KDHE-related cavern compliance
with the installation of wellhead control equipment and well
meters. In addition, 2005 includes our capital contribution of
$24.4 million to Discovery for construction of the Tahiti
pipeline lateral expansion project. Net cash used by investing
activities in 2003 also includes our predecessors
$101.6 million capital contribution to Discovery for the
repayment of Discoverys outstanding debt in December 2003.
91
Net cash used by financing activities for the three months ended
March 31, 2006 includes $5.0 million of distributions
paid to unitholders partially offset by $1.2 million in
indemnifications and reimbursements received from Williams
pursuant to the omnibus agreement. Net cash provided by
financing activities in 2005 includes the cash flows related to
our initial public offering on August 23, 2005. These
consisted of $100.2 million in net proceeds from the sale
of the common and subordinated units, a $58.8 million
distribution to Williams and the payment of $4.3 million in
expenses associated with our initial public offering. Net cash
provided (used) by financing activities for 2004 and 2005
also includes the pass through of $1.2 million and
$3.7 million, respectively, of net cash flows to Williams
prior to August 23, 2005, under its cash management
program. Following the closing of our initial public offering on
August 23, 2005, we no longer participate in Williams
cash management program, and our net cash flows no longer pass
through to Williams. The annual 2005 period also includes
$2.1 million of distributions paid to unitholders and
$1.6 million in indemnifications and reimbursements
received from Williams pursuant to the omnibus agreement.
Net cash provided by financing activities in 2003 includes
advances from Williams to fund our $101.6 million share of
a Discovery cash call discussed below. The remaining 2003
financing cash flows represent the pass through of our net cash
flows to Williams under its cash management program as described
above.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended | |
|
|
Years Ended December 31, | |
|
March 31, | |
|
|
| |
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
($ in thousands) | |
Net cash provided by operating activities
|
|
$ |
44,025 |
|
|
$ |
35,623 |
|
|
$ |
30,814 |
|
|
$ |
7,981 |
|
|
$ |
18,515 |
|
Net cash provided (used) by investing activities
|
|
|
(12,073 |
) |
|
|
(39,115 |
) |
|
|
(65,997 |
) |
|
|
(7,097 |
) |
|
|
608 |
|
Net cash provided (used) by financing activities
|
|
|
409 |
|
|
|
|
|
|
|
1,339 |
|
|
|
|
|
|
|
(6,215 |
) |
Net cash provided by operating activities increased
$10.5 million in the first three months of 2006 as compared
to the first three months of 2005 due primarily to a
$4.2 million increase in operating income, adjusted for
non-cash expenses, and a $6.3 million increase in cash from
changes in working capital. The $6.3 million increase in
cash from changes in working capital resulted primarily from the
payment, in the first quarter of 2005, of an extra month of
liquid sales invoices outstanding at the end of 2004.
Net cash provided by operating activities decreased
$4.8 million in 2005 as compared to 2004 due primarily to
expenditures incurred for repairs following Hurricane Katrina
that have not yet been reimbursed by Discoverys insurance
carrier. The 2005 use of cash related to accounts receivable
included a $24.6 million outstanding receivable from a
subsidiary of Williams for the marketing activities associated
with the TGP and TETCO open seasons discussed under
Recent Events; this was offset by a
similar change in accounts payable for a balance due to the
shippers on TGP and TETCO. The 2005 use of cash related to
accounts receivable also included other increases in
customers outstanding balances of $8.6 million. The
2005 source of cash related to accounts payable also included a
$7.7 million imbalance with a customer.
Net cash provided by operating activities decreased
$8.4 million in 2004 as compared to 2003 due primarily to
the favorable impact in 2003 of improved accounts receivable
collections. Working capital levels remained more constant in
2004 as compared to 2003. As a result, net cash provided by
operating activities in 2004 did not include significant amounts
from changes in working capital and reflected the return to more
normal levels.
Net cash provided by investing activities increased
$7.7 million in the first three months of 2006 as compared
to the first three months of 2005 due to higher capital
expenditures in 2005 related primarily to capital expenditures
for Discoverys market expansion project and for the
purchase of leased compressors at
92
the Larose processing plant. Capital expenditures in the first
three months of 2006 related primarily to the Tahiti pipeline
lateral expansion project, which were funded from amounts
previously escrowed and included on the balance sheet as
restricted cash.
During 2005, net cash used by investing activities included
$44.6 million to fund escrow accounts for the Tahiti
pipeline lateral project and related interest income and
$21.4 million of capital expenditures for (1) the
completion of the Front Runner and market expansion projects,
(2) the initial expenditures for the Tahiti project, and
(3) the purchase of leased compressors at the Larose
processing plant. During 2004, net cash used by investing
activities was primarily used for the construction of a
gathering lateral to connect our pipeline system to the Front
Runner prospect. During 2003, net cash used for investing
activities included the $3.5 million purchase of a
12-inch gathering
pipeline and $4.5 million of initial capital expenditures
incurred for the construction of a gathering lateral to connect
to Discoverys pipeline system to the Front Runner prospect.
Net cash used by financing activities in the first three months
of 2006 includes:
|
|
|
|
|
|
$13.6 million of distributions paid to members, including a
regular quarterly distribution of $11.0 million; partially
offset by |
|
|
|
|
|
$7.4 million of capital contributions from members for the
construction of the Tahiti pipeline lateral expansion. |
|
During 2005, net cash provided by financing activities included
capital contributions from members totaling $48.3 million
for the construction of the Tahiti pipeline lateral expansion,
the distribution of $43.8 million associated with
Discoverys operations prior to our initial public offering
and a $3.2 million quarterly distribution to members in the
fourth quarter of 2005. During 2003, Discoverys members
made capital contributions of $254.1 million in response to
a cash call by Discovery. Discovery used these contributions to
retire its outstanding debt of $253.7 million.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended | |
|
|
Years Ended December 31, | |
|
March 31, | |
|
|
| |
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
($ in thousands) | |
|
|
|
|
Net cash provided by operating activities
|
|
$ |
122,266 |
|
|
$ |
134,387 |
|
|
$ |
156,039 |
|
|
$ |
37,027 |
|
|
$ |
29,464 |
|
Net cash used by investing activities
|
|
|
(6,581 |
) |
|
|
(13,920 |
) |
|
|
(27,578 |
) |
|
|
(2,540 |
) |
|
|
(1,250 |
) |
Net cash used by financing activities
|
|
|
(115,685 |
) |
|
|
(120,467 |
) |
|
|
(128,461 |
) |
|
|
(34,487 |
) |
|
|
(28,214 |
) |
The $7.6 million decrease in net cash provided by operating
activities in the first three months of 2006 as compared to the
first three months of 2005 is due primarily to a
$11.9 million increase in cash used by changes in working
capital partially offset by a $4.3 million increase in
operating income as adjusted for non-cash items. The
$11.9 million increase in cash used by changes in working
capital was due primarily to $6.9 million in changes in the
shrink replacement gas imbalance, a $3.0 million change in
cash associated with accounts receivable and $2.0 million
in greater outflows associated with accounts payable.
The $21.7 million increase in net cash provided by
operating activities in 2005 as compared to 2004 is due
primarily to:
|
|
|
|
|
$8.0 million increase in operating income, as adjusted for
non-cash expenses; and |
|
|
|
$13.8 million in cash provided from changes in working
capital related primarily to a change in the shrink replacement
gas imbalance from 2004 to 2005. |
93
The increase of $12.1 million in net cash provided by
operating activities in 2004 as compared to 2003 was due
primarily to:
|
|
|
|
|
$9.4 million increase in operating income, as adjusted for
non-cash expenses; and |
|
|
|
$2.7 million in cash provided from changes in working
capital related primarily to a change in accounts payable. |
Net cash used by investing activities in 2003, 2004 and 2005 and
the first three months of 2005 and 2006 included maintenance
capital expenditures of $2.0 million, $1.1 million,
$3.2 million, $2.5 million and $1.6 million,
respectively. Additionally, other capital expenditures for 2003,
2004 and 2005 and the first three months of 2005 and 2006 were
$6.1 million, $13.0 million, $24.4 million, $0.0
and $6.8 million, respectively. These expenditures related
primarily to the connection of new wells. Net cash used by
investing activities in 2003 was favorably impacted by
$1.5 million in proceeds from sales of property, plant and
equipment.
Net cash used by financing activities for all periods are
distributions of Four Corners net cash flows to Williams.
A summary of our contractual obligations as of December 31,
2005, is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 | |
|
2007-2008 | |
|
2009-2010 | |
|
2011+ | |
|
Total | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
Notes payable/long-term debt
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Capital leases
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating leases
|
|
|
30 |
|
|
|
55 |
|
|
|
10 |
|
|
|
|
|
|
|
95 |
|
Purchase obligations
|
|
|
5,135 |
|
|
|
2,928 |
|
|
|
240 |
|
|
|
120 |
(a) |
|
|
8,423 |
|
Other long-term liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
5,165 |
|
|
$ |
2,983 |
|
|
$ |
250 |
|
|
$ |
120 |
|
|
$ |
8,518 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
Year 2011 represents one year of payments associated with an
operating agreement whose term is tied to the life of the
underlying gas reserves. |
Our equity investee, Discovery, also has contractual obligations
for which we are not contractually liable. These contractual
obligations, however, will impact Discoverys ability to
make cash distributions to us. A summary of Discoverys
total contractual obligations as of December 31, 2005, is
as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 | |
|
2007-2008 | |
|
2009-2010 | |
|
2011+ | |
|
Total | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
Notes payable/long-term debt
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Capital leases
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating leases
|
|
|
854 |
|
|
|
1,712 |
|
|
|
1,716 |
|
|
|
4,109 |
|
|
|
8,391 |
|
Purchase obligations(a)
|
|
|
30,807 |
|
|
|
23,488 |
|
|
|
|
|
|
|
|
|
|
|
54,295 |
|
Other long-term liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
31,661 |
|
|
$ |
25,200 |
|
|
$ |
1,716 |
|
|
$ |
4,109 |
|
|
$ |
62,686 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
With the exception of $3.4 million of 2006 outstanding
purchase orders, all other amounts are Tahiti-related
expenditures that will be funded from the amounts escrowed for
this project in September 2005 and capital contributions from
members, including us. Please read Financial
Condition and Liquidity Outlook for 2006. |
Effects of Inflation
Inflation in the United States has been relatively low in recent
years and did not have a material impact on our results of
operations for the three-year period ended December 31,
2005. It may in the future, however, increase the cost to
acquire or replace property, plant and equipment and may
increase the costs of labor and
94
supplies. Our operating revenues and costs are influenced to a
greater extent by specific price changes in natural gas and
NGLs. To the extent permitted by competition, regulation and our
existing agreements, we have and will continue to pass along
increased costs to our customers in the form of higher fees.
Regulatory Matters
As of March 31, 2006, Discovery had deferred amounts of
$6.4 million relating to retained system gas gains and the
over-recovery of lost and unaccounted-for gas on the Discovery
system. Please read Note 7 to the Discovery Producer
Services LLC Consolidated Financial Statements included
elsewhere in this prospectus. Certain shippers challenged
Discoverys right to retain these gains. FERC requested and
received from Discovery additional information regarding both
lost and unaccounted-for volumes and gas gains. Discovery
responded to the information request and on October 31,
2005, FERC accepted the filing and no requests for rehearing
were filed. As a result, we recognized the portion of this
reserve for the period 2002 through 2004 of $10.7 million
in 2005.
Discoverys natural gas pipeline transportation is subject
to rate regulation by FERC under the Natural Gas Act. For more
information on federal and state regulations affecting our
business, please read Risk Factors and
Business FERC Regulation elsewhere in
this prospectus.
Environmental
Our Conway storage facilities are subject to strict
environmental regulation by the Underground Storage Unit within
the Geology Section of the Bureau of Water of the KDHE under the
Underground Hydrocarbon and Natural Gas Storage Program, which
became effective on April 1, 2003.
We are in the process of modifying our Conway storage
facilities, including the caverns and brine ponds, and we expect
our storage operations will be in compliance with the
Underground Hydrocarbon and Natural Gas Storage Program
regulations by the applicable required compliance dates. In
2003, we began to complete workovers on approximately 30 to
40 salt caverns per year and install, on average, a double
liner on one brine pond per year. The incremental costs of these
activities is approximately $5.5 million per year to
complete the workovers and approximately $900,000 per year
to install a double liner on a brine bond. In response to these
increased costs, we raised our storage rates in 2004 by an
amount sufficient to preserve our margins in this business.
Accordingly, we do not believe that these increased costs have
had a material effect on our business or results of operations.
We expect on average to complete workovers on each of our
caverns every five to ten years and install double liners on
each of our brine ponds every 18 years.
As of March 31, 2006, we had accrued environmental
liabilities of $5.3 million related to four remediation
projects at the Conway storage facilities. In 2004, we purchased
an insurance policy that covers up to $5.0 million of
remediation costs until an active remediation system is in place
or April 30, 2008, whichever is earlier, excluding
operation and maintenance costs and ongoing monitoring costs,
for these four projects to the extent such costs exceed a
$4.2 million deductible. The policy also covers costs
incurred as a result of third party claims associated with then
existing but unknown contamination related to the storage
facilities. The aggregate limit under the policy for all claims
is $25 million. In the omnibus agreement, Williams agreed
to indemnify us for these remediation expenditures to the extent
not recovered under the insurance policy, excluding costs of
project management and soil and groundwater monitoring, and
certain other environmental and related obligations arising out
of or associated with the operation of the assets before the
closing date of our initial public offering. There is an
aggregate cap of $14.0 million on the total amount of
indemnity coverage under the omnibus agreement, which will be
reduced by actual recoveries under the environmental insurance
policy, subject to a three-year limit from the closing date of
our initial public offering. We estimate that the approximate
cost of the project management and soil and groundwater
monitoring associated with the four remediation projects at the
Conway storage facilities and for which we will not be
indemnified will be approximately $200,000 to $400,000 per
year following the completion of remediation work. The benefit
of the indemnification will be accounted for as a capital
contribution to us by Williams as the costs are incurred. Please
read Certain Relationships and Related
Transactions Omnibus Agreement.
95
In connection with our operations at the Conway facilities, we
are required by the KDHE regulations to provide assurance of our
financial capability to plug and abandon the wells and abandon
the brine facilities we operate at Conway. As of May 18,
2006, Williams had posted two letters of credit on our behalf in
an aggregate amount of $18.0 million to guarantee our
plugging and abandonment responsibilities for these facilities.
We anticipate providing assurance in the form of letters of
credit in future periods until such time as we obtain an
investment-grade credit rating.
In connection with the construction of Discoverys
pipeline, approximately 73 acres of marshland was
traversed. Discovery is required to restore marshland in other
areas to offset the damage caused during the initial
construction. In Phase I of this project, Discovery created
new marshlands to replace about half of the traversed acreage.
Phase II, which will complete the project, began during
2005 and will cost approximately $2.0 million.
Qualitative and Quantitative Disclosures About Market Risk
Market risk is the risk of loss arising from adverse changes in
market rates and prices. The principal market risk to which we
are exposed is commodity price risk for natural gas and NGLs. We
were also exposed to the risk of interest rate fluctuations on
our intercompany balances with Williams prior to the forgiveness
of these balances by Williams in connection with our initial
public offering.
Certain of Discoverys processing contracts are exposed to
the impact of price fluctuations in the commodity markets,
including the correlation between natural gas and NGL prices. In
addition, price fluctuations in commodity markets could impact
the demand for Discoverys services in the future.
Carbonate Trend and our fractionation and storage operations are
not directly affected by changing commodity prices except for
product imbalances, which are exposed to the impact of price
fluctuation in NGL markets. Price fluctuations in commodity
markets could also impact the demand for storage and
fractionation services in the future. In connection with our
initial public offering, Williams transferred to us a gas
purchase contract for the purchase of a portion of our fuel
requirements at the Conway fractionator at a market price not to
exceed a specified level. This physical contract is intended to
mitigate the fuel price risk under one of our fractionation
contracts which contains a cap on the per-unit fee that we can
charge, at times limiting our ability to pass through the full
amount of increases in variable expenses to that customer.
Please read Our Operations
Gathering and Processing Segment and Our
Operations NGL Services Segment for more
information. For the three months ended March 31, 2006,
approximately 49% of Four Corners processing volumes are
under keep-whole or
percent-of-liquids
contracts, and an additional 51% of Four Corners
processing volumes are under combined keep-whole and fee-based
contracts. These contracts are exposed to the impact of price
fluctuations in the commodity markets, including the correlation
between natural gas and NGL prices. In addition, price
fluctuations in commodity markets could impact the demand for
Four Corners services in the future. We, Discovery and
Four Corners do not currently use financial derivatives to
manage the risks associated with these price fluctuations.
Historically, our interest rate exposure was related to advances
from Williams to our predecessor. The table below provides
information as of December 31, 2004 about our interest rate
risk. We had no borrowings and no interest rate risk as of
December 31, 2005 and March 31, 2006.
|
|
|
|
|
|
|
|
|
|
|
December 31, 2004 | |
|
|
| |
|
|
Carrying | |
|
Fair | |
|
|
Value | |
|
Value | |
|
|
| |
|
| |
|
|
($ in thousands) | |
Advances from Williams
|
|
$ |
186,024 |
|
|
$ |
186,024 |
|
These advances were due on demand. Prior to the closing of our
initial public offering, Williams forgave these advances to our
predecessor. The variable interest rate was 7.4% at
December 31, 2004.
96
BUSINESS
Our Partnership
We are a Delaware limited partnership formed by Williams in
February 2005, to own, operate and acquire a diversified
portfolio of complementary assets. We are principally engaged in
the business of gathering, transporting and processing natural
gas and fractionating and storing NGLs. NGLs, such as ethane,
propane and butane, result from natural gas processing and crude
oil refining and are used as petrochemical feedstocks, heating
fuels and gasoline additives, among other applications.
Operations of our businesses are located in the United States
and are organized into two reporting segments:
(1) Gathering and Processing; and (2) NGL Services.
Please read Note 14 of our Consolidated Financial
Statements for financial information about our segments.
On April 6, 2006, we entered into an agreement to acquire a
25.1% membership interest in Four Corners from affiliates of
Williams. Four Corners owns a
3,500-mile natural gas
gathering system, including three natural gas processing plants
and two natural gas treating plants, located in the
San Juan Basin in Colorado and New Mexico. Please read
Acquisition of Interest in Four Corners. This is our
first acquisition since our initial public offering in August
2005. We intend to acquire additional assets in the future and
have a management team dedicated to a growth strategy.
Our current asset portfolio consists of:
|
|
|
|
|
a 40% interest in Discovery, which owns an integrated natural
gas gathering and transportation pipeline system extending from
offshore in the Gulf of Mexico to a natural gas processing
facility and an NGL fractionator in Louisiana; |
|
|
|
the Carbonate Trend natural gas gathering pipeline off the coast
of Alabama; and |
|
|
|
three integrated NGL storage facilities and a 50% interest in an
NGL fractionator near Conway, Kansas. |
Discovery provides integrated wellhead to market
services to natural gas producers operating in the shallow and
deep waters of the Gulf of Mexico off the coast of Louisiana.
Discovery consists of a
105-mile mainline,
168 miles of lateral gathering pipelines, a natural gas
processing plant and an NGL fractionation facility. Discovery
has interconnections with five natural gas pipeline systems,
which allow producers to benefit from flexible and diversified
access to a variety of natural gas markets. The Discovery
mainline was placed into service in 1998 and has a design
capacity of 600 million cubic feet per day. Additionally,
Discovery has recently signed definitive agreements with
Chevron, Shell, and Statoil to construct an approximate
35-mile gathering
pipeline lateral to connect Discoverys existing pipeline
system to these producers production facilities for the
Tahiti prospect in the deepwater region of the Gulf of Mexico.
The Tahiti pipeline lateral expansion will have a design
capacity of approximately 200 million cubic feet per day,
and its anticipated completion date is May 2007 with initial
production expected in April 2008.
Our Carbonate Trend gathering pipeline is a
34-mile pipeline that
gathers sour gas production from the Carbonate Trend area off
the coast of Alabama. Sour gas is natural gas that
has relatively high concentrations of acidic gases, such as
hydrogen sulfide and carbon dioxide, that exceed normal gas
transportation specifications. The pipeline was built and placed
into service in 2000 and has a maximum design capacity of
120 million cubic feet per day.
We are also engaged in NGL storage and fractionation near
Conway, Kansas, which is the principal NGL market hub for the
Mid-Continent region of the United States. We believe our
integrated NGL storage facility at Conway is one of the largest
in the Mid-Continent region. These storage facilities consist of
a network of interconnected underground caverns that hold large
volumes of NGLs and other hydrocarbons and have an aggregate
capacity of approximately 20 million barrels. Our Conway
storage facilities connect directly with MAPL and the Kinder
Morgan NGL pipeline systems and indirectly with three other
large interstate NGL pipelines. We also own a 50% undivided
interest in the Conway NGL fractionation facility, which is
strategically located at the junction of the south, east and
west legs of MAPL. This fractionation
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facility also benefits from its proximity to other NGL pipelines
in the Conway area, and from its proximity to our Conway storage
facility. Our share of the fractionators capacity is
approximately 53,500 barrels per day.
We account for our 40% interest in Discovery as an equity
investment, and therefore do not consolidate its financial
results. For the year ended December 31, 2005 and the three
months ended March 31, 2006, we generated Adjusted EBITDA
Excluding Equity Investments of approximately $10.9 million
and $2.8 million, respectively. In addition, our 40%
interest in Discovery generated Adjusted EBITDA of approximately
$17.6 million and $6.1 million for the year ended
December 31, 2005 and the three months ended March 31,
2006, respectively. Please read Prospectus
Summary Summary Historical and Pro Forma Financial
and Operating Data Non-GAAP Financial Measures
for an explanation of our Adjusted EBITDA Excluding Equity
Investments and an explanation of Discoverys Adjusted
EBITDA as well as a reconciliation of these measures to our and
Discoverys most directly comparable financial measures,
calculated and presented in accordance with GAAP.
Business Strategies
Our primary business objectives are to generate stable cash
flows sufficient to make quarterly cash distributions to our
unitholders and to increase quarterly cash distributions over
time by executing the following strategies:
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grow through accretive acquisitions of complementary energy
assets from third parties, Williams or both, such as our
proposed acquisition of a 25.1% interest in Four Corners; |
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capitalize on expected long-term increases in natural gas
production in proximity to Discoverys pipelines in the
Gulf of Mexico; |
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optimize the benefits of our scale, strategic location and
pipeline connectivity serving the Mid-Continent NGL market; |
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leverage the scale and competitive position of Four
Corners standing as a leading provider of natural gas
gathering, processing and treating services in the San Juan
Basin; and |
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manage our existing and future asset portfolio to minimize the
volatility of our cash flows. |
Competitive Strengths
We believe we are well positioned to execute our business
strategies successfully because of the following competitive
strengths:
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our ability to grow through acquisitions is enhanced by our
affiliation with Williams, and we expect this relationship to
provide us access to attractive acquisition opportunities, such
as our proposed acquisition of a 25.1% interest in Four Corners; |
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our assets are strategically located in areas with high demand
for our services; |
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our assets are diversified geographically and encompass
important aspects of the midstream natural gas and NGL
businesses; |
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the senior management team and board of directors of our general
partner have extensive industry experience and include the most
senior officers of Williams; and |
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Williams has established a reputation in the midstream natural
gas and NGL industry as a reliable and cost-effective operator,
and we believe that we and our customers will benefit from
Williams scale and operational expertise as well as our
access to the broad array of midstream services that Williams
offers. |
Our Relationship with Williams
One of our principal attributes is our relationship with
Williams, an integrated energy company with 2005 revenues in
excess of $12.5 billion that trades on the New York Stock
Exchange under the symbol
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WMB. Williams operates in a number of segments of
the energy industry, including natural gas exploration and
production, interstate natural gas transportation and midstream
services. Williams has been in the midstream natural gas and NGL
industry for more than 20 years.
Williams has a long history of successfully pursuing and
consummating energy acquisitions and intends to use our
partnership as a growth vehicle for its midstream, natural gas,
NGL and other complementary energy businesses. Although we
expect to have the opportunity to make additional acquisitions
directly from Williams in the future, we cannot say with any
certainty which, if any, of these acquisition opportunities may
be made available to us or if we will choose to pursue any such
opportunity. In addition, through our relationship with
Williams, we will have access to a significant pool of
management talent and strong commercial relationships throughout
the energy industry. While our relationship with Williams and
its subsidiaries is a significant attribute, it is also a source
of potential conflicts. For example, Williams is not restricted
from competing with us. Williams may acquire, construct or
dispose of midstream or other assets in the future without any
obligation to offer us the opportunity to purchase or construct
those assets. Please read Conflicts of Interest and
Fiduciary Duties.
Following this offering, Williams will have a significant
interest in our partnership through its ownership of a 39.2%
limited partner interest and all of our 2% general partner
interest. Additionally, subsidiaries of Williams market
substantially all of the NGLs to which Discovery and Four
Corners take title and affiliates of Williams have contracts
with Four Corners related to processing natural gas and
providing waste heat from the Milagro co-generation plant to
assist in the operation of the Milagro treating plant.
Industry Overview
We are engaged in important aspects of the midstream natural gas
and NGL businesses along the Gulf Coast and in the Mid-Continent
region of the United States. Offshore of and onshore in
Louisiana, we gather, transport and process natural gas produced
in the Gulf of Mexico, including natural gas that is associated
with crude oil production. Near Conway, Kansas, we fractionate
and store NGLs. As such, our business is directly impacted by
changes in domestic demand for and production of natural gas.
Natural gas continues to be a critical component of energy
consumption in the United States. According to the Energy
Information Administration, or the EIA, total annual domestic
consumption of natural gas is expected to increase from
approximately 20.4 trillion cubic feet, or Tcf,
(55.9 Bcf/d) in 2005 to approximately 21.6 Tcf
(59.3 Bcf/d) in 2010, representing an average annual growth
rate of over 1.2% per year. By 2010, natural gas is
expected to represent approximately 22% of all end-user domestic
energy requirements. From 2001 to 2005, the United States has on
average consumed approximately 20.7 Tcf per year
(56.7 Bcf/d) with average annual domestic production of
approximately 19.8 Tcf (54.3 Bcf/d) during the same period.
The industrial and electricity generation sectors are the
largest users of natural gas in the United States. During the
last three years, these sectors accounted for approximately 61%
of the total natural gas consumed in the United States.
According to the EIA, annual consumption in the industrial and
electricity generation sectors is expected to increase by over
1.4% per year, on average, to 13.3 Tcf (36.5 Bcf/d) in
2010 from an estimated 12.4 Tcf (34.1 Bcf/d) in 2005.
Gulf of Mexico. The Gulf of Mexico is a significant
producing area for natural gas consumed in the U.S. Many
long-haul natural gas pipelines depend on the Gulf of Mexico as
a significant source of natural gas. According to the EIA,
historic natural gas production rates in the Gulf of Mexico
since 1992 have fluctuated from a peak of approximately
14.1 Bcf/d in 1997 to approximately 10.6 Bcf/d in
2004. Over that same period, natural gas produced from deepwater
wells (greater than 200 meters), as opposed to shallow water
wells (less than 200 meters), has constituted an increasingly
greater component of total Gulf of Mexico natural gas production.
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The following graph shows total natural gas production in the
Gulf of Mexico since 1992 and the portions attributable to both
shallow water and deepwater production. A significant portion of
this Gulf of Mexico production includes natural gas associated
with crude oil production.
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Source: |
Energy Information Agency, Gulf of Mexico Federal Offshore
Production, 2004 |
According to EIAs Annual Energy Outlook 2006, both total
and deepwater natural gas production levels in the Gulf of
Mexico are projected to increase over the next decade. The
following graph shows the EIAs projection of total natural
gas production in the Gulf of Mexico increasing from
approximately 11.2 Bcf/d in 2005 to approximately
13.9 Bcf/d in 2015 and deepwater natural gas production in
the Gulf of Mexico increasing from approximately 4.9 Bcf/d
in 2005 to approximately 8.6 Bcf/d in 2015.
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Source: |
Energy Information Agency Annual Energy Outlook 2006 |
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Mid-Continent. The following graph shows the EIAs
estimates of Mid-Continent natural gas production through the
year 2015. The EIA defines the Mid-Continent to include
Minnesota, Iowa, Missouri, Nebraska, Kansas, Arkansas, Oklahoma,
and the Texas panhandle. According to EIAs Annual Energy
Outlook 2006, Mid-Continent natural gas production is projected
to remain at levels above 6.5 Bcf/d per year through 2015.
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Source: |
Energy Information Agency Annual Energy Outlook 2006 |
General. Once natural gas is produced from wells in areas
such as the Gulf of Mexico, producers then seek to deliver the
natural gas and its components to end-use markets. The midstream
natural gas industry is the link between upstream exploration
and production activities and downstream end-use markets. The
midstream natural gas industry generally consists of natural gas
gathering, transportation, processing, storage and fractionation
activities. The midstream industry is generally characterized by
regional competition based on the proximity of gathering systems
and processing plants to natural gas producing wells.
The following diagram illustrates the natural gas gathering,
processing, fractionation, storage and transportation process.
We supply our customers with all of these services from our
processing, fractionation and storage facilities, except for
natural gas and NGL transportation to end users and natural gas
storage.
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Offshore Natural Gas Gathering. An offshore gathering
system typically consists of multiple gathering laterals of
smaller diameter pipe that collect natural gas directly from
production platforms or, in some cases, subsea connections to
the wellhead. Production platforms provide production handling
services, which in the case of a well producing a mixture of oil
and gas involves the separation of natural gas from the oil and
water before the natural gas enters the gathering lateral.
Gathering laterals then connect to a main or trunk line of
larger diameter pipe. The mainline then transports the natural
gas collected from the various laterals to an onshore location,
typically a treating facility or gas processing plant. As new
natural gas discoveries are made within the vicinity of the
mainline or the existing laterals, new step out
laterals or extensions of existing laterals are built to connect
the gathering system to the newly producing wells. Gathering
contracts with offshore natural gas producers are typically
executed in conjunction with a reserve dedication. A reserve
dedication commits the producer to utilize the midstream service
providers gathering and transportation system for all
current and future production, often for the life of the
producers reservoir lease.
Natural Gas Processing and Transportation. The principal
component of natural gas is methane, but most natural gas also
contains varying amounts of NGLs including ethane, propane,
normal butane, isobutane and natural gasoline. NGLs have
economic value and are utilized as a feedstock in the
petrochemical and oil refining industries or directly as a
heating, engine or industrial fuel. Long-haul natural gas
pipelines have specifications as to the maximum NGL content of
the gas to be shipped. Because of the presence of NGLs, natural
gas collected through a gathering system is typically unsuitable
for long-haul pipeline transportation. In order to meet quality
standards for pipelines, unsuitable natural gas must be
processed to separate hydrocarbon liquids that can have higher
values as mixed NGLs from the natural gas. NGLs are typically
recovered by cooling the natural gas until the mixed NGLs become
separated through condensation. Cryogenic recovery methods are
processes where this is accomplished at temperatures lower than
-150 °F, and which provide higher NGL recovery yields.
After being extracted from natural gas, the mixed NGLs are
typically transported to a fractionator for separation of the
NGLs into their component parts.
In addition to NGLs, natural gas collected through a gathering
system may also contain impurities, such as water, sulfur
compounds, nitrogen or helium. As a result, a natural gas
processing plant will typically provide ancillary services such
as dehydration and condensate separation prior to processing.
Dehydration removes water from the natural gas stream which can
form ice when combined with natural gas and cause corrosion when
combined with carbon dioxide or hydrogen sulfide. Condensate
separation involves the removal of crude oil-like hydrocarbons
from the natural gas stream. Once the condensate has been
removed, it may be stabilized for transportation away from the
processing plant via truck, rail or pipeline. Natural gas with a
carbon dioxide or hydrogen sulfide content higher than permitted
by pipeline quality standards requires treatment with chemicals
called amines at a separate treating plant prior to processing.
Fractionation. NGL fractionation facilities separate
mixed NGL streams into discrete NGL products: ethane, propane,
normal butane, isobutane and natural gasoline.
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Ethane. Ethane is primarily used in the petrochemical
industry as feedstock for ethylene, one of the basic building
blocks used in a wide range of plastics and other chemical
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Propane. Propane is used both as a petrochemical
feedstock in the production of ethylene and propylene and as a
heating, engine and industrial fuel; |
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Normal Butane. Normal butane is used as a petrochemical
feedstock in the production of ethylene and butadiene (a key
ingredient in synthetic rubber), as a blendstock for motor
gasoline and to derive isobutane through isomerization; |
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Isobutane. Isobutane is fractionated from mixed butane (a
stream of normal butane and isobutane in solution) or refined
from normal butane through the process of isomerization,
principally for use in refinery alkylation to enhance the octane
content of motor gasoline; and |
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Natural Gasoline. Natural gasoline, a mixture of pentanes
and heavier hydrocarbons, is used primarily as motor gasoline
blendstock or petrochemical feedstock. |
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NGLs are fractionated by heating mixed NGL streams and passing
them through a series of distillation towers. Fractionation
takes advantage of the differing boiling points of the various
NGL products. As the temperature of the NGL stream is increased,
the lightest (lowest boiling point) NGL product boils off to the
top of the tower where it is condensed and routed to storage.
The mixture from the bottom of the first tower is then moved
into the next tower where the process is repeated, and a heavier
NGL product is separated and stored. This process is repeated
until the NGLs have been separated into their components. Since
the fractionation process requires large quantities of heat,
energy costs are a major component of the total cost of
fractionation.
The following diagram illustrates the NGL fractionation process:
NGLs are produced domestically in the United States from two
sources gas processing plants and crude oil
refineries. We believe, based on industry data, NGLs produced
from domestic gas processing operations accounted for
approximately 70% of the total NGL supplies in the United States
in 2003. The mixed NGLs delivered from domestic gas processing
plants and crude oil refineries to fractionation facilities are
typically transported by NGL pipelines and, to a lesser extent,
by railcar and truck.
Gas processing facilities have some flexibility in the degree to
which they separate NGLs from natural gas. The actual volume of
NGLs produced is often determined by the extent to which NGL
prices exceed the cost of separating the mixed NGLs from the
natural gas stream. This in turn is influenced by the cost of
the natural gas consumed in the fractionation process. When
operating and extraction costs of gas processing and
fractionation plants are higher than the incremental value of
the NGL products that would be received by NGL extraction, the
recovery levels of certain NGL products, particularly ethane,
may be reduced. The increase or decrease in NGL recovery levels
is a primary factor behind changes in gross fractionation
volumes.
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The following graph shows the total domestic NGL production from
1993 through 2004, the most recent year for which this data is
available.
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Source: |
Energy Information Agency U.S. Crude Oil, Natural Gas, and
Natural Gas Liquids Reserves 2004 Annual Report. |
NGL Storage. After NGLs are fractionated, the
fractionated products are stored for customers when they are
unable or do not wish to take immediate delivery. NGL storage
customers may include both NGL producers, who sell to end users,
and NGL end users, such as retail propane companies. Both the
producers and the end users seek to store NGLs to ensure an
adequate supply for their respective customers over the course
of the year, particularly during periods of increased demand. A
significant portion of the U.S. NGL production is brought
through pipelines to two market centers: one on the Gulf Coast
at Mont Belvieu, Texas and the other in the Mid-Continent area
at Conway, Kansas.
Fractionated NGL products are typically stored underground in
salt formations because large capacity above-ground storage
would be uneconomical. NGL products must be pressurized or
refrigerated for storage or transportation in a liquid state.
Salt formations, which are indigenous to the Mont Belvieu and
Conway areas, provide a medium that is impervious to the stored
products and can contain large quantities of hydrocarbons in a
safe manner and at a significantly lower per-unit cost than any
above-ground alternative. A salt cavern is formed by drilling
and dissolving, through percolation, an underground cavern in a
naturally existing salt formation and installing related surface
facilities. Water mixed with salt, or brine, is used to displace
the stored products and to maintain pressure in the well as
product volumes fluctuate. The typical salt cavern storage
facility consists of a solution mining plant, which provides
fresh water to dissolve cavities within the underlying salt,
brine handling and disposal facilities, and the necessary
surface equipment to compress the fractionated products into the
cavity and allow them to flow back into a pipeline.
Gathering and Processing The Discovery Assets
We own a 40% interest in Discovery, which in turn owns:
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a 273-mile natural gas
gathering and transportation pipeline system, located primarily
off the coast of Louisiana in the Gulf of Mexico, with a
FERC-certified capacity of approximately 600 MMcf/d on its
mainline; |
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a cryogenic natural gas processing plant in Larose, Louisiana
with a capacity of approximately 600 MMcf/d; |
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a fractionator in Paradis, Louisiana with a current capacity of
approximately 32,000 bpd (which can be expanded to
42,000 bpd); and |
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two onshore liquids pipelines, including a
22-mile mixed NGL
pipeline connecting the gas processing plant to the fractionator
and a 10-mile
condensate pipeline connecting the gas processing plant to a
third party oil gathering facility. |
Although Discovery includes fractionation operations, which
would normally fall within the NGL Services segment, it is
primarily engaged in gathering and processing and is managed as
such. Accordingly, this equity investment is considered part of
the Gathering and Processing segment.
Additionally, Discovery signed definitive agreements with
Chevron, Shell, and Statoil to construct an approximate
35-mile gathering
pipeline lateral to connect Discoverys existing pipeline
system to these producers production facilities for the
Tahiti prospect in the deepwater region of the Gulf of Mexico.
The Tahiti pipeline lateral expansion is expected to have a
design capacity of approximately 200 MMcf/d, and its
anticipated completion date is May 2007 with initial production
expected in April 2008.
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The following map shows the location of the Discovery offshore
gathering and transportation pipelines and the blocks of
reserves dedicated to Discovery.
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The following map shows the locations of Discoverys
onshore Larose natural gas processing plant, the raw make
pipeline, the Paradis fractionator and the connecting long-haul
natural gas pipeline systems.
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Discovery Natural Gas Pipeline System |
General. The Discovery natural gas gathering and
transportation pipeline system consists of:
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a 105-mile,
30-inch natural gas
pipeline, or mainline, that runs from the edge of the Outer
Continental Shelf in the Gulf of Mexico north to
Discoverys natural gas processing plant in Larose,
Louisiana and continues as a four-mile,
20-inch natural gas
pipeline that connects to the Texas Eastern Pipeline; and |
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approximately 168 miles of gathering laterals, with
pipeline diameters ranging from eight inches to 20 inches. |
The mainline and approximately 60 miles of the gathering
laterals are under the jurisdiction of FERC.
Transportation and Gathering Natural Gas Pipeline. The
mainline of the Discovery pipeline system consists of a
105-mile,
30-inch diameter
natural gas and condensate pipeline, which begins at a platform,
owned by a third party, located in the offshore Louisiana Outer
Continental Shelf at Ewing Bank 873 and extends northerly to the
Larose gas processing plant and a four-mile,
20-inch natural gas
pipeline that connects the Larose plant to the Texas Eastern
Pipeline. Approximately 66 miles of the mainline is located
offshore, in water depths ranging from approximately 40 to
800 feet. Producers have dedicated their production from
approximately 60 offshore blocks to Discovery. Each block
represents an area of 5,760 square acres. The mainline has
a FERC-certificated capacity of approximately 600 MMcf/d.
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The Discovery system connects to five natural gas pipeline
systems, two of which provide 1.3 Bcf/d of takeaway
capacity: the Bridgeline system, which serves southern Louisiana
and connects to the Henry Hub natural gas market point, and the
Texas Eastern Pipeline system, which serves markets from Texas
to the northeastern United States. Additionally,
Discoverys recently completed market expansion project
connects Discovery to the following pipeline systems: Tennessee
Gas Pipeline, Columbia Gulf Transmission and Transco. Together,
these three pipeline systems provide up to an additional
500 MMcf/d of takeaway capacity. This market expansion
project, consisting of approximately 40 miles of
20-inch diameter pipe
extending from the Larose processing plant to Pointe Au Chien,
Louisiana and Old Lady Lake, Louisiana commenced operations in
June 2005 and has a FERC-certificated capacity of approximately
150 MMcf/d. Discoverys interconnections allow
producers to benefit from flexible and diversified access to a
variety of natural gas markets from the Gulf of Mexico to the
eastern United States.
Shallow Water/ Onshore Gathering. Discovery also owns
shallow water and onshore gathering assets that consist of:
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90 miles of offshore laterals with pipeline diameters
ranging from 12 inches to 20 inches with connections
to the mainline. These shallow water laterals are located in
water depths ranging from approximately 50 to 360 feet. Of
the 90 miles of shallow water laterals, 60 miles are
regulated by FERC; |
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a fixed-leg shelf production handling facility installed along
the mainline at Grand Isle 115. The platform facility allows for
the injection of condensate into the pipeline and is equipped
with a production handling facility; and |
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a five-mile onshore gathering lateral with
20-inch diameter pipe
that extends from a production area north of the Larose gas
processing plant directly to the plant. This lateral is not
regulated by FERC. |
A Chevron-owned gathering system also connects to the Larose gas
processing plant.
Deepwater Gathering. Discoverys deepwater gathering
assets, which are located in water depths of greater than
1,000 feet, consist of 73 miles of gathering laterals,
with pipeline diameters ranging from eight inches to
16 inches that extend to deepwater producing areas in the
Gulf of Mexico such as the Morpeth prospect, Allegheny prospect
and Front Runner prospect. The maximum water depth of these
deepwater laterals is approximately 3,200 feet.
Additionally, Discovery signed definitive agreements to
construct a gathering pipeline lateral to connect
Discoverys existing pipeline system to certain
producers production facilities for the Tahiti prospect
described above. None of Discoverys deepwater laterals are
regulated by FERC.
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Larose Gas Processing Plant |
Discoverys cryogenic gas processing plant is located near
Larose, Louisiana at the onshore terminus of Discoverys
natural gas pipeline and has a design capacity of approximately
600 MMcf/d. The plant was placed in service in January 1998
and is located on land that Discovery leases from a third party.
The initial term of the lease is 20 years and is renewable
for ten-year intervals thereafter at Discoverys option for
up to a total of 50 years.
We believe that the Larose plant is one of the most efficient
and flexible gas processing plants in south Louisiana. The
Larose plant is able to recover over 90% of the ethane contained
in the natural gas stream and effectively 100% of the propane
and heavier liquids. In addition, the processing plant is able
to reject ethane down to effectively 0% when justified by market
economics, while retaining a propane recovery rate of over 95%
and butanes and heavier liquids recovery rates of effectively
100%. We believe that the Larose plant consumes very low amounts
of natural gas as fuel, using only approximately 1.4% of the
volume of natural gas processed.
In addition to its gas processing activities, the Larose plant
generates additional revenues by charging separate fees for
ancillary services, such as dehydration and condensate
separation and stabilization. Producers may also contract with
Discovery for transportation of condensate from offshore
production
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handling facilities and upon separation and stabilization,
through Discoverys ten-mile condensate pipeline to a third
partys oil gathering facility. Discovery also provides
compression services for a third partys onshore gathering
system that connects to Discoverys onshore lateral.
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Paradis Fractionation Facility |
The fractionator is located onshore near Paradis, Louisiana. The
fractionator and mixed NGL pipeline went into service in January
1998. The initial term of the lease is 20 years and is
renewable for ten-year intervals thereafter at Discoverys
option for up to a total of 50 years. The Paradis
fractionator is designed to fractionate 32,000 bpd of mixed
NGLs and is expandable to 42,000 bpd. In 2005, Discovery
fractionated an average of approximately 9,600 bpd of mixed
NGLs. All products can be delivered through the Chevron TENDS
NGL pipeline system and propane and heavier products may be
transported by truck or railway.
Discovery fractionates NGLs for third party customers and for
itself, and typically it receives title to approximately
one-half of the mixed NGL volumes leaving the Larose plant. A
subsidiary of Williams markets substantially all of the NGLs and
excess natural gas to which Discovery takes title by purchasing
them from Discovery and reselling them to end-users. Discovery
fractionates third party NGL volumes for a fractionation fee,
which typically includes a base fractionation fee per gallon,
that is subject to adjustment for changes in certain
fractionation expenses, including natural gas fuel costs on a
monthly basis and labor costs on an annual basis, which are the
principal variable costs in NGL fractionation. As a result,
Discovery is generally able to pass through increases in those
fractionation expenses to its customers.
Discovery is currently owned 40% by us, 20% by Williams and 40%
by Duke Energy Field Services, or DEFS. Williams is the operator
of the Discovery assets. Discovery is managed by a three member
management committee consisting of representation from each of
the three owners. The members of the management committee have
voting power that corresponds to the ownership interest of the
owner they represent. However, except under limited
circumstances, all actions and decisions relating to Discovery
require the unanimous approval of the owners. Discovery must
make quarterly distributions of available cash (generally, cash
from operations less required and discretionary reserves) to its
owners. The management committee, by majority approval, will
determine the amount of such distributions. In addition, the
owners are required to offer to Discovery all opportunities to
construct pipeline laterals within an area of
interest.
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Discovery Customers and Contracts |
Customers. Discoverys customers are primarily
offshore natural gas producers. Discovery provides these
customers with wellhead to market delivery options
by offering a full range of services including gathering,
transportation, processing and fractionation. Discovery also has
the ability to provide its customers with other specialized
services, such as offshore production handling, condensate
separation and stabilization and dehydration. Five offshore
producer customers accounted for approximately 21% and 20% of
Discoverys revenues in 2005 and the three months ended
March 31, 2006, respectively. No single customer accounted
for over 10% of Discoverys revenues in 2005. Additionally,
a subsidiary of Williams, which markets substantially all of the
NGLs and excess natural gas to which Discovery takes title,
accounted for approximately 57.7% and 71% of Discoverys
revenues in 2005 and the three months ended March 31, 2006,
respectively, even though it does not produce any of the natural
gas that is supplied to Discovery.
Contracts. Discovery provides a complete range of
wellhead to market services for its customers who
are offshore producers in the Gulf of Mexico. The principal
services provided include gathering, transportation, processing
and fractionation. Discovery also provides ancillary services
such as dehydration and condensate transportation, separation
and stabilization. Each of these services is usually supported
by a separate customer contract.
The mainline and FERC-regulated laterals generate revenues
through FERC-regulated tariffs for several types of
service firm transportation service on a commodity
basis with reserve dedication, firm transportation service on a
commodity basis without reserve dedication to accommodate
temporary outages
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due to Hurricane Katrina, and traditional interruptible
transportation service. Discovery also offers another type of
service, traditional firm service with reservation fees, but
none of Discoverys customers currently contracts for this
transportation service. Please read Managements
Discussion and Analysis of Financial Condition and Results of
Operations Our Operations Gathering and
Processing Segment.
Discoverys maximum regulated rate for mainline
transportation is scheduled to decrease in 2008. At that time,
Discovery may be required to reduce its mainline transportation
rate on all of its contracts that have rates above the new
reduced rate. This could reduce the revenues generated by
Discovery. Discovery may elect to file a rate case with FERC to
alter this scheduled reduction. However, if filed, we cannot
assure you that a rate case would be successful in even
partially preventing the scheduled rate reduction. Please read
FERC Regulation.
Discoverys portfolio of processing contracts includes the
following types of contracts:
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Fee-based. Under fee-based contracts, Discovery receives
revenue based on the volume of natural gas processed and the
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Percent-of-liquids.
Under
percent-of-liquids gas
processing contracts, Discovery (1) processes natural gas
for customers, (2) delivers to customers an agreed upon
percentage of the NGLs extracted in processing and
(3) retains a portion of the extracted NGLs. Discovery
generates revenue from the sale of these retained NGLs to third
parties at market prices. Some of Discoverys
percent-of-liquids
contracts have a bypass option. Under contracts with
a bypass option, if customers elect not to process their natural
gas due to unfavorable processing economics, Discovery retains a
portion of the customers natural gas in lieu of NGLs as a
fee. Discovery may choose to process gas that a customer has
elected to bypass, but then must deliver natural gas with an
equivalent Btu content to the customer. |
Please read Managements Discussion and Analysis of
Financial Condition and Results of Operations Our
Operations Gathering and Processing
Segment Processing and Fractionation Contracts
for additional information on Discoverys contracts.
The Discovery pipeline system competes with other wellhead
to market delivery options available to offshore producers
in the Gulf of Mexico. While Discovery offers integrated
gathering, transportation, processing and fractionation services
through a single provider, it generally competes with other
offshore Gulf of Mexico gathering systems and interconnecting
gas processing and fractionation facilities, some of which may
have the same owner. On the continental shelf in shallow water,
Discoverys pipeline system competes primarily with the
MantaRay/ Nautilus system, the Trunkline system, the Tennessee
System and the Venice Gathering System. These competing shallow
water gathering systems connect to the following gas processing
and fractionation facilities: the MantaRay/ Nautilus System
connects to the Neptune gas processing plant, the Trunkline
pipeline connects to the Patterson and Calumet gas processing
plants, the Tennessee pipeline connects to the Yscloskey gas
processing plant, and the Venice Gathering System connects to
the Venice gas processing plant. In the deepwater region of the
Gulf of Mexico, the Discovery pipeline system competes primarily
with the Enterprise pipeline and the Cleopatra pipeline. The
Enterprise pipeline connects to the ANR/ Pelican gas processing
plant near Patterson, Louisiana, and the Cleopatra pipeline
connects to the Neptune plant in Centerville, Louisiana.
Approximately 60 offshore production blocks are currently
dedicated to the Discovery system. Recently connected blocks
include Murphys Front Runner discovery, Energy
Partners Rock Creek discovery and Apaches Tarantula
discovery. Additionally, Discovery signed definitive agreements
with certain producers to construct an approximate
35-mile gathering
pipeline lateral to connect Discoverys existing pipeline
system to these producers production facilities for the
Tahiti prospect described above. Furthermore, in areas that we
believe are accessible to the Discovery pipeline system,
approximately 600 deepwater blocks are currently
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leased and approximately 100 have related exploration plans
filed with the Minerals Management Service of the
U.S. Department of the Interior, or the MMS, or are named
prospects. A named prospect is an individual lease or group of
adjacent leases that are generally considered by a producer to
have some economic potential for production.
Gathering and Processing The Carbonate Trend
Pipeline
Our Carbonate Trend gathering pipeline is a sour gas gathering
pipeline consisting of approximately 34 miles of
12-inch diameter pipe
that is used to gather sour gas production from the Carbonate
Trend area off the coast of Alabama. Our Carbonate Trend
pipeline is not regulated under the Natural Gas Act but is
regulated under the Outer Continental Shelf Lands Act, which
requires us to transport gas supplies on the Outer Continental
Shelf on an open and non-discriminatory access basis.
Sour gas is natural gas that has relatively high
concentrations of acidic gases such as hydrogen sulfide and
carbon dioxide. Our pipeline is designed to transport gas with a
hydrogen sulfide and carbon dioxide content that exceeds normal
gas transportation specifications. The pipeline was built and
placed in service in 2000 and has a maximum design throughput
capacity of approximately 120 MMcf/d. For the year ended
December 31, 2005, our average transportation volume was
approximately 35 MMcf/d. For the three months ended
March 31, 2006, our average transportation volume was
approximately 33 MMcf/d.
Gas is shipped through our pipeline to Shells offshore
sour gas gathering pipeline and Yellowhammer sour gas treating
facility located onshore in Coden, Alabama. From the
Yellowhammer facility, treated gas can be delivered to the
Williams-owned Mobile Bay gas processing plant, which has
multiple pipeline interconnections to Transco, Florida Gas
Transmission, Gulfstream, Mobile Gas Services and GulfSouth
pipelines. Treated gas may also be delivered directly into the
GulfSouth or the Transco pipelines at the tailgate of the
Yellowhammer facility without processing.
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The following map shows the location of our Carbonate Trend
gathering pipeline, the Yellowhammer facility and Williams
Mobile Bay gas processing plant.
Our pipeline extends from Chevrons production platform
located at Viosca Knoll Block 251 to an interconnection
point with Shells offshore sour gas gathering facility
located at Mobile Bay Block 113. The pipeline is operated
by Chevron under an operating agreement. We contract with
Williams for the formulation of a corrosion control program to
ensure the maintenance and reliability of our pipeline. Due to
the corrosive nature of the sour gas, Williams has formulated
and Chevron has implemented a corrosion control program for the
Carbonate Trend pipeline. Please read Safety
and Maintenance.
Revenue from the Carbonate Trend pipeline is generated through
negotiated fees that we charge our customers to transport gas to
the Shell offshore sour gas gathering system. These fees
typically depend on the volume of gas we transport.
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Carbonate Trend Customers and Contracts |
Customers. Our primary customer on the Carbonate Trend
pipeline is Chevron, which, together with Noble Energy, has
large lease positions in the Carbonate Trend area. Chevron and
Noble Energy own an interest in more than 30 federal leases in
the Carbonate Trend area and Chevron is the operator for the
majority of these leases. For the year ended December 31,
2005 and the three months ended March 31, 2006, volumes
from these Chevron leases represented approximately 67% and 68%,
respectively, of Carbonate Trends total throughput and 74%
and 76%, respectively, of Carbonate Trends total revenue
with volumes from Noble Energy constituting the remainder. On
May 16, 2006, Noble Energy agreed to sell its Gulf of
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Mexico shelf assets to Coldren Resources LP. The sale is
expected to close during the second quarter of 2006.
Contracts. We have long-term transportation agreements
with Chevron and Noble Energy. Pursuant to these agreements,
Chevron and Noble Energy have agreed to transport on our
pipeline all gas produced on their 27 Carbonate Trend leases for
the life of the leases or the economic life of the underlying
reserves. There is no minimum volume requirement, and if the
leases held by Chevron and Noble Energy expire or the underlying
reserves are depleted, Chevron and Noble Energy will not be
committed to ship any natural gas on our pipeline. In addition,
if any lease expires, and is reacquired by the same company
within ten years of such expiration, all production from that
lease must again be transported via our pipeline. Under these
agreements Chevron and Noble Energy may make an annual election
to utilize capacity along a segment of Transco. When Chevron or
Noble Energy utilize this capacity, our per-unit gathering fee
is determined by subtracting FERC tariff-based rate charged by
Transco for this capacity from the total negotiated fee. If
these customers elect not to utilize the capacity along this
segment of Transco, we can make no assurance that this capacity
will be made available to these customers in the future. We have
the option to terminate these agreements if expenses exceed
certain levels or if revenues fall below certain levels and we
are not compensated for these expenses or shortfalls.
Other than the producer gathering lines that connect to the
Carbonate Trend pipeline, there are no other sour gas gathering
and transportation pipelines in the Carbonate Trend area, and we
know of no current plans to build competing pipelines. As a
result, as other blocks in the Carbonate Trend are developed, we
believe that producers will find it more cost effective to
connect to our pipeline than to construct or commission new sour
gas pipelines of their own.
Chevron developed the Viosca Knoll Carbonate Trend area in the
shallow waters of the Mobile and Viosca Knoll areas in the
eastern Gulf of Mexico. Chevron has filed several exploration
plans with the MMS that we believe could result in the discovery
of additional amounts of natural gas. Other producers may also
transport gas on the Carbonate Trend pipeline. If the
Yellowhammer facility becomes unavailable for the treatment of
our customers sour gas, we believe that we can construct
pipeline connections to access either of two third party-owned
treating facilities also located in Coden, Alabama.
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NGL Services The Conway Assets
Our Conway assets are strategically located at one of the two
major NGL trading hubs in the continental United States and
consist of:
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three integrated NGL storage facilities; and |
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a 50% interest in an NGL fractionator. |
The following map shows our Conway storage facilities, the
Conway fractionator, connecting NGL and mixed NGL pipelines and
competing storage and fractionation facilities.
General. We believe we are the largest NGL storage
facility, in terms of capacity, in the Mid-Continent Region. We
own and operate three integrated underground NGL storage
facilities in the Conway, Kansas area with an aggregate capacity
of approximately 20 million barrels, which we refer to as
the Conway West, Conway East and Mitchell storage
facilities. Each facility is comprised of a network of caverns
located several hundred feet below ground, and all three
facilities are connected by pipeline. The caverns hold large
volumes of NGLs and other hydrocarbons, such as propylene and
naphtha. We operate these assets as one coordinated facility.
Three lines connect the Mitchell facility to the Conway West
facility and two lines connect the Conway East facility to the
Conway West Facility. These facilities have a total brine pond
capacity of approximately 13 million barrels.
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Our Conway storage facilities interconnect directly with two
end-use interstate NGL pipelines: MAPL and the Kinder Morgan
pipeline. We also, through connections of less than a mile,
indirectly interconnect to two additional end-use interstate NGL
pipelines: the Kaneb pipeline and the ONEOK pipeline. Through
these pipelines and other storage facilities we can provide our
customers interconnectivity to additional interstate NGL
pipelines. We believe that the attributes of our storage
facilities, such as the number and size of our caverns and well
bores and our extensive brine system, coupled with our direct
connectivity to MAPL through multiple meters allows our
customers to inject, withdraw and deliver all of their products
stored in our facilities more rapidly than products stored with
our competitors.
Conway West. The Conway West facility located adjacent to
the Conway fractionation facility in McPherson County, Kansas is
our primary storage facility. This facility has an aggregate
storage capacity of approximately ten million barrels.
Conway East. The Conway East facility is located
approximately four miles east of the Conway West facility in
McPherson County, Kansas. The Conway East facility has an
aggregate storage capacity of approximately five million
barrels. The Conway East facility also has an active truck
loading and unloading facility, each with two spots, and a rail
loading and unloading facility with 20 spots.
Mitchell. The Mitchell facility is located approximately
14 miles west of the Conway West facility in Rice County,
Kansas and has an aggregate storage capacity of approximately
five million barrels.
Customers. Our NGL storage customers include NGL
producers, NGL pipeline operators, NGL service providers and NGL
end-users. Our three largest customers, which accounted for 65%
and 59% of our storage revenues in 2005 and the three months
ended March 31, 2006, respectively, are SemStream,
Enterprise and ONEOK, Inc. Enterprise is an NGL pipeline
operator, ONEOK is an NGL service provider, while SemStream is
principally involved in propane marketing and distribution.
Contracts. Our storage year for customer contracts runs
from April 1 to March 31. We lease capacity on varying
terms from less than six months to a year or more and have
additional capacity available to contract. Our storage revenues
are not generally affected by seasonality because our customers
generally pay for storage capacity, not injected or withdrawn
volumes.
We have long-term contracts with SemStream, Enterprise and
ONEOK, Inc. These three customers contract for approximately
seven million barrels of storage capacity per year for terms
that expire between 2009 and 2018. Each of these contracts is
based on a percentage of our published price of storage in our
Conway facilities, which we adjust annually.
Aside from our long-term contracts, most of our contracts are
for a period of one year. In addition, we also enter into
contracts for fungible product storage in increments of six
months, three months or one month. For contracts of one year or
less, our customers are required to remit the full contract
price at the time the contract is signed, which makes us less
susceptible to credit risks. One of our customers is the
beneficiary of an agreement, which terminates in 2019, that
provides this customer with a yearly $177,000 credit against
storage fees that it may incur in excess of the fees that it
incurs for its contracted storage.
We currently offer our customers four types of storage
contracts single product fungible, two product
fungible, multi-product fungible and segregated product
storage in various quantities and at varying terms.
Single product fungible storage allows customers to store a
single product. Two-product fungible storage allows customers to
store any combination of two fungible products. Multi-product
fungible storage allows customers to store any combination of
fungible products. In the case of two-product and multi-product
storage, the customer designates the quantity of storage space
for each product at the beginning of the lease period. Customers
may change their quantity configurations throughout the year
based upon our ability to accommodate each change. Segregated
storage also is available to customers who desire to store
non-fungible products at Conway, such as propylene, refinery
grade butane and naphtha. We evaluate pricing, volume and
availability for segregated storage on a case-by-case basis.
Segregated storage allows a customer to lease an entire storage
cavern and have its own product injected and withdrawn without
having its product commingled
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with the products of our other customers. In addition to the
fees we charge for fungible product storage and segregated
product storage, we also receive fees for overstorage.
We compete with other salt cavern storage facilities. Our most
direct competitor is a ONEOK-owned Bushton, Kansas storage
facility that is directly connected to a Kinder Morgan pipeline.
Other competitors include a ONEOK-owned facility in Conway,
Kansas, a NCRA-owned facility in Conway, Kansas, a ONEOK-owned
facility in Hutchinson, Kansas and an Enterprise Products
Partners-owned facility in Hutchinson, Kansas. We also compete
with storage facilities on the Gulf Coast and in Canada to the
extent that NGL product commodity prices differ between the
Mid-Continent region and those areas and interstate pipelines to
the extent that they offer storage services.
An increase in competition in the market could arise from new
ventures or expanded operations from existing competitors. Other
competitive factors include (1) the quantity, location and
physical flow characteristics of interconnected pipelines,
(2) the ability to offer service from multiple storage
locations, (3) the costs of service and rates of our
competitors and (4) NGL product commodity prices in the
Mid-Continent region as compared to prices in other regions.
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NGL Sources and Transportation Options |
We generally receive the NGLs that we inject into our
facilities, and our customers generally choose to transport the
NGLs that we withdraw from our facilities, through the
interstate NGL pipelines that interconnect with our storage
facilities, including MAPL, a Kinder Morgan pipeline, a Kaneb
pipeline and a ONEOK pipeline. We also receive substantially all
of the separated NGLs from our fractionator for storage and
further transportation through these interstate pipelines.
Additionally, our customers have the option to have NGLs
delivered to or transported from our storage facility, through
our active truck loading and unloading facility, each with two
spots, or our rail loading and unloading facility with 20 spots.
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The Conway Fractionation Facility |
General. The Conway fractionation facility is
strategically located at the junction of the south, east and
west legs of MAPL and has interconnections with the Buckeye
Partners, L.P. Wattenberg pipeline and the ConocoPhillips
Chisholm pipeline, each of which transports mixed NGLs to our
facility. The Conway fractionation facility began operations in
1973 with single production train. In 1977, a second train was
added and the capacity of the first train was upgraded, which
brought the total design capacity of the Conway fractionation
facility to approximately 107,000 bpd.
We own a 50% undivided interest in the Conway fractionation
facility, representing capacity of approximately
53,500 bpd. ConocoPhillips owns a 40% undivided interest,
representing capacity of approximately 42,800 bpd, and
ONEOK owns a 10% undivided interest, representing capacity of
approximately 10,700 bpd. Each joint owner markets its own
capacity independently. Each owner can also contract with the
other owners for additional capacity at the Conway fractionation
facility, if necessary. We are the operator of the facility
pursuant to an operating agreement that extends until May 2011.
We primarily fractionate NGLs for third party customers for a
fee based on the volumes of mixed NGLs fractionated. The
per-unit fee we charge is generally subject to adjustment for
changes in certain fractionation expenses, including natural
gas, electricity and labor costs, which are the principal
variable costs in NGL fractionation. As a result, we are
generally able to pass through increases in those fractionation
expenses to our customers. However, under one of our long-term
fractionation contracts described below, there is a cap on the
per-unit fee and, under current natural gas market conditions,
we are not able to pass through the full amount of increases in
variable expenses to this customer. In order to mitigate the
fuel price risk with respect to our purchases of natural gas
needed to perform under this contract, upon the closing of our
initial public offering, Williams transferred to us a contract
for the purchase of a sufficient quantity of natural gas from a
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wholly owned subsidiary of Williams at a price not to exceed a
specified price to satisfy our fuel requirements under this
fractionation contract. Please read Managements
Discussion and Analysis of Financial Condition and Results of
Operations Our Operations NGL Services
Segment Fractionation Contracts.
The results of operations of the Conway fractionation facility
are dependent upon the volume of mixed NGLs fractionated and the
level of fractionation fees charged. Overall, the NGL
fractionation business exhibits little to no seasonal variation
as NGL production is relatively constant throughout the year. We
have capacity available at our fractionation facility to
accommodate additional volumes.
Customers. We have long-term fractionation agreements
with BP and Enterprise, which together accounted for
approximately 64% and 66% of our NGL fractionation capacity at
the Conway facility for the year ended December 31, 2005
and the three months ended March 31, 2006, respectively.
Our other fractionation customers include Duke Energy Field
Services and Coffeyville Resources. Our four largest customers
for the year ended December 31, 2005 and the three months
ended March 31, 2006, were Williams Power Company,
SemStream, L.P., BP, and Enterprise. These entities accounted
for approximately 25.9%, 17.1%, 13.5% and 14.1%, respectively,
of our total revenue for the year ended December 31, 2005
and 36.1%, 12.4%, 9.8% and 15.7%, respectively, of our total
revenue for the three months ended March 31, 2006.
Contracts. We have a long-term contract with BP which
requires BP to deliver all of its proprietary mixed NGLs from
the Buckeye Partners, L.P. Wattenberg pipeline, which runs from
eastern Colorado to Bushton, Kansas, and its Hugoton, Kansas gas
processing plant to the Conway fractionator. There is no minimum
volume requirement, however, and if BPs Hugoton processing
plant and the Wattenberg pipeline were to cease operations for
any reason, BP would not be required to deliver any mixed NGLs
for fractionation under this agreement. BP accounted for
approximately 24.6%, 16.1% and 13.5% of our total revenue in
2003, 2004 and 2005, respectively, and approximately 9.8% of our
total revenue during the three months ended March 31, 2006.
The term of the agreement with respect to deliveries from the
Wattenberg pipeline expires on January 1, 2008 but will
automatically be renewed on a
year-to-year basis
unless otherwise terminated by the parties. The term of the
agreement with respect to deliveries from Hugoton expires on
January 1, 2013 and may be terminated effective
January 1, 2008 if either party provides notice of
termination before December 31, 2005. Pursuant to the terms
of this agreement, we provided notice of termination to BP in
July 2005.
Another long-term contract requires a customer to deliver all of
the mixed NGLs that customer purchases from Pioneers Texas
Panhandle and southwestern Kansas natural gas processing
facilities to the Conway fractionator if it chooses to ship its
mixed NGLs to the Mid-Continent region, as defined in the
agreement. However, if the customer chooses to ship its mixed
NGLs to another region, it has the right, on a
month-to-month basis,
to deliver its mixed NGLs elsewhere. The customers
decision on whether to ship its products to the Mid-Continent
region or to another region depends on factors including supply
and demand in the respective regions and the current price being
paid for fractionated products in each region. Deliveries of
mixed NGL products under this agreement have remained consistent
during the term of this agreement. This agreement expires in
2009.
We generally enter into contracts that cover a portion of our
remaining capacity at the Conway facility for periods of one
year or less.
Although competition for NGL fractionation services is primarily
based on the fractionation fee, the ability of an NGL
fractionator to obtain mixed NGLs and distribute NGL products
are also important competitive factors and are determined by the
existence of the necessary pipeline and storage infrastructure.
NGL fractionators connected to extensive storage, transportation
and distribution systems such as ours have direct access to
larger markets than those with less extensive connections. Our
principal competitors are a
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ONEOK-owned fractionator located in Medford, Oklahoma, a
ONEOK-owned fractionator located in Hutchinson, Kansas and a
ONEOK-owned fractionator located in Bushton, Kansas. We compete
with the two other joint owners of the Conway fractionation
facility for third party customers. We also compete with
fractionation facilities on the Gulf Coast, to the extent that
NGL product commodity prices differ between the Mid-Continent
region and the Gulf Coast.
An increase in competition in the market could arise from new
ventures or expanded operations from existing competitors. Other
competitive factors include (1) the quantity and location
of interconnected pipelines, (2) the costs and rates of our
competitors, (3) whether fractionation providers offer to
purchase a customers mixed NGLs instead of providing fee based
fractionation services and (4) NGL product commodity prices
in the Mid-Continent region as compared to prices in other
regions.
Based on EIA projections of relatively stable production levels
of natural gas in the Mid-Continent region over the next ten
years, we believe that sufficient volumes of mixed NGLs will be
available for fractionation in the foreseeable future. In
addition, through connections with MAPL and the Buckeye
Partners, L.P. Wattenberg pipeline, the Conway fractionation
facility has access to mixed NGLs from additional major supply
basins in North America, including additional major supply
basins in the Rocky Mountain production area.
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NGL Transportation Options |
After the mixed NGLs are separated at the fractionator, the NGL
products are typically transported to our storage facilities. At
our storage facilities, the NGLs may be stored or transported on
one of the interconnected NGL pipelines. Our customers also have
the option to have their NGL products transported through our
truck loading and rail loading facilities. Additionally, when
market conditions dictate, we have the ability to place propane
directly into MAPL from our fractionator, providing our
customers with expedited access to interstate markets.
Safety and Maintenance
Discoverys natural gas pipeline system is subject to
regulation by the United States Department of Transportation,
referred to as DOT, under the Accountable Pipeline and Safety
Partnership Act of 1996, referred to as the Hazardous Liquid
Pipeline Safety Act, and comparable state statutes with respect
to design, installation, testing, construction, operation,
replacement and management. The Hazardous Liquid Pipeline Safety
Act covers petroleum and petroleum products and requires any
entity that owns or operates pipeline facilities to comply with
such regulations, to permit access to and copying of records and
to file certain reports and provide information as required by
the United States Secretary of Transportation. These regulations
include potential fines and penalties for violations.
Discoverys gas pipeline system is also subject to the
Natural Gas Pipeline Safety Act of 1968 and the Pipeline Safety
Improvement Act of 2002. The Natural Gas Pipeline Safety Act
regulates safety requirements in the design, construction,
operation and maintenance of gas pipeline facilities while the
Pipeline Safety Improvement Act establishes mandatory
inspections for all United States oil and natural gas
transportation pipelines and some gathering lines in
high-consequence areas within ten years. The DOT has developed
regulations implementing the Pipeline Safety Improvement Act
that will require pipeline operators to implement integrity
management programs, including more frequent inspections and
other safety protections in areas where the consequences of
potential pipeline accidents pose the greatest risk to people
and their property. We currently estimate we will incur costs of
approximately $1.7 million between 2006 and 2008 to
implement integrity management program testing along certain
segments of Discoverys 16, 20, and
30-inch diameter
natural gas pipelines and its 10, 14, and
18-inch diameter NGL
pipelines. This does not include the costs, if any, of any
repair, remediation, preventative or mitigating actions that may
be determined to be necessary as a result of the testing program.
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States are largely preempted by federal law from regulating
pipeline safety but may assume responsibility for enforcing
federal intrastate pipeline regulations and inspection of
intrastate pipelines. In practice, states vary considerably in
their authority and capacity to address pipeline safety. We do
not anticipate any significant problems in complying with
applicable state laws and regulations in those states in which
we or the entities in which we own an interest operate.
Our natural gas pipelines have continuous inspection and
compliance programs designed to keep its facilities in
compliance with pipeline safety and pollution control
requirements. In compliance with applicable permit requirements,
we completed a survey of portions of our Carbonate Trend
pipeline. As a result of this survey, we have determined that it
will be necessary for us to undertake certain restoration
activities to repair the partial erosion of the pipeline
overburden caused by Hurricane Ivan in September 2004. We
estimate that the cost of these restoration activities will be
between $3.4 and $4.6 million and that they will be
completed by the end of 2006. In the omnibus agreement, Williams
agreed to reimburse us for the cost of these restoration
activities. We believe that our natural gas pipelines are in
material compliance with the applicable requirements of these
safety regulations.
Our Carbonate Trend pipeline requires a corrosion control
program to protect the integrity of the pipeline and prolong its
life. The corrosion control program consists of continuous
monitoring and injection of corrosion inhibitor into the
pipeline, periodic chemical treatments and annual detailed
comprehensive inspections. We believe that this is an aggressive
and proactive corrosion control program that will reduce metal
loss, limit corrosion and possibly extend the service life of
the pipe by 15 to 20 years.
In addition, we are subject to a number of federal and state
laws and regulations, including the federal Occupational Safety
and Health Act, referred to as OSHA, and comparable state
statutes, whose purpose is to protect the health and safety of
workers, both generally and within the pipeline industry. In
addition, the OSHA hazard communication standard, the EPA
community right-to-know
regulations under Title III of the federal Superfund
Amendment and Reauthorization Act and comparable state statutes
require that information be maintained about hazardous materials
used or produced in our operations and that this 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 point 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 requirements. We believe that we are in material
compliance with the OSHA regulations.
FERC Regulation
The Carbonate Trend sour gas gathering pipeline and the offshore
portion of Discoverys natural gas pipeline are subject to
regulation under the Outer Continental Shelf Lands Act, which
calls for nondiscriminatory transportation on pipelines
operating in the outer continental shelf region of the Gulf of
Mexico.
Portions of Discoverys natural gas pipeline are also
subject to regulation by FERC, under the Natural Gas Act. The
Natural Gas Act requires, among other things, that the rates be
just and reasonable and nondiscriminatory. Under the
Natural Gas Act, FERC has authority over the construction,
operation and expansion of interstate pipeline facilities, as
well as the terms and conditions of service provided by the
operator of such facilities. In general, Discovery must receive
prior FERC approval to construct, operate or expand its
FERC-regulated facilities, to initiate new service using such
facilities, to alter the terms and conditions of service
provided on such facilities, and to abandon service provided by
its FERC-regulated facilities. With respect to certain types of
construction activities and certain types of service, FERC has
issued rules that allow regulated pipelines to obtain blanket
authorizations that obviate the need for prior
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specific FERC approvals for initiating and abandoning service.
Commencing in 1992, FERC issued a series of orders, or Order
No. 636, which require interstate pipelines to provide
transportation service separate or unbundled from
the pipelines sales of gas. Order No. 636 also
required interstate pipelines, such as Discovery to provide open
access transportation on a non-discriminatory basis that is
equal for all similarly situated shippers. The Natural Gas Act
also gives FERC the authority to regulate the rates that
Discovery charges for service on portions of its natural gas
pipeline system. The natural gas pipeline industry has
historically been heavily regulated by federal and state
governments, and we cannot predict what further actions FERC,
state regulators, or federal and state legislators may take in
the future.
The Discovery 105-mile
mainline, approximately 60 miles of laterals and its market
expansion project are subject to regulation by FERC. The
following table shows the maximum transportation tariffs that
Discovery can charge on its regulated transportation pipelines:
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Discovery Asset |
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Mainline
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$0.1569/MMBtu through January 2008; |
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$0.08 thereafter |
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FERC-regulated laterals
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$0.039/MMBtu |
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Market expansion project
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$0.08/MMBtu |
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Under Discoverys current FERC-approved tariff, the maximum
rate that Discovery may charge its customers for the
transportation of natural gas along its mainline is $0.1569/
MMBtu. This maximum rate is scheduled to decrease in 2008 to
$0.08/ MMBtu. At that time, Discovery may be required to reduce
its mainline transportation rate on all of its contracts that
have rates above the new maximum rate. This could reduce the
revenues generated by Discovery. Discovery may elect to file a
rate case with FERC seeking to alter this scheduled reduction.
However, if filed, we cannot assure you that a rate case would
be successful in even partially preventing the scheduled rate
reduction.
In connection with a rate case filed by Discovery, all aspects
of its cost of service and rate design of its rates could be
reviewed, including the following:
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the overall cost of service, including operating costs and
overhead; |
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the allocation of overhead and other administrative and general
expenses to the rate; |
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the appropriate capital structure to be utilized in calculating
rates; |
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the appropriate rate of return on equity; |
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the cost of debt; |
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the rate base, including the proper starting rate base; |
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the throughput underlying the rate; and |
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the proper allowance for federal and state income taxes. |
In a decision issued in July 2004 involving an oil pipeline
limited partnership, BP West Coast Products, LLC v.
FERC, the United States Court of Appeals for the District of
Columbia Circuit upheld, among other things, FERCs
determination that certain rates of an interstate petroleum
products pipeline, SFPP, L.P., or SFPP, were grandfathered rates
under the Energy Policy Act of 1992 and that SFPPs
shippers had not demonstrated substantially changed
circumstances that would justify modification of those rates.
The court also vacated the portion of FERCs decision
applying the Lakehead policy. In its Lakehead
decision, FERC allowed an oil pipeline publicly traded
partnership to include in its
cost-of-service an
income tax allowance to the extent that its unitholders were
corporations subject to income tax. In May and June 2005, FERC
issued a statement of general policy, as well as an order on
remand of BP West Coast, respectively, in which it stated
it will permit pipelines to include in
cost-of-service a tax
allowance to reflect actual or potential tax liability on their
public utility income attributable to all partnership or limited
liability company interests, if the ultimate owner of the
interest has an actual or potential income tax liability on such
income. Whether a
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pipelines owners have such actual or potential income tax
liability will be reviewed by FERC on a case-by-case basis.
Although the new policy is generally favorable for pipelines
that are organized as pass-through entities, it still entails
rate risk due to the case-by-case review requirement. In
December 2005, FERC issued its first case-specific oil pipeline
review of the income tax allowance issue in the SFPP proceeding,
reaffirming its new income tax allowance policy and directing
SFPP to provide certain evidence necessary for the pipeline to
determine its income allowance. FERCs BP West Coast
remand decision and the new tax allowance policy have been
appealed to the D.C. Circuit. The FERC has not issued an order
determining the income tax allowance for SFPP. Therefore, the
ultimate outcome of these proceedings is not certain and could
result in changes to FERCs treatment of income tax
allowances in cost of service. If FERC were to disallow a
substantial portion of Discoverys income tax allowance, it
may be more difficult for Discovery to justify its rates.
These aspects of Discoverys rates also could be reviewed
if FERC or a shipper initiated a complaint proceeding. However,
we do not believe that it is likely that there will be a
challenge to Discoverys rates by a current shipper that
would materially affect its revenues or cash flows.
In 2000, FERC issued Order No. 637 which, among other
things:
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required pipelines to implement imbalance management services; |
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restricted the ability of pipelines to impose penalties for
imbalances, overruns and non-compliance with operational flow
orders; and |
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implemented a number of new pipeline reporting requirements. |
In addition, FERC implemented new regulations governing the
procedure for obtaining authorization to construct new pipeline
facilities and has issued a policy statement, which it largely
affirmed in a recent order on rehearing, establishing a
presumption in favor of requiring owners of new pipeline
facilities to charge rates based solely on the costs associated
with such new pipeline facilities. We cannot predict what
further action FERC will take on these matters. However, we do
not believe that Discovery will be affected by any action taken
previously or in the future on these matters materially
differently than other natural gas gatherers and processors with
which it competes.
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 such as Discovery. Order No. 2004 became
effective in 2004. Among other matters, Order No. 2004
requires interstate pipelines to operate independently from
their energy affiliates, prohibits interstate pipelines from
providing non-public transportation or shipper information to
their energy affiliates; prohibits interstate pipelines from
favoring their energy affiliates in providing service; and
obligates interstate pipelines to post on their websites a
number of items of information concerning the pipeline,
including its organizational structure, facilities shared with
energy affiliates, discounts given for transportation service,
and instances in which the pipeline has agreed to waive
discretionary terms of its tariff. Discovery requested and
received a partial waiver from certain portions of Order
No. 2004. Since the effective date of Order No. 2004,
Discovery has determined that additional waivers from compliance
with Order No. 2004 are necessary to accommodate the
management committee structure under which Discovery operates.
Discovery filed for additional limited waivers from Order
No. 2004 compliance on May 4, 2005 requesting a
limited waiver to permit three DEFS employees to be shared
between Discovery and DEFS and to provide information necessary
for DEFS to carry out its responsibilities as an owner of
Discovery. FERC has not yet acted on this filing.
The Carbonate Trend pipeline is a gathering pipeline, and is not
subject to FERC jurisdiction under the Natural Gas Act.
On August 8, 2005, Congress enacted the Energy Policy Act
of 2005, or EP Act 2005. Among other matters, EP Act
2005 amends the Natural Gas Act, or NGA, to add an
antimanipulation 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 provides FERC
with additional civil penalty authority. On January 19,
2006, the FERC issued Order No. 670, a rule implementing
the antimanipulation provision of EP Act 2005, and
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subsequently denied rehearing. The rules make it unlawful 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, for
any entity, directly or indirectly, to use or employ any device,
scheme or artifice to defraud; to make any untrue statement of
material fact or omit to make any such statement necessary to
make the statements made not misleading; or to engage in any act
or practice that operates as a fraud or deceit upon any person.
The new anti-manipulation rule does not apply to activities that
relate only to intrastate or other non-jurisdictional sales or
gathering, but does apply to activities of interstate gas
pipelines 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. EP Act 2005 also amends the NGA to give
FERC authority to impose civil penalties for violations of the
NGA 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. The antimanipulation
rule and enhanced civil penalty authority reflect an expansion
of the FERCs NGA enforcement authority. FERC has not yet
taken action pursuant to this enhanced authority. Additional
proposals and proceedings that might affect the natural gas
industry are pending before Congress, FERC and the courts. The
natural gas industry historically has been heavily regulated.
Accordingly, we cannot assure you that the less stringent and
pro-competition regulatory approach recently pursued by FERC and
Congress will continue.
The primary function of Discoverys natural gas processing
plant is the extraction of NGLs and the conditioning of natural
gas for marketing into the natural gas pipeline grid. FERC has
traditionally maintained that a processing plant that primarily
extracts NGLs is not a facility for transportation or sale of
natural gas for resale in interstate commerce and therefore is
not subject to its jurisdiction under the Natural Gas Act. We
believe that the natural gas processing plant is primarily
involved in removing NGLs and, therefore, is exempt from the
jurisdiction of FERC.
Environmental Regulation
Our operation of pipelines, plants and other facilities for
gathering, transporting, processing, treating or storing natural
gas, NGLs and other products is subject to stringent and complex
federal, state, and local laws and regulations governing the
discharge of materials into the environment, or otherwise
relating to the protection of the environment. Due to the myriad
of complex federal, state and local laws and regulations that
may affect us, directly or indirectly, you should not rely on
the following discussion of certain laws and regulations as an
exhaustive review of all regulatory considerations affecting our
operations.
As with the industry generally, compliance with existing and
anticipated laws and regulations increases our overall cost of
business, including our capital costs to construct, maintain,
and upgrade equipment and facilities. While these laws and
regulations affect our maintenance capital expenditures and net
income, we believe that they do not affect our competitive
position in that the operations of our competitors are similarly
affected. We believe that our operations are in material
compliance with applicable environmental laws and regulations.
However, these laws and regulations are subject to frequent, and
often times more stringent, change by regulatory authorities and
we are unable to predict the ongoing cost to us of complying
with these laws and regulations or the future impact of these
laws and regulations on our operations. Violation of
environmental laws, regulations and permits can result in the
imposition of significant administrative, civil and criminal
penalties, remedial obligations, injunctions and construction
bans or delays. A discharge of hydrocarbons or hazardous
substances into the environment could, to the extent the event
is not insured, subject us to substantial expense, including
both the cost to comply with applicable laws and regulations and
claims made by neighboring landowners and other third parties
for personal injury and property damage.
We or the entities in which we own an interest inspect the
pipelines regularly using equipment rented from third party
suppliers. Third parties also assist us in interpreting the
results of the inspections.
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In the omnibus agreement, Williams agreed to indemnify us in an
aggregate amount not to exceed $14.0 million, including any
amounts recoverable under our insurance policy covering
remediation costs and unknown claims at Conway, generally for
three years after the closing of our initial public offering in
August 2005, for certain environmental noncompliance and
remediation liabilities associated with the assets transferred
to us and occurring or existing before the closing date of our
initial public offering.
Our operations are subject to the Clean Air Act and comparable
state and local statutes. Amendments to the Clean Air Act
enacted in late 1990 require or will require most industrial
operations in the United States to incur capital expenditures in
order to meet air emission control standards developed by the
U.S. Environmental Protection Agency, or EPA, and state
environmental agencies. As a result of these amendments, our
facilities that emit volatile organic compounds or nitrogen
oxides are subject to increasingly stringent regulations,
including requirements that some sources install maximum or
reasonably available control technology. In addition, the 1990
Clean Air Act Amendments established a new operating permit for
major sources. Although we can give no assurances, we believe
that the expenditures needed for us to comply with the 1990
Clean Air Act Amendments will not have a material adverse effect
on our financial condition or results of operations.
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Hazardous Substances and Waste |
To a large extent, the environmental laws and regulations
affecting our operations relate to the release of hazardous
substances or solid wastes into soils, groundwater and surface
water, and include measures to control pollution of the
environment. These laws generally regulate the generation,
storage, treatment, transportation and disposal of solid and
hazardous waste. They also require corrective action, including
the investigation and remediation of certain units, at a
facility where such waste 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 the owner or operator 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 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 from the responsible
classes of persons the costs they incur. 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) that 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 federal Solid Waste
Disposal Act, the federal Resource Conservation and Recovery
Act, referred to as RCRA, and comparable state statutes. From
time to time, the EPA considers the adoption of stricter
disposal standards for wastes currently designated as
non-hazardous. 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 subject to more
rigorous and costly disposal requirements than non-hazardous
wastes. 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
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disposed of or released on or under the properties owned or
leased by us or on or under other locations where these
hydrocarbons and wastes have been taken for treatment or
disposal. In addition, certain of these properties have been
operated by third parties whose treatment and disposal or
release of hydrocarbons or other wastes was not under our
control. These properties and 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.
The Federal Water Pollution Control Act of 1972, as renamed and
amended as the Clean Water Act, also referred to as the CWA, and
analogous state laws impose restrictions and strict controls
regarding the discharge of pollutants into navigable waters.
Pursuant to the CWA and analogous state laws, permits must be
obtained to discharge pollutants into state and federal waters.
The CWA imposes substantial potential civil and criminal
penalties for non-compliance. State laws for the control of
water pollution also provide varying civil and criminal
penalties and liabilities. In addition, some states maintain
groundwater protection programs that require permits for
discharges or operations that may impact groundwater conditions.
The EPA has promulgated regulations that require us to have
permits in order to discharge certain storm water run-off. The
EPA has entered into agreements with certain states in which we
operate whereby the permits are issued and administered by the
respective states. These permits may require us to monitor and
sample the storm water run-off. 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 or results of operations.
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Hazardous Materials Transportation Requirements |
The DOT regulations affecting pipeline safety require pipeline
operators to implement measures designed to reduce the
environmental impact of discharge from onshore pipelines. These
regulations require operators to maintain comprehensive spill
response plans, including extensive spill response training for
pipeline personnel. In addition, the DOT regulations contain
detailed specifications for pipeline operation and maintenance.
We believe our operations are in substantial compliance with
these regulations. Please read Safety and
Maintenance.
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Kansas Department of Health and Environment
Obligations |
We currently own and operate underground storage caverns near
Conway, Kansas that have been created by solution mining the
caverns in the Hutchinson salt formation. These storage caverns
are used to store NGLs and other liquid hydrocarbons. These
caverns are subject to strict environmental regulation by the
Underground Storage Unit within the Bureau of Water, Geology
Section of the KDHE under the Underground Hydrocarbon and
Natural Gas Storage Program. The current revision of the
Underground Hydrocarbon and Natural Gas Storage regulations
became effective on April 1, 2003 (temporary) and
August 8, 2003 (permanent); these rules regulate the
storage of liquefied petroleum gas, hydrocarbons and natural gas
in bedded salt for the purpose of protecting public health and
safety, property and the environment and regulates the
construction, operation and closure of brine ponds associated
with our storage caverns. The regulations specify several
compliance deadlines including the final permit application for
existing hydrocarbon storage wells by April 1, 2006,
certain equipment requirements no later than April 1, 2008
and mechanical integrity and casing testing requirements by
April 1, 2010. Failure to comply with the Underground
Hydrocarbon and Natural Gas Storage Program may lead to the
assessment of administrative, civil or criminal penalties.
We are in the process of modifying our Conway storage
facilities, including the caverns and brine ponds, and we
believe that our storage operations will be in compliance with
the Underground Hydrocarbon and Natural Gas Storage Program
regulations by the applicable compliance dates. In 2003, we
began to complete workovers on approximately 30 to 40 salt
caverns per year and install, on average, a double liner on one
brine pond per year. The incremental costs of these activities
is approximately $5.5 million per year to complete the
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workovers and approximately $1.0 million per year to
install a double liner on a brine pond. In response to these
increased costs, we raised our storage rates by an amount
sufficient to preserve our margins in this business.
Accordingly, we do not believe that these increased costs have
had a material effect on our business or results of operations.
We expect on average to complete workovers on each of our
caverns every five to ten years and install double liners on
each of our brine ponds every 18 years.
Additionally, we are currently undergoing remedial activities
pursuant to KDHE Consent Orders issued in the early 1990s. The
Consent Orders were issued after elevated concentrations of
chlorides were discovered in various
on-site and off-site
shallow groundwater resources at each of our Conway storage
facilities. With KDHE approval, we are currently installing and
implementing a containment and monitoring system to delineate
further the scope of and to arrest the continued migration of
the chloride plume at the Mitchell facility. Investigation and
delineation of chloride impacts is ongoing at the two Conway
area facilities as specified in their respective consent orders.
One of these facilities is located near the Groundwater
Management District No. 2s jurisdictional boundary of
the Equus Beds aquifer. At the other Conway area facility,
remediation of residual hydrocarbon derivatives from a historic
pipeline release is included in the consent order required
activities.
Although not mandated by any consent order, we are currently
cooperating with the KDHE and other area operators in an
investigation of fugitive NGLs observed in the subsurface at the
Conway Underground East facility. In addition, we have also
recently detected fugitive NGLs in groundwater monitoring wells
adjacent to two abandoned storage caverns at the Conway West
facility. Although the complete extent of the contamination
appears to be limited and appears to have been arrested, we are
continuing to work to delineate further the scope of the
contamination. To date, the KDHE has not undertaken any
enforcement action related to the releases around the abandoned
storage caverns.
We are continuing to evaluate our assets to prevent future
releases. While we maintain an extensive inspection and audit
program designed, as appropriate, to prevent and to detect and
address such releases promptly, there can be no assurance that
future environmental releases from our assets will not have a
material effect on us.
Title to Properties and
Rights-of-Way
Our real property falls into two categories:
(1) parcels that we own in fee, such as land at the Conway
fractionation and storage facility, and (2) parcels in
which our interest derives from leases, easements,
rights-of-way, permits
or licenses from landowners or governmental authorities
permitting the use of such land for our operations. The fee
sites upon which major facilities are located have been owned by
us or our predecessors in title for many years without any
material challenge known to us relating to the title to the land
upon which the assets are located, and we believe that we have
satisfactory title to such fee sites. We have no knowledge of
any challenge to the underlying fee title of any material lease,
easement, right-of-way
or license held by us or to our title to any material lease,
easement, right-of-way,
permit or lease, and we believe that we have satisfactory title
to all of our material leases, easements,
right-of-way and
licenses.
Employees
We do not have any employees. We are managed and operated by the
directors and officers of our general partner. To carry out our
operations, as of December 31, 2005, our general partner or
its affiliates employed approximately 36 people who will spend
at least a majority of their time operating the Conway and
Carbonate Trend facilities and approximately 30 general and
administrative full-time equivalent employees in support of
these operations. Discovery is operated by Williams pursuant to
an operating and maintenance agreement and the employees who
operate the Discovery assets are therefore not included in the
above numbers. Please read Management
Management of Williams Partners L.P. and Certain
Relationships and Related Transactions Discovery
Operating and Maintenance Agreements.
Legal Proceedings
We are not a party to any legal proceeding but are a party to
various administrative and regulatory proceedings that have
arisen in the ordinary course of our business. Please read
FERC Regulation and
Environmental Regulation.
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MANAGEMENT
Management of Williams Partners L.P.
Williams Partners GP LLC, as our general partner, manages our
operations and activities. Our general partner is not elected by
our unitholders and is not subject to re-election on a regular
basis in the future. Unitholders are not entitled to elect the
directors of our general partner or directly or indirectly
participate in our management or operation.
Our general partner owes a fiduciary duty to our unitholders.
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. Whenever possible, our general partner
intends to incur indebtedness or other obligations that are
nonrecourse.
Three members of the board of directors of our general partner
serve on a conflicts committee to review specific matters that
the board believes may involve conflicts of interest. The
conflicts committee will determine if the resolution of the
conflict of interest is fair and reasonable to us. The members
of the conflicts committee may not be officers or employees of
our general partner or directors, officers, or employees of its
affiliates, and must meet the independence and experience
standards established by the New York Stock Exchange and
the Sarbanes-Oxley Act of 2002 and other federal securities
laws. Any matters approved by the conflicts 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, we have an audit committee of three independent
directors that review our external financial reporting,
recommend engagement of our independent auditors and review
procedures for internal auditing and the adequacy of our
internal accounting controls. We also have a compensation
committee, consisting of three independent members, with the
limited function of administering our long-term incentive plan
and any future compensation plans. Please read
Long-Term Incentive Plan.
We are managed and operated by the directors and officers of our
general partner. All of our operational personnel are employees
of an affiliate of our general partner.
All of the senior officers of our general partner are also
senior officers of Williams and spend a sufficient amount of
time overseeing the management, operations, corporate
development and future acquisition initiatives of our business.
Alan Armstrong, the chief operating officer of our general
partner, is the principal executive responsible for the
oversight of our affairs. Our non-executive directors will
devote as much time as is necessary to prepare for and attend
board of directors and committee meetings.
Directors and Executive Officers of Our General Partner
The following table shows information for the directors and
executive officers of our general partner as of May 15,
2006.
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Position with Williams Partners GP LLC |
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Steven J. Malcolm
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57 |
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Chairman of the Board and Chief Executive Officer |
Donald R. Chappel
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54 |
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Chief Financial Officer and Director |
Alan S. Armstrong
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43 |
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Chief Operating Officer and Director |
James J. Bender
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49 |
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General Counsel |
Thomas C. Knudson
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60 |
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Director and Member of Audit, Conflicts and Compensation
Committees |
Bill Z. Parker
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59 |
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Director and Member of Audit, Conflicts and Compensation
Committees |
Alice M. Peterson
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53 |
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Director and Member of Audit, Conflicts and Compensation
Committees |
Phillip D. Wright
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50 |
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Director |
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The directors of our general partner are elected for one-year
terms and hold office until the earlier of their death,
resignation, removal or disqualification or until their
successors have been elected and qualified. Officers serve at
the discretion of the board of directors of our general partner.
There are no family relationships among any of the directors or
executive officers of our general partner.
Steven J. Malcolm has served as the chairman of the board
of directors and chief executive officer of our general partner
since February 2005. Mr. Malcolm has served as president of
Williams since September 2001, chief executive of Williams since
January 2002, and chairman of the board of directors of Williams
since May 2002. From May 2001 to September 2001, he served as
executive vice president of Williams. From December 1998 to May
2001, he served as president and chief executive officer of
Williams Energy Services, LLC. From November 1994 to December
1998, Mr. Malcolm served as the senior vice president and
general manager of Williams Field Services Company.
Mr. Malcolm served as chief executive officer and chairman
of the board of directors of the general partner of Williams
Energy Partners L.P. from the initial public offering in
February 2001 of Williams Energy Partners L.P. (now known as
Magellan Midstream Partners, L.P.) to the sale of Williams
interests therein in June 2003. Mr. Malcolm has served as a
member of the board of directors of BOK Financial Corporation
since 2002. Mr. Malcolm has been named as a defendant in
numerous shareholder class action suits that have been filed
against Williams. These class actions include issues related to
the spin-off of WilTel Communications, a previously-owned
subsidiary of Williams, Williams Power Company, and public
offerings in January 2001, August 2001 and January 2002, known
as the FELINE PACS offering. Additionally, four class action
complaints were filed against Williams, certain committee
members and certain members of the Williams board of directors,
including Mr. Malcolm, under the Employee Retirement Income
Security Act of 1974, or ERISA, by participants in
Williams Investment Plus Plan. Final court approval of the
ERISA litigation and dismissal with prejudice occurred in
November 2005.
Donald R. Chappel has served as the chief financial
officer and a director of our general partner since February
2005. Mr. Chappel has served as senior vice president and
chief financial officer of Williams since April 2003. From 2000
to April 2003, Mr. Chappel founded and served as chief
executive officer of a development business in Chicago,
Illinois. From 1987 though February 2000, Mr. Chappel
served in various financial, administrative and operational
leadership positions for Waste Management, Inc., including twice
serving as chief financial officer, during 1997 and 1998 and
most recently during 1999 through February 2000.
Alan S. Armstrong has served as the chief operating
officer and a director of our general partner since February
2005. Mr. Armstrong has served as a senior vice president
of Williams since February 2002 responsible for heading
Williams midstream business unit. From 1999 to February
2002, Mr. Armstrong was vice president, gathering and
processing in Williams midstream business unit and from
1998 to 1999 was vice president, commercial development in
Williams midstream business unit. From 1997 to 1998,
Mr. Armstrong was vice president of retail energy in
Williams energy services business unit. Prior to this,
Mr. Armstrong served in various operations, engineering and
commercial leadership roles within Williams.
James J. Bender has served as the general counsel of our
general partner since February 2005. Mr. Bender has served
as senior vice president and general counsel of Williams since
December 2002. From June 2000 until joining Williams,
Mr. Bender was senior vice president and general counsel
with NRG Energy, Inc. Mr. Bender was vice president,
general counsel and secretary of NRG Energy from June 1997 to
June 2000. NRG Energy filed a voluntary bankruptcy petition
during 2003 and its plan of reorganization was approved in
December 2003.
Thomas C. Knudson has served as a director of our general
partner since November 2005. Mr. Knudson has served as a
member of the board of directors of Bristow Group Inc. (formerly
Offshore Logistics, Inc.), a leading provider of helicopter
transportation services to the oil and gas industry, since
January 2004. Mr. Knudson has also served as a director of
NATCO Group Inc., a leading provider of wellhead process
equipment, systems and services used in the production of oil
and gas, since April 2005. From 2000 to 2003, Mr. Knudson
was a senior vice president of ConocoPhillips.
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Bill Z. Parker has served as a director of our general
partner since August 2005. Mr. Parker has served as a
director for Latigo Petroleum, Inc., a privately-held
independent oil and gas production company, since January 2003.
From April 2000 to November 2002, Mr. Parker served as
executive vice president of Phillips Petroleum Companys
worldwide upstream operations. Mr. Parker was executive
vice president of Phillips Petroleum Companys worldwide
downstream operations from September 1999 to April 2000.
Alice M. Peterson has served as a director of our general
partner since September 2005. Ms. Peterson is the president
of Syrus Global, a provider of ethics, compliance and reputation
management solutions. Ms. Peterson has served as a director
for RIM Finance, LLC, a wholly owned subsidiary of Research In
Motion, Ltd., the maker of the
BlackBerrytm
handheld device, since 2000. Ms. Peterson served as a
director of TBC Corporation, a marketer of private branded
replacement tires, from July 2005 to November 2005, when it was
acquired by Sumitomo Corporation of America. From 1998 to August
2004, she served as a director of Fleming Companies. From
December 2000 to December 2001, Ms. Peterson served as
president and general manager of RIM Finance, LLC. From April
2000 to September 2000, Ms. Peterson served as the chief
executive officer of Guidance Resources.com, a
start-up business
focused on providing online behavioral health and concierge
services to employer groups and other associations. From 1998 to
2000, Ms. Peterson served as vice president of Sears Online
and from 1993 to 1998, as vice president and treasurer of Sears,
Roebuck and Co. Following the bankruptcy of Fleming Companies in
2003, Ms. Peterson was named as a defendant, along with
each other member of the companys board of directors, in a
securities class action. The case was settled and all claims
against Ms. Peterson were released and dismissed after the
courts approval of the settlement which became a final
judgment in December 2005. Ms. Peterson has also been named
as a defendant, along each other member of the board of
directors of Fleming Companies, in connection with a claim by
trade creditors of Dunigan Fuels (a subsidiary of the former
Fleming Companies) for conspiracy to breach fiduciary
duties.
Phillip D. Wright has served as a director of our general
partner since February 2005. Mr. Wright has served as
senior vice president of Williams gas pipeline operations
since January 2005. From October 2002 to January 2005,
Mr. Wright served as chief restructuring officer of
Williams. From September 2001 to October 2002, Mr. Wright
served as president and chief executive officer of Williams
Energy Services. From 1996 to September 2001, Mr. Wright
was senior vice president, enterprise development and planning
for Williams energy services group. From 1989 to 1996,
Mr. Wright served in various capacities for Williams.
Mr. Wright served as president, chief operating officer and
director of the general partner of Williams Energy Partners L.P.
from the initial public offering in February 2001 of Williams
Energy Partners L.P. (now known as Magellan Midstream Partners,
L.P.) to the sale of Williams interests therein in June
2003. Mr. Wright has been named as a defendant in four
class action complaints filed under ERISA against Williams,
certain members of the benefits and investment committees and
certain members of the Williams board of directors, by
participants in Williams Investment Plus Plan. Final court
approval of the ERISA litigation and dismissal with prejudice
occurred in November 2005.
Executive Compensation
Williams Partners L.P. and our general partner were formed in
February 2005. We have no employees. We are managed by the
officers of our general partner. We reimburse Williams for
direct and indirect general and administrative expenses incurred
on our behalf. For the fiscal year ended December 31, 2005,
Williams allocated approximately $22,341 of salary and bonus
expense to us (and our predecessor for the portion of the year
prior to our formation) for Steven J. Malcolm, the chairman of
the board and chief executive officer of our general partner,
and approximately $27,659 for all other expenses related to his
compensation. For the fiscal year ended December 31, 2004,
Williams allocated approximately $19,846 of salary and bonus
expense to our predecessor for Mr. Malcolm and
approximately $14,873 for all other expenses related to his
compensation. Allocated expenses related to
Mr. Malcolms compensation other than salary and bonus
included Williams deferred stock awards, matching contributions
made under a Williams 401(k) plan and premiums for life
insurance. We also allocated a portion of Williams
expenses related to perquisites which did not exceed $50,000 or
10% of Mr. Malcolms salary and bonus from Williams.
The foregoing amounts exclude expenses allocated by Williams to
Discovery. Total compensation received by Mr. Malcolm, who
is
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also the chairman, president and chief executive officer of
Williams, is set forth in the proxy statement for Williams
2006 annual meeting of stockholders which is available on the
SECs website at http://www.sec.gov and on
Williams website at http://www.williams.com under
the heading Investors SEC Filings. No
other executive officer of our general partner received salary
and bonus compensation allocable to us or our predecessor in
excess of $100,000 and no awards were granted to our general
partners executive officers under the Williams Partners GP
LLC Long-Term Incentive Plan in 2004 or 2005.
Employment Agreements
The executive officers of our general partner are also executive
officers of Williams. These executive officers do not have
employment agreements in their capacity as officers of our
general partner.
Compensation of Directors
Members of the board of directors of our general partner who are
also officers or employees of our affiliates do not receive
additional compensation for serving on the board of directors.
Subject to the proration provisions of the policy, members of
the board of directors who are not officers or employees of our
affiliates (each a Non-Employee Director) each
receive an annual compensation package consisting of the
following: (a) $50,000 cash; (b) restricted units
representing limited partnership interests in us valued at
$25,000; and (c) $5,000 cash each for service on the
conflicts and audit committees of the board. In addition, each
Non-Employee Director receives a one-time grant of restricted
units valued at $25,000. Restricted units are granted under the
Williams Partners GP LLC Long-Term Incentive Plan and vest
180 days after the date of grant. Cash distributions will
be paid on the restricted units granted to the Non-Employee
Directors. Each Non-Employee Director is reimbursed for
out-of-pocket expenses
in connection with attending meetings of the board of directors
or its committees. Each director will be fully indemnified by us
for actions associated with being a director to the extent
permitted under Delaware law. We also reimburse Non-Employee
directors for the costs of education programs relevant to their
duties as board members.
Long-Term Incentive Plan
In connection with our initial public offering, our general
partner adopted the Williams Partners GP LLC Long-Term Incentive
Plan for employees, consultants and directors of our general
partner and employees and consultants of its affiliates who
perform services for our general partner or its affiliates. To
date, the only grants under the plan have been grants of
restricted units to Non-Employee Directors. The long-term
incentive plan consists of four components: restricted units,
phantom units, unit options and unit appreciation rights. The
long-term incentive plan currently permits the grant of awards
covering an aggregate of 700,000 units. The plan is
administered by the compensation committee of the board of
directors of our general partner.
Our general partners board of directors, or its
compensation committee, in its discretion may terminate, suspend
or discontinue the long-term incentive plan at any time with
respect to any award that has not yet been granted. Our general
partners board of directors, or its compensation
committee, also has the right to alter or amend the long-term
incentive plan or any part of the plan from time to time,
including increasing the number of units that may be granted
subject to unitholder approval as required by the exchange upon
which the common units are listed at that time. However, no
change in any outstanding grant may be made that would
materially impair the rights of the participant without the
consent of the participant.
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Restricted Units and Phantom Units |
A restricted unit is a common unit subject to forfeiture prior
to the vesting of the award. 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 the
compensation committee, cash equivalent to the value of a common
unit. The compensation committee may determine to make grants
under the plan of restricted units and phantom units to
employees, consultants and directors containing such terms as
the compensation committee shall determine. The compensation
committee determines the period over which restricted units and
phantom units granted to employees, consultants and directors
will vest. The committee may base its determination upon the
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achievement of specified financial objectives. In addition, the
restricted units and phantom units will vest upon a change of
control of Williams Partners L.P., our general partner or
Williams, unless provided otherwise by the compensation
committee.
If a grantees employment, service relationship or
membership on the board of directors terminates for any reason,
the grantees restricted units and phantom units will be
automatically forfeited unless, and to the extent, the
compensation committee provides otherwise. Common units to be
delivered in connection with the grant of restricted units or
upon the vesting of phantom units may be common units acquired
by our general partner on 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 is entitled to
reimbursement by us for the cost incurred in acquiring common
units. Thus, the cost of the restricted units and delivery of
common units upon the vesting of phantom units will be borne by
us. If we issue new common units in connection with the grant of
restricted units or upon vesting of the phantom units, the total
number of common units outstanding will increase. The
compensation committee, in its discretion, may grant tandem
distribution rights with respect to restricted units and tandem
distribution equivalent rights with respect to phantom units.
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Unit Options and Unit Appreciation Rights |
The long-term incentive plan permits the grant of options
covering common units and the grant of unit appreciation rights.
A unit appreciation right is an award that, upon exercise,
entitles the participant to receive the excess of the fair
market value of a unit on the exercise date over the exercise
price established for the unit appreciation right. Such excess
may be paid in common units, cash, or a combination thereof, as
determined by the compensation committee in its discretion. The
compensation committee may make grants of unit options and unit
appreciation rights under the plan to employees, consultants and
directors containing such terms as the committee shall
determine. Unit options and unit appreciation rights may not
have an exercise price that is less than the fair market value
of the common units on the date of grant. In general, unit
options and unit appreciation rights granted will become
exercisable over a period determined by the compensation
committee. In addition, the unit options and unit appreciation
rights will become exercisable upon a change in control of
Williams Partners L.P., our general partner or Williams, unless
provided otherwise by the committee. The compensation committee,
in its discretion may grant tandem distribution equivalent
rights with respect to unit options and unit appreciation rights.
Upon exercise of a unit option (or a unit appreciation right
settled in common units), our general partner will acquire
common units on the open market or directly from us or any other
person or use common units already owned by our general partner,
or any combination of the foregoing. Our general partner will be
entitled to reimbursement by us for the difference between the
cost incurred by our general partner in acquiring these common
units and the proceeds received from a participant at the time
of exercise. Thus, the cost of the unit options (or a unit
appreciation right settled in common units) will be borne by us.
If we issue new common units upon exercise of the unit options
(or a unit appreciation right settled in common units), the
total number of common units outstanding will increase, and our
general partner will pay us the proceeds it receives from an
optionee upon exercise of a unit option. The availability of
unit options and unit appreciation rights is intended to furnish
additional compensation to employees, consultants and directors
and to align their economic interests with those of common
unitholders.
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Reimbursement of Expenses of Our General Partner
Our general partner will not receive any management fee or other
compensation for its management of Williams Partners L.P. Our
general partner and its affiliates are reimbursed for expenses
incurred on our behalf, including the compensation of employees
of an affiliate of our general partner that perform services on
our behalf. These expenses include all expenses necessary or
appropriate to the conduct of the business of, and allocable to,
Williams Partners L.P. Our partnership agreement provides that
our general partner will determine in good faith the expenses
that are allocable to Williams Partners L.P. There is no cap on
the amount that may be paid or reimbursed to our general partner
for compensation or expenses incurred on our behalf, except that
pursuant to the omnibus agreement, Williams will provide a
partial credit for general and administrative expenses that we
incur for a period of five years following our initial public
offering in August 2005. Please read Certain Relationships
and Related Transactions Omnibus Agreement.
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HOW WE MAKE CASH DISTRIBUTIONS
General
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Rationale for our Cash Distribution Policy |
Our cash distribution policy reflects a basic judgment that our
unitholders will be better served by distributing our available
cash rather than retaining it. Our available cash includes cash
generated from the operation of our assets and businesses, which
include the gathering, transporting and processing of natural
gas and the fractionating and storing of NGLs, as described
elsewhere in this prospectus. Our cash distribution policy is
consistent with the terms of our partnership agreement, which
requires that we distribute all of our available cash on a
quarterly basis. Because we are not subject to an entity-level
federal income tax, we have more cash to distribute to you than
would be the case if we were subject to such tax.
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Limitations on Our Ability to Make Quarterly
Distributions |
There is no guarantee that unitholders will receive quarterly
distributions from us. Our distribution policy may become
subject to limitations and restrictions and may be changed at
any time, including:
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Our board of directors has broad discretion to establish
reserves for the prudent conduct of our business and the
establishment of those reserves could result in a reduction in
the amount of cash available to pay distributions. |
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Although our ability to make distributions is not currently
restricted under Williams revolving credit agreement,
Williams other debt instruments or our working capital
facility with Williams, we or Williams may enter into future
debt arrangements that could subject our ability to pay
distributions to compliance with certain tests or ratios or
otherwise restrict our ability to pay distributions. |
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Our ability to make distributions of available cash will depend,
to a significant extent, on Discoverys and Four
Corners ability to make cash distributions to us. In
addition, although Discoverys limited liability company
agreement has been, and Four Corners limited liability
company agreement will be, amended to provide for quarterly
distributions of available cash, Discovery and Four Corners have
a limited history of making distributions to their respective
members. Discoverys and Four Corners management
committees, on which we are and will be represented, have broad
discretion to establish reserves for the prudent conduct of
their respective businesses. The establishment of those reserves
could result in a reduction in Discoverys and Four
Corners cash available to pay distributions, which could
cause a corresponding reduction in the amount of our cash
available to pay distributions. |
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Even if our cash distribution policy is not modified, the amount
of distributions we pay and the decision to make any
distribution is at the discretion of our general partner, taking
into consideration the terms of our partnership agreement. |
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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. |
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Although our partnership agreement requires us to distribute our
available cash, our partnership agreement, including provisions
requiring us to make cash distributions contained therein, may
be amended. Although during the subordination period, with
certain exceptions, our partnership agreement may not be amended
without approval of nonaffiliated common unitholders, our
partnership agreement can be amended with the approval of a
majority of the outstanding common units after the subordination
period has ended. After this offering, Williams will own
approximately 8.9% of the outstanding common units and 100% of
the outstanding subordinated units. |
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Our Cash Distribution Policy May Limit Our Ability to
Grow |
Because we distribute all of our available cash, our growth may
not be as fast as businesses that reinvest their available cash
to expand ongoing operations. We intend generally to rely upon
external financing sources, including borrowings and issuances
of debt and equity securities, to fund our acquisition and growth
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capital expenditures. However, to the extent we are unable to
finance growth externally, our cash distribution policy will
significantly impair our ability to grow.
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Discoverys Cash Distribution Policy |
A substantial portion of our cash available to pay distributions
is cash we receive as distributions from Discovery. As in our
partnership agreement, Discoverys limited liability
company agreement, as amended, provides for the distribution of
available cash on a quarterly basis, with available cash defined
to mean, for each fiscal quarter, cash generated from
Discoverys business less reserves that are necessary or
appropriate to provide for the conduct of its business and to
comply with applicable law or any debt instrument or other
agreement to which it is a party. Under Discoverys limited
liability company agreement, the amount of Discoverys
quarterly distributions, including the amount of cash reserves
not distributed, is determined by the members of
Discoverys management committee representing a
majority-in-interest in
Discovery. We own a 40% interest in Discovery, and an affiliate
of Williams owns a 20% interest in Discovery. Discoverys
limited liability agreement may only be amended with the
unanimous approval of all its members.
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Four Corners Cash Distribution Policy |
A substantial portion of our cash available to pay distributions
will be cash we receive as distributions from Four Corners. Four
Corners limited liability company agreement, as amended
effective as of the closing of this offering, provides for the
distribution of available cash at least quarterly, with
available cash defined to mean, for each fiscal quarter, cash
generated from Four Corners business less reserves that
are necessary or appropriate to provide for the conduct of its
business and to comply with applicable law or any debt
instrument or other agreement to which it is a party. Under Four
Corners limited liability company agreement, the amount of
Four Corners quarterly distributions, including the amount
of cash reserves not distributed, will be determined by the
members of Four Corners management committee representing
a majority-in-interest
in Four Corners. We will own a 25.1% interest in Four Corners,
and an affiliate of Williams will own a 74.9% interest in Four
Corners. Four Corners limited liability agreement may only
be amended with the unanimous approval of all its members.
Operating Surplus and Capital Surplus
All cash distributed to unitholders will be characterized as
either operating surplus or capital
surplus. We treat distributions of available cash from
operating surplus differently than distributions of available
cash from capital surplus.
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Definition of Available Cash |
We define available cash in the glossary, and it generally
means, for each fiscal quarter all cash on hand at the end of
the quarter:
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less the amount of cash reserves established by our general
partner to: |
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provide for the proper conduct of our business (including
reserves for future capital expenditures and for our anticipated
credit needs); |
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comply with applicable law, any of our debt instruments or other
agreements; or |
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provide funds for distribution to our unitholders and to our
general partner for any one or more of the next four quarters; |
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plus all cash on hand on the date of determination of available
cash for the quarter resulting from working capital borrowings
made after the end of the quarter for which the determination is
being made. Working capital borrowings are generally borrowings
that will be made under our working capital facility with
Williams and in all cases are used solely for working capital
purposes or to pay distributions to partners. |
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Definition of Operating Surplus |
We define operating surplus in the glossary, and for any period
it generally means:
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our cash balance of $12.8 million on the closing date of
our initial public offering, excluding amounts retained from the
proceeds of our initial public offering to make a capital
contribution to Discovery to fund an escrow account required in
connection with the Tahiti pipeline lateral expansion project;
plus |
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$10.0 million; plus |
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all of our cash receipts after the closing of our initial public
offering, excluding (1) cash from borrowings that are not
working capital borrowings, (2) sales of equity and debt
securities and (3) sales or other dispositions of assets
outside the ordinary course of business; plus |
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working capital borrowings made after the end of a quarter but
before the date of determination of operating surplus for the
quarter; less |
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all of our operating expenditures after the closing of our
initial public offering (including the repayment of working
capital borrowings, but not the repayment of other borrowings)
and maintenance capital expenditures (including capital
contributions to Discovery to be used by Discovery for
maintenance capital expenditures); less |
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the amount of cash reserves established by our general partner
for future operating expenditures. |
Please read Managements Discussion and Analysis of
Financial Condition and Results of Operations
Financial Condition and Liquidity.
Because operating surplus is a cash accounting concept, the
benefit that we receive from our gas purchase contract with a
subsidiary of Williams and the partial credit for general and
administrative expenses and other reimbursements we receive from
Williams under the omnibus agreement will be part of our
operating surplus.
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 $10.0 million of cash we receive in the future from
non-operating sources, such as asset sales, issuances of
securities, and long-term borrowings, that would otherwise be
distributed as capital surplus.
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Definition of Capital Surplus |
We also define capital surplus in the glossary, and it will
generally be generated only by:
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borrowings other than working capital borrowings; |
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sales of debt and equity securities; and |
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sales or other disposition of assets for cash, other than
inventory, accounts receivable and other current assets sold in
the ordinary course of business or non-current assets sold as
part of normal retirements or replacements of assets. |
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Characterization of Cash Distributions |
We will treat all available cash distributed as coming from
operating surplus until the sum of all available cash
distributed since we began operations equals the operating
surplus as of the most recent date of determination of available
cash. We will treat any amount distributed in excess of
operating surplus, regardless of its source, as capital surplus.
We do not anticipate that we will make any distributions from
capital surplus.
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Subordination Period
During the subordination period, which we define below and in
the glossary, the common units will have the right to receive
distributions of available cash from operating surplus in an
amount equal to the minimum quarterly distribution of
$0.35 per quarter, 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.
Distribution arrearages do not accrue on the subordinated units.
The purpose of the subordinated units is to increase the
likelihood that during the subordination period there will be
available cash from operating surplus to be distributed on the
common units.
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Definition of Subordination Period |
We define the subordination period in the glossary. Except as
described below under Early Termination of
Subordination Period, the subordination period will extend
until the first day of any quarter beginning after June 30,
2008 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 and subordinated units equaled
or exceeded the minimum quarterly distribution for each of the
three consecutive, non-overlapping four-quarter periods
immediately preceding that date; |
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the adjusted operating surplus (as defined below)
generated during each of the three consecutive, non-overlapping
four-quarter periods immediately preceding that date equaled or
exceeded the sum of the minimum quarterly distributions on all
of the outstanding common units and subordinated units during
those periods on a fully diluted basis and the related
distribution on the 2% general partner interest during those
periods; and |
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there are no arrearages in payment of the minimum quarterly
distribution on the common units. |
If the unitholders remove our general partner without cause, the
subordination period may end early.
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Early Termination of Subordination Period |
The subordination period will automatically terminate and all of
the subordinated units will convert into common units on a
one-for-one basis if each of the following occurs:
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distributions of available cash from operating surplus on each
outstanding common unit and subordinated unit equaled or
exceeded $2.10 (150% of the annualized minimum quarterly
distribution) for any four-quarter period immediately preceding
that date; |
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the adjusted operating surplus (as defined below)
generated during any four-quarter period immediately preceding
that date equaled or exceeded the sum of a distribution of $2.10
(150% of the annualized minimum quarterly distribution) on all
of the outstanding common units and subordinated units on a
fully diluted basis; and |
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there are no arrearages in payment of the minimum quarterly
distribution on the common units. |
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Definition of Adjusted Operating Surplus |
We define adjusted operating surplus in the glossary, and for
any period it generally means:
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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 reduction in cash reserves for operating expenditures
made 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. |
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.
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Effect of Expiration of the Subordination Period |
Upon expiration of the subordination period, each outstanding
subordinated unit will convert into one common unit and will
then participate pro rata with the other common units in
distributions of available cash. In addition, if the unitholders
remove our general partner other than for cause and units held
by our general partner and its affiliates are not voted in favor
of such removal:
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the subordination period will end and each subordinated unit
will immediately convert into one common unit; |
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any existing arrearages in payment of the minimum quarterly
distribution on the common units will be extinguished; and |
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our general partner will have the right to convert its general
partner interest and, if any, its incentive distribution rights
into common units or to receive cash in exchange for those
interests. |
Distributions of Available Cash from Operating Surplus During
the Subordination Period
We will 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% to the common unitholders, pro rata, and 2% 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% to the common unitholders, pro rata, and 2%
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% to the subordinated unitholders, pro rata, and
2% 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
Incentive Distribution Rights below. |
The preceding discussion is based on the assumptions that our
general partner maintains its 2% general partner interest and
that we do not issue additional classes of equity securities.
Distributions of Available Cash from Operating Surplus After
the Subordination Period
We will 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% to all unitholders, pro rata, and 2% 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
Incentive Distribution Rights below. |
The preceding discussion is based on the assumptions that our
general partner maintains its 2% general partner interest and
that we do not issue additional classes of equity securities.
Incentive Distribution Rights
Incentive distribution rights represent the right to receive an
increasing percentage 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,
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but may transfer these rights separately from its general
partner interest, subject to restrictions in the partnership
agreement.
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; |
then, we will distribute any additional available cash from
operating surplus for that quarter among the unitholders and our
general partner in the following manner:
|
|
|
|
|
first, 98% to all unitholders, pro rata, and 2% to our
general partner, until each unitholder receives a total of
$0.4025 per unit for that quarter (the first target
distribution); |
|
|
|
second, 85% to all unitholders, pro rata, and 15% to our
general partner, until each unitholder receives a total of
$0.4375 per unit for that quarter (the second target
distribution); |
|
|
|
third, 75% to all unitholders, pro rata, and 25% to our
general partner, until each unitholder receives a total of
$0.5250 per unit for that quarter (the third target
distribution); and |
|
|
|
thereafter, 50% to all unitholders, pro rata, and 50% to
our general partner. |
In each case, the amount of the target distribution set forth
above is exclusive of any distributions to common unitholders to
eliminate any cumulative arrearages in payment of the minimum
quarterly distribution. The percentage interests set forth above
for our general partner assumes that our general partner
maintains its 2% general partner interest, that our general
partner has not transferred the incentive distribution rights
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
the additional available cash from operating surplus among the
unitholders and our general partner up to the various target
distribution levels. The amounts set forth under Marginal
Percentage Interest in Distributions are the percentage
interests of the unitholders and our general partner in any
available cash from operating surplus we distribute up to and
including the corresponding amount in the column Total
Quarterly Distribution Target Amount, until available cash
from operating surplus we distribute reaches the next target
distribution level, if any. The percentage interests shown for
the 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% general partner interest and
assume our general partner has contributed additional capital to
maintain its 2% general partner interest, that our general
partner has not transferred the incentive distribution rights
and that we do not issue additional classes of equity securities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marginal Percentage Interest in |
|
|
|
|
Distributions |
|
|
Total Quarterly Distribution |
|
|
|
|
Target Amount |
|
Unitholders |
|
General Partner |
|
|
|
|
|
|
|
Minimum Quarterly Distribution
|
|
$0.3500 |
|
|
98 |
% |
|
|
2 |
% |
First Target Distribution
|
|
up to $0.4025 |
|
|
98 |
% |
|
|
2 |
% |
Second Target Distribution
|
|
above $0.4025 up to $0.4375 |
|
|
85 |
% |
|
|
15 |
% |
Third Target Distribution
|
|
above $0.4375 up to $0.5250 |
|
|
75 |
% |
|
|
25 |
% |
Thereafter
|
|
above $0.5250 |
|
|
50 |
% |
|
|
50 |
% |
137
Distributions from Capital Surplus
|
|
|
How Distributions from Capital Surplus Will Be Made |
We will make distributions of available cash from capital
surplus, if any, in the following manner:
|
|
|
|
|
first, 98% to all unitholders, pro rata, and 2% to 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; |
|
|
|
second, 98% to the common unitholders, pro rata, and 2%
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 |
|
|
|
thereafter, we will make all distributions of available
cash from capital surplus as if they were from operating surplus. |
The preceding discussion is based on the assumption that our
general partner maintains its 2% general partner interest and
that we do not issue additional classes of equity securities.
|
|
|
Effect of a Distribution from Capital Surplus |
The partnership agreement treats a distribution of capital
surplus as the repayment of the initial unit price from our
initial public offering, which is a return of capital. The
initial public offering price less any distributions of capital
surplus per unit is referred to as the unrecovered initial
unit price. Each time a distribution of capital surplus is
made, the minimum quarterly distribution and the target
distribution levels will be reduced in the same proportion as
the corresponding 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 in an amount equal
to the initial unit price, we will reduce the minimum quarterly
distribution and the target distribution levels to zero. We will
then make all future distributions from operating surplus, with
50% being paid to the holders of units and 50% to our general
partner. The percentage interests shown for our general partner
assume that our general partner maintains its 2% general partner
interest, that our general partner has not transferred the
incentive distribution rights and that we do not issue
additional classes of equity securities.
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, we will
proportionately adjust:
|
|
|
|
|
the minimum quarterly distribution; |
|
|
|
the target distribution levels; |
|
|
|
the unrecovered initial unit price; and |
|
|
|
the number of common units into which a subordinated unit is
convertible. |
For example, if a two-for-one split of the common units should
occur, the minimum quarterly distribution, the target
distribution levels and the unrecovered initial unit price would
each be reduced to 50% of its initial level and each
subordinated unit would be convertible into two common units. We
will not make any adjustment by reason of the issuance of
additional units for cash or property.
138
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, we will reduce the minimum quarterly distribution and
the target distribution levels for each quarter by multiplying
each distribution level by a fraction, the numerator of which is
available cash for that quarter and the denominator of which is
the sum of available cash for that quarter plus 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
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 our general partner, in
accordance with their capital account balances, as adjusted to
reflect any gain or loss upon the sale or other disposition of
our assets in liquidation.
The allocations of gain and loss upon liquidation are intended,
to the extent possible, to entitle the holders of outstanding
common units to a preference over the holders of outstanding
subordinated units upon our liquidation, to the extent required
to permit common unitholders to receive their unrecovered
initial unit price plus the minimum quarterly distribution for
the quarter during which liquidation occurs plus any unpaid
arrearages in payment of the minimum quarterly distribution on
the common units. However, there may not be sufficient gain upon
our liquidation to enable the holders of common units to fully
recover all of these amounts, even though there may be cash
available to pay distributions 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:
|
|
|
|
|
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; |
|
|
|
second, 98% to the common unitholders, pro rata, and 2%
to our general partner, until the capital account for each
common unit is equal to the sum of: |
|
|
|
(1) the unrecovered initial unit price for that common unit; |
|
|
(2) the amount of the minimum quarterly distribution for
the quarter during which our liquidation occurs; and |
|
|
(3) any unpaid arrearages in payment of the minimum
quarterly distribution; |
|
|
|
|
|
third, 98% to the subordinated unitholders, pro rata, and
2% to our general partner until the capital account for each
subordinated unit is equal to the sum of: |
|
|
|
(1) the unrecovered initial unit price for that
subordinated unit; and |
|
|
(2) the amount of the minimum quarterly distribution for
the quarter during which our liquidation occurs; |
|
|
|
|
|
fourth, 98% to all unitholders, pro rata, and 2% to 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 |
139
|
|
|
(2) the cumulative amount per unit of any distributions of
available cash from operating surplus in excess of the minimum
quarterly distribution per unit that we distributed 98% to the
unitholders, pro rata, and 2% to our general partner, for each
quarter of our existence; |
|
|
|
|
|
fifth, 85% to all unitholders, pro rata, and 15% 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% to the
unitholders, pro rata, and 15% to our general partner for each
quarter of our existence; |
|
|
|
|
|
sixth, 75% to all unitholders, pro rata, and 25% 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% to the
unitholders, pro rata, and 25% to our general partner for each
quarter of our existence; and |
|
|
|
|
|
thereafter, 50% to all unitholders, pro rata, and 50% to
our general partner. |
The percentage interests set forth above for our general partner
assume that our general partner maintains its 2% general partner
interest, that our general partner has not transferred the
incentive distribution rights and that we do not issue
additional classes of equity securities.
If the liquidation occurs after the end of the subordination
period, the distinction between common units and subordinated
units will disappear, so that clause (3) of the second
bullet point above and all of the third bullet point above will
no longer be applicable.
|
|
|
Manner of Adjustments for Losses |
If our liquidation occurs before the end of the subordination
period, we will generally allocate any loss to our general
partner and the unitholders in the following manner:
|
|
|
|
|
first, 98% to holders of subordinated units in proportion
to the positive balances in their capital accounts and 2% to our
general partner, until the capital accounts of the subordinated
unitholders have been reduced to zero; |
|
|
|
second, 98% to the holders of common units in proportion
to the positive balances in their capital accounts and 2% to our
general partner, until the capital accounts of the common
unitholders have been reduced to zero; and |
|
|
|
thereafter, 100% to our general partner. |
The percentage interests set forth above for our general partner
assume that our general partner maintains its 2% general partner
interest, that our general partner has not transferred the
incentive distribution rights and that we do not issue
additional classes of equity securities.
If the liquidation occurs after the end of the subordination
period, the distinction between common units and subordinated
units will disappear, so that all of the first bullet point
above will no longer be applicable.
140
|
|
|
Adjustments to Capital Accounts |
We will make adjustments to capital accounts upon the issuance
of additional units. In doing so, we will allocate any
unrealized and, for tax purposes, unrecognized gain or loss
resulting from the adjustments to the unitholders and our
general partner in the same manner as we allocate gain or loss
upon liquidation. In the event that we make positive adjustments
to the capital accounts upon the issuance of additional units,
we will allocate any later negative adjustments to the capital
accounts resulting from the issuance of additional units or upon
our liquidation in a manner which results, to the extent
possible, in our 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.
141
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
The following table sets forth the beneficial ownership of units
of Williams Partners L.P. that will be owned upon the
consummation of this offering by:
|
|
|
|
|
each person known by us to be a beneficial owner of more than 5%
of the units; |
|
|
|
each of the directors of our general partner; |
|
|
|
each of the named executive officers of our general
partner; and |
|
|
|
all directors and executive officers of our general partner as a
group. |
The amounts and percentage of units beneficially owned are
reported on the basis of regulations of the SEC governing the
determination of beneficial ownership of securities. Under the
rules of the SEC, a person is deemed to be a beneficial
owner of a security if that person has or shares
voting power, which includes the power to vote or to
direct the voting of such security, or investment
power, which includes the power to dispose of or to direct
the disposition of such security. A person is also deemed to be
a beneficial owner of any securities of which that person has a
right to acquire beneficial ownership within 60 days. Under
these rules, more than one person may be deemed a beneficial
owner of the same securities and a person may be deemed a
beneficial owner of securities as to which he has no economic
interest.
Except as indicated by footnote, the persons named in the table
below have sole voting and investment power with respect to all
units shown as beneficially owned by them, subject to community
property laws where applicable.
Percentage of total units to be beneficial owned after this
offering is based on 20,606,146 units outstanding. The
table assumes that the underwriters option to purchase
additional units is not exercised. The address for the
beneficial owners listed below and in the table on the following
page is One Williams Center, Tulsa, Oklahoma
74172-0172.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of |
|
|
|
Percentage of |
|
|
|
|
Common |
|
Common |
|
Subordinated |
|
Subordinated |
|
Percentage of |
|
|
Units |
|
Units |
|
Units |
|
Units |
|
Total Units |
|
|
Beneficially |
|
Beneficially |
|
Beneficially |
|
Beneficially |
|
Beneficially |
Name of Beneficial Owner |
|
Owned |
|
Owned |
|
Owned |
|
Owned |
|
Owned |
|
|
|
|
|
|
|
|
|
|
|
The Williams Companies, Inc.(1)
|
|
|
1,250,000 |
|
|
|
9.2 |
% |
|
|
7,000,000 |
|
|
|
100.0 |
% |
|
|
40.0 |
% |
Williams Energy Services, LLC(1)
|
|
|
821,761 |
|
|
|
6.0 |
|
|
|
4,601,861 |
|
|
|
65.7 |
|
|
|
26.3 |
|
Williams Energy, L.L.C.(1)
|
|
|
447,308 |
|
|
|
3.3 |
|
|
|
2,504,925 |
|
|
|
35.8 |
|
|
|
14.3 |
|
Williams Discovery Pipeline LLC(1)
|
|
|
215,980 |
|
|
|
1.6 |
|
|
|
1,209,486 |
|
|
|
17.3 |
|
|
|
6.9 |
|
Williams Partners Holdings LLC(1)
|
|
|
428,239 |
|
|
|
3.1 |
|
|
|
2,398,139 |
|
|
|
34.3 |
|
|
|
13.7 |
|
MAPCO Inc.(1)
|
|
|
447,308 |
|
|
|
3.3 |
|
|
|
2,504,925 |
|
|
|
35.8 |
|
|
|
14.3 |
|
Steven J. Malcolm(2)
|
|
|
25,100 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
* |
|
Donald R. Chappel
|
|
|
10,000 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
* |
|
Alan S. Armstrong
|
|
|
10,000 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
* |
|
James J. Bender
|
|
|
2,000 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
* |
|
Thomas C. Knudson(3)
|
|
|
1,494 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
* |
|
Bill Z. Parker(3)
|
|
|
7,326 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
* |
|
Alice M. Peterson(3)
|
|
|
2,326 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
* |
|
Phillip D. Wright
|
|
|
2,000 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
* |
|
All directors and executive officers as a group (8 persons)
|
|
|
60,246 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
* |
|
|
|
(1) |
As noted in the Schedule 13D filed with the SEC on
September 2, 2005, as amended on April 13, 2006, The
Williams Companies, Inc. is the ultimate parent company of
Williams Energy Services, LLC, |
142
|
|
|
Williams Energy, L.L.C., Williams Discovery Pipeline LLC and
Williams Partners Holdings LLC and may, therefore, be deemed to
beneficially own the units held by Williams Energy Services,
LLC, Williams Energy, L.L.C., Williams Discovery Pipeline LLC
and Williams Partners Holdings LLC. The Williams Companies,
Inc.s common stock is listed on the New York Stock
Exchange under the symbol WMB. The Williams
Companies, Inc. files information with or furnishes information
to, the Securities and Exchange Commission pursuant to the
information requirements of the Securities Exchange Act of 1934,
as amended. Williams Energy Services, LLC is the record owner of
158,473 common units and 887,450 subordinated units and, as the
sole stockholder of MAPCO Inc. and the sole member of Williams
Discovery Pipeline LLC, may, pursuant to
Rule 13d-3, be
deemed to beneficially own the units beneficially owned by MAPCO
Inc. and Williams Discovery Pipeline LLC. MAPCO Inc., as the
sole member of Williams Energy, L.L.C., may, pursuant to
Rule 13d-3, be
deemed to beneficially own the units held by Williams Energy,
L.L.C. |
|
(2) |
Represents units beneficially owned by Mr. Malcolm that are
held by the Steven J. Malcolm Revocable Trust. |
|
|
(3) |
Includes unvested restricted units granted pursuant to the
Williams Partners GP LLC Long-Term Incentive Plan which may be
voted by the grantees as follows: Mr. Knudson, 1,494;
Mr. Parker, 2,326; and Ms. Peterson, 2,326. The
restricted units held by Ms. Peterson and Mr. Parker
will vest on May 28, 2006. |
|
The following table sets forth, as of May 15, 2006, the
number of shares of common stock of Williams 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares |
|
|
|
Percentage of |
|
|
|
|
Underlying |
|
Total Shares of |
|
Total Shares |
|
|
Shares of |
|
Options |
|
Common |
|
of Common |
|
|
Common Stock |
|
Exercisable |
|
Stock |
|
Stock |
|
|
Owned Directly |
|
Within |
|
Beneficially |
|
Beneficially |
Name of Beneficial Owner |
|
or Indirectly(1) |
|
60 Days |
|
Owned |
|
Owned |
|
|
|
|
|
|
|
|
|
Alan S. Armstrong
|
|
|
124,159 |
|
|
|
0 |
|
|
|
124,159 |
|
|
|
* |
|
James J. Bender
|
|
|
157,708 |
|
|
|
0 |
|
|
|
157,708 |
|
|
|
* |
|
Donald R. Chappel
|
|
|
261,673 |
|
|
|
0 |
|
|
|
261,673 |
|
|
|
* |
|
Steven J. Malcolm
|
|
|
812,888 |
|
|
|
0 |
|
|
|
812,888 |
|
|
|
* |
|
Bill Z. Parker
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Alice M. Peterson
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Thomas C. Knudson
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Phillip D. Wright
|
|
|
220,344 |
|
|
|
0 |
|
|
|
220,344 |
|
|
|
* |
|
All directors and executive officers as a group (8 persons)
|
|
|
1,576,772 |
|
|
|
0 |
|
|
|
1,576,772 |
|
|
|
* |
|
|
|
(1) |
Includes shares held under the terms of incentive and investment
plans as follows: (a) Mr. Armstrong
14 shares in The Williams Companies Investment Plus Plan,
100,034 deferred shares and 24,111 beneficially owned
shares; (b) Mr. Bender 6,000 shares
owned by children, 100,034 deferred shares and 51,674
beneficially owned shares; (c) Mr. Chappel
146,100 deferred shares and 115,573 beneficially owned shares;
(d) Mr. Malcolm 44,623 shares in The
Williams Companies Investment Plus Plan, 484,758 deferred shares
and 283,507 beneficially owned shares; and
(e) Mr. Wright 14,742 shares in The
Williams Investment Plus Plan, 100,034 deferred shares and
105,568 beneficially owned shares. |
143
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
After this offering, our general partner and its affiliates will
own 1,250,000 common units and 7,000,000 subordinated units
representing a 39.2% limited partner interest in us. In
addition, our general partner will own a 2% general partner
interest in us.
Distributions and Payments to Our General Partner and Its
Affiliates
The following table summarizes the distributions and payments
made or to be made by us to our general partner and its
affiliates in connection with the ongoing operation and
liquidation of Williams Partners L.P. These distributions and
payments were determined by and among affiliated entities and,
consequently, are not the result of arms-length
negotiations.
Operational Stage
|
|
|
Distributions of available cash to our general partner and its
affiliates |
|
We will generally make cash distributions 98% to unitholders,
including our general partner and its affiliates as holders of
an aggregate of 1,250,000 common units, all of the subordinated
units and the remaining 2% to our general partner. |
|
|
|
In addition, if distributions exceed the minimum quarterly
distribution and other higher target levels, our general partner
will be entitled to increasing percentages of the distributions,
up to 50% of the distributions above the highest target level.
We refer to the rights to the increasing distributions as
incentive distribution rights. Please read How
We Make Cash Distributions Incentive Distribution
Rights for more information regarding the incentive
distribution rights. |
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Payments to our general partner and its affiliates |
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Our general partner does not receive a management fee or other
compensation for the management of our partnership. Our general
partner and its affiliates are reimbursed, however, for all
direct and indirect expenses incurred on our behalf. Our general
partner determines the amount of these expenses. |
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Withdrawal or removal of our general partner |
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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 Agreement Withdrawal or Removal of Our
General Partner. |
Liquidation Stage
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Liquidation |
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Upon our liquidation, the partners, including our general
partner, will be entitled to receive liquidating distributions
according to their particular capital account balances. |
Agreements Governing the Transactions
We, our general partner, our operating company and other
affiliates of Williams have entered into or will enter into the
various documents and agreements that effected our formation
transactions and will effect our acquisition of the interest in
Four Corners, including the vesting of assets in, and the
assumption of liabilities
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by, us and our subsidiaries, and the application of the proceeds
of our initial public offering and this offering. These
agreements are not and will not be the result of
arms-length negotiations, and they, or any of the
transactions that they provide for, are not and may not be
effected on terms at least as favorable to the parties to these
agreements as they could have been obtained from unaffiliated
third parties. All of the $4.3 million of transaction
expenses incurred in connection with our formation transactions,
including the expenses associated with vesting assets into our
subsidiaries, were paid from the proceeds of our initial public
offering. In addition, all of the transaction expenses incurred
in connection with our acquisition of the interest in Four
Corners will be paid from the proceeds of this offering.
Omnibus Agreement
Upon the closing of our initial public offering, we entered into
an omnibus agreement with Williams and its affiliates that
governs our relationship with them regarding the following
matters:
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reimbursement of certain general and administrative expenses; |
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indemnification for certain environmental liabilities, tax
liabilities and
right-of-way defects; |
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reimbursement for certain expenditures; and |
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a license for the use of certain software and intellectual
property. |
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General and Administrative Expenses |
Williams will provide us with a five-year partial credit for
general and administrative, or G&A, expenses incurred on our
behalf. For 2005, the amount of this credit was
$3.9 million on an annualized basis but was pro rated from
the closing of our initial public offering in August 2005
through the end of the year. In 2006, the amount of the G&A
credit will be $3.2 million, and the amount of the credit
will decrease by $800,000 for each subsequent year. As a result,
after 2009, we will no longer receive any credit and will be
required to reimburse Williams for all of the general and
administrative expenses incurred on our behalf.
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Indemnification for Environmental and Related
Liabilities |
Williams agreed to indemnify us after the closing of our initial
public offering against certain environmental and related
liabilities arising out of or associated with the operation of
the assets before the closing date of our initial public
offering. These liabilities include both known and unknown
environmental and related liabilities, including:
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remediation costs associated with the KDHE Consent Orders and
certain fugitive NGLs associated with our Conway storage
facilities; |
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the costs associated with the installation of wellhead control
equipment and well meters at our Conway storage facility; |
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KDHE-related cavern compliance at our Conway storage
facility; and |
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the costs relating to the restoration of the overburden along
our Carbonate Trend pipeline in connection with erosion caused
by Hurricane Ivan in September 2004. |
Williams will not be required to indemnify us for any project
management or monitoring costs. This indemnification obligation
will terminate three years after the closing of our initial
public offering, except in the case of the remediation costs
associated with the KDHE Consent Orders which will survive for
an unlimited period of time. There is an aggregate cap of
$14.0 million on the amount of indemnity coverage,
including any amounts recoverable under our insurance policy
covering those remediation costs and unknown claims at Conway.
Please read Managements Discussion and Analysis of
Financial Condition and Results of Operations
Environmental. In addition, we are not entitled to
indemnification until the aggregate amounts of claims exceed
$250,000. Liabilities resulting from a change of law after the
closing of our initial public offering are excluded from the
environmental indemnity by Williams for the unknown
environmental liabilities.
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Williams will also indemnify us for liabilities related to:
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certain defects in the easement rights or fee ownership
interests in and to the lands on which any assets contributed to
us in connection with our initial public offering are located
and failure to obtain certain consents and permits necessary to
conduct our business that arise within three years after the
closing of our initial public offering; and |
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certain income tax liabilities attributable to the operation of
the assets contributed to us in connection with our initial
public offering prior to the time they were contributed. |
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Reimbursement for Certain Expenditures Attributable to
Discovery |
Williams has agreed to reimburse us for certain capital
expenditures, subject to limits, including for certain
excess capital expenditures in connection with
Discoverys Tahiti pipeline lateral expansion project. We
expect the cost of the Tahiti pipeline lateral expansion project
will be approximately $69.5 million, of which our 40% share
will be approximately $27.8 million. Williams will
reimburse us for the excess (up to $3.4 million) of our 40%
share of the total cost of the Tahiti pipeline lateral expansion
project above the amount of the required escrow deposit
($24.4 million) attributable to our 40% interest in
Discovery. Williams will reimburse us for these capital
expenditures upon the earlier to occur of a capital call from
Discovery or Discovery actually incurring the expenditure.
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Intellectual Property License |
Williams and its affiliates granted a license to us for the use
of certain marks, including our logo, for as long as Williams
controls our general partner, at no charge.
The omnibus agreement may not be amended without the prior
approval of the conflicts committee if the proposed amendment
will, in the reasonable discretion of our general partner,
adversely affect holders of our common units.
Williams is not restricted under the omnibus agreement from
competing with us. Williams 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
those assets.
Credit Facilities
At the closing of our initial public offering in August 2005, we
entered into a $20 million revolving credit facility with
Williams as the lender. The facility is available exclusively to
fund working capital borrowings. Borrowings under the facility
will mature on May 3, 2007 and bear interest at the same
rate as would be available for borrowings under the Williams
credit agreement described in Managements Discussion
and Analysis of Financial Condition and Results of
Operations Financial Condition and
Liquidity Credit Facilities.
We are required to reduce all borrowings under our working
capital credit facility to zero for a period of at least 15
consecutive days once each
12-month period prior
to the maturity date of the facility.
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Williams Credit Agreement |
In addition, we also have the ability to borrow up to
$75 million under the Williams credit agreement. Please
read Managements Discussion and Analysis of
Financial Condition and Results of Operations
Financial Condition and Liquidity Credit
Facilities, and Risk Factors Risks
Inherent in Our Business Williams credit
agreement and Williams public indentures contain financial
and operating
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restrictions that may limit our access to credit. In addition,
our ability to obtain credit in the future will be affected by
Williams credit ratings.
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Four Corners Credit Facility |
At the closing of this offering, Four Corners will enter into a
$20 million revolving credit facility with Williams as the
lender. The facility is available to fund working capital
borrowings and for other purposes. Borrowings under the facility
will mature on the third anniversary of the closing of our
acquisition of a 25.1% interest in Four Corners. Please read
Managements Discussion and Analysis of Financial
Condition and Results of Operations Financial
Condition and Liquidity Credit Facilities for
additional information regarding the commitment fee Four Corners
will be required to pay and the rate on the borrowing under this
credit facility.
Discovery Limited Liability Company Agreement
We, an affiliate of Williams and Duke Energy Field Services have
entered into an amended and restated limited liability company
agreement for Discovery Producer Services LLC. This agreement
governs the ownership and management of Discovery and provides
for quarterly distributions of available cash to the members.
The amount of any such distributions is determined by majority
approval of Discoverys management committee, which
consists of representatives from each of the three owners. In
addition, to the extent Discovery requires working capital in
excess of applicable reserves, the Williams affiliate that is a
Discovery member (Williams Energy, L.L.C.) must make capital
advances to Discovery up to the amount of Discoverys two
most recent prior quarterly distributions of available cash, but
Discovery must repay these advances before it makes any future
distributions. In addition, the owners are required to offer to
Discovery all opportunities to construct pipeline laterals
within an area of interest.
Discovery Operating and Maintenance Agreements
Discovery is party to three operating and maintenance agreements
with Williams: one relating to Discovery Producer Services LLC,
one relating to Discovery Gas Transmission LLC and another
relating to the Paradis Fractionation Facility and the Larose
Gas Processing Plant. Under these agreements, Discovery is
required to reimburse Williams for direct payroll and employee
benefit costs incurred on Discoverys behalf. Most costs
for materials, services and other charges are third-party
charges and are invoiced directly to Discovery. Discovery is
required to pay Williams a monthly operation and management fee
to cover the cost of accounting services, computer systems and
management services provided to Discovery under each of these
agreements. Discovery also pays Williams a project management
fee to cover the cost of managing capital projects. This fee is
determined on a project by project basis.
Gas Purchase Contract
Upon the closing of our initial public offering, an affiliate of
Williams transferred to us a contract for the purchase of a
sufficient quantity of natural gas from a wholly owned
subsidiary of Williams at a price not to exceed a specified
price to satisfy our fuel requirements under this fractionation
contract. The fair value of this gas purchase contract was an
equity contribution to us by Williams. This gas purchase
contract terminates on December 31, 2007. Please read
Managements Discussion and Analysis of Financial
Condition and Results of Operations Our
Operations NGL Services Segment
Fractionation Contracts.
Natural Gas and NGL Marketing Contracts
Certain subsidiaries of Williams markets substantially all of
the NGLs and excess natural gas to which Discovery, our Conway
fractionation and storage facility and Four Corners take title.
Discovery, our Conway fractionation and storage facility and
Four Corners conduct the sales of the NGLs and excess natural
gas to which they take title pursuant to a base contract for
sale and purchase of natural gas and a natural gas liquids
master purchase, sale and exchange agreement. These agreements
contain the general terms and conditions governing the
transactions such as apportionment of taxes, timing and manner
of payment, choice of law and
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confidentiality. Historically, the sales of natural gas and NGLs
to which Discovery, our Conway fractionation and storage
facility and Four Corners take title have been conducted at
market prices with certain subsidiaries of Williams as the
counter parties. Additionally, Discovery, our Conway
fractionation and storage facility and Four Corners may purchase
natural gas to meet their fuel and other requirements and our
Conway storage facility may purchase NGLs as needed to maintain
inventory balances.
Purchase and Sale Agreement
On April 6, 2006, we entered into a Purchase and Sale
Agreement with Williams Energy Services, LLC, Williams Field
Services Group, LLC, Williams Field Services Company, LLC, our
general partner and Williams Partners Operating. Pursuant to the
Purchase and Sale Agreement, we will acquire a 25.1% membership
interest in Four Corners in exchange for aggregate consideration
of $360 million. Four Corners owns gathering, processing
and treating assets in the San Juan Basin in New Mexico and
Colorado. In connection with the transactions contemplated by
the Purchase and Sale Agreement, we will contribute the 25.1%
interest in Four Corners to Williams Partners Operating. Please
read Acquisition of Interest in Four Corners for
more information on Four Corners.
Four Corners Limited Liability Company Agreement
In connection with the closing of our acquisition of a 25.1%
interest in Four Corners, Williams Field Services Company, LLC
and Williams Partners Operating will enter into an amended and
restated limited liability company agreement for Four Corners.
This agreement will govern the ownership and management of Four
Corners and provides for distributions of available cash to the
members at least quarterly. The amount of any such distributions
will be determined by unanimous approval of Four Corners
management committee, which consists of representatives from
each of the two owners. Williams Field Services Company will be
the operator of Four Corners. Under the limited liability
company agreement, Four Corners will be required to reimburse
Williams Field Services Company for all direct and indirect
expenses it incurs or payments it makes on behalf of Four
Corners and all other expenses allocable to Four Corners or
otherwise incurred by Williams Field Services Company in
connection with operating Four Corners business. Williams
Field Services Company shall determine the expenses that are
allocable to Four Corners in good faith.
Gathering, Processing and Treating Contracts
Four Corners maintains two contracts with an affiliate of
Williams, a gas gathering and treating contract and a gas
gathering and processing contract. Pursuant to the gas gathering
and treating contract, Four Corners gathers and treats coal seam
gas delivered by the affiliate to Four Corners gathering
systems. Deliveries of gas under this agreement averaged
approximately 34 MMcf/d during 2003, 39 MMcf/d during
2004 and 42 MMcf/d during 2005. The term of this agreement
expires on December 31, 2022, but will continue thereafter
on a year-to-year basis
subject to termination by either party giving at least six
months written notice of termination prior to the expiration of
each one year period.
Pursuant to the gas gathering and processing contract, Four
Corners gathers and processes conventional and coal seam gas
delivered by the affiliate to Four Corners gathering
systems. Deliveries of gas under this agreement averaged
approximately 101 MMcf/d during 2003, 92 MMcf/d during
2004 and 93 MMcf/d during 2005. The primary term of the
agreement ended on March 1, 2004, but it continues to
remain in effect on a
year-to-year basis
subject to termination by either party giving at least three
months written notice of termination prior to the expiration of
each one-year period.
Revenues recognized pursuant to these contracts totaled
$35.5 million in 2003, $30.2 million in 2004 and
$26.1 million in 2005.
Four Corners Natural Gas Purchases
Four Corners purchases natural gas for fuel and shrink
replacement from Williams Power Company, an affiliate of
Williams. With the exception of volumes purchased pursuant to
the contract discussed in the immediately following paragraph,
these purchases are made at market rates at the time of
purchase. Four
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Corners purchased approximately $53.3 million,
$70.0 million and $73.3 million of natural gas for
fuel and shrink replacement from Williams Power Company during
2003, 2004 and 2005, respectively.
Four Corners maintains a contract with two affiliates of
Williams pursuant to which one of the affiliates, Williams Power
Company, Inc., sells natural gas to Four Corners. The natural
gas sold to Four Corners by Williams Power Company is favorably
impacted by Williams Power Companys fixed price natural
gas fuel contracts. Four Corners provides a portion of the
purchased natural gas to the other affiliate, Williams Flexible
Generation, LLC, who burns the gas at its co-generation plant
that produces waste heat that assists in the operation of the
Milagro treating plant. Four Corners uses the remainder of the
natural gas in connection with various operations at the Milagro
plant. Pursuant to this contract, Four Corners purchased
$30.0 million, $23.3 million and $33.0 million of
natural gas from Williams Power Company in 2003, 2004 and 2005,
respectively, and Four Corners provided $8.4 million,
$6.6 million and $8.9 million of the purchased natural
gas to Williams Flexible Generation in 2003, 2004 and 2005,
respectively. The term of the agreement expires on
December 31, 2006, or when Williams Flexible Generation and
Four Corners are no longer affiliated with each other, whichever
occurs earlier. The affiliates have options to extend the
agreement through December 31, 2007 and through
December 31, 2008, subject in each case to earlier
termination of the agreement when Williams Flexible Generation
and Four Corners are no longer affiliated with each other.
Balancing Services Contract
Four Corners maintains a balancing services contract with
Williams Power Company, Inc., an affiliate of Williams. Pursuant
to this agreement, Williams Power Company balances deliveries of
natural gas processed by Four Corners between certain points on
Four Corners gathering system. Four Corners and Williams
Power Company communicate on a daily basis to determine the
volumes of natural gas to be moved between gathering systems at
established interconnect points to optimize flow, an activity
referred to as crosshauling. As a result, Four
Corners must purchase gas for delivery to customers at certain
plant outlets and Four Corners has excess volumes to sell at
other plant outlets. These purchase and sales transactions are
conducted for us by Williams Power Company at current market
prices. Historically, Williams Power Company has not charged us
a fee for providing this service, but has occasionally benefited
from price differentials that historically existed from time to
time between the plant outlets. The revenues and costs related
to the purchases and sales pursuant to this arrangement have
historically tended to offset each other. The term of this
agreement expires on the later of December 31, 2006 or upon
six months or more written notice of termination.
Summary of Other Four Corners Transactions
Four Corners incurred approximately $40.7 million,
$45.6 million and $47.9 million in operating and
maintenance and general and administrative expenses (excluding
other natural gas and steam expenses) expended by Williams on
its behalf during 2003, 2004 and 2005, respectively. Please read
Note 4 to Williams Four Corners Predecessors
Financial Statements for more information.
Four Corners sells the NGLs to which it takes title to Williams
Midstream Marketing and Risk Management, LLC, an affiliate of
Williams. These sales are made at market rates at the time of
sale. Four Corners sold approximately $122.8 million,
$199.2 million and $222.6 million of NGLs to Williams
Midstream Marketing and Risk Management during 2003, 2004 and
2005, respectively.
Four Corners previously sold electricity to Williams Power
Company, an affiliate of Williams, at the Ignacio plant. The
revenues from these sales were $1.5 million and
$0.9 million during 2003 and 2004, respectively.
When Williams Field Services Company, LLC conveys assets to Four
Corners on or prior to the closing of this offering and our
acquisition of an interest in Four Corners, outstanding
intercompany advances are expected to be distributed to Williams.
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Summary of Transactions with Williams
In connection with the closing of our initial public offering in
August 2005:
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we issued 2,000,000 common units, 7,000,000 subordinated units,
a 2% general partner interest and incentive distribution rights
to affiliates of Williams in exchange for the contribution of
interests in our operating subsidiaries and Discovery; |
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we distributed $58.8 million to affiliates of Williams to
reimburse Williams for certain capital expenditures incurred
prior to our formation and for the contribution by an affiliate
of Williams to one of our operating subsidiaries of a gas
purchase contract that provides for the purchase of a sufficient
quantity of natural gas from a wholly-owned subsidiary of
Williams at a price not to exceed a specified price to satisfy
our fuel requirements under a fractionation contract; |
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we provided $24.4 million to make a capital contribution to
Discovery to fund an escrow account in connection with the
Tahiti pipeline lateral expansion project; and |
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Williams forgave $186.0 million in intercompany advances to
our predecessor. |
In addition, for the year ended December 31, 2005:
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we incurred $17.6 million from Williams for direct and
indirect expenses incurred on our behalf pursuant to the
partnership agreement; |
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we distributed $1.3 million to affiliates of Williams as
quarterly distributions on their common units, subordinated
units and 2% general partner interest; |
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we received from Williams $1.4 million of general and
administrative credits pursuant to the omnibus agreement; |
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Williams indemnified us $0.5 million, primarily for
KDHE-required compliance costs, pursuant to the omnibus
agreement; |
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Discovery reimbursed Williams $3.4 million for direct
payroll and employee benefit costs pursuant to the operating and
maintenance agreements as well as $0.4 million for
capitalized labor costs; |
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Discovery paid Williams $2.1 million for operation and
management fees pursuant to the operating and maintenance
agreements as well as a $0.1 million fee for managing
capitalized projects; |
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we purchased a gross amount of $22.4 million of natural gas
for the Conway fractionator from an affiliate of Williams; |
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we purchased $15.7 million of NGLs to replenish deficit
product positions from a subsidiary of Williams based on market
pricing; |
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we sold $13.4 million to a subsidiary of Williams that
markets substantially all of the NGLs and excess natural gas to
which our Conway fractionation and storage facility takes title
based on market pricing; |
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Discovery sold $70.8 million of NGLs to a subsidiary of
Williams that markets substantially all of the NGLs and excess
natural gas to which Discovery takes title based on market
pricing; and |
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Discovery purchased $7.9 million of natural gas for fuel
and shrink replacement from Williams Power Company based on
market pricing; |
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For the year ended December 31, 2004:
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we incurred $12.5 million from Williams for direct and
indirect expenses incurred on our behalf; |
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Discovery reimbursed Williams $3.1 million for direct
payroll and employee benefit costs pursuant to the operating and
maintenance agreements as well as $0.3 million for
capitalized labor costs; |
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Discovery paid Williams $1.4 million for operation and
management fees pursuant to the operating and maintenance
agreements as well as a $0.9 million fee for managing
capitalized projects; |
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we purchased a gross amount of $17.1 million of natural gas
for the Conway fractionator from an affiliate of Williams; |
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we purchased $1.3 million of NGLs to replenish deficit
product positions from a subsidiary of Williams based on market
pricing; |
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we sold $0.5 million to a subsidiary of Williams that
markets substantially all of the NGLs and excess natural gas to
which our Conway fractionation and storage facility takes title
based on market pricing; |
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Discovery sold $57.8 million of NGLs to a subsidiary of
Williams that markets substantially all of the NGLs and excess
natural gas to which Discovery takes title based on market
pricing; and |
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Discovery purchased $0.4 million of natural gas for fuel
and shrink replacement from Williams Power Company based on
market pricing. |
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For the year ended December 31, 2003:
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we sold $2.4 million in storage services to a Williams
affiliate that was subsequently sold to a third party; |
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we incurred $4.2 million from Williams for interest expense
related to intercompany advances; |
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Discovery reimbursed Williams $3.0 million for direct
payroll and employee benefit costs pursuant to the operating and
maintenance agreements as well as $0.2 million for
capitalized labor costs; |
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Discovery paid Williams $1.4 million for operation and
management fees pursuant to the operating and maintenance
agreements as well as a $0.1 million fee for managing
capitalized projects; |
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we purchased a gross amount of $12.8 million of natural gas
for the Conway fractionator from an affiliate of Williams; |
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Discovery sold $54.1 million of NGLs to a subsidiary of
Williams that markets substantially all of the NGLs and excess
natural gas to which Discovery takes title based on market
pricing; and |
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Discovery purchased $7.8 million of natural gas for fuel
and shrink replacement from Williams Power Company based on
market pricing. |
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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES
Conflicts of Interest
Conflicts of interest exist and may arise in the future as a
result of the relationships between our general partner and its
affiliates, including Williams, on the one hand, and us 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 us
in a manner beneficial to us and our unitholders. Our
partnership agreement contains provisions that modify and limit
our general partners fiduciary duties to the unitholders.
Our partnership agreement also restricts the remedies available
to unitholders for actions taken that, without those
limitations, might constitute breaches of fiduciary duty.
Whenever a conflict arises between our general partner or its
affiliates, on the one hand, and us or any other partner, on the
other, our general partner will resolve that conflict. Our
general partner may, but is not required to, seek the approval
of such resolution from the conflicts committee of the board of
directors of our general partner. An independent third party is
not required to evaluate the fairness of the resolution.
Our general partner will not be in breach of its obligations
under the partnership agreement or its duties to us or our
unitholders if the resolution of the conflict is:
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approved by the conflicts committee, 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 between the parties involved, including other
transactions that may be particularly favorable or advantageous
to us. |
If our general partner does not seek approval from the conflicts
committee and the board of directors of our general partner
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 conflicts committee may
consider any factors it determines in good faith to consider
when resolving a conflict. When our partnership agreement
requires someone to act in good faith, it requires that person
to reasonably believe that he is acting in the best interests of
the partnership, unless the context otherwise requires. Please
read Management Management of Williams
Partners L.P. for information about the conflicts
committee of the board of directors of our general partner.
Conflicts of interest could arise in the situations described
below, among others.
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Actions taken by our general partner may affect the amount
of cash available to pay distributions to unitholders or
accelerate the right to convert subordinated units. |
The amount of cash that is available for distribution to
unitholders is affected by decisions of our general partner
regarding such matters as:
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amount and timing of asset purchases and sales; |
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cash expenditures; |
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borrowings; |
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issuance of additional units; and |
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the creation, reduction or increase of reserves in any quarter. |
In addition, borrowings by us and our affiliates do not
constitute a breach of any duty owed 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. |
For example, in the event we have not generated sufficient cash
from our operations to pay the minimum quarterly distribution on
our common units and our subordinated units, our partnership
agreement permits us to borrow funds, which would enable us to
make this distribution on all outstanding units. Please read
How We Make Cash Distributions Subordination
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 not borrow funds from
us, our operating company, or its operating subsidiaries.
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Neither our partnership agreement nor any other agreement
requires Williams to pursue a business strategy that favors us
or utilizes our assets or dictates what markets to pursue or
grow. Williams directors and officers have a fiduciary
duty to make these decisions in the best interests of the
stockholders of Williams, which may be contrary to our
interests. |
Because the officers and certain of the directors of our general
partner are also directors and/or officers of Williams, such
directors and officers have fiduciary duties to Williams that
may cause them to pursue business strategies that
disproportionately benefit Williams or which otherwise are not
in our best interests.
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Our general partner is allowed to take into account the
interests of parties other than us, such as Williams, in
resolving conflicts of interest. |
Our partnership agreement contains provisions that reduce the
standards to which our general partner would otherwise be held
by state fiduciary duty law. For example, our partnership
agreement permits our general partner to make a number of
decisions in its individual capacity, as opposed to in its
capacity as our general partner. This entitles our general
partner to consider only the interests and factors that it
desires, and it has no duty or obligation to give any
consideration to any interest of, or factors affecting, us, our
affiliates or any limited partner. Examples include the exercise
of its limited call right, its 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.
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Our general partner has limited its liability and reduced
its fiduciary duties, and has also restricted the remedies
available to our unitholders for actions that, without the
limitations, might constitute breaches of 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 fiduciary duty. For example, our
partnership agreement:
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provides that the 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 it acted in good faith, meaning it
believed that the decision was in the best interests of our
partnership; |
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generally provides that affiliated transactions and resolutions
of conflicts of interest not approved by the conflicts committee
of the board of directors of our general partner and not
involving a vote of unitholders must be on terms no less
favorable to us than those generally being provided to or
available from unrelated third parties or be fair and
reasonable to us, as determined by the general |
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partner in good faith, and that, in determining whether a
transaction or resolution is fair and reasonable,
our general partner may consider the totality of the
relationships 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, our limited
partners for any acts or omissions unless there has been a final
and non-appealable judgment entered by a court of competent
jurisdiction determining that our general partner or those other
persons acted in bad faith or engaged in fraud or willful
misconduct. |
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We do not have any officers or employees and rely solely
on officers and employees of our general partner and its
affiliates. |
Affiliates of our general partner conduct businesses and
activities of their own in which we 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
general partner. The officers of general partner are not
required to work full time on our affairs. These officers are
required to devote time to the affairs of Williams or its
affiliates and are compensated by them for the services rendered
to them.
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Certain of our officers are not required to devote their
full time to our business. |
All of the senior officers of our general partner are also
senior officers of Williams and spend sufficient amounts of
their time overseeing the management, operations, corporate
development and future acquisition initiatives of our business.
Alan Armstrong, the chief operating officer of our general
partner, is the principal executive responsible for the
oversight of our affairs. Our non-executive directors devote as
much time as is necessary to prepare for and attend board of
directors and committee meetings.
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We reimburse our general partner and its affiliates for
expenses. |
We reimburse our general partner and its affiliates for 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 the expenses that are allocable to us in good faith.
Please read Certain Relationships and Related
Transactions Omnibus Agreement.
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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 other party has recourse
only to our assets and not against our general partner or its
assets or any affiliate of our general partner or its assets.
Our partnership agreement provides that any action taken by our
general partner to limit its or our liability is not a breach of
our general partners fiduciary duties, even if we could
have obtained terms that are more favorable without the
limitation on liability.
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Common unitholders have no right to enforce obligations of
our general partner and its affiliates under agreements with
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.
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Contracts between us, on the one hand, and our general
partner and its affiliates, on the other, are not and will not
be the result of arms-length negotiations. |
Neither our partnership agreement nor any of the other
agreements, contracts and arrangements between us and our
general partner and its affiliates are or will be the result of
arms-length negotiations. Our
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partnership agreement generally provides that any affiliated
transaction, such as an agreement, contract or arrangement
between us and our general partner and its affiliates, must be:
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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 between the parties involved
(including other transactions that may be particularly favorable
or advantageous to us). |
Our general partner determines, in good faith, the terms of any
of these transactions.
Our general partner and its affiliates have no obligation to
permit us to use any facilities or assets of our general partner
and its affiliates, except as may be provided in contracts
entered into specifically dealing with that use. Our general
partner may also enter into additional contractual arrangements
with any of its affiliates on our behalf. There is no obligation
of our general partner and its affiliates to enter into any
contracts of this kind.
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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 conflicts 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
securities of the partnership, and the incurring of any other
obligations; |
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the making of tax, regulatory and other filings, or rendering of
periodic or other reports to governmental or other agencies
having jurisdiction over our business or assets; |
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the acquisition, disposition, mortgage, pledge, encumbrance,
hypothecation or exchange of any or all of our assets or the
merger or other combination of us with or into another person; |
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the negotiation, execution and performance of any contracts,
conveyances or other instruments; |
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the distribution of partnership 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, and the
contribution of property and the making of loans to, any further
limited or general partnerships, joint ventures, corporations,
limited liability companies or other relationships; |
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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 and otherwise engaging in the conduct of litigation,
arbitration or mediation and the incurring of legal expense and
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 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; 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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Please read The Partnership Agreement Voting
Rights for information regarding the voting rights of
unitholders.
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Common units are subject to our general partners
limited call right. |
Our general partner may exercise its right to call and purchase
common units as provided in the partnership agreement or assign
this right to one of its affiliates or to us. Our general
partner may use its own discretion, free of fiduciary duty
restrictions, in determining whether to exercise this right. As
a result, a common unitholder may have his common units
purchased from him at an undesirable time or price. Please read
The Partnership Agreement Limited Call
Right.
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We may not choose to retain separate counsel for ourselves
or for the holders of common units. |
The attorneys, independent accountants and others who perform
services for us 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
conflicts 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.
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Our general partners affiliates may compete with us
and neither our general partner nor its affiliates have any
obligation to present business opportunities to us. |
Our partnership agreement provides that our general partner is
restricted from engaging in any business activities other than
those incidental to its ownership of interests in us. However,
affiliates of our general partner are not prohibited from
engaging in other businesses or activities, including those that
might be in direct competition with us. Williams may acquire,
construct or dispose of midstream or other assets in the future
without any obligation to offer us the opportunity to acquire
those assets. In addition, under our partnership agreement, the
doctrine of corporate opportunity, or any analogous doctrine,
will not apply to the general partner and its affiliates. As a
result, neither the general partner nor any of its affiliates
have any obligation to present business opportunities to us.
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 Revised Uniform Limited Partnership Act, which we refer
to as the Delaware Act, provides that Delaware limited
partnerships may, in their partnership agreements, expand,
restrict or eliminate 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 provisions to
allow our general partner or its affiliates to engage in
transactions with us that otherwise would be prohibited by
state-law fiduciary 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 the board of directors of our general
partner has fiduciary duties to manage our general partner in a
manner beneficial both to its owner, Williams, as well as to
you. Without these modifications, the general partners
ability to make decisions involving conflicts of interests would
be restricted. The modifications to the fiduciary standards
benefit our general partner by enabling it to take into
consideration all parties involved in the proposed action. These
modifications also strengthen the ability of our general partner
to attract and retain experienced and capable directors. These
modifications represent a detriment to the common 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
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interests of third parties in addition to our interests when
resolving conflicted interests. The following is a summary of:
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the fiduciary duties imposed on our general partner by the
Delaware Act; |
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material modifications of these duties contained in our
partnership agreement; and |
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certain rights and remedies of unitholders contained in the
Delaware Act. |
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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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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 as to compliance with
fiduciary duties or applicable law. For example,
Section 7.9 of our partnership agreement provides that when
our general partner is acting in 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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Our partnership agreement generally provides that affiliated
transactions and resolutions of conflicts of interest not
involving a vote of unitholders and that are not approved
by the conflicts committee of the board of directors of our
general partner must be: |
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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 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 conflicts
committee and the board of directors of our general partner
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, and in any proceeding brought by
or on behalf of any |
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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. |
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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, its affiliates and
their officers and directors will not be liable for monetary
damages to us, our limited partners 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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Rights and remedies of unitholders |
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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. These actions include
actions against a general partner for breach of its fiduciary
duties or of the partnership agreement. 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. |
In order to become one of our limited partners, a common
unitholder is required to agree to be bound by the provisions in
the partnership agreement, including the provisions discussed
above. Please read Description of the Common
Units Transfer of Common Units. 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 to sign
our partnership agreement does not render the partnership
agreement unenforceable against that person.
Under the partnership agreement, we must indemnify our general
partner and its officers, directors and managers, to the fullest
extent permitted by law, against liabilities, costs and expenses
incurred by our 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 also must 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 that these provisions purport to
include indemnification for liabilities arising under the
Securities Act, in the opinion of the Securities and Exchange
Commission such indemnification is contrary to public policy and
therefore unenforceable. If you have questions regarding the
fiduciary duties of our general partner please read The
Partnership Agreement Indemnification.
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DESCRIPTION OF THE COMMON UNITS
The 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 units and
subordinated units in and to partnership distributions, please
read this section, How We Make Cash Distributions
and Description of the Subordinated Units. 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
EquiServe Trust Company, N.A. serves as registrar and transfer
agent for the common units. We 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 holder of a common
unit; and |
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other similar fees or charges. |
There is no charge to unitholders for disbursements of our cash
distributions. We will indemnify the transfer agent against all
claims and losses that may arise out of all actions of the
transfer agent or its agents or subcontractors for their
activities in that capacity, except for any liability due to any
gross negligence or willful misconduct of the transfer agent or
its agents or subcontractors.
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 has 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.
Transfer of Common Units
By transfer of common units or the issuance of common units in a
merger or consolidation in accordance with our partnership
agreement, each transferee of common units will be admitted as a
limited partner with respect to the common units transferred
when such transfer and admission is reflected in our books and
records. Additionally, each transferee:
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represents that the transferee has the capacity, power and
authority to enter into 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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gives the consents and approvals contained in our partnership
agreement. |
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An assignee 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 and are transferable according to
the laws governing transfer of securities. 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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DESCRIPTION OF THE SUBORDINATED UNITS
The subordinated units represent a separate class of limited
partner interests in our partnership, and the rights of holders
of subordinated units to participate in distributions differ
from, and are subordinated to, the rights of the holders of
common units. Unlike the common units, the subordinated units
are not publicly traded.
Cash Distribution Policy
During the subordination period, the common units will have the
right to receive distributions of available cash from operating
surplus in an amount equal to the minimum quarterly distribution
of $0.35 per common unit, 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.
The purpose 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. The
subordinated units are not entitled to receive any arrearages in
the payment of the minimum quarterly distribution from prior
quarters. For a more complete description of our cash
distribution policy on the subordinated units, please read
How We Make Cash Distributions Distributions
of Available Cash from Operating Surplus During the
Subordination Period.
Conversion of the Subordinated Units
Each subordinated unit will convert into one common unit at the
end of the subordination period, which will end once we meet the
financial tests in the partnership agreement. For a more
complete description of the circumstances under which the
subordinated units will convert into common units, please read
How We Make Cash Distributions Subordination
Period.
Distributions Upon Liquidation
If we liquidate during the subordination period, we will, to the
extent possible, allocate gain and loss to entitle the holders
of common units a preference over the holders of subordinated
units to the extent required to permit the common unitholders to
receive their unrecovered initial unit price, plus the minimum
quarterly distribution for the quarter during which liquidation
occurs, plus any arrearages. For a more complete description of
this liquidation preference, please read How We Make Cash
Distributions Distributions of Cash Upon
Liquidation.
Limited Voting Rights
For a more complete description of the voting rights of holders
of subordinated units, please read The Partnership
Agreement Voting Rights.
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THE PARTNERSHIP AGREEMENT
The following is a summary of the material provisions of our
partnership agreement. Our partnership agreement is incorporated
by reference as an exhibit to the registration statement of
which this prospectus constitutes a part. We will provide
prospective investors with a copy of this 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
How We Make Cash Distributions; |
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with regard to the transfer of common units, please read
Description of the Common Units Transfer of
Common Units; and |
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with regard to allocations of taxable income and taxable loss,
please read Material Tax Consequences. |
Organization and Duration
We were organized on February 28, 2005 and have a perpetual
existence.
Purpose
Our purpose under the partnership agreement is limited to
serving as the sole member of our operating company and engaging
in any business activities that may be engaged in by our
operating company and its subsidiaries or that are approved by
our general partner. The limited liability company agreement of
our operating company provides that it may, directly or
indirectly, engage in:
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(1) its operations as conducted immediately before our
initial public offering; |
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(2) any other activity approved by our general partner but
only to the extent that our general partner determines that, as
of the date of the acquisition or commencement of the activity,
the activity generates qualifying income as this
term is defined in Section 7704 of the Internal Revenue
Code; or |
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(3) any activity that enhances the operations of an
activity that is described in (1) or (2) above. |
Although our general partner has the ability to cause us, our
operating company or its subsidiaries to engage in activities
other than gathering, transporting and processing natural gas
and the fractionating and storing of NGLs, 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
authorized in general to perform all acts it determines to be
necessary or appropriate to carry out our purposes and to
conduct our business.
Power of Attorney
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. Please read Amendment
of the Partnership Agreement below.
Capital Contributions
Unitholders are not obligated to make additional capital
contributions, except as described below under
Limited Liability.
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Limited Liability
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Participation in the Control of Our Partnership |
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
our partnership agreement, his liability under the Delaware Act
will be limited, subject to possible exceptions, to the amount
of capital he is obligated to contribute to us for his common
units plus his share of any undistributed profits and assets. If
it were determined, however, that the right, or exercise of the
right, by the limited partners as a group:
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to remove or replace our general partner; |
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to approve some amendments to our partnership agreement; or |
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to take other action under our partnership agreement; |
constituted participation in the control of our
business for the purposes of the Delaware Act, then the limited
partners could be held personally liable for our obligations
under the laws of Delaware, to the same extent as our general
partner. This liability would extend to persons who transact
business with us who reasonably believe that the limited partner
is a general partner. Neither our partnership agreement nor the
Delaware Act specifically provides for legal recourse against
our general partner if a limited partner were to lose limited
liability through any fault of our general partner. While this
does not mean that a limited partner could not seek legal
recourse, we know of no precedent for such a claim in Delaware
case law.
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Unlawful Partnership Distribution |
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.
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Failure to Comply with the Limited Liability Provisions of
Jurisdictions in Which We Do Business |
Our subsidiaries may be deemed to conduct business in Kansas,
Louisiana and Alabama. Upon the consummation of the acquisition
of the interest in Four Corners, we may also be deemed to
conduct business in Colorado and New Mexico. Our subsidiaries
may conduct business in other states in the future. Maintenance
of our limited liability may require compliance with legal
requirements in the jurisdictions in which the operating company
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
membership interest in our operating company 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 our general partner, to approve some amendments to our
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 our general partner under the
circumstances. We will operate in a manner that our general
partner considers reasonable and necessary or appropriate to
preserve the limited liability of the limited partners.
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Voting Rights
The following matters require the unitholder vote specified
below. Matters requiring 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. |
In voting their common and subordinated units, our general
partner and its affiliates 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 and 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 our 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. Please read Merger, Sale or
Other Disposition of Assets. |
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Amendment of the limited liability company agreement of the
operating company and other action taken by us as the sole
member of our operating company |
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Unit majority if such amendment or other action would adversely
affect our limited partners (or any particular class of limited
partners) in any material respect. Please read
Amendment of the Partnership
Agreement Action Relating to the Operating
Company. |
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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 partnership upon dissolution Withdrawal of
our general partner |
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Unit majority. Please read Termination and
Dissolution. 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 June 30, 2015 in
a manner which would cause a dissolution of our partnership.
Please read Withdrawal or Removal of Our
General Partner. |
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Removal of our 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 Our
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
the 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 |
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units, excluding common units held by our general partner and
its affiliates, is required in other circumstances for a
transfer of the general partner interest to a third party prior
to June 30, 2015. Please read Transfer of
General Partner Interest. |
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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 with or
into, or sale of all or substantially all of its assets to, or
sale of all or substantially all of its equity interest to, such
person, the approval of a majority of the common units,
excluding common units held by our general partner and its
affiliates, is required in most circumstances for a transfer of
the incentive distribution rights to a third party prior to
June 30, 2015. 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 Our
General Partner. |
Issuance of Additional Securities
Our partnership agreement authorizes us to issue an unlimited
number of additional partnership securities and rights to buy
partnership securities, subject to the limitations imposed by
the New York Stock Exchange, 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
equity securities. Holders of any additional common units we
issue will be entitled to share equally with the then-existing
holders of common units in our distributions of available cash.
In addition, the issuance of additional partnership interests
may dilute the value of the interests of the then-existing
holders of common units in our net assets.
In accordance with Delaware law and the provisions of our
partnership agreement, we may also issue additional partnership
securities that, 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 the issuance by our subsidiaries of equity securities,
which may effectively rank senior to our common units.
Upon issuance of additional partnership securities other than
upon exercise of the underwriters option to purchase
additional units, our general partner will have the right, but
not the obligation, to make additional capital contributions to
the extent necessary to maintain its 2% general partner interest
in us. Our general partners 2% 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% 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 equity 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 its and
its affiliates percentage interest, including its interest
represented by common units 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
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
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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 must seek
written approval of the holders of the number of units required
to approve the amendment or 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.
No amendment may be made that would:
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(1) 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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(2) 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 may be given or withheld at its
option. |
The provision of our partnership agreement preventing the
amendments having the effects described in clauses (1) or
(2) above can be amended upon the approval of the holders
of at least 90% of the outstanding units voting together as a
single class (including units owned by our general partner and
its affiliates). Upon completion of this offering, our general
partner and its affiliates will own approximately 40.0% of the
outstanding units.
Our general partner may generally make amendments to our
partnership agreement without the approval of any limited
partner to reflect:
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(1) a change in our name, the location of our principal
place of business, our registered agent or our registered office; |
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(2) the admission, substitution, withdrawal or removal of
partners in accordance with our partnership agreement; |
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(3) a change that our general partner determines to be
necessary or appropriate for us to qualify or to 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, the operating company
nor 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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(4) 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 ERISA whether or not substantially
similar to plan asset regulations currently applied or proposed; |
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(5) subject to the limitations on the issuance of
additional partnership securities described above, an amendment
that our general partner determines to be necessary or
appropriate for the authorization of additional partnership
securities or rights to acquire partnership securities; |
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(6) any amendment expressly permitted in our partnership
agreement to be made by our general partner acting alone; |
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(7) 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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(8) 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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(9) a change in our fiscal year or taxable year and related
changes; |
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(10) certain mergers or conveyances as set forth in our
partnership agreement; or |
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(11) any other amendments substantially similar to any of
the matters described in clauses (1) through
(10) above. |
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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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 the 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 not result in a loss of limited
liability to the limited partners or result in our being taxed
as an entity for federal income tax purposes in connection with
any of the amendments described above under No
Unitholder Approval. 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 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 must be approved by the affirmative vote of limited
partners whose aggregate outstanding units constitute not less
than the voting requirement sought to be reduced.
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Action Relating to the Operating Company |
Without the approval of the holders of units representing a unit
majority, our general partner is prohibited from consenting on
our behalf, as the sole member of the operating company, to any
amendment to the limited liability company agreement of the
operating company or taking any action on our behalf permitted
to be taken by a member of the operating company, in each case,
that would adversely affect our limited partners (or any
particular class of limited partners) in any material respect.
Merger, Sale or Other Disposition of Assets
A merger or consolidation of us requires the consent of our
general partner. However, our general partner will have no duty
or obligation to consent to any merger or consolidation and may
decline to do so
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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 addition,
the partnership agreement generally prohibits our general
partner, without the prior approval of the holders of units
representing 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 that
approval. Our general partner may also sell all or substantially
all of our assets under a foreclosure or other realization upon
those encumbrances without that approval. Finally, our general
partner may consummate any merger or consolidation without the
prior approval of our unitholders if our general partner has
received an opinion of counsel that the merger or consolidation,
as the case may be, would not result in the loss of the limited
liability of to the limited partners or result in our being
taxed as an entity for federal income tax purposes, we are the
surviving entity in the transaction, the transaction would not
result in an amendment to our partnership agreement that the
could not otherwise be adopted solely by our general partner,
each of our units will be an identical unit of our partnership
following the transaction, and the units to be issued do not
exceed 20% of our outstanding units immediately prior to the
transaction.
If the conditions specified in our 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 some or all of our
assets to, a newly formed entity if the sole purpose of that
merger or conveyance is to effect a mere change in our legal
form into another limited liability entity. The unitholders are
not entitled to dissenters rights of appraisal under our
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 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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(1) the election of our general partner to dissolve us, if
approved by the holders of units representing a unit majority; |
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(2) the entry of a decree of judicial dissolution of our
partnership; |
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(3) 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
withdrawal or removal following approval and admission of a
successor; or |
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(4) there being no limited partners, unless we are
continued without dissolution in accordance with applicable
Delaware law. |
Upon a dissolution under clause (3) 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 the 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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none of our partnership, the limited partnership, our operating
company 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. |
Liquidation and Distribution of Proceeds
Upon our dissolution, unless we are reconstituted and 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
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necessary or appropriate, liquidate our assets and apply the
proceeds of the liquidation as described in How We Make
Cash Distributions Distributions of Cash Upon
Liquidation. The liquidator may defer liquidation or
distribution of our assets for a reasonable period at time or
distribute assets to partners in kind if it determines that a
sale would be impractical or would cause undue loss to the
partners.
Withdrawal or Removal of Our General Partner
Except as described below, our general partner has agreed not to
withdraw voluntarily as the general partner of our partnership
prior to June 30, 2015 without obtaining 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, and furnishing an opinion of counsel regarding
limited liability and tax matters. On or after June 30,
2015, our general partner may withdraw as general partner
without first obtaining approval of any unitholder by giving
90 days written notice, and that withdrawal will not
constitute a violation of our partnership agreement.
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 person
and its affiliates other than our general partner and its
affiliates. In addition, our 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 Interest and Transfer of
Incentive Distribution Rights below.
Upon the 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 majority of the outstanding common units
and subordinated units, 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 of time 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 and subordinated units, voting as separate classes. 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 the
general partners removal. At the closing of this offering,
our general partner and its affiliates will own approximately
40.0% of the outstanding 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 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 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 the interests at the time. |
In the event of 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
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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 their 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.
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 the departing general
partner, including, without limitation, all employee-related
liabilities, including severance liabilities, incurred for the
termination of any employees employed by the departing general
partner or its affiliates for our benefit.
Transfer of General Partner Interest
Except for transfer by our general partner of all, but not less
than all, of its general partner interest in us 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, |
our general partner may not transfer all or any part of its
general partner interest in us to another person prior to
June 30, 2015 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, among other
things, assume 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 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 the ownership interests in the
holder or the sale of all or substantially all of its assets to,
that entity without the prior approval of the unitholders. Prior
to June 30, 2015, other transfers of the 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 June 30, 2015, the incentive distribution rights will
be freely transferable.
Transfer of Ownership Interests in Our General
Partner
At any time, the members of our general partner may sell or
transfer all or part of their membership interests in our
general partner to an affiliate or a third party without the
approval of our unitholders.
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Change of Management Provisions
Our partnership agreement contains specific provisions that are
intended to discourage a person or group from attempting to
remove Williams Partners GP LLC as our general partner or
otherwise change 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 rights on all of its units. This loss of
voting rights does not apply to any person or group that
acquires the units from our general partner or its affiliates
and any transferees of that person or group 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 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 interest and its incentive distribution rights into
common units or to receive cash in exchange for those interests. |
Limited Call Right
If at any time our general partner and its affiliates hold more
than 80% of the then-issued and outstanding partnership
securities of any class, our general partner will have the
right, but not the obligation, 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 remaining partnership securities 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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(1) the highest price paid by either of our general partner
or any of its affiliates for any partnership securities 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 partnership securities; and |
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(2) the current market price as of the date three days
before the date the notice is mailed. |
As a result of our general partners right to purchase
outstanding partnership securities, a holder of partnership
securities may have his partnership securities purchased at an
undesirable time or price. Our partnership agreement provides
that the resolution of any conflict of interest that is fair and
reasonable will not be a breach of the partnership agreement.
Our general partner may, but it is not obligated to, submit the
conflict of interest represented by the exercise of the limited
call right to the conflicts committee for approval or seek a
fairness opinion from an investment banker. If our general
partner exercises its limited call right, it will make a
determination at the time, based on the facts and circumstances,
and upon the advice of counsel, as to the appropriate method of
determining the fairness and reasonableness of the transaction.
Our general partner is not obligated to obtain a fairness
opinion regarding the value of the common units to be
repurchased by it upon exercise of the limited call right.
There is no restriction in our partnership agreement that
prevents our general partner from issuing additional common
units and exercising its call right. If our general partner
exercised its limited call right, the effect would be to take us
private and, if the units were subsequently deregistered, we
would no longer be subject to the reporting requirements of the
Securities Exchange Act of 1934.
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
Consequences Disposition of Common Units.
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Meetings; Voting
Except as described below regarding a person or group owning 20%
or more of any class of units then outstanding, unitholders who
are record holders of units on the record date will be entitled
to notice of, and to vote at, meetings of our limited partners
and to act upon matters for which approvals may be solicited. In
the case of common units held by our general partner on behalf
of non-citizen assignees, our general partner will distribute
the votes on those common units in the same ratios as the votes
of limited partners on other units are cast.
Our general partner does not anticipate that any meeting of
unitholders will be called in the foreseeable future. Any action
that is required or permitted to be taken by the unitholders may
be taken either at a meeting of the unitholders or without a
meeting if consents in writing describing the action so taken
are signed by holders of the number of units 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 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
above. 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, or a person or group who acquire units with the
prior approval of the board of our general partner 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 the 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 any 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 is reflected in our books and
records.
Except as described above under Limited
Liability above, 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 determination of our general partner,
create a substantial risk of cancellation or forfeiture of any
property in which we have an interest because of the
nationality, citizenship or other related status of any limited
partner we may redeem the units held by the limited partner at
their current market price, in accordance with the procedures
set forth in our partnership agreement. 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 or assignee
fails to furnish information about his nationality, citizenship
or other related status within
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30 days after 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.
Indemnification
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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(1) our general partner; |
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(2) any departing general partner; |
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(3) any person who is or was an affiliate of our general
partner (including Williams and its subsidiaries) or any
departing general partner; |
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(4) any person who is or was an officer, director, member,
partner, fiduciary or trustee of any entity described in (1),
(2) or (3) above; |
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(5) any person who is or was serving as an officer,
director, 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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(6) any person designated by our general partner. |
Any indemnification under these provisions will only be out of
our assets. Unless it otherwise agrees, our general partner will
not be personally liable for, or have any obligation to
contribute or loan 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 the
partnership agreement.
Books and Reports
Our general partner is required to keep appropriate books of our
business at our principal offices. The books are maintained for
both tax and financial reporting purposes on an accrual basis.
For tax and financial reporting purposes, our fiscal year is the
calendar year.
We will furnish or make available to record holders of common
units, within 120 days after the close of each fiscal year,
an annual report containing audited financial statements and a
report on those financial statements by our independent
registered public accounting firm or make such reports available
on the SECs Electronic Data Gathering, Analysis, and
Retrieval (EDGAR) System. Except for our fourth quarter, we
will also furnish or make available on EDGAR summary financial
information within 90 days after the close of each quarter.
We will furnish each record holder of a unit with information
reasonably required for tax reporting purposes within
90 days after the close of each calendar year. This
information is expected to be furnished in summary form so that
some complex calculations normally required of partners can be
avoided. Our ability to furnish this summary information to
unitholders will depend on the cooperation of unitholders in
supplying us with specific information. Every unitholder will
receive information to assist him in determining his federal and
state tax liability and filing his federal and state income tax
returns, regardless of whether he supplies us with information.
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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 demand stating the purpose of such
demand and at his own expense, obtain:
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(1) a current list of the name and last known address of
each partner; |
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(2) a copy of our tax returns; |
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(3) information as to the amount of cash, and a description
and statement of the net agreed value of any other property or
services, contributed or to be contributed by each partner and
the date on which each became a partner; |
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(4) copies of our partnership agreement, the certificate of
limited partnership of the partnership, related amendments and
powers of attorney under which they have been executed; |
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(5) information regarding the status of our business and
financial condition; and |
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(6) any other information regarding our affairs as is just
and reasonable. |
Our general partner may, and intends to, keep confidential from
the limited partners trade secrets or other information the
disclosure of which our general partner believes in good faith
is not in our best interests, could damage us or our business or
that we are required by law or by agreements with third parties
to keep confidential.
Registration Rights
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 Williams Partners GP LLC as our general
partner. We are obligated to pay all expenses incidental to the
registration, excluding underwriting discounts and commissions.
Please read Units Eligible for Future Sale beginning
on the following page.
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UNITS ELIGIBLE FOR FUTURE SALE
After the sale of the common units offered by this prospectus,
our general partner and its affiliates will hold, directly and
indirectly, an aggregate of 1,250,000 common units and 7,000,000
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 common and
subordinated 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 this offering will generally be freely
transferable without restriction or further registration under
the Securities Act, except that any common units held 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. |
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 public information
requirements, volume limitations, manner of sale provisions and
notice requirements of Rule 144.
The partnership agreement does not restrict our ability to issue
equity securities at any time. 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, common units then
outstanding. Please read The Partnership
Agreement Issuance 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 applicable state securities laws the offer
and sale of any units 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 to require registration of any of
these units and to include any of these units 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 applicable state securities laws
arising from the registration statement or prospectus. We will
bear all costs and expenses incidental to any registration,
excluding any underwriting discounts and commissions. Except as
described below, our general partner and its affiliates may sell
their units in private transactions at any time, subject to
compliance with applicable laws.
We, our subsidiaries and our general partner and its affiliates,
including the directors and executive officers of our general
partner have agreed not to sell any common units for a period of
90 days after the date of this prospectus, subject to
certain exceptions. Please read Underwriting
Lock-Up Agreements for a description of these
lock-up provisions.
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MATERIAL TAX CONSEQUENCES
This section is a discussion of the material tax considerations
that may be relevant to prospective unitholders who are
individual citizens or residents of the United States and,
unless otherwise noted in the following discussion, is the
opinion of Andrews Kurth LLP, counsel to our general partner and
us, insofar as it relates to matters of United States federal
income tax law and legal conclusions with respect to those
matters. 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 Williams Partners L.P. and our
operating company.
The following discussion does not address all federal income tax
matters affecting us or the unitholders. Moreover, the
discussion focuses on unitholders who are individual citizens or
residents of the United States and has only limited application
to corporations, estates, trusts, nonresident aliens or other
unitholders subject to specialized tax treatment, such as
tax-exempt institutions, foreign persons, individual retirement
accounts (IRAs), real estate investment trusts (REITs), employee
benefit plans or mutual funds. Accordingly, we urge 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 the 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 Andrews Kurth LLP and are
based on the accuracy of the representations made by us and our
general partner.
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 and advice of Andrews Kurth LLP. 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 in
this discussion 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 to
pay distributions 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, Andrews Kurth LLP has not
rendered an opinion with respect to the following specific
federal income tax issues:
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the treatment of a unitholder whose common units are loaned to a
short seller to cover a short sale of common units (please read
Tax Consequences of Unit Ownership
Treatment of Short Sales); |
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whether our monthly convention for allocating taxable income and
losses is permitted by existing Treasury Regulations (please
read Disposition of Common Units
Allocations Between Transferors and Transferees); and |
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whether our method for depreciating Section 743 adjustments
is sustainable in certain cases (please read
Tax Consequences of Unit Ownership
Section 754 Election and Uniformity
of Units). |
Partnership Status
A partnership is not a taxable entity and incurs no federal
income tax liability. Instead, each partner of a partnership is
required to take into account his share of items of income,
gain, loss and deduction of the partnership in computing his
federal income tax liability, regardless of whether cash
distributions are made to him by the partnership. Distributions
by a partnership to a partner are generally not taxable to the
partner unless the amount of cash distributed is in excess of
the partners adjusted basis in his partnership interest.
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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 and processing 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 2% of our current income is
not qualifying income; however, this estimate could change from
time to time. Based on and subject to this estimate, the factual
representations made by us and our general partner and a review
of the applicable legal authorities, Andrews Kurth LLP 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.
No ruling has been or will be sought from the IRS and the IRS
has made no determination as to our status 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 Andrews Kurth LLP
that, based upon the Internal Revenue Code, its regulations,
published revenue rulings and court decisions and the
representations described below, we will be classified as a
partnership and the operating company will be disregarded as an
entity separate from us for federal income tax purposes.
In rendering its opinion, Andrews Kurth LLP has relied on
factual representations made by us and our general partner. The
representations made by us and our general partner upon which
Andrews Kurth LLP has relied include:
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(a) Neither we nor our operating company have elected nor
will elect to be treated as a corporation; and |
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(b) For each taxable year, more than 90% of our gross
income will be income that Andrews Kurth LLP has opined or will
opine is qualifying income within the meaning of
Section 7704(d) of the Internal Revenue Code. |
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, we will be
treated as if we had transferred all of our assets, subject to
liabilities, to a newly formed corporation, on the first day of
the year in which we fail to meet the Qualifying Income
Exception, in return for stock in that corporation, and then
distributed that stock to the unitholders in liquidation of
their interests in us. This deemed contribution and liquidation
would 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 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 the 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 Andrews Kurth LLPs
opinion that we will be classified as a partnership for federal
income tax purposes.
Limited Partner Status
Unitholders who have become limited partners of Williams
Partners L.P. will be treated as partners of Williams Partners
L.P. for federal income tax purposes. Also, unitholders whose
common units are held in
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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 Williams Partners L.P. 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 Ownership
Treatment of Short Sales.
Items of our income, gain, loss or deduction 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 be fully taxable as ordinary income. These holders are
urged to consult their own tax advisors with respect to their
status as partners in Williams Partners L.P. 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 corresponding
cash distributions are received by 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 or years 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 to the extent of his tax basis in
his 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 our
general partner, bears the economic risk of loss, known as
nonrecourse liabilities, will be treated as a
distribution of cash to that unitholder. To the extent our
distributions cause a unitholders at risk
amount to be less than zero at the end of any taxable year, he
must recapture any losses deducted in previous years. Please
read Limitations on Deductibility of
Losses.
A decrease in a unitholders percentage interest in us
because of our issuance of additional common units will decrease
his share of our nonrecourse liabilities, and thus will result
in a corresponding deemed distribution of cash, 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 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 the non-pro rata
portion of that distribution over the unitholders tax
basis 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
December 31, 2008, will be allocated, on a cumulative
basis, an amount of federal taxable income for that period that
will be less than 20% of the cash distributed to the unitholder
with respect to that period. We anticipate that after the
taxable year ending December 31, 2008, 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 make the minimum quarterly distribution
on all units and other assumptions with respect to capital
expenditures, cash flow and anticipated cash distributions.
These estimates and assumptions are subject to, among other
things,
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numerous business, economic, regulatory, 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,
and any differences could be material and could materially
affect the value of the common units.
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
Units Recognition of Gain or Loss.
Limitations on Deductibility of Losses. The deduction by
a unitholder of his share of our losses will be limited to the
tax basis in his units and, in the case of an individual
unitholder or a corporate unitholder, if more than 50% of the
value of the corporate unitholders stock is owned directly
or indirectly by or for five or fewer individuals or some
tax-exempt organizations, to the amount for which the unitholder
is considered to be at risk with respect to our
activities, if that amount is less than his tax basis. A
unitholder 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 excess loss above
that gain previously suspended by the at risk or basis
limitations is no longer 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 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.
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 corporate or partnership
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 unrelated party. The
passive activity loss rules are applied after other applicable
limitations on deductions, including the at risk rules and the
basis limitation.
A unitholders share of our net earnings 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.
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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. |
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 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 partner 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 the 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
the 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 partner in
which event the partner 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 our assets at the time of an offering, referred
to in this discussion as Contributed Property. These
allocations are required to eliminate the difference between a
partners book capital account, credited with
the fair market value of Contributed Property, and the
tax capital account, credited with the tax basis of
Contributed Property, referred to in this discussion as the
Book-Tax Disparity. The effect of these allocations
to a unitholder purchasing common units in this offering will be
essentially the same as if the tax basis of Contributed Property
was equal to its 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
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 partner who was allocated the deduction giving rise to the
treatment of that gain as recapture income in order to minimize
the recognition of ordinary income by some unitholders.
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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), 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. |
Andrews Kurth LLP is of the opinion that, with the exception of
the issues described in Tax Consequences of
Unit Ownership Section 754 Election,
Uniformity of Units and
Disposition of Common Units
Allocations Between Transferors and Transferees,
allocations under our partnership agreement will be given effect
for federal income tax purposes in determining a partners
share of an item of income, gain, loss or deduction.
Treatment of Short Sales. A unitholder whose units are
loaned to a short seller to cover a short sale of
units may be considered as having disposed of those units. If
so, he would no longer be a partner for tax purposes 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. |
Andrews Kurth LLP 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 studying issues relating to the tax
treatment of short sales of partnership interests. Please also
read Disposition of Common Units
Recognition of Gain or Loss.
Alternative Minimum Tax. Each unitholder will be required
to take into account his distributive share of any items of our
income, gain, loss or deduction for purposes of the alternative
minimum tax. The current minimum tax rate for non-corporate
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 United
States federal income tax rate for individuals is currently 35%
and the maximum United States federal income tax rate for net
capital gains of an individual is currently 15% if the asset
disposed of was held for more than 12 months at the time of
disposition.
Section 754 Election. We have made the election
permitted by Section 754 of the Internal Revenue Code. That
election is irrevocable without the consent of the IRS. The
election will generally permit us to adjust a common unit
purchasers tax basis in our assets (inside
basis) under Section 743(b) of the Internal Revenue
Code to reflect his purchase price. This election does not apply
to a person who purchases common units directly from us. The
Section 743(b) adjustment belongs to the purchaser and not
to other unitholders. For purposes of this discussion, a
unitholders inside basis in our assets will be considered
to
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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.
Treasury Regulations under Section 743 of the Internal
Revenue Code require, if the remedial allocation method is
adopted (which we have adopted), a portion of the
Section 743(b) adjustment attributable to recovery property
to be depreciated over the remaining cost recovery period for
the Section 704(c) built-in gain. 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
Treasury Regulations. Please read Uniformity
of Units.
Although Andrews Kurth LLP is unable to opine as to the validity
of this approach because there is no clear 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 common basis
of the property, or treat that portion as non-amortizable to the
extent attributable to property the common basis of 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 Section 754 election is advantageous if the
transferees tax basis in his units is higher than the
units share of the aggregate tax basis of our assets
immediately prior to the transfer. In that case, as a result of
the election, the transferee would have, among other items, a
greater amount of depreciation deductions and his share of any
gain or loss on a sale of our assets would be less. Conversely,
a Section 754 election is disadvantageous if the
transferees tax basis in his units is lower than those
units share of the aggregate tax basis of our assets
immediately prior to the transfer. Thus, the fair market value
of the units may be affected either favorably or unfavorably by
the election. A basis adjustment is required regardless of
whether a Section 754 election is made in the case of a
transfer of an interest in us if we have a substantial built-in
loss immediately after the transfer, or if we distribute
property and have a substantial basis reduction. Generally a
basis reduction or a built-in loss 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 we allocated to our tangible
assets to goodwill instead. Goodwill, 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 different than our taxable year and who
disposes of all of his units following the close of our taxable
year but before the close of his taxable year must include his
share of our income, gain, loss and deduction in income for his
taxable year, with the result that he will be required to
include in income for his taxable year his share of more than
one year of our income, gain, loss and deduction. Please read
Disposition of Common Units
Allocations Between Transferors and Transferees.
Initial Tax Basis, Depreciation and Amortization. We use
the tax basis of our assets 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, its
affiliates and our other unitholders as of the time of the
offering. Please read Tax Consequences of Unit
Ownership Allocation of Income, Gain, Loss and
Deduction.
To the extent allowable, we may elect to use the depreciation
and cost recovery methods that will result in the largest
deductions being taken in the early years after assets are
placed in service. Property we subsequently acquire or construct
may be depreciated using accelerated methods permitted by the
Internal Revenue Code.
If we dispose of depreciable property by sale, foreclosure or
otherwise, all or a portion of any gain, determined by reference
to the amount of depreciation previously deducted and the nature
of the property, may be subject to the recapture rules and taxed
as ordinary income rather than capital gain. Similarly, a
unitholder who has taken cost recovery or depreciation
deductions with respect to property we own will likely be
required to recapture some or all of those deductions as
ordinary income upon a sale of his interest in us. Please read
Tax Consequences of Unit Ownership
Allocation of Income, Gain, Loss and Deduction and
Disposition of Common Units
Recognition of Gain or Loss.
The costs incurred in selling our units (called
syndication expenses) must be capitalized and cannot
be deducted currently, ratably or upon our termination. There
are uncertainties regarding the classification of costs as
organization expenses, which we may be able to amortize, and as
syndication expenses, which we may not amortize. The
underwriting discounts and commissions we incur will be treated
as syndication expenses.
Valuation and Tax Basis of Our Properties. The federal
income tax consequences of the ownership and disposition of
units will depend in part on our estimates of the relative fair
market values, and the 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.
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. 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.
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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 12 months
will generally be taxed at a maximum rate of 15%. However, a
portion of this gain or loss 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
on 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. 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
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 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. |
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
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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, Andrews Kurth LLP is unable
to opine on the validity of this method of allocating income and
deductions between unitholders. If this method is not allowed
under the Treasury Regulations, or only applies to transfers of
less than all of the unitholders interest, our taxable
income or losses might be reallocated among the unitholders. We
are authorized to revise our method of allocation between
unitholders, as well as among 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, other than through a broker, generally is 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 required to notify us in writing of that purchase
within 30 days after the purchase, unless a broker or
nominee will satisfy such requirement. We are required to notify
the IRS of any such transfers 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.
Constructive Termination. We will be considered to have
been terminated for tax purposes if there is a sale or exchange
of 50% or more of the total interests in our capital and profits
within a 12-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 different from our taxable year, the
closing of our taxable year may result in more than
12 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.
Uniformity of Units
Because we cannot match transferors and transferees of units, we
must maintain uniformity of the economic and tax characteristics
of the units to a purchaser of these units. In the absence of
uniformity, we may be unable to completely comply with a number
of federal income tax requirements, both statutory and
regulatory. A lack of uniformity can result from a literal
application of Treasury
Regulation Section 1.167(c)-1(a)(6). Any
non-uniformity could have a negative impact on the value of the
units. Please read Tax Consequences of Unit
Ownership Section 754 Election.
We intend to depreciate the portion of a Section 743(b)
adjustment attributable to unrealized appreciation in the value
of Contributed Property, to the extent of any unamortized
Book-Tax Disparity, using a rate of depreciation or amortization
derived from the depreciation or amortization method and useful
life applied to the common basis of that property, or treat that
portion as nonamortizable, to the extent attributable to
property the common basis of 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
Ownership Section 754 Election. To the
extent that the Section 743(b) adjustment is attributable
to appreciation in value in excess of the unamortized Book-Tax
Disparity, we will apply the rules described in the Treasury
Regulations and legislative history. If we determine that this
position cannot reasonably be taken, we may adopt a depreciation
and amortization position under which all purchasers acquiring
units in the same month would receive depreciation and
amortization deductions, whether attributable to a common basis
or Section 743(b) adjustment, based upon the same
applicable rate as
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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, Andrews Kurth
LLP, 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 Units
Recognition of Gain or Loss.
Tax-Exempt Organizations and Other Investors
Ownership of units by employee benefit plans, other tax-exempt
organizations, regulated investment companies, 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.
A regulated investment company or mutual fund is
required to derive 90% or more of its gross income from certain
permitted sources. The American Jobs Creation Act of 2004
generally treats net income from the ownership of publicly
traded partnerships as derived from such a permitted source. We
anticipate that all of our net income will be treated as derived
from such a permitted source.
Non-resident aliens and foreign corporations, trusts or estates
that own units will be considered to be engaged in business in
the United States because of the ownership of units. As a
consequence, they will be required to file federal tax returns
to report their share of our income, gain, loss or deduction and
pay federal income tax at regular rates on their share of our
net income or gain. Moreover, under rules applicable to publicly
traded partnerships, we will withhold 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 United States trade or business, that
corporation may be subject to the United States branch profits
tax at a rate of 30%, in addition to regular federal income tax,
on its share of our income and gain, as adjusted for changes in
the foreign corporations U.S. net equity,
that is effectively connected with the conduct of a United
States trade or business. That tax may be reduced or eliminated
by an income tax treaty between the United States and the
country in which the foreign corporate unitholder is a
qualified resident. In addition, this type of
unitholder is subject to special information reporting
requirements under Section 6038C of the Internal Revenue
Code.
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 United
States trade or business of the foreign unitholder. 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.
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Administrative Matters
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 his share of our income,
gain, loss and deduction for our preceding taxable year. In
preparing this information, which will not be reviewed by
counsel, we will take various accounting and reporting
positions, some of which have been mentioned earlier, to
determine each unitholders share of income, gain, loss and
deduction. We cannot assure you that those positions will yield
a result that conforms to the requirements of the Internal
Revenue Code, Treasury Regulations or administrative
interpretations of the IRS. Neither we nor Andrews Kurth LLP can
assure prospective unitholders that the IRS will not
successfully contend in court that those positions are
impermissible. Any challenge by the IRS could negatively affect
the value of the units.
The IRS may audit our federal income tax information returns.
Adjustments resulting from an IRS audit may require each
unitholder to adjust a prior years tax liability, and
possibly may result in an audit of his return.
Any audit of a unitholders return could result in
adjustments not related to our returns as well as those related
to our returns.
Partnerships generally are treated as separate entities for
purposes of federal tax audits, judicial review of
administrative adjustments by the IRS and tax settlement
proceedings. The tax treatment of partnership items of income,
gain, loss and deduction are determined in a partnership
proceeding rather than in separate proceedings with the
partners. The Internal Revenue Code requires that one partner be
designated as the Tax Matters Partner for these
purposes. The partnership agreement names Williams Partners GP
LLC as our Tax Matters Partner.
The Tax Matters Partner will make some elections on our behalf
and on behalf of unitholders. In addition, the Tax Matters
Partner can extend the statute of limitations for assessment of
tax deficiencies against unitholders for items in our returns.
The Tax Matters Partner may bind a unitholder with less than a
1% profits interest in us to a settlement with the IRS unless
that unitholder elects, by filing a statement with the IRS, not
to give that authority to the Tax Matters Partner. The Tax
Matters Partner may seek judicial review, by which all the
unitholders are bound, of a final partnership administrative
adjustment and, if the Tax Matters Partner fails to seek
judicial review, judicial review may be sought by any unitholder
having at least a 1% interest in profits or by any group of
unitholders having in the aggregate at least a 5% interest in
profits. However, only one action for judicial review will go
forward, and each unitholder with an interest in the outcome may
participate.
A unitholder must file a statement with the IRS identifying the
treatment of any item on his federal income tax return that is
not consistent with the treatment of the item on our return.
Intentional or negligent disregard of this consistency
requirement may subject a unitholder to substantial penalties.
Nominee Reporting. Persons who hold an interest in us as
a nominee for another person are required to furnish to us:
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(a) the name, address and taxpayer identification number of
the beneficial owner and the nominee; |
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(b) a statement regarding whether the beneficial owner is: |
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1. a person that is not a United States person; |
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2. a foreign government, an international organization or
any wholly owned agency or instrumentality of either of the
foregoing; or |
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3. a tax-exempt entity; |
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(c) the amount and description of units held, acquired or
transferred for the beneficial owner; and |
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(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. |
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Brokers and financial institutions are required to furnish
additional information, including whether they are United States
persons and specific information on units they acquire, hold or
transfer for their own account. A penalty of $50 per
failure, up to a maximum of $100,000 per calendar year, is
imposed by the Internal Revenue Code for failure to report that
information to us. The nominee is required to supply the
beneficial owner of the units with the information furnished to
us.
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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:
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(1) for which there is, or was, substantial
authority; or |
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(2) as to which there is a reasonable basis and the
pertinent facts of that position are 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 to
avoid liability for this penalty. More stringent rules apply to
tax shelters, but we believe we are not a tax
shelter.
A substantial valuation misstatement exists if the value of any
property, or the adjusted basis of any property, claimed on a
tax return is 200% or more of the amount determined to be the
correct amount of the valuation or adjusted basis. 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 400%
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
that it produces certain kinds of losses in excess of
$2 million. Our participation in a reportable transaction
could increase the likelihood that our federal income tax
information return (and possibly your tax return) would be
audited by the IRS. Please read Information
Returns and Audit Procedures above.
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 Accuracy-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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in the case of a listed transaction, an extended statute of
limitations. |
We do not expect to engage in any reportable
transactions.
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State, Local and Other Tax Considerations
In addition to federal income taxes, you likely will be subject
to other taxes, such as state and local 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 own
property or do business in Kansas, Louisiana and Alabama. We may
also own property or do business in other jurisdictions in the
future, including Colorado and New Mexico upon the consummation
of the acquisition of the interest in Four Corners. Although you
may not be required to file a return and pay taxes in some
jurisdictions because your income from that jurisdiction falls
below the filing and payment requirement, you will be required
to file income tax returns and to pay income taxes in many of
these jurisdictions in which we do business or own property and
may be subject to penalties for failure to comply with those
requirements. In some jurisdictions, tax losses may not produce
a tax benefit in the year incurred and may not be available to
offset income in subsequent taxable years. Some of the
jurisdictions may require us, or we may elect, to withhold a
percentage of income from amounts to be distributed to a
unitholder who is not a resident of the jurisdiction.
Withholding, the amount of which may be greater or less than a
particular unitholders income tax liability to the
jurisdiction, generally does not relieve a nonresident
unitholder from the obligation to file an income tax return.
Amounts withheld will be treated as if distributed to
unitholders for purposes of determining the amounts distributed
by us. Please read Tax Consequences of Unit
Ownership Entity-Level Collections. Based
on current law and our estimate of our future operations, our
general partner anticipates that any amounts required to be
withheld will not be material.
It is the responsibility of each unitholder to investigate
the legal and tax consequences, under the laws of pertinent
jurisdictions, of his investment in us. Accordingly, each
prospective unitholder is urged to consult, and depend on, his
own tax counsel or other advisor with regard to those matters.
Further, it is the responsibility of each unitholder to file all
state and local, as well as United States federal tax returns,
that may be required of him. Andrews Kurth LLP has not rendered
an opinion on the state, local or foreign tax consequences of an
investment in us.
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INVESTMENT IN WILLIAMS PARTNERS L.P. BY EMPLOYEE BENEFIT
PLANS
An investment in us by an employee benefit plan is subject to
additional considerations to the extent that the investments by
these plans are subject to the fiduciary responsibility and
prohibited transaction provisions of ERISA, and restrictions
imposed by Section 4975 of the Internal Revenue Code. For
these purposes, the term employee benefit plan
includes, but is not limited to, certain qualified pension,
profit-sharing and stock bonus plans, Keogh plans, simplified
employee pension plans and individual retirement annuities or
accounts (IRAs) established or maintained by an employer or
employee organization. Incident to making an investment in us,
among other things, consideration should be given by an employee
benefit plan 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, that plan will satisfy the
diversification requirements of Section 404(a)(l)(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. |
In addition, the person with investment discretion with respect
to the assets of an employee benefit plan or other arrangement
that is covered by the prohibited transactions restrictions of
the Internal Revenue Code 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 or arrangement.
Section 406 of ERISA and Section 4975 of the Internal
Revenue Code prohibit certain employee benefit plans, and
Section 4975 of the Internal Revenue Code prohibits IRAs
and certain other arrangements that are not considered part of
an employee benefit plan, from engaging in specified
transactions involving plan assets with parties that
are parties in interest under ERISA or
disqualified persons under the Internal Revenue Code
with respect to the plan or other arrangement that is covered by
ERISA or the Internal Revenue Code.
In addition to considering whether the purchase of common units
is a prohibited transaction, a fiduciary of an employee benefit
plan or other arrangement should consider whether the plan or
arrangement will, by investing in us, be deemed to own an
undivided interest in our assets, with the result that our
general partner also would be considered to be a fiduciary of
the plan and our operations would be subject to the regulatory
restrictions of ERISA, including its prohibited transaction
rules and/or the prohibited transaction rules of the Internal
Revenue Code.
The U.S. Department of Labor regulations provide guidance
with respect to whether the assets of an entity in which
employee benefit plans or other arrangements described above
acquire equity interests would be deemed plan assets
under some circumstances. Under these regulations, an
entitys assets would not be considered to be plan
assets if, among other things:
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the equity interests acquired by employee benefit plans or other
arrangements described above are publicly offered securities;
i.e., the equity interests are widely held by 100 or more
investors independent of the issuer and each other, freely
transferable and registered under some provisions of the federal
securities laws; |
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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 |
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there is no significant investment by benefit plan investors,
which is defined to mean that less than 25% of the value of each
class of equity interest, disregarding any such interests held
by our general partner, its affiliates, and some other persons,
is held by the employee benefit plans referred to above, IRAs
and other employee benefit plans or arrangements 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 in our common units will satisfy the requirements in
the first bullet point above.
Plan fiduciaries contemplating a purchase of common units should
consult with their own counsel regarding the consequences of
such purchase under ERISA and the Internal Revenue Code in light
of possible personal liability for any breach of fiduciary
duties and the imposition of serious penalties on persons who
engage in prohibited transactions under ERISA or the Internal
Revenue Code.
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UNDERWRITING
Lehman Brothers Inc. and Citigroup Global Markets Inc. are
acting as joint book-running managers and representatives of the
underwriters. Under the terms of an underwriting agreement,
which is filed as an exhibit to the registration statement, each
of the underwriters named below has severally agreed to purchase
from us the respective number of common units opposite their
names below.
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Number of | |
Underwriters |
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Common Units | |
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Lehman Brothers Inc.
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Citigroup Global Markets Inc.
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A.G. Edwards & Sons, Inc.
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Merrill Lynch, Pierce, Fenner & Smith
Incorporated
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Wachovia Capital Markets, LLC
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RBC Capital Markets Corporation
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Raymond James & Associates, Inc.
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Total
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6,600,000 |
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The underwriting agreement provides that the underwriters
obligation to purchase the common units depends on the
satisfaction of the conditions contained in the underwriting
agreement including:
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the obligation to purchase all of the common units offered
hereby if any of the common units are purchased; |
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the representations and warranties made by us to the
underwriters are true; |
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there is no material change in the financial markets; and |
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we deliver customary closing documents to the underwriters. |
Commissions and Expenses
The following table summarizes the underwriting discounts and
commissions we will pay to the underwriters. These amounts are
shown assuming both no exercise and full exercise of the
underwriters option to purchase additional common units.
The underwriting fee is the difference between the initial price
to the public and the amount the underwriters pay to us for the
common units.
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No Exercise | |
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Paid by us per unit
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Total
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$ |
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We have been advised by the underwriters that the underwriters
propose to offer the common units directly to the public at the
public offering price on the cover of this prospectus and to
selected dealers, which may include the underwriters, at such
offering price less a selling concession not in excess of
$ per
common unit. After the offering, the representatives may change
the offering price and other selling terms.
The expenses of the offering that are payable by us are
estimated to be approximately $2.4 million (exclusive of
underwriting discounts and commissions).
Option to Purchase Additional Common Units
We have granted the underwriters an option exercisable for
30 days after the date of this prospectus to purchase, from
time to time, in whole or in part, up to an aggregate of 990,000
additional common units at the public offering price less
underwriting discounts and commissions. This option may be
exercised if the underwriters sell more than 6,600,000 common
units in connection with this offering. To the extent that this
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option is exercised, each underwriter will be obligated, subject
to certain conditions, to purchase its pro rata portion of these
additional common units based on the underwriters
percentage underwriting commitment in the offering as indicated
in the table at the beginning of this Underwriting section.
Lock-Up Agreements
We, our operating company, our general partner and certain of
its affiliates, including the directors and executive officers
of the general partner, have agreed, without the prior written
consent of Lehman Brothers Inc. and Citigroup Global Markets
Inc., not to (1) directly or indirectly, offer, pledge,
sell, contract to sell, sell an option or contract to purchase,
purchase any option or contract to sell, grant any option, right
or warrant to purchase, or otherwise transfer or dispose of any
common units or any securities which may be converted into or
exchanged for any common units, other than certain permitted
transfers, issuances and grants of options, (2) 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, (3) file or cause to be filed a registration
statement, including any amendments (other than a registration
statement on
Form S-8 or
Form S-3), with
respect to the registration of any common units or securities
convertible or exchangeable into common units or
(4) publicly disclose the intention to do any of the
foregoing for a period of 90 days from the date of this
prospectus.
The 90-day restricted
period described in the preceding paragraph will be extended if:
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during the last 17 days of the
90-day restricted
period we issue an earnings release or announce material news or
a material event; or |
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prior to the expiration of the
90-day restricted
period, we announce that we will release earnings results during
the 16-day period
beginning on the last day of the
90-day period, |
in which case the restrictions described in the preceding
paragraph will continue to apply until the expiration of the
18-day period beginning
on the issuance of the earnings release or the announcement of
the material news or material event.
Lehman Brothers Inc. and Citigroup Global Markets Inc., in their
discretion, may release the common units subject to these
restrictions in whole or in part at anytime with or without
notice. When determining whether or not to release common units
from these restrictions, the primary factors that Lehman
Brothers Inc. and Citigroup Global Markets Inc. will consider
include the requesting unitholders reasons for requesting
the release, the number of common units for which the release is
being requested and the prevailing economic and equity market
conditions at the time of the request.
Indemnification
We, our operating company and our general partner have agreed to
indemnify the underwriters against certain liabilities,
including liabilities under the Securities Act, and to
contribute to payments that the underwriters may be required to
make for these liabilities.
Stabilization, Short Positions and Penalty Bids
The underwriters may engage in stabilizing transactions, short
sales and purchases to cover positions created by short sales,
and penalty bids or purchases for the purpose of pegging, fixing
or maintaining the price of the common units, in accordance with
Regulation M under the Securities Exchange Act of 1934.
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Stabilizing transactions permit bids to purchase the underlying
security so long as the stabilizing bids do not exceed a
specified maximum. |
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A short position involves a sale by the underwriters of the
common units in excess of the number of common units the
underwriters are obligated to purchase in the offering, which
creates the syndicate short position. This short position may be
either a covered short position or a naked short position. In a
covered short position, the number of common units involved in
the sales made by the underwriters in excess of the number of
common units they are obligated to purchase is not greater than
the number of common units that they may purchase by exercising
their option to purchase additional |
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common units. In a naked short position, the number of common
units involved is greater than the number of common units in
their option to purchase additional common units. The
underwriters may close out any short position by either
exercising their option to purchase additional common units
and/or purchasing common units in the open market. In
determining the source of common units to close out the short
position, 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. A naked short position is more likely to be created if
the underwriters are concerned that there could be downward
pressure on the price of the common units in the open market
after pricing that could adversely affect investors who purchase
in the offering. |
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Syndicate covering transactions involve purchases of the common
units in the open market after the distribution has been
completed in order to cover syndicate short positions. |
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Penalty bids permit the representatives to reclaim a selling
concession from a syndicate member when the common units
originally sold by the syndicate member are purchased in a
stabilizing or syndicate covering transaction to cover syndicate
short positions. |
These stabilizing transactions, syndicate covering transactions
and penalty bids may have the effect of raising or maintaining
the market price of our common units or preventing or retarding
a decline in the market price of the common units. As a result,
the price of the common units may be higher than the price that
might otherwise exist in the open market. These transactions may
be effected on The New York Stock Exchange or otherwise and, if
commenced, may be discontinued at any time.
Neither we nor any of the underwriters make any representation
or prediction as to the direction or magnitude of any effect
that the transactions described above may have on the price of
the common units. In addition, neither we nor any of the
underwriters make any representation that the representatives
will engage in these stabilizing transactions or that any
transaction, once commenced, will not be discontinued without
notice.
Electronic Distribution
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 common units for sale to online brokerage
account holders. Any such allocation for online distributions
will be made by the representative 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.
New York Stock Exchange
The common units are listed on the New York Stock Exchange under
the symbol WPZ.
Relationships
Lehman Brothers Inc. is serving as Williams financial
advisor in connection with our acquisition of the 25.1% interest
in Four Corners. Lehman Brothers Inc. was the sole bookrunning
manager, and Citigroup Global Markets Inc., RBC Capital Markets
Corporation and Wachovia Capital Markets, LLC were each
underwriters, in our initial public offering in August 2005. In
addition, Lehman Brothers Inc. and Citigroup Global Markets Inc.
are joint book-running managers, and Merrill Lynch, Pierce,
Fenner & Smith
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Incorporated and Wachovia Capital Markets, LLC intend to act as
underwriters in our concurrent private placement of senior
notes. Lehman Brothers Inc. and Citigroup Global Markets Inc.
and the other underwriters performed and may in the future
perform investment banking, advisory and other banking services
for us from time to time for which they received or may receive
customary fees and expenses. In addition, some of the
underwriters and their affiliates have performed, and may in the
future perform, various financial advisory, investment banking
and other banking services in the ordinary course of business
with Williams for which they received or will receive customary
compensation.
An affiliate of Lehman Brothers Inc. is a lender, affiliates of
Citigroup Global Markets Inc. are agents and lenders, an
affiliate of Merrill Lynch, Pierce, Fenner & Smith
Incorporated is a lender, an affiliate of RBC Capital
Markets Corporation is a lender and an affiliate of Wachovia
Capital Markets, LLC is a managing agent under Williams
$1.5 billion credit agreement under which we have a
$75 million borrowing limit, and each such affiliate of
Lehman Brothers Inc., Citigroup Global Markets Inc., Merrill
Lynch, Pierce, Fenner & Smith Incorporated,
RBC Capital Markets Corporation and Wachovia Capital
Markets, LLC has received customary fees for such services.
NASD Conduct Rules
Because the National Association of Securities Dealers, Inc.
views the common units offered hereby as interests in a direct
participation program, the offering is being made in compliance
with Rule 2810 of the NASDs Conduct 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.
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VALIDITY OF THE COMMON UNITS
The validity of the common units will be passed upon for us by
Andrews Kurth LLP, Houston, Texas. Certain legal matters in
connection with the common units offered hereby will be passed
upon for the underwriters by Vinson & Elkins L.L.P.,
Houston, Texas.
EXPERTS
The financial statements of Williams Partners L.P. as of
December 31, 2005 and 2004 and for each of the three years
in the period ended December 31, 2005 appearing in this
prospectus and the registration statement of which this
prospectus forms a part have been audited by Ernst &
Young LLP, independent registered public accounting firm, as set
forth in their report thereon appearing elsewhere herein, and
are included in reliance upon such report given on the authority
of such firm as experts in accounting and auditing.
The financial statements of Discovery Producer Services LLC as
of December 31, 2005 and 2004 and for each of the three
years in the period ended December 31, 2005 appearing in
this prospectus and the registration statement of which this
prospectus forms a part have been audited by Ernst &
Young LLP, independent auditors, as set forth in their report
thereon appearing elsewhere herein, and are included in reliance
upon such report given on the authority of such firm as experts
in accounting and auditing.
The financial statements of Williams Four Corners LLC as of
December 31, 2005 and 2004 and for each of the three years
in the period ended December 31, 2005 appearing in this
prospectus and the registration statement of which this
prospectus forms a part have been audited by Ernst &
Young LLP, independent auditors, as set forth in their report
thereon appearing elsewhere herein, and are included in reliance
upon such report given on the authority of such firm as experts
in accounting and auditing.
The balance sheet of Williams Partners GP LLC as of
December 31, 2005 appearing in this prospectus and the
registration statement of which this prospectus forms a part
have been audited by Ernst & Young LLP, independent
registered public accounting firm, as set forth in their report
thereon appearing elsewhere herein, and are included in reliance
upon such report given on the authority of such firm as experts
in accounting and auditing.
WHERE YOU CAN FIND MORE INFORMATION
We have filed with the Securities and Exchange Commission 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 and can also be inspected and copied at the
offices of the New York Stock Exchange, Inc., 20 Broad
Street, New York, New York 10005.
You should rely only on the information contained in this
prospectus. We have not, and the underwriters have not,
authorized any other person to provide you with different
information. If anyone provides you with different or
inconsistent information, you should not rely on it. We are not,
and the underwriters are not, making an offer to sell these
securities in any jurisdiction where an offer or sale is not
permitted. You should assume that the information appearing in
this prospectus is accurate as of the date on the front cover of
this
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prospectus only. Our business, financial condition, results of
operations and prospects may have changed since that date.
We file with or furnish to the SEC periodic reports and other
information. These reports and other information may be
inspected and copied at the public reference facilities
maintained by the SEC or obtained from the SECs website as
provided above. Our website on the Internet is located at
http://www.williamslp.com, and we make our periodic reports and
other information filed with or furnished to the SEC available,
free of charge, through our website, as soon as reasonably
practicable after those reports and other information are
electronically filed with or furnished to the SEC. Information
on our website or any other website is not incorporated by
reference into this prospectus and does not constitute a part of
this prospectus.
We intend to furnish or make available to our unitholders annual
reports containing our audited financial statements prepared in
accordance with GAAP. Our annual report will contain a detailed
statement of any transactions with our general partner or its
affiliates, and of fees, commissions, compensation and other
benefits paid, or accrued to our general partner or its
affiliates for the fiscal year completed, showing the amount
paid or accrued to each recipient and the services performed. We
also intend to furnish or make available to our unitholders
quarterly reports containing our unaudited interim financial
information, including the information required by
Form 10-Q, for the
first three fiscal quarters of each fiscal year.
Williams is subject to the information requirements of the
Securities Exchange Act of 1934, and in accordance therewith
files reports and other information with the SEC. You may read
Williams filings on the SECs web site and at the
public reference room described above. Williams common
stock trades on the New York Stock Exchange under the symbol
WMB. Reports that Williams files with the New York
Stock Exchange may be inspected and copied at the offices of the
New York Stock Exchange described above.
FORWARD-LOOKING STATEMENTS
Certain matters discussed in this prospectus, excluding
historical information, include forward-looking
statements statements that discuss our expected
future results based on current and pending business operations.
We make these forward-looking statements in reliance on the safe
harbor protections provided under the Private Securities
Litigation Reform Act of 1995.
Forward-looking statements can be identified by words such as
may, anticipates, believes,
expects, planned, scheduled,
could, continues, estimates,
forecasts, might, potential,
projects or similar expressions. Similarly,
statements that describe our future plans, objectives or goals
are also forward-looking statements.
Although we believe these forward-looking statements are based
on reasonable assumptions, statements made regarding future
results are subject to a number of assumptions, uncertainties
and risks that may cause future results to be materially
different from the results stated or implied in this document.
These risks and uncertainties include, among other things:
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We may not have sufficient cash from operations to enable us to
pay the minimum quarterly distribution following establishment
of cash reserves and payment of fees and expenses, including
payments to our general partner. |
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Because of the natural decline in production from existing
wells, the success of our gathering and transportation business
depends on our ability to connect new sources of natural gas
supply, which is dependent on factors beyond our control. Any
decrease in supplies of natural gas could adversely affect our
business and operating results. |
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Lower natural gas and oil prices could adversely affect our
fractionation and storage businesses. |
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We depend on certain key customers and producers for a
significant portion of our revenues and supply of natural gas
and natural gas liquids. The loss of any of these key customers
or producers could result in a decline in our revenues and cash
available to pay distributions. |
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If third-party pipelines and other facilities interconnected to
our pipelines and facilities become unavailable to transport
natural gas and natural gas liquids or to treat natural gas, our
revenues and cash available to pay distributions could be
adversely affected. |
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Our processing, fractionation and storage businesses could be
affected by any decrease in the price of natural gas liquids or
a change in the price of natural gas liquids relative to the
price of natural gas. |
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Williams credit agreement and Williams public
indentures contain financial and operating restrictions that may
limit our access to credit. In addition, our ability to obtain
credit in the future will be affected by Williams credit
ratings. |
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Our general partner and its affiliates have conflicts of
interest and limited fiduciary duties, which may permit them to
favor their own interests to the detriment of our unitholders. |
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Even if unitholders are dissatisfied, they cannot currently
remove our general partner without its consent. |
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You may be required to pay taxes on your share of our income
even if you do not receive any cash distributions from us. |
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Our operations are subject to operational hazards and unforeseen
interruptions for which we may or may not be adequately insured. |
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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. The forward-looking statements included in this
prospectus are only made as of the date of this prospectus and
we undertake no obligation to publicly update forward-looking
statements to reflect subsequent events or circumstances.
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INDEX TO FINANCIAL STATEMENTS
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UNAUDITED WILLIAMS PARTNERS L.P. PRO FORMA FINANCIAL STATEMENTS:
|
|
|
|
|
|
|
|
|
F-2 |
|
|
|
|
|
F-3 |
|
|
|
|
|
F-4 |
|
|
|
|
|
F-5 |
|
WILLIAMS PARTNERS L.P. CONSOLIDATED FINANCIAL STATEMENTS:
|
|
|
|
|
|
|
|
|
F-7 |
|
|
|
|
|
F-8 |
|
|
|
|
|
F-9 |
|
|
|
|
|
F-10 |
|
|
|
|
|
F-11 |
|
|
|
|
|
F-12 |
|
|
|
|
|
F-32 |
|
DISCOVERY PRODUCER SERVICES LLC CONSOLIDATED FINANCIAL
STATEMENTS:
|
|
|
|
|
|
|
|
|
F-33 |
|
|
|
|
|
F-34 |
|
|
|
|
|
F-35 |
|
|
|
|
|
F-36 |
|
|
|
|
|
F-37 |
|
|
|
|
|
F-38 |
|
WILLIAMS FOUR CORNERS PREDECESSOR FINANCIAL STATEMENTS:
|
|
|
|
|
|
|
|
|
F-47 |
|
|
|
|
|
F-48 |
|
|
|
|
|
F-49 |
|
|
|
|
|
F-50 |
|
|
|
|
|
F-51 |
|
|
|
|
|
F-52 |
|
WILLIAMS PARTNERS GP LLC FINANCIAL STATEMENTS:
|
|
|
|
|
|
|
|
|
F-61 |
|
|
|
|
|
F-62 |
|
|
|
|
|
F-63 |
|
F-1
UNAUDITED WILLIAMS PARTNERS L.P. PRO FORMA FINANCIAL
STATEMENTS
The pro forma financial statements present the impact on our
financial position and results of operations of our acquisition
of a 25.1% interest in Williams Four Corners LLC financed by the
issuance of 6,600,000 common units pursuant to this offering and
$150 million of senior notes in a concurrent private
placement. The pro forma financial statements as of
March 31, 2006 and for the year ended December 31,
2005 and three months ended March 31, 2006 have been
derived from our historical consolidated financial statements
set forth elsewhere in this prospectus and are qualified in
their entirety by reference to such historical consolidated
financial statements and related notes contained therein. The
unaudited pro forma financial statements should be read in
conjunction with the notes accompanying such pro forma financial
statements and with the historical consolidated financial
statements and related notes set forth elsewhere in this
prospectus.
The pro forma adjustments are based upon currently available
information and certain estimates and assumptions; therefore,
actual adjustments will differ from the pro forma adjustments.
However, management believes that the assumptions provide a
reasonable basis for presenting the significant effects of the
transactions as contemplated and that the pro forma adjustments
give appropriate effect to those assumptions and are properly
applied in the pro forma financial information.
The pro forma financial statements may not be indicative of the
results that actually would have occurred if we had owned a
25.1% interest in Four Corners on the dates indicated.
F-2
WILLIAMS PARTNERS L.P.
UNAUDITED PRO FORMA BALANCE SHEET
March 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Historical | |
|
Adjustments | |
|
Pro Forma | |
|
|
| |
|
| |
|
| |
|
|
|
|
($ in thousands) | |
|
|
ASSETS |
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
4,315 |
|
|
$ |
231,660 |
(a) |
|
$ |
15,511 |
|
|
|
|
|
|
|
|
150,000 |
(b) |
|
|
|
|
|
|
|
|
|
|
|
(9,846 |
)(c) |
|
|
|
|
|
|
|
|
|
|
|
(2,350 |
)(d) |
|
|
|
|
|
|
|
|
|
|
|
(355,268 |
)(e) |
|
|
|
|
|
|
|
|
|
|
|
(3,000 |
)(f) |
|
|
|
|
|
Accounts receivable
|
|
|
2,948 |
|
|
|
|
|
|
|
2,948 |
|
|
Other current assets
|
|
|
6,820 |
|
|
|
375 |
(f) |
|
|
7,195 |
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
14,083 |
|
|
|
11,571 |
|
|
|
25,654 |
|
Investment in Discovery Producer Services
|
|
|
149,641 |
|
|
|
|
|
|
|
149,641 |
|
Investment in Williams Four Corners
|
|
|
|
|
|
|
153,309 |
(e) |
|
|
153,309 |
|
Property, plant and equipment, net
|
|
|
68,239 |
|
|
|
|
|
|
|
68,239 |
|
Other noncurrent assets
|
|
|
3,565 |
|
|
|
2,625 |
(f) |
|
|
6,190 |
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$ |
235,528 |
|
|
$ |
167,505 |
|
|
$ |
403,033 |
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL |
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$ |
5,647 |
|
|
$ |
|
|
|
$ |
5,647 |
|
|
Deferred revenue
|
|
|
222 |
|
|
|
|
|
|
|
222 |
|
|
Accrued liabilities
|
|
|
2,718 |
|
|
|
|
|
|
|
2,718 |
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
8,587 |
|
|
|
|
|
|
|
8,587 |
|
Long-term debt
|
|
|
|
|
|
|
150,000 |
(b) |
|
|
150,000 |
|
Other non-current liabilities
|
|
|
4,727 |
|
|
|
|
|
|
|
4,727 |
|
Partners capital:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common unitholders
|
|
|
108,627 |
|
|
|
231,660 |
(a) |
|
|
328,091 |
|
|
|
|
|
|
|
|
(9,846 |
)(c) |
|
|
|
|
|
|
|
|
|
|
|
(2,350 |
)(d) |
|
|
|
|
|
Subordinated unitholders
|
|
|
108,490 |
|
|
|
|
|
|
|
108,490 |
|
|
General partner
|
|
|
5,097 |
|
|
|
(201,959 |
)(e) |
|
|
(196,862 |
) |
|
|
|
|
|
|
|
|
|
|
Total partners capital
|
|
|
222,214 |
|
|
|
17,505 |
|
|
|
239,719 |
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners capital
|
|
$ |
235,528 |
|
|
$ |
167,505 |
|
|
$ |
403,033 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to unaudited pro forma financial
statements.
F-3
WILLIAMS PARTNERS L.P.
UNAUDITED PRO FORMA STATEMENT OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2005 | |
|
Three Months Ended March 31, 2006 | |
|
|
| |
|
| |
|
|
Historical | |
|
Adjustments | |
|
Pro Forma | |
|
Historical | |
|
Adjustments | |
|
Pro Forma | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
($ in thousands except per unit amounts) | |
Revenues
|
|
$ |
51,769 |
|
|
$ |
|
|
|
$ |
51,769 |
|
|
$ |
17,063 |
|
|
$ |
|
|
|
$ |
17,063 |
|
Cost and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense
|
|
|
25,111 |
|
|
|
|
|
|
|
25,111 |
|
|
|
7,691 |
|
|
|
|
|
|
|
7,691 |
|
|
Product cost
|
|
|
11,821 |
|
|
|
|
|
|
|
11,821 |
|
|
|
5,723 |
|
|
|
|
|
|
|
5,723 |
|
|
Depreciation and accretion
|
|
|
3,619 |
|
|
|
|
|
|
|
3,619 |
|
|
|
900 |
|
|
|
|
|
|
|
900 |
|
|
General and administrative expense
|
|
|
5,323 |
|
|
|
|
|
|
|
5,323 |
|
|
|
1,948 |
|
|
|
|
|
|
|
1,948 |
|
|
Taxes other than income
|
|
|
700 |
|
|
|
|
|
|
|
700 |
|
|
|
207 |
|
|
|
|
|
|
|
207 |
|
|
Other net
|
|
|
(6 |
) |
|
|
|
|
|
|
(6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
46,568 |
|
|
|
|
|
|
|
46,568 |
|
|
|
16,469 |
|
|
|
|
|
|
|
16,469 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
5,201 |
|
|
|
|
|
|
|
5,201 |
|
|
|
594 |
|
|
|
|
|
|
|
594 |
|
Equity earnings
|
|
|
8,331 |
|
|
|
28,668 |
(g) |
|
|
36,999 |
|
|
|
3,781 |
|
|
|
8,387 |
(g) |
|
|
12,168 |
|
Interest expense affiliate
|
|
|
(7,461 |
) |
|
|
7,401 |
(h) |
|
|
(60 |
) |
|
|
(15 |
) |
|
|
|
(h) |
|
|
(15 |
) |
Interest expense third party
|
|
|
(777 |
) |
|
|
(11,800 |
)(i) |
|
|
(12,577 |
) |
|
|
(221 |
) |
|
|
(2,906 |
)(i) |
|
|
(3,127 |
) |
Interest income
|
|
|
165 |
|
|
|
|
|
|
|
165 |
|
|
|
70 |
|
|
|
|
|
|
|
70 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle
|
|
$ |
5,459 |
|
|
$ |
24,269 |
|
|
$ |
29,728 |
|
|
$ |
4,209 |
|
|
$ |
5,481 |
|
|
$ |
9,690 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocation of income before cumulative effect of change in
accounting principle:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle
|
|
$ |
5,459 |
|
|
|
|
|
|
$ |
29,728 |
|
|
$ |
4,209 |
|
|
|
|
|
|
$ |
9,690 |
|
|
Loss before cumulative effect of change in accounting principle
applicable to the period through August 22, 2005
|
|
|
(103 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting
principle applicable to the period August 23 through
December 31, 2005
|
|
|
5,562 |
|
|
|
|
|
|
|
|
|
|
|
4,209 |
|
|
|
|
|
|
|
|
|
|
Allocation of loss before cumulative effect of change in
accounting principle to general partner
|
|
|
(1,261 |
) |
|
|
|
|
|
|
(777 |
) |
|
|
(689 |
) |
|
|
|
|
|
|
(317 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocation of income before cumulative effect of change in
accounting principle to limited partners
|
|
$ |
6,823 |
|
|
|
|
|
|
$ |
30,505 |
|
|
$ |
4,898 |
|
|
|
|
|
|
$ |
10,007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted income before cumulative effect of change in
accounting principle per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
$ |
0.49 |
|
|
|
|
|
|
$ |
1.48 |
|
|
$ |
0.35 |
|
|
|
|
|
|
$ |
0.49 |
|
|
Subordinated units
|
|
|
0.49 |
|
|
|
|
|
|
|
1.48 |
|
|
|
0.35 |
|
|
|
|
|
|
|
0.49 |
|
Weighted average number of limited partner units outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
|
7,001,366 |
|
|
|
|
|
|
|
13,606,146 |
|
|
|
7,006,146 |
|
|
|
|
|
|
|
13,606,146 |
|
|
Subordinated units
|
|
|
7,000,000 |
|
|
|
|
|
|
|
7,000,000 |
|
|
|
7,000,000 |
|
|
|
|
|
|
|
7,000,000 |
|
See accompanying notes to unaudited pro forma financial
statements.
F-4
UNAUDITED WILLIAMS PARTNERS L.P. PRO FORMA FINANCIAL
STATEMENTS
|
|
Note 1. |
Basis of Presentation Four Corners Acquisition |
Unless the context clearly indicates otherwise, references in
this report to we, our, us
or like terms refer to Williams Partners L.P. and its
subsidiaries. The historical financial information is derived
from our historical consolidated financial statements. The pro
forma adjustments have been prepared as if we acquired the
interest in Williams Four Corners LLC (Four Corners)
on March 31, 2006 for the balance sheet and on
January 1, 2005 in the case of the pro forma statement of
income. The pro forma statement of income also includes
adjustments to reflect the effects of the forgiveness of
advances from affiliate in connection with our August 2005
initial public offering (IPO) as if the IPO had
taken place on January 1, 2005.
The pro forma financial statements reflect the following
transactions:
|
|
|
|
|
|
the issuance of 6,600,000 of our common units to the public, |
|
|
|
|
the issuance of $150 million of Senior Notes at a 7.5%
interest rate, |
|
|
|
the acquisition of a 25.1% interest in Four Corners from the
Williams Companies, Inc. (Williams) and the
distribution to Williams of the aggregate consideration, and |
|
|
|
the payment of estimated underwriters commissions and
other offering expenses. |
|
|
Note 2. |
Pro Forma Adjustments and Assumptions |
|
|
|
|
|
a) |
Reflects $231.7 million of proceeds to us from the issuance
and sale of 6,600,000 common units at an offering price of
$35.10 per unit. |
|
|
|
b) |
Reflects $150.0 million of proceeds to us from the issuance
of Senior Notes. |
|
|
|
c) |
Reflects the payment of estimated underwriters commissions
and structuring fees of $9.8 million, which will be
allocated to the common units. |
|
|
|
|
d) |
Reflects the payment of $2.4 million for the estimated
costs associated with the offering of the common units. |
|
|
|
|
e) |
Reflects the acquisition, from Williams, of the 25.1% interest
in Four Corners and related distribution to Williams of the
aggregate consideration for the interest in Four Corners less
the retention of $4.7 million in cash representing a
contribution by our general partner sufficient to maintain its
two percent ownership interest in the partnership. This
acquisition will be recorded at Williams historical cost
as it is considered a transaction between entities under common
control. The recognition of the investment at Williams
historical cost rather than the aggregate consideration causes a
deficit capital balance for the general partner. |
|
|
|
|
|
|
Aggregate consideration
|
|
$ |
360.0 |
|
General partner contribution
|
|
|
(4.7 |
) |
|
|
|
|
Distribution to Williams
|
|
|
355.3 |
|
Historical cost of Four Corners investment
|
|
|
(153.3 |
) |
|
|
|
|
Net charge to general partner equity
|
|
$ |
(202.0 |
) |
|
|
|
|
|
|
|
|
f) |
Reflects the payment of $3.0 million for the estimated
costs associated with the issuance of the Senior Notes. These
costs will be amortized to interest expense over the eight-year
term of the notes. |
|
|
|
|
g) |
Reflects the increase in equity earnings associated with the
acquisition of a 25.1% interest in Four Corners. |
F-5
UNAUDITED WILLIAMS PARTNERS L.P. PRO FORMA FINANCIAL
STATEMENTS (Continued)
|
|
|
|
h) |
Reflects the effect on affiliate interest expense of the
forgiveness of the advances from affiliate effective with the
closing of the IPO on August 23, 2005 and a full
years commitment fees in 2005 under our $20 million
working capital credit facility entered into in connection with
our IPO. |
|
|
|
|
i) |
Includes the following increases to third-party interest expense: |
|
|
|
|
|
|
a $0.2 million increase to reflect a full years commitment
fees in 2005 associated with our $75 million borrowing
limit under Williams revolving credit facility; and |
|
|
|
|
|
interest on the $150 million of Senior Notes to be issued
concurrently with this offering as described in adjustment b. We
have assumed a 7.5% interest rate on these borrowings and also
included amortization of debt issuance costs. |
|
|
|
Note 3. |
Pro Forma Earnings Per Unit |
Pro forma earnings per unit is determined by dividing the pro
forma earnings that would have been allocated, in accordance
with the net income and loss allocation provisions of our
limited partnership agreement, to the common and subordinated
unitholders under the two-class method, after deducting the
general partners interest in the pro forma earnings, by
the weighted average number of common and subordinated units,
assuming each of the following were outstanding since
January 1, 2005:
|
|
|
|
|
7,000,000 common units and 7,000,000 subordinated units issued
in connection with our August 2005 initial public offering; |
|
|
|
|
6,600,000 common units to be issued in connection with this
offering; and |
|
|
|
|
6,146 common units granted to non-employee directors of our
general partner. |
For the year ended December 31, 2005, we allocated $777,000
pro forma loss to the general partner based upon the following
assumptions:
|
|
|
|
|
$1.4 million specific allocation of costs associated with
capital contributions to us from our general partner; and |
|
|
|
No incentive distributions to our general partner. |
For the three months ended March 31, 2006, we allocated
$317,000 pro forma loss to the general partner based upon the
following assumptions:
|
|
|
|
|
|
$0.8 million specific allocation of costs associated with
capital contributions to us from our general partner; and |
|
|
|
|
|
$0.3 million of incentive distributions to our general
partner. |
|
Basic and diluted pro forma earnings per unit are equivalent as
there are no dilutive units.
F-6
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors of Williams Partners GP LLC
General Partner of Williams Partners L.P.
We have audited the accompanying consolidated balance sheets of
Williams Partners L.P. as of December 31, 2005 and 2004,
and the related consolidated statements of operations,
partners capital, and cash flows for each of the three
years in the period ended December 31, 2005. These
financial statements are the responsibility of the
Partnerships management. Our responsibility is to express
an opinion on these 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. We were not engaged to perform an
audit of the Partnerships internal control over financial
reporting. Our audits included consideration of internal control
over financial reporting as a basis for designing audit
procedures that are appropriate in the circumstances, but not
for the purpose of expressing an opinion on the effectiveness of
the Partnerships internal control over financial
reporting. Accordingly, we express no such opinion. An audit
also includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant
estimates made by management, and 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 consolidated
financial position of Williams Partners L.P. at
December 31, 2005 and 2004, and the consolidated results of
its operations and its cash flows for each of the three years in
the period ended December 31, 2005, in conformity with
U.S. generally accepted accounting principles.
As described in Note 7, effective January 1, 2003,
Williams Partners L.P. adopted Statement of Financial Accounting
Standards No. 143, Accounting for Asset Retirement
Obligations, and effective December 31, 2005, adopted
Financial Accounting Standards Board Interpretation No. 47,
Accounting for Conditional Asset Retirement Obligations.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
February 27, 2006
F-7
WILLIAMS PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, | |
|
|
|
|
| |
|
March 31, | |
|
|
2004 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
|
|
|
(Unaudited) | |
|
|
(In thousands) | |
|
|
ASSETS |
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
|
|
|
$ |
6,839 |
|
|
$ |
4,315 |
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trade
|
|
|
2,150 |
|
|
|
1,840 |
|
|
|
1,424 |
|
|
|
Other
|
|
|
1,388 |
|
|
|
2,104 |
|
|
|
1,524 |
|
|
Product imbalance
|
|
|
|
|
|
|
760 |
|
|
|
295 |
|
|
Gas purchase contract affiliate
|
|
|
|
|
|
|
5,320 |
|
|
|
5,155 |
|
|
Prepaid expenses
|
|
|
749 |
|
|
|
1,133 |
|
|
|
1,370 |
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
4,287 |
|
|
|
17,996 |
|
|
|
14,083 |
|
Investment in Discovery Producer Services
|
|
|
147,281 |
|
|
|
150,260 |
|
|
|
149,641 |
|
Property, plant and equipment, net
|
|
|
67,793 |
|
|
|
67,931 |
|
|
|
68,239 |
|
Gas purchase contract noncurrent
affiliate
|
|
|
|
|
|
|
4,754 |
|
|
|
3,565 |
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$ |
219,361 |
|
|
$ |
240,941 |
|
|
$ |
235,528 |
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL |
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trade
|
|
$ |
2,480 |
|
|
$ |
3,906 |
|
|
$ |
3,269 |
|
|
|
Affiliate
|
|
|
1,980 |
|
|
|
4,729 |
|
|
|
2,378 |
|
|
Product imbalance
|
|
|
1,071 |
|
|
|
|
|
|
|
|
|
|
Deferred revenue
|
|
|
3,305 |
|
|
|
3,552 |
|
|
|
222 |
|
|
Accrued liabilities
|
|
|
3,924 |
|
|
|
2,373 |
|
|
|
2,718 |
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
12,760 |
|
|
|
14,560 |
|
|
|
8,587 |
|
Advances from affiliate
|
|
|
186,024 |
|
|
|
|
|
|
|
|
|
Environmental remediation liabilities
|
|
|
3,909 |
|
|
|
3,964 |
|
|
|
3,964 |
|
Other noncurrent liabilities
|
|
|
|
|
|
|
762 |
|
|
|
763 |
|
Commitments and contingent liabilities (Note 13)
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners capital:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor partners equity
|
|
|
16,668 |
|
|
|
|
|
|
|
|
|
|
Common unitholders (7,006,146 outstanding at December 31,
2005 and March 31, 2006 (unaudited))
|
|
|
|
|
|
|
108,526 |
|
|
|
108,627 |
|
|
Subordinated unitholders (7,000,000 outstanding at
December 31, 2005 and March 31, 2006 (unaudited))
|
|
|
|
|
|
|
108,491 |
|
|
|
108,490 |
|
|
General partner
|
|
|
|
|
|
|
4,638 |
|
|
|
5,097 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total partners capital
|
|
|
16,668 |
|
|
|
221,655 |
|
|
|
222,214 |
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners capital
|
|
$ |
219,361 |
|
|
$ |
240,941 |
|
|
$ |
235,528 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F-8
WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended | |
|
|
Year Ended December 31, | |
|
March 31, | |
|
|
| |
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(In thousands) | |
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Storage:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
$ |
2,426 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
Third-party
|
|
|
9,223 |
|
|
|
15,318 |
|
|
|
20,290 |
|
|
|
4,388 |
|
|
|
5,105 |
|
|
Fractionation
|
|
|
8,221 |
|
|
|
9,070 |
|
|
|
10,770 |
|
|
|
2,430 |
|
|
|
3,953 |
|
|
Gathering
|
|
|
5,513 |
|
|
|
3,883 |
|
|
|
3,063 |
|
|
|
880 |
|
|
|
733 |
|
|
Product sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
|
|
|
|
506 |
|
|
|
13,400 |
|
|
|
2,829 |
|
|
|
6,141 |
|
|
|
Third-party
|
|
|
1,263 |
|
|
|
7,947 |
|
|
|
63 |
|
|
|
63 |
|
|
|
|
|
|
Other
|
|
|
1,648 |
|
|
|
4,252 |
|
|
|
4,183 |
|
|
|
779 |
|
|
|
1,131 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
28,294 |
|
|
|
40,976 |
|
|
|
51,769 |
|
|
|
11,369 |
|
|
|
17,063 |
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
8,789 |
|
|
|
9,986 |
|
|
|
13,378 |
|
|
|
2,653 |
|
|
|
4,000 |
|
|
|
Third-party
|
|
|
5,171 |
|
|
|
9,390 |
|
|
|
11,733 |
|
|
|
3,075 |
|
|
|
3,691 |
|
|
Product cost
|
|
|
1,263 |
|
|
|
6,635 |
|
|
|
11,821 |
|
|
|
2,735 |
|
|
|
5,723 |
|
|
Depreciation and accretion
|
|
|
3,707 |
|
|
|
3,686 |
|
|
|
3,619 |
|
|
|
905 |
|
|
|
900 |
|
|
General and administrative expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
1,738 |
|
|
|
2,534 |
|
|
|
4,186 |
|
|
|
687 |
|
|
|
1,415 |
|
|
|
Third-party
|
|
|
75 |
|
|
|
79 |
|
|
|
1,137 |
|
|
|
19 |
|
|
|
533 |
|
|
Taxes other than income
|
|
|
640 |
|
|
|
716 |
|
|
|
700 |
|
|
|
192 |
|
|
|
207 |
|
|
Other net
|
|
|
(133 |
) |
|
|
(91 |
) |
|
|
(6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
21,250 |
|
|
|
32,935 |
|
|
|
46,568 |
|
|
|
10,266 |
|
|
|
16,469 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
7,044 |
|
|
|
8,041 |
|
|
|
5,201 |
|
|
|
1,103 |
|
|
|
594 |
|
Equity earnings Discovery Producer Services
|
|
|
3,447 |
|
|
|
4,495 |
|
|
|
8,331 |
|
|
|
2,212 |
|
|
|
3,781 |
|
Impairment of investment in Discovery Producer Services
|
|
|
|
|
|
|
(13,484 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
(4,176 |
) |
|
|
(11,980 |
) |
|
|
(7,461 |
) |
|
|
(2,805 |
) |
|
|
(15 |
) |
|
Third-party
|
|
|
|
|
|
|
(496 |
) |
|
|
(777 |
) |
|
|
(199 |
) |
|
|
(221 |
) |
Interest income
|
|
|
|
|
|
|
|
|
|
|
165 |
|
|
|
|
|
|
|
70 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before cumulative effect of change in accounting
principle
|
|
|
6,315 |
|
|
|
(13,424 |
) |
|
|
5,459 |
|
|
|
311 |
|
|
|
4,209 |
|
Cumulative effect of change in accounting principle
|
|
|
(1,099 |
) |
|
|
|
|
|
|
(628 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$ |
5,216 |
|
|
$ |
(13,424 |
) |
|
$ |
4,831 |
|
|
$ |
311 |
|
|
$ |
4,209 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocation of net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
$ |
4,831 |
|
|
|
|
|
|
$ |
4,209 |
|
|
Net loss applicable to the period through August 22, 2005
|
|
|
|
|
|
|
|
|
|
|
(103 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
4,934 |
|
|
|
|
|
|
|
4,209 |
|
|
Allocation of net loss to general partner
|
|
|
|
|
|
|
|
|
|
|
(1,273 |
) |
|
|
|
|
|
|
(689 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocation of net income to limited partners
|
|
|
|
|
|
|
|
|
|
$ |
6,207 |
|
|
|
|
|
|
$ |
4,898 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted net income per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting
principle:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
|
|
|
|
|
|
|
|
$ |
0.49 |
|
|
|
|
|
|
$ |
0.35 |
|
|
|
Subordinated units
|
|
|
|
|
|
|
|
|
|
$ |
0.49 |
|
|
|
|
|
|
$ |
0.35 |
|
|
Cumulative effect of change in accounting principle:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
|
|
|
|
|
|
|
|
$ |
(0.05 |
) |
|
|
|
|
|
|
|
|
|
|
Subordinated units
|
|
|
|
|
|
|
|
|
|
$ |
(0.05 |
) |
|
|
|
|
|
|
|
|
|
Net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
|
|
|
|
|
|
|
|
$ |
0.44 |
|
|
|
|
|
|
|
|
|
|
|
Subordinated units
|
|
|
|
|
|
|
|
|
|
$ |
0.44 |
|
|
|
|
|
|
|
|
|
Weighted average number of units outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
|
|
|
|
|
|
|
|
|
7,001,366 |
|
|
|
|
|
|
|
7,006,146 |
|
|
Subordinated units
|
|
|
|
|
|
|
|
|
|
|
7,000,000 |
|
|
|
|
|
|
|
7,000,000 |
|
See accompanying notes to consolidated financial statements.
F-9
WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENT OF PARTNERS CAPITAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated | |
|
|
|
|
Pre-IPO | |
|
Limited Partners | |
|
|
|
Other | |
|
Total | |
|
|
Owners | |
|
| |
|
General | |
|
Comprehensive | |
|
Partners | |
|
|
Equity | |
|
Common | |
|
Subordinated | |
|
Partner | |
|
Income (Loss) | |
|
Capital | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(Dollars in thousands) | |
Balance January 1, 2003
|
|
$ |
24,876 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
(1,962 |
) |
|
$ |
22,914 |
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income 2003
|
|
|
5,216 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,216 |
|
|
Other comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized losses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(116 |
) |
|
|
(116 |
) |
|
|
Net reclassification into earnings of derivative instrument
losses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,078 |
|
|
|
2,078 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,962 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,178 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2003
|
|
|
30,092 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30,092 |
|
|
Net loss 2004
|
|
|
(13,424 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(13,424 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2004
|
|
|
16,668 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,668 |
|
Accounts receivable not contributed
|
|
|
(2,640 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,640 |
) |
Net loss attributable to the period through August 22, 2005
|
|
|
(103 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(103 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,925 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,925 |
|
Contribution of net assets of predecessor companies (2,000,000
common units; 7,000,000 subordinated units)
|
|
|
(13,925 |
) |
|
|
10,471 |
|
|
|
106,427 |
|
|
|
4,343 |
|
|
|
|
|
|
|
107,316 |
|
Issuance of units to public (5,000,000 common units)
|
|
|
|
|
|
|
100,247 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
100,247 |
|
Offering costs
|
|
|
|
|
|
|
(4,291 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,291 |
) |
Net income (loss) attributable to the period August 23,
2005 through December 31, 2005
|
|
|
|
|
|
|
3,104 |
|
|
|
3,103 |
|
|
|
(1,273 |
) |
|
|
|
|
|
|
4,934 |
|
Cash distributions ($.1484 per unit)
|
|
|
|
|
|
|
(1,039 |
) |
|
|
(1,039 |
) |
|
|
(42 |
) |
|
|
|
|
|
|
(2,120 |
) |
Issuance of common units (6,146 common units)
|
|
|
|
|
|
|
34 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34 |
|
Contributions pursuant to the omnibus agreement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,610 |
|
|
|
|
|
|
|
1,610 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2005
|
|
|
|
|
|
|
108,526 |
|
|
|
108,491 |
|
|
|
4,638 |
|
|
|
|
|
|
|
221,655 |
|
Net income (loss) three months ended March 31,
2006 (unaudited)
|
|
|
|
|
|
|
2,449 |
|
|
|
2,449 |
|
|
|
(689 |
) |
|
|
|
|
|
|
4,209 |
|
Cash distributions ($0.35 per unit) (unaudited)
|
|
|
|
|
|
|
(2,452 |
) |
|
|
(2,450 |
) |
|
|
(100 |
) |
|
|
|
|
|
|
(5,002 |
) |
Contributions pursuant to omnibus agreement (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,248 |
|
|
|
|
|
|
|
1,248 |
|
Other (unaudited)
|
|
|
|
|
|
|
104 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
104 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance March 31, 2006 (unaudited)
|
|
$ |
|
|
|
$ |
108,627 |
|
|
$ |
108,490 |
|
|
$ |
5,097 |
|
|
$ |
|
|
|
$ |
222,214 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F-10
WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended | |
|
|
Year Ended December 31, | |
|
March 31, | |
|
|
| |
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
|
|
|
|
|
|
(Unaudited) | |
|
|
(In thousands) | |
OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) before cumulative effect of change in
accounting principle
|
|
$ |
6,315 |
|
|
$ |
(13,424 |
) |
|
$ |
5,459 |
|
|
$ |
311 |
|
|
$ |
4,209 |
|
|
Adjustments to reconcile to cash provided by operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and accretion
|
|
|
3,707 |
|
|
|
3,686 |
|
|
|
3,619 |
|
|
|
905 |
|
|
|
900 |
|
|
|
Impairment of investment in Discovery Producer Services
|
|
|
|
|
|
|
13,484 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of gas purchase contract affiliate
|
|
|
|
|
|
|
|
|
|
|
2,033 |
|
|
|
|
|
|
|
1,354 |
|
|
|
Distributions in excess of/ (undistributed) equity earnings of
Discovery Producer Services
|
|
|
(3,447 |
) |
|
|
(4,495 |
) |
|
|
(7,051 |
) |
|
|
(2,212 |
) |
|
|
619 |
|
|
|
Cash provided (used) by changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(850 |
) |
|
|
261 |
|
|
|
(3,045 |
) |
|
|
678 |
|
|
|
996 |
|
|
|
|
Other current assets
|
|
|
(187 |
) |
|
|
(362 |
) |
|
|
(384 |
) |
|
|
(45 |
) |
|
|
(237 |
) |
|
|
|
Accounts payable
|
|
|
(274 |
) |
|
|
2,711 |
|
|
|
4,215 |
|
|
|
(1,495 |
) |
|
|
(3,028 |
) |
|
|
|
Accrued liabilities
|
|
|
(320 |
) |
|
|
(417 |
) |
|
|
(737 |
) |
|
|
(209 |
) |
|
|
345 |
|
|
|
|
Deferred revenue
|
|
|
1,108 |
|
|
|
775 |
|
|
|
247 |
|
|
|
(3,200 |
) |
|
|
(3,330 |
) |
|
|
Other, including changes in noncurrent assets and liabilities
|
|
|
592 |
|
|
|
484 |
|
|
|
(2,463 |
) |
|
|
1,212 |
|
|
|
567 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
6,644 |
|
|
|
2,703 |
|
|
|
1,893 |
|
|
|
(4,055 |
) |
|
|
2,395 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(1,167 |
) |
|
|
(1,534 |
) |
|
|
(3,688 |
) |
|
|
(212 |
) |
|
|
(1,165 |
) |
|
|
Contribution to Discovery Producer Services
|
|
|
(101,643 |
) |
|
|
|
|
|
|
(24,400 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities
|
|
|
(102,810 |
) |
|
|
(1,534 |
) |
|
|
(28,088 |
) |
|
|
(212 |
) |
|
|
(1,165 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from sale of common units
|
|
|
|
|
|
|
|
|
|
|
100,247 |
|
|
|
|
|
|
|
|
|
|
|
Payment of offering costs
|
|
|
|
|
|
|
|
|
|
|
(4,291 |
) |
|
|
|
|
|
|
|
|
|
|
Distribution to The Williams Companies, Inc.
|
|
|
|
|
|
|
|
|
|
|
(58,756 |
) |
|
|
|
|
|
|
|
|
|
|
Changes in advances from affiliates net
|
|
|
96,166 |
|
|
|
(1,169 |
) |
|
|
(3,656 |
) |
|
|
4,267 |
|
|
|
|
|
|
|
Distributions to unitholders
|
|
|
|
|
|
|
|
|
|
|
(2,120 |
) |
|
|
|
|
|
|
(5,002 |
) |
|
|
Contributions per omnibus agreement
|
|
|
|
|
|
|
|
|
|
|
1,610 |
|
|
|
|
|
|
|
1,248 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by financing activities
|
|
|
96,166 |
|
|
|
(1,169 |
) |
|
|
33,034 |
|
|
|
4,267 |
|
|
|
(3,754 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents
|
|
|
|
|
|
|
|
|
|
|
6,839 |
|
|
|
|
|
|
|
(2,524 |
) |
Cash and cash equivalents at beginning of period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,839 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$ |
|
|
|
$ |
|
|
|
$ |
6,839 |
|
|
$ |
|
|
|
$ |
4,315 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F-11
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Unless the context clearly indicates otherwise, references in
this report to we, our, us
or like terms refer to Williams Partners L.P. and its
subsidiaries. Unless the context clearly indicates otherwise,
references to we, our, and
us include the operations of Discovery Producer
Services LLC (Discovery), in which we own a
40 percent interest. When we refer to Discovery by name, we
are referring exclusively to its businesses and operations.
We are a Delaware limited partnership that was formed in
February 2005, to acquire and own
(1) a 40 percent interest in Discovery;
(2) the Carbonate Trend gathering pipeline off the coast of
Alabama; (3) three integrated natural gas liquids
(NGL) product storage facilities near Conway,
Kansas; and (4) a 50 percent undivided ownership
interest in a fractionator near Conway, Kansas. Prior to the
closing of our initial public offering (the IPO) in
August 2005, the 40 percent interest in Discovery was held
by Williams Energy, L.L.C. (Energy) and Williams
Discovery Pipeline LLC; the Carbonate Trend gathering pipeline
was held in Carbonate Trend Pipeline LLC (CTP),
which was owned by Williams Mobile Bay Producers Services,
L.L.C.; and the NGL product storage facilities and the interest
in the fractionator were owned by Mid-Continent Fractionation
and Storage, LLC (MCFS). All of these are wholly
owned indirect subsidiaries of The Williams Companies, Inc.
(collectively Williams). Williams Partners GP LLC, a
Delaware limited liability company, was also formed in February
2005, to serve as our general partner. We also formed Williams
Partners Operating LLC, an operating limited liability company
(wholly owned by us) through which all our activities are
conducted.
The accompanying unaudited interim consolidated financial
statements include all normal recurring adjustments that, in the
opinion of our management, are necessary to present fairly our
financial position at March 31, 2006, and the results of
operations and cash flows for the three months ended
March 31, 2005 and 2006.
|
|
|
Initial Public Offering and Related Transactions |
On August 23, 2005, we completed our IPO of 5,000,000
common units representing limited partner interests in us at a
price of $21.50 per unit. The proceeds of
$100.2 million, net of the underwriters discount and
a structuring fee totaling $7.3 million, were used to:
|
|
|
|
|
distribute $58.8 million to Williams, in part to reimburse
Williams for capital expenditures relating to the assets
contributed to us and for a gas purchase contract contributed to
us; |
|
|
|
provide $24.4 million to make a capital contribution to
Discovery to fund an escrow account required in connection with
the Tahiti pipeline lateral expansion project; |
|
|
|
provide $12.7 million of additional working
capital; and |
|
|
|
pay $4.3 million of expenses associated with the IPO and
related formation transactions. |
Concurrent with the closing of the IPO, the 40 percent
interest in Discovery and all of the interests in CTP and MCFS
were contributed to us by Williams subsidiaries in
exchange for an aggregate of 2,000,000 common units and
7,000,000 subordinated units. The public, through the
underwriters of the offering, contributed $107.5 million
($100.2 million net of the underwriters discount and
a structuring fee) to us in exchange for 5,000,000 common units,
representing a 35 percent limited partner interest in us.
Additionally, at the closing of the IPO, the underwriters fully
exercised their option to purchase 750,000 common units
from Williams subsidiaries at the IPO price of
$21.50 per unit, less the underwriters discount and a
structuring fee.
F-12
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
Acquisition of Four Corners |
On April 6, 2006, we entered into a Purchase and Sale
Agreement (the Purchase Agreement) with Williams
Energy Services, LLC (WES), Williams Field Services
Group, LLC (WFSG), Williams Field Services Company,
LLC (WFSC), Williams Partners Operating LLC and our
general partner. Pursuant to the Purchase Agreement, WES, WFSG,
WFSC and our general partner will contribute to us a
25.1 percent membership interest in Williams Four Corners
LLC (Four Corners) for aggregate consideration of
$360 million. Prior to or at closing, WFSC will contribute
to Four Corners its natural gas gathering, processing and
treating assets in the San Juan Basin in New Mexico and
Colorado. The closing of the Purchase Agreement is subject to
the satisfaction of a number of conditions, including our
ability to obtain financing and the receipt of all necessary
consents.
|
|
Note 2. |
Description of Business |
We are principally engaged in the business of gathering,
transporting and processing natural gas and fractionating and
storing NGLs. Operations of our businesses are located in the
United States and are organized into two reporting segments:
(1) Gathering and Processing and (2) NGL Services. Our
Gathering and Processing segment includes our equity investment
in Discovery and the Carbonate Trend gathering pipeline. Our NGL
Services segment includes the Conway fractionation and storage
operations.
Gathering and Processing. We own a 40 percent
interest in Discovery, which includes a wholly owned subsidiary,
Discovery Gas Transmission LLC. Discovery owns (1) a
273-mile natural gas
gathering and transportation pipeline system, located primarily
off the coast of Louisiana in the Gulf of Mexico, (2) a
600 million cubic feet per day cryogenic natural gas
processing plant in Larose, Louisiana, (3) a
32,000 barrels per day (bpd) natural gas
liquids fractionator in Paradis, Louisiana and (4) two
onshore liquids pipelines, including a
22-mile mixed NGL
pipeline connecting the gas processing plant to the fractionator
and a 10-mile
condensate pipeline connecting the gas processing plant to a
third party oil gathering facility. Although Discovery includes
fractionation operations, which would normally fall within the
NGL Services segment, it is primarily engaged in gathering and
processing and is managed as such. Hence, this equity investment
is considered part of the Gathering and Processing segment.
Our Carbonate Trend gathering pipeline is an unregulated sour
gas gathering pipeline consisting of approximately 34 miles
of pipeline off the coast of Alabama.
NGL Services. Our Conway storage facilities include three
underground NGL storage facilities in the Conway, Kansas, area
with a storage capacity of approximately 20 million
barrels. The facilities are connected via a series of pipelines.
The storage facilities receive daily shipments of a variety of
products, including mixed NGLs and fractionated products. In
addition to pipeline connections, one facility offers truck and
rail service.
Our Conway fractionation facility is located near Conway,
Kansas, and has a capacity of approximately 107,000 bpd. We
own a 50 percent undivided interest in these facilities
representing capacity of approximately 53,500 bpd.
ConocoPhillips and ONEOK Partners, L.P. are the other owners.
Williams operates the facility pursuant to an operating
agreement that extends until May 2011. The fractionator
separates mixed NGLs into five products: ethane/propane mix,
propane, normal butane, isobutane and natural gasoline. Portions
of these products are then transported and stored at our Conway
storage facilities.
|
|
Note 3. |
Summary of Significant Accounting Policies |
Basis of Presentation. The consolidated financial
statements have been prepared based upon accounting principles
generally accepted in the United States and include the accounts
of the parent and our wholly owned subsidiaries. Intercompany
accounts and transactions have been eliminated.
F-13
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Use of Estimates. The preparation of financial statements
in conformity with accounting principles generally accepted in
the United States requires management to make estimates and
assumptions that affect the amounts reported in the consolidated
financial statements and accompanying notes. Actual results
could differ from those estimates.
Estimates and assumptions which, in the opinion of management,
are significant to the underlying amounts included in the
financial statements and for which it would be reasonably
possible that future events or information could change those
estimates include:
|
|
|
|
|
impairment assessments of investments and long-lived assets; |
|
|
|
loss contingencies; |
|
|
|
environmental remediation obligations; and |
|
|
|
asset retirement obligations. |
These estimates are discussed further throughout the
accompanying notes.
Proportional Accounting for the Conway Fractionator. No
separate legal entity exists for the fractionator. We hold a
50 percent undivided interest in the fractionator property,
plant and equipment, and we are responsible for our proportional
share of the costs and expenses of the fractionator. As operator
of the facility, we incur the liabilities of the fractionator
(except for certain fuel costs purchased directly by one of the
co-owners) and are reimbursed by the co-owners for their
proportional share of the total costs and expenses. Each
co-owner is responsible for the marketing of their proportional
share of the fractionators capacity. Accordingly, we
reflect our proportionate share of the revenues and costs and
expenses of the fractionator in the Consolidated Statements of
Operations; and we reflect our proportionate share of the
fractionator property, plant and equipment in the Consolidated
Balance Sheets. Liabilities in the Consolidated Balance Sheets
include those incurred on behalf of the co-owners with
corresponding receivables from the co-owners. Accounts
receivable also includes receivables from our customers for
fractionation services.
Cash and Cash Equivalents. Cash and cash equivalents
include demand and time deposits, certificates of deposit and
other marketable securities with maturities of three months or
less when acquired.
Accounts Receivable. Accounts receivable are carried on a
gross basis, with no discounting, less an allowance for doubtful
accounts. No allowance for doubtful accounts is recognized at
the time the revenue which generates the accounts receivable is
recognized. We estimate the allowance for doubtful accounts
based on existing economic conditions, the financial condition
of our customers, and the amount and age of past due accounts.
Receivables are considered past due if full payment is not
received by the contractual due date. Past due accounts are
generally written off against the allowance for doubtful
accounts only after all collection attempts have been
unsuccessful.
Investments. The voting rights under Discoverys
limited liability company agreement are such that our
40 percent interest combined with the additional interest
held by Williams do not control Discovery. Hence, we account for
our investment in Discovery under the equity method. Prior to
2004, the excess of the carrying value of our investment over
the amount of underlying equity in net assets of Discovery
represented interest capitalized during construction on the
funds advanced to Discovery for construction prior to
Discoverys receipt of external financing. This excess was
being amortized on a straight-line basis over the life of the
related assets. In 2004, we recognized an other-than-temporary
impairment of our investment. As a result, Discoverys
underlying equity exceeds the carrying value of our investment
at December 31, 2005.
Property, Plant and Equipment. Property, plant and
equipment is recorded at cost. We base the carrying value of
these assets on capitalized costs, useful lives and salvage
values. Depreciation of property, plant and equipment is
provided on the straight-line basis over estimated useful lives.
Expenditures for maintenance and repairs are expensed as
incurred. Expenditures that enhance the functionality or extend
the
F-14
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
useful lives of the assets are capitalized. The cost of
property, plant and equipment sold or retired and the related
accumulated depreciation is removed from the accounts in the
period of sale or disposition. Gains and losses on the disposal
of property, plant and equipment are recorded in the
Consolidated Statements of Operations.
We record an asset and a liability equal to the present value of
each expected future asset retirement obligation
(ARO). The ARO asset is depreciated in a manner
consistent with the depreciation of the underlying physical
asset. We measure changes in the liability due to passage of
time by applying an interest method of allocation. This amount
is recognized as an increase in the carrying amount of the
liability and as a corresponding accretion expense included in
operating income.
Revenue Recognition. The nature of our businesses result
in various forms of revenue recognition. Our Gathering and
Processing segment recognizes revenue from gathering services
when the services have been performed. Our NGL Services segment
recognizes (1) fractionation revenues when services have
been performed and product has been delivered, (2) storage
revenues under prepaid contracted storage capacity evenly over
the life of the contract as services are provided and
(3) product sales revenue when the product has been
delivered.
Gas Purchase Contract. In connection with the IPO,
Williams transferred to us a gas purchase contract for the
purchase of a portion of our fuel requirements at the Conway
fractionator at a market price not to exceed a specified level.
The gas purchase contract is for the purchase of
80,000 MMBtu per month and terminates on December 31,
2007. The initial value of this contract is being amortized to
expense over the contract life.
Product Imbalances. In the course of providing
fractionation and storage services to our customers, we realize
product gains and losses that are reflected as product imbalance
receivables or payables on the Consolidated Balance Sheets.
These imbalances are valued based on the market price of the
products when the imbalance is identified and are evaluated for
the impact of a change in market prices at the balance sheet
date. Certain of these product gains and losses arise due to the
product blending process at the fractionator. Others are
realized when storage caverns are emptied. Storage caverns are
emptied periodically to determine whether any product gains or
losses have occurred, and as these caverns are emptied, it is
possible that the resulting product gains or losses could have a
material impact to the results of operations for the period
during which the cavern drain is performed.
Impairment of Long-Lived Assets and Investments. We
evaluate our long-lived assets of identifiable business
activities for impairment when events or changes in
circumstances indicate the carrying value of such assets may not
be recoverable. The impairment evaluation of tangible long-lived
assets is measured pursuant to the guidelines of Statement of
Financial Accounting Standards (SFAS) No. 144,
Accounting for the Impairment or Disposal of Long-Lived
Assets. When an indicator of impairment has occurred, we
compare our managements estimate of undiscounted future
cash flows attributable to the assets to the carrying value of
the assets to determine whether the carrying value of the assets
is recoverable. We apply a probability weighted approach to
consider the likelihood of different cash flow assumptions and
possible outcomes. If the carrying value is not recoverable, we
determine the amount of the impairment recognized in the
financial statements by estimating the fair value of the assets
and recording a loss for the amount that the carrying value
exceeds the estimated fair value.
We evaluate our investments for impairment when events or
changes in circumstances indicate, in our managements
judgment, that the carrying value of such investments may have
experienced an other-than-temporary decline in value. When
evidence of loss in value has occurred, we compare our estimate
of fair value of the investment to the carrying value of the
investment to determine whether an impairment has occurred. If
the estimated fair value is less than the carrying value and we
consider the decline in value to be
F-15
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
other than temporary, the excess of the carrying value over the
estimated fair value is recognized in the financial statements
as an impairment.
Judgments and assumptions are inherent in our managements
estimate of undiscounted future cash flows used to determine
recoverability of an asset and the estimate of an assets
fair value used to calculate the amount of impairment to
recognize. The use of alternate judgments and/or assumptions
could result in the recognition of different levels of
impairment charges in the financial statements.
Income Taxes. We are not a taxable entity for federal and
state income tax purposes. The tax on our net income is borne by
the individual partners through the allocation of taxable
income. Net income for financial statement purposes may differ
significantly from taxable income of unitholders as a result of
differences between the tax basis and financial reporting basis
of assets and liabilities and the taxable income allocation
requirements under our partnership agreement. The aggregate
difference in the basis of our net assets for financial and tax
reporting purposes cannot be readily determined because
information regarding each partners tax attributes in us
is not available to us.
Environmental. Environmental expenditures that relate to
current or future revenues are expensed or capitalized based
upon the nature of the expenditures. Expenditures that relate to
an existing contamination caused by past operations that do not
contribute to current or future revenue generation are expensed.
Accruals related to environmental matters are generally
determined based on site-specific plans for remediation, taking
into account our prior remediation experience. Environmental
contingencies are recorded independently of any potential claim
for recovery.
Capitalized Interest. We capitalize interest on major
projects during construction to the extent we incur interest
expense. Historically, Williams provided the financing for
capital expenditures; hence, the rates used to calculate the
interest were based on Williams average interest rate on
debt during the applicable period in time.
Earnings Per Unit. In accordance with the Emerging Issues
Task Force (EITF)
Issue 03-6, we use
the two-class method to calculate basic and diluted earnings per
unit whereby net income, adjusted for items specifically
allocated to our general partner, is allocated on a pro-rata
basis between unitholders and our general partner. Basic and
diluted earnings per unit are based on the average number of
common and subordinated units outstanding. Basic and diluted
earnings per unit are equivalent as there are no dilutive
securities outstanding.
Recent Accounting Standards. In December 2004, the
Financial Accounting Standards Board (FASB) issued
revised SFAS No. 123, Share-Based Payment.
The Statement requires that compensation costs for all
share-based awards to employees be recognized in the financial
statements at fair value. The Statement, as issued by the FASB,
was to be effective as of the beginning of the first interim or
annual reporting period that begins after June 15, 2005.
However, in April 2005, the Securities and Exchange Commission
(SEC) adopted a new rule that delayed the effective
date for revised SFAS No. 123 to the beginning of the
next fiscal year that begins after June 15, 2005. We intend
to adopt the revised Statement as of January 1, 2006.
Payroll costs directly charged to us by Williams and general and
administrative costs allocated to us by Williams (see
Note 5) will include such compensation costs beginning
January 1, 2006. Our and Williams adoption of this
Statement will not have a material impact on our Consolidated
Financial Statements.
In November 2004, the FASB issued SFAS No. 151,
Inventory Costs, an amendment of ARB No. 43,
Chapter 4, which will be applied prospectively for
inventory costs incurred in fiscal years beginning after
June 15, 2005. The Statement amends Accounting Research
Bulletin (ARB) No. 43, Chapter 4, Inventory
Pricing, to clarify that abnormal amounts of certain costs
should be recognized as current period charges and that the
allocation of overhead costs should be based on the normal
capacity of the production facility. The impact of this
Statement on our Consolidated Financial Statements will not be
material.
F-16
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In December 2004, the FASB issued SFAS No. 153,
Exchanges of Nonmonetary Assets, an amendment of APB
Opinion No. 29, which is effective for nonmonetary
asset exchanges occurring in fiscal periods beginning after
June 15, 2005, and will be applied prospectively. The
Statement amends APB Opinion No. 29, Accounting for
Nonmonetary Transactions. The guidance in APB Opinion
No. 29 is based on the principle that exchanges of
nonmonetary assets should be measured based on the fair value of
the assets exchanged but includes certain exceptions to that
principle. SFAS No. 153 amends APB Opinion No. 29
to eliminate the exception for nonmonetary exchanges of similar
productive assets and replaces it with a general exception for
exchanges of nonmonetary assets that do not have commercial
substance. A nonmonetary exchange has commercial substance if
the future cash flows of the entity are expected to change
significantly as a result of the exchange.
In May 2005, the FASB issued SFAS No. 154,
Accounting Changes and Error Corrections a
replacement of APB Opinion No. 20 and FASB Statement
No. 3, which is effective prospectively for reporting
a change in accounting principle for fiscal years beginning
after December 15, 2005. The Statement changes the
reporting of a change in accounting principle to require
retrospective application to prior periods financial
statements, except for explicit transition provisions provided
for in any existing accounting pronouncements, including those
in the transition phase when SFAS No. 154 becomes
effective.
In January 2006, Williams adopted SFAS No. 123(R),
Share-Based Payment. Accordingly, payroll costs
charged to us by our general partner reflect additional
compensation costs related to the adoption of this accounting
standard. These costs relate to Williams common stock
equity awards made between Williams and its employees. For the
first quarter of 2006 there is approximately $100,000 of cost
related to Williams share-based payment plan reflected in
our general and administrative expense on the Consolidated
Statements of Operations. The cost is charged to us through
specific allocations of certain employees if they directly
support our operations, and through an allocation methodology
among all Williams affiliates if they provide indirect support.
These allocated costs are based on a three-factor formula, which
considers revenues; property, plant and equipment; and payroll.
|
|
Note 4. |
Allocation of Net Income and Distributions |
The allocation of net income between our general partner and
limited partners for the period August 23, 2005 through
December 31, 2005 is as follows (in thousands):
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|
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|
|
Allocation of net income to general partner:
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|
Net income for the period August 23, 2005 through
December 31, 2005
|
|
$ |
4,934 |
|
|
Direct charges to general partner:
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|
|
|
|
|
Reimbursable general and administrative costs
|
|
|
1,400 |
|
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|
|
|
|
Income before direct charges to general partner
|
|
|
6,334 |
|
|
General partners share of net income
|
|
|
2.0 |
% |
|
|
|
|
|
General partners allocated share of net income before
direct charges
|
|
|
127 |
|
|
Direct charges to general partner
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|
|
(1,400 |
) |
|
|
|
|
Net loss allocated to general partner
|
|
$ |
(1,273 |
) |
|
|
|
|
Net income for the period August 23, 2005 through
December 31, 2005
|
|
$ |
4,934 |
|
Net loss allocated to general partner
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|
|
(1,273 |
) |
|
|
|
|
Net income allocated to limited partners
|
|
$ |
6,207 |
|
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|
|
|
F-17
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The allocation of net income between our general partner and
limited partners for the three months ended March 31, 2006
is as follows (in thousands) (unaudited):
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|
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|
Allocation to general partner:
|
|
|
|
|
|
Net income
|
|
$ |
4,209 |
|
|
Charges direct to general partner:
|
|
|
|
|
|
|
Reimbursable general and administrative costs
|
|
|
789 |
|
|
|
|
|
|
Income before direct charges to general partner
|
|
|
4,998 |
|
|
General partners share of net income
|
|
|
2.0 |
% |
|
|
|
|
|
General partners allocated share of net income before
direct charges
|
|
|
100 |
|
|
Direct charges to general partner
|
|
|
(789 |
) |
|
|
|
|
Net loss allocated to general partner
|
|
$ |
(689 |
) |
|
|
|
|
Net income
|
|
$ |
4,209 |
|
Net loss allocated to general partner
|
|
|
(689 |
) |
|
|
|
|
Net income allocated to limited partners
|
|
$ |
4,898 |
|
|
|
|
|
The reimbursable general and administrative costs represent the
general and administrative costs charged against our income that
are required to be reimbursed to us by our general partner under
the terms of the Omnibus Agreement.
We paid or have authorized payment of the following cash
distributions during 2005 and 2006 (in thousands, except for per
unit amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per Unit | |
|
Common | |
|
Subordinated | |
|
General | |
|
Total Cash | |
Payment Date |
|
Distribution | |
|
Units | |
|
Units | |
|
Partner | |
|
Distribution | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
11/14/2005(a)
|
|
$ |
0.1484 |
|
|
$ |
1,039 |
|
|
$ |
1,039 |
|
|
$ |
42 |
|
|
$ |
2,120 |
|
2/14/2006
|
|
$ |
0.3500 |
|
|
$ |
2,452 |
|
|
$ |
2,450 |
|
|
$ |
100 |
|
|
$ |
5,002 |
|
5/15/2006(b)(unaudited)
|
|
$ |
0.3800 |
|
|
$ |
2,662 |
|
|
$ |
2,660 |
|
|
$ |
109 |
|
|
$ |
5,431 |
|
|
|
|
|
(a) |
|
This distribution represents the $0.35 per unit minimum
quarterly distribution pro-rated for the
39-day period following
the IPO closing date (August 23, 2005 through
September 30, 2005). |
|
|
(b) |
|
The board of directors of our general partner declared this cash
distribution on April 27, 2006 to be paid on May 15,
2006 to unitholders of record at the close of business on
May 8, 2006. |
|
|
|
Note 5. |
Related Party Transactions |
The employees of our operated assets and all of our general and
administrative employees are employees of Williams. Williams
directly charges us for the payroll costs associated with the
operations employees and certain general and administrative
employees. Williams carries the obligations for most
employee-related benefits in its financial statements, including
the liabilities related to the employee retirement and medical
plans and paid time off. Certain of these costs are charged back
to the other Conway fractionator co-owners. Our share of those
costs are charged to us through affiliate billings and reflected
in Operating and maintenance expense Affiliate in
the accompanying Consolidated Statements of Operations.
Williams charges its affiliates, including us and its Midstream
segment, of which we are a part, for certain corporate
administrative expenses that are directly identifiable or
allocable to the affiliates. Direct costs charged from Williams
represent the direct costs of services provided by Williams on
our behalf. Prior to the IPO, a portion of the charges allocated
to the Midstream segment were then reallocated to us. These
allocated corporate administrative expenses are based on a
three-factor formula, which considered revenues;
F-18
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
property, plant and equipment; and payroll. Certain of these
costs are charged back to the other Conway fractionator
co-owners. Our share of these costs is reflected in General and
administrative expense Affiliate in the accompanying
Consolidated Statements of Operations. In managements
estimation, the allocation methodologies used are reasonable and
result in a reasonable allocation to us of our costs of doing
business incurred by Williams. Under the Omnibus Agreement,
Williams gives us a quarterly credit for general and
administrative expenses. These amounts are reflected as a
capital contribution from our general partner. The annual
amounts of the credits are as follows: $3.9 million in 2005
($1.4 million pro-rated for the portion of the year from
August 23 to December 31), $3.2 million in 2006,
$2.4 million in 2007, $1.6 million in 2008 and
$0.8 million in 2009.
At December 31, 2005, we have a contribution receivable
from our general partner of $0.3 million, which is netted
against Partners capital on the Consolidated Balance
Sheets, for amounts reimbursable to us under the Omnibus
Agreement.
We purchase fuel for the Conway fractionator, including fuel on
behalf of the co-owners, from Williams Power Company
(Power), a wholly owned subsidiary of Williams.
These purchases are made at market rates at the time of
purchase. In connection with the IPO, Williams transferred to us
a gas purchase contract for the purchase of a portion of our
fuel requirements at the Conway fractionator at a market price
not to exceed a specified level. The amortization of this
contract is reflected in Operating and maintenance
expense Affiliate in the accompanying Consolidated
Statements of Operations. The carrying value of this contract is
reflected as Gas purchase contract affiliate and Gas
purchase contract noncurrent affiliate
on the Consolidated Balance Sheets.
During a portion of 2003, we provided propane storage,
fractionation, transportation and terminaling services to
subsidiaries of Williams that have subsequently been sold. In
December 2004, we began selling surplus propane and other NGLs
to Power, which takes title to the product and resells it, for
its own account, to end users. Revenues associated with these
activities are reflected as Affiliate revenues on the
Consolidated Statements of Operations. Correspondingly, we
purchase ethane and other NGLs from Power to replenish deficit
product positions. The transactions conducted between us and
Power are transacted at current market prices for the products.
A summary of the general and administrative expenses directly
charged and allocated to us, fuel purchases from Power and NGL
purchases from Power for the periods stated is as follows:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003 | |
|
2004 | |
|
2005 | |
|
|
| |
|
| |
|
| |
|
|
(In thousands) | |
General and administrative expenses, including amounts
subsequently charged to co-owners:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated
|
|
$ |
1,392 |
|
|
$ |
2,078 |
|
|
$ |
3,494 |
|
|
Directly charged
|
|
|
346 |
|
|
|
456 |
|
|
|
992 |
|
Operating and maintenance expenses, including amounts
subsequently charged to co-owners:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel purchases, including amortization of gas contract
|
|
|
12,843 |
|
|
|
17,053 |
|
|
|
24,478 |
|
|
Salaries and benefits
|
|
|
2,105 |
|
|
|
3,473 |
|
|
|
3,514 |
|
NGL purchases
|
|
|
|
|
|
|
1,271 |
|
|
|
15,657 |
|
The per-unit gathering fee associated with two of our Carbonate
Trend gathering contracts was negotiated on a bundled basis that
includes transportation along a segment of a pipeline system
owned by Transcontinental Gas Pipe Line Company
(Transco), a wholly owned subsidiary of Williams.
The fees we realize are dependent upon whether our customer
elects to utilize this Transco capacity. When they make this
election, our gathering fee is determined by subtracting the
Transco tariff from the total negotiated fee. The
F-19
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
rate associated with the capacity agreement is based on a
Federal Energy Regulatory Commission tariff that is subject to
change. Accordingly, if the Transco rate increases, our net
gathering fees for these two contracts may be reduced. The
customers with these bundled contracts must make an annual
election to receive this capacity. For 2005 and 2006, only one
of our customers has elected to utilize this capacity.
We historically participated in Williams cash management
program; thus, we carried no cash balance on our Consolidated
Balance Sheet at December 31, 2004. Effective with the IPO,
we began maintaining our own bank accounts but continue to
utilize Williams personnel to manage our cash and
investments. As of December 31, 2004, our net Advances from
affiliate consisted of an unsecured promissory note agreement
with Williams for both advances to and from Williams. The
advances were due on demand; however, Williams did not
historically require repayment. Therefore, Advances from
affiliate at December 31, 2004 were classified as
noncurrent. Prior to the closing of the IPO, Williams forgave
the advances due to them at the date the net assets were
transferred to us. Accordingly, the advances balance was
transferred to Partners capital at that date.
Affiliate interest expense includes interest on the advances
with Williams calculated using Williams weighted average
cost of debt applied to the outstanding balance of the advances
with Williams and commitment fees on the working capital credit
facility (see Note 11). The interest rate on the advances
with Williams was 7.373 percent at December 31, 2004.
|
|
Note 6. |
Investment in Discovery Producer Services |
Our 40 percent investment in Discovery is accounted for
using the equity method of accounting. At December 31,
2005, Williams owned an additional 20 percent ownership
interest in Discovery through Energy. Although we and Williams
hold a 60 percent interest in Discovery on a combined
basis, the voting provisions of Discoverys limited
liability company agreement give the other member of Discovery
significant participatory rights such that we and Williams do
not control Discovery.
Of the total ownership interest owned by Williams prior to the
transfer of 40 percent to us, a portion was acquired by
Williams in April 2005 resulting in a revised basis used for the
calculation of the 40 percent interest transferred to us in
connection with the IPO. As a result, the carrying value of our
40 percent interest in Discovery and Partners capital
decreased $11.0 million during the second quarter of 2005.
On August 22, 2005, Discovery made a distribution of
approximately $43.8 million to Williams and the other
member of Discovery at that date. This distribution was
associated with Discoverys operations prior to the IPO;
hence, we did not receive any portion of this distribution. The
distribution resulted in a revised basis used for the
calculation of the 40 percent interest transferred to us in
connection with the IPO. As a result, the carrying value of our
40 percent interest in Discovery and Partners capital
decreased $17.5 million during the third quarter of 2005.
In September 2005, we made a $24.4 million capital
contribution to Discovery for a substantial portion of our share
of the estimated future capital expenditures for the Tahiti
pipeline lateral expansion project.
Williams is the operator of Discovery. Discovery reimburses
Williams for actual payroll and employee benefit costs incurred
on its behalf. In addition, Discovery pays Williams a monthly
operations and management fee to cover the cost of accounting
services, computer systems and management services provided to
it. Discovery also has an agreement with Williams pursuant to
which Williams markets the NGLs and excess natural gas to which
Discovery takes title.
During 2004, we performed an impairment review of this
investment because of Williams planned purchase of an
additional interest in Discovery at an amount below its carrying
value. As a result, we recorded a $13.5 million impairment
of our investment in Discovery based on a probability-weighted
estimation of fair value of our investment. In December 2003,
each of the owners made an additional
F-20
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
investment in Discovery, which was subsequently used by
Discovery to repay maturing debt. Our proportionate share of
this additional investment was approximately $101.6 million.
Due to the significance of Discoverys equity earnings to
our results of operations, the summarized financial position and
results of operations for 100 percent of Discovery are
presented below (in thousands).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, | |
|
|
|
|
| |
|
March 31, | |
|
|
2004 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
|
|
|
|
|
(Unaudited) | |
Current assets
|
|
$ |
67,534 |
|
|
$ |
70,525 |
|
|
$ |
62,700 |
|
Non-current restricted cash
|
|
|
|
|
|
|
44,559 |
|
|
|
41,859 |
|
Property, plant and equipment
|
|
|
356,385 |
|
|
|
344,743 |
|
|
|
340,935 |
|
Current liabilities
|
|
|
(31,572 |
) |
|
|
(45,070 |
) |
|
|
(27,475 |
) |
Non-current liabilities
|
|
|
(702 |
) |
|
|
(1,121 |
) |
|
|
(1,146 |
) |
|
|
|
|
|
|
|
|
|
|
Members capital
|
|
$ |
391,645 |
|
|
$ |
413,636 |
|
|
$ |
416,873 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended | |
|
|
Years Ended December 31, | |
|
March 31, | |
|
|
| |
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
|
|
|
|
|
|
(Unaudited) | |
Revenues
|
|
$ |
103,178 |
|
|
$ |
99,876 |
|
|
$ |
122,745 |
|
|
$ |
27,289 |
|
|
$ |
62,120 |
|
Costs and expenses
|
|
|
84,519 |
|
|
|
88,756 |
|
|
|
102,597 |
|
|
|
22,042 |
|
|
|
52,867 |
|
Interest expense
|
|
|
9,611 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
|
|
|
|
(550 |
) |
|
|
(1,685 |
) |
|
|
(284 |
) |
|
|
(626 |
) |
Foreign exchange loss
|
|
|
|
|
|
|
|
|
|
|
1,005 |
|
|
|
|
|
|
|
427 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle
|
|
$ |
9,048 |
|
|
$ |
11,670 |
|
|
$ |
20,828 |
|
|
$ |
5,531 |
|
|
$ |
9,452 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
8,781 |
|
|
$ |
11,670 |
|
|
$ |
20,652 |
|
|
$ |
5,531 |
|
|
$ |
9,452 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 7. |
Property, Plant and Equipment |
Property, plant and equipment, at cost, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, | |
|
Estimated |
|
|
| |
|
Depreciable |
|
|
2004 | |
|
2005 | |
|
Lives |
|
|
| |
|
| |
|
|
|
|
(In thousands) | |
|
|
Land and right of way
|
|
$ |
2,373 |
|
|
$ |
2,373 |
|
|
|
Fractionation plant and equipment
|
|
|
16,555 |
|
|
|
16,646 |
|
|
30 years |
Storage plant and equipment
|
|
|
63,632 |
|
|
|
65,892 |
|
|
30 years |
Pipeline plant and equipment
|
|
|
23,684 |
|
|
|
23,684 |
|
|
20-30 years |
Construction work in progress
|
|
|
566 |
|
|
|
1,886 |
|
|
|
Other
|
|
|
1,490 |
|
|
|
1,492 |
|
|
5-45 years |
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment
|
|
|
108,300 |
|
|
|
111,973 |
|
|
|
Accumulated depreciation
|
|
|
40,507 |
|
|
|
44,042 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
$ |
67,793 |
|
|
$ |
67,931 |
|
|
|
|
|
|
|
|
|
|
|
|
We adopted SFAS No. 143, Accounting for Asset
Retirement Obligations on January 1, 2003. As a
result, we recorded a liability of $993,000 representing the
present value of expected future asset retirement
F-21
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
obligations at January 1, 2003, and a decrease to earnings
of $992,000 reflected as a cumulative effect of a change in
accounting principle. An additional $107,000 reduction of
earnings is reflected as a cumulative effect of a change in
accounting principle for our 40 percent interest in
Discoverys cumulative effect of a change in accounting
principle related to the adoption of SFAS No. 143.
Effective December 31, 2005, we adopted FASB Interpretation
(FIN) No. 47, Accounting for Conditional
Asset Retirement Obligations. This Interpretation
clarifies that an entity is required to recognize a liability
for the fair value of a conditional ARO when incurred if the
liabilitys fair value can be reasonably estimated. The
Interpretation clarifies when an entity would have sufficient
information to reasonably estimate the fair value of an ARO. As
required by the new standard, we reassessed the estimated
remaining life of all our assets with a conditional ARO. We
recorded additional liabilities totaling $573,000 equal to the
present value of expected future asset retirement obligations at
December 31, 2005. The liabilities are slightly offset by a
$16,000 increase in property, plant and equipment, net of
accumulated depreciation, recorded as if the provisions of the
Interpretation had been in effect at the date the obligation was
incurred. The net $557,000 reduction to earnings is reflected as
a cumulative effect of a change in accounting principle for the
year ended 2005. An additional $70,000 reduction of earnings is
reflected as a cumulative effect of a change in accounting
principle for our 40 percent interest in Discoverys
cumulative effect of a change in accounting principle related to
the adoption of FIN No. 47. If the Interpretation had
been in effect at the beginning of 2003, the impact to our
income from continuing operations and net income would have been
immaterial.
The obligations relate to underground storage caverns and the
associated brine ponds. At the end of the useful life of each
respective asset, we are legally obligated to properly abandon
the storage caverns, empty the brine ponds and restore the
surface, and remove any related surface equipment.
A rollforward of our asset retirement obligation for 2004 and
2005 is presented below.
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2005 | |
|
|
| |
|
| |
|
|
(In thousands) | |
Balance, January 1
|
|
$ |
801 |
|
|
$ |
760 |
|
Liabilities incurred during the period
|
|
|
79 |
|
|
|
91 |
|
Liabilities settled during the period
|
|
|
(166 |
) |
|
|
(204 |
) |
Accretion expense
|
|
|
83 |
|
|
|
1 |
|
Estimate revisions
|
|
|
|
|
|
|
(460 |
) |
FIN No. 47 revisions
|
|
|
|
|
|
|
574 |
|
Gain on settlements
|
|
|
(37 |
) |
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31
|
|
$ |
760 |
|
|
$ |
762 |
|
|
|
|
|
|
|
|
F-22
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
Note 8. |
Accrued Liabilities |
Accrued liabilities are as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31, | |
|
|
| |
|
|
2004 | |
|
2005 | |
|
|
| |
|
| |
|
|
(In thousands) | |
Environmental remediation current portion
|
|
$ |
1,633 |
|
|
$ |
1,424 |
|
Customer volume deficiency payment
|
|
|
749 |
|
|
|
|
|
Asset retirement obligation current portion
|
|
|
760 |
|
|
|
|
|
Employee costs affiliate
|
|
|
317 |
|
|
|
387 |
|
Taxes other than income
|
|
|
359 |
|
|
|
375 |
|
Other
|
|
|
106 |
|
|
|
187 |
|
|
|
|
|
|
|
|
|
|
$ |
3,924 |
|
|
$ |
2,373 |
|
|
|
|
|
|
|
|
|
|
Note 9. |
Long-Term Incentive Plan |
In November 2005, our general partner adopted the Williams
Partners GP LLC Long-Term Incentive Plan (the Plan)
for employees, consultants and directors of our general partner
and its affiliates who perform services for us. The Plan permits
the grant of awards covering an aggregate of 700,000 common
units. These awards may be in the form of options, restricted
units, phantom units or unit appreciation rights. The
compensation committee of our general partners board of
directors administers the Plan.
During November and December 2005, our general partner granted
6,146 restricted units pursuant to the Plan to members of our
general partners board of directors who are not officers
or employees of our general partner or its affiliates. These
restricted units vest six months from grant date. We recognized
compensation expense of $34 thousand associated with these
awards in 2005.
|
|
Note 10. |
Major Customers, Concentrations of Credit Risk and Financial
Instruments |
In 2003, four customers, BP, Enterprise, Chevron and Williams
Power Company (an affiliate company), accounted for
approximately 24.6 percent, 15.9 percent,
14.7 percent and 11.6 percent, respectively, of our
total revenues. In 2004, three customers, SemStream, L.P., BP
and Enterprise accounted for approximately 20.6 percent,
16.1 percent and 16.0 percent, respectively, of our
total revenues. In 2005, four customers, Williams Power Company,
SemStream, L.P., Enterprise and BP Products North America, Inc.
(BP) accounted for approximately 25.9 percent,
17.1 percent, 14.1 percent and 13.5 percent,
respectively, of our total revenues. SemStream, L.P., BP,
Enterprise and Williams Power Company are customers of the NGL
Services segment. Chevron is a customer of the Gathering and
Processing segment.
Our Carbonate Trend gathering pipeline has only two customers.
The loss of either of these customers, unless replaced, would
have a significant impact on the Gathering and Processing
segment.
|
|
|
Concentrations of Credit Risk |
Our cash equivalents consist of high-quality securities placed
with various major financial institutions with credit ratings at
or above AA by Standard & Poors or Aa by
Moodys Investors Service.
F-23
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table summarizes the concentration of accounts
receivable by service and segment.
|
|
|
|
|
|
|
|
|
|
|
|
December 31, | |
|
|
| |
|
|
2004 | |
|
2005 | |
|
|
| |
|
| |
|
|
(In thousands) | |
Gathering and Processing:
|
|
|
|
|
|
|
|
|
|
Natural gas gathering
|
|
$ |
441 |
|
|
$ |
525 |
|
NGL Services:
|
|
|
|
|
|
|
|
|
|
Fractionation services
|
|
|
468 |
|
|
|
532 |
|
|
Amounts due from fractionator partners
|
|
|
1,381 |
|
|
|
1,834 |
|
|
Storage
|
|
|
1,241 |
|
|
|
793 |
|
|
Other
|
|
|
7 |
|
|
|
260 |
|
|
|
|
|
|
|
|
|
|
$ |
3,538 |
|
|
$ |
3,944 |
|
|
|
|
|
|
|
|
Our fractionation and storage customers include crude refiners;
propane wholesalers and retailers; gas producers; natural gas
plant, fractionator and storage operators; and NGL traders and
pipeline operators. Our two Carbonate Trend natural gas
gathering customers are oil and gas producers. While sales to
our customers are unsecured, we routinely evaluate their
financial condition and creditworthiness.
We used the following methods and assumptions to estimate the
fair value of financial instruments.
Cash and cash equivalents. The carrying amounts reported
in the balance sheets approximate fair value due to the
short-term maturity of these instruments.
Advances from affiliates. At December 31, 2004, our
net Advances from affiliate consisted of an unsecured promissory
note agreement with Williams for both advances to and from
Williams. The carrying amounts reported in the Consolidated
Balance Sheet approximate fair value as this instrument had an
interest rate approximating market.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2005 | |
|
|
| |
|
| |
|
|
Carrying | |
|
Fair | |
|
Carrying | |
|
Fair | |
|
|
Amount | |
|
Value | |
|
Amount | |
|
Value | |
|
|
| |
|
| |
|
| |
|
| |
|
|
(In thousands) | |
Cash and cash equivalents
|
|
|
|
|
|
|
|
|
|
$ |
6,839 |
|
|
$ |
6,839 |
|
Advances from affiliates
|
|
$ |
186,024 |
|
|
$ |
186,024 |
|
|
|
|
|
|
|
|
|
|
|
Note 11. |
Credit Facilities and Leasing Activities |
On May 20, 2005, Williams amended its $1.275 billion
revolving credit facility (Williams facility), which
is available for borrowings and letters of credit, to allow us
to borrow up to $75 million under the Williams facility.
Borrowings under the Williams facility mature on May 3,
2007. Our $75 million borrowing limit under the Williams
facility is available for general partnership purposes,
including acquisitions, but only to the extent that sufficient
amounts remain unborrowed by Williams and its other
subsidiaries. At December 31, 2005, letters of credit
totaling $378 million had been issued on behalf of Williams
by the participating institutions under the Williams facility
and no revolving credit loans were outstanding.
Interest on any borrowings under the Williams facility is
calculated based on our choice of two methods: (i) a
fluctuating rate equal to the facilitating banks base rate
plus an applicable margin or (ii) a periodic fixed rate
equal to LIBOR plus an applicable margin. We are also required
to pay or reimburse Williams for
F-24
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
a commitment fee based on the unused portion of its
$75 million borrowing limit under the Williams facility,
currently 0.325 percent annually. The applicable margin,
currently 1.75 percent, and the commitment fee are based on
Williams senior unsecured long-term debt rating. Under the
Williams facility, Williams and certain of its subsidiaries,
other than us, are required to comply with certain financial and
other covenants. Significant financial covenants under the
Williams facility to which Williams is subject include the
following:
|
|
|
|
|
ratio of debt to net worth no greater than
(i) 70 percent through December 31, 2005, and
(ii) 65 percent for the remaining term of the
agreement; |
|
|
|
ratio of debt to net worth no greater than 55 percent for
Northwest Pipeline Corporation, a wholly owned subsidiary of
Williams, and Transco; and |
|
|
|
ratio of EBITDA to interest, on a rolling four quarter basis, no
less than (i) 2.0 for any period after March 31, 2005
through December 31, 2005, and (ii) 2.5 for the
remaining term of the agreement. |
In August 2005, we entered into a $20 million revolving
credit facility (the credit facility) with Williams
as the lender. The credit facility is available exclusively to
fund working capital requirements. Borrowings under the credit
facility mature on May 3, 2007 and bear interest at the
same rate as for borrowings under the Williams facility
described above. We pay a commitment fee to Williams on the
unused portion of the credit facility of 0.30 percent
annually. We are required to reduce all borrowings under the
credit facility to zero for a period of at least 15 consecutive
days once each 12-month
period prior to the maturity date of the credit facility. No
amounts have been drawn on this facility.
In May 2006, Williams replaced its $1.275 billion secured
credit facility with a $1.5 billion unsecured credit
facility. The new facility contains similar terms and covenants
applicable to us. This revolving credit facility is available
for borrowings and letters of credit and will continue to allow
us to borrow up to $75 million for general partnership
purposes, including acquisitions, but only to the extent that
sufficient amounts remain unborrowed by Williams and its other
subsidiaries.
We lease automobiles for use in our NGL Services segment. We
account for these leases as operating leases. Future minimum
annual rentals under non-cancelable operating leases as of
December 31, 2005 are as follows (in thousands):
|
|
|
|
|
2006
|
|
$ |
30 |
|
2007
|
|
|
29 |
|
2008
|
|
|
27 |
|
2009
|
|
|
10 |
|
2010
|
|
|
|
|
|
|
|
|
|
|
$ |
96 |
|
|
|
|
|
Total rent expense was $116,000, $110,000 and $119,000 for 2003,
2004 and 2005, respectively.
|
|
Note 12. |
Partners Capital |
Of the 7,006,146 common units outstanding at December 31,
2005, 5,756,146 are held by the public, with the remaining
1,250,000 held by our affiliates. All of the 7,000,000
subordinated units are held by our affiliates.
Upon expiration of the subordination period, 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.
F-25
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The subordination period will end on the first day of any
quarter beginning after June 30, 2008 or when we meet
certain financial tests provided for in our partnership
agreement.
Significant information regarding rights of the limited partners
include the following:
|
|
|
|
|
Right to receive distributions of available cash within
45 days after the end of each quarter. |
|
|
|
No limited partner shall have any management power over our
business and affairs; the general partner shall conduct, direct
and manage our activities. |
|
|
|
The general partner may be removed if such removal is approved
by the unitholders holding at least
662/3
percent of the outstanding units voting as a single
class, including units held by our general partner and its
affiliates. |
|
|
|
Right to receive information reasonably required for tax
reporting purposes within 90 days after the close of the
calendar year. |
Our general partner is entitled to incentive distributions if
the amount we distribute to unitholders with respect to any
quarter exceeds specified target levels shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
General | |
Quarterly Distribution Target Amount (per unit) |
|
Unitholders | |
|
Partner | |
|
|
| |
|
| |
Minimum quarterly distribution of $0.35
|
|
|
98 |
% |
|
|
2 |
% |
Up to $0.4025
|
|
|
98 |
|
|
|
2 |
|
Above $0.4025 up to $0.4375
|
|
|
85 |
|
|
|
15 |
|
Above $0.4375 up to $0.5250
|
|
|
75 |
|
|
|
25 |
|
Above $0.5250
|
|
|
50 |
|
|
|
50 |
|
In the event of a liquidation, all property and cash in excess
of that required to discharge all liabilities will be
distributed to the unitholders and our general partner, in
proportion to their capital account balances, as adjusted to
reflect any gain or loss upon the sale or other disposition of
our assets in liquidation.
|
|
|
Other Comprehensive Income |
The main component of our accumulated other comprehensive loss
is our share of Discoverys accumulated other comprehensive
loss which is related to a cash flow hedge of interest rate risk
held by Discovery in 2003.
|
|
Note 13. |
Commitments and Contingencies |
Environmental Matters. We are a participant in certain
environmental remediation activities associated with soil and
groundwater contamination at our Conway storage facilities.
These activities relate to four projects that are in various
remediation stages including assessment studies, cleanups and/or
remedial operations and monitoring. We continue to coordinate
with the Kansas Department of Health and Environment
(KDHE) to develop screening, sampling, cleanup and
monitoring programs. The costs of such activities will depend
upon the program scope ultimately agreed to by the KDHE and are
expected to be paid over the next two to nine years.
In 2004, we purchased an insurance policy that covers up to
$5 million of remediation costs until an active remediation
system is in place or April 30, 2008, whichever is earlier,
excluding operation and maintenance costs and ongoing monitoring
costs, for these projects to the extent such costs exceed a
$4.2 million deductible. The policy also covers costs
incurred as a result of third party claims associated with then
existing but unknown contamination related to the storage
facilities. The aggregate limit under the policy for all claims
is $25 million. In addition, under an omnibus agreement
with Williams entered into at the
F-26
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
closing of the IPO, Williams has agreed to indemnify us for the
$4.2 million deductible (less amounts expended prior to the
closing of the IPO) of remediation expenditures not covered by
the insurance policy, excluding costs of project management and
soil and groundwater monitoring. There is a $14 million cap
on the total amount of indemnity coverage under the omnibus
agreement, which will be reduced by actual recoveries under the
environmental insurance policy. There is also a three-year time
limitation from the IPO closing date, August 23, 2005. The
benefit of this indemnification will be accounted for as a
capital contribution to us by Williams as the costs are
reimbursed. We estimate that the approximate cost of this
project management and soil and groundwater monitoring
associated with the four remediation projects at the Conway
storage facilities and for which we will not be indemnified will
be approximately $200,000 to $400,000 per year following
the completion of the remediation work.
At December 31, 2005, and March 31, 2006 (unaudited),
we had accrued liabilities totaling $5.4 and $5.3 million,
respectively, for these costs. It is reasonably possible that we
will incur losses in excess of our accrual for these matters.
However, a reasonable estimate of such amounts cannot be
determined at this time because actual costs incurred will
depend on the actual number of contaminated sites identified,
the amount and extent of contamination discovered, the final
cleanup standards mandated by KDHE and other governmental
authorities and other factors.
Hurricane Costs. At March 31, 2006 (unaudited),
Williams had an insurance receivable of $965,000 for costs
incurred to assess property damage caused by Hurricane Ivan in
2004 to the Carbonate Trend pipeline. Although Williams believes
these costs to be recoverable under its property damage
insurance, it has not received approval from its insurer and it
is reasonably possible that the insurer will deny some or all of
this claim. If Williams is unable to recover these costs
from insurance we will recognize a loss for these costs as they
relate to the Carbonate Trend pipeline. This loss will be fully
allocated to our general partner.
Other. We are not currently a party to any legal
proceedings but are a party to various administrative and
regulatory proceedings that have arisen in the ordinary course
of our business. Management, including internal counsel,
currently believes that the ultimate resolution of the foregoing
matters, taken as a whole, and after consideration of amounts
accrued, insurance coverage or other indemnification
arrangements, will not have a material adverse effect upon our
future financial position.
|
|
Note 14. |
Segment Disclosures |
Our reportable segments are strategic business units that offer
different products and services. The segments are managed
separately because each segment requires different industry
knowledge, technology and marketing strategies. The accounting
policies of the segments are the same as those described in
Note 3, Summary of Significant Accounting Policies.
Long-lived assets are comprised of property, plant and equipment.
F-27
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering & | |
|
NGL | |
|
|
|
|
Processing | |
|
Services | |
|
Total | |
|
|
| |
|
| |
|
| |
|
|
(In thousands) | |
2003
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues
|
|
$ |
5,513 |
|
|
$ |
22,781 |
|
|
$ |
28,294 |
|
Operating and maintenance expense
|
|
|
379 |
|
|
|
13,581 |
|
|
|
13,960 |
|
Product cost
|
|
|
|
|
|
|
1,263 |
|
|
|
1,263 |
|
Depreciation and accretion
|
|
|
1,200 |
|
|
|
2,507 |
|
|
|
3,707 |
|
Direct general and administrative expenses
|
|
|
|
|
|
|
421 |
|
|
|
421 |
|
Other, net
|
|
|
|
|
|
|
507 |
|
|
|
507 |
|
|
|
|
|
|
|
|
|
|
|
Segment operating income
|
|
|
3,934 |
|
|
|
4,502 |
|
|
|
8,436 |
|
Equity earnings
|
|
|
3,447 |
|
|
|
|
|
|
|
3,447 |
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$ |
7,381 |
|
|
$ |
4,502 |
|
|
$ |
11,883 |
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated Statement of Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income
|
|
|
|
|
|
|
|
|
|
$ |
8,436 |
|
|
Allocated general and administrative expenses
|
|
|
|
|
|
|
|
|
|
|
(1,392 |
) |
|
|
|
|
|
|
|
|
|
|
|
Combined operating income
|
|
|
|
|
|
|
|
|
|
$ |
7,044 |
|
|
|
|
|
|
|
|
|
|
|
Other financial information:
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$ |
177,769 |
|
|
$ |
52,381 |
|
|
$ |
230,150 |
|
Equity method investments
|
|
|
156,269 |
|
|
|
|
|
|
|
156,269 |
|
Additions to long-lived assets
|
|
|
|
|
|
|
1,176 |
|
|
|
1,176 |
|
F-28
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering & | |
|
NGL | |
|
|
|
|
Processing | |
|
Services | |
|
Total | |
|
|
| |
|
| |
|
| |
|
|
(In thousands) | |
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues
|
|
$ |
4,833 |
|
|
$ |
36,143 |
|
|
$ |
40,976 |
|
Operating and maintenance expense
|
|
|
572 |
|
|
|
18,804 |
|
|
|
19,376 |
|
Product cost
|
|
|
|
|
|
|
6,635 |
|
|
|
6,635 |
|
Depreciation and accretion
|
|
|
1,200 |
|
|
|
2,486 |
|
|
|
3,686 |
|
Direct general and administrative expenses
|
|
|
|
|
|
|
535 |
|
|
|
535 |
|
Other, net
|
|
|
|
|
|
|
625 |
|
|
|
625 |
|
|
|
|
|
|
|
|
|
|
|
Segment operating income
|
|
|
3,061 |
|
|
|
7,058 |
|
|
|
10,119 |
|
Equity earnings
|
|
|
4,495 |
|
|
|
|
|
|
|
4,495 |
|
Impairment of investment
|
|
|
(13,484 |
) |
|
|
|
|
|
|
(13,484 |
) |
|
|
|
|
|
|
|
|
|
|
Segment profit (loss)
|
|
$ |
(5,928 |
) |
|
$ |
7,058 |
|
|
$ |
1,130 |
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated Statement of Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income
|
|
|
|
|
|
|
|
|
|
$ |
10,119 |
|
|
Allocated general and administrative expenses
|
|
|
|
|
|
|
|
|
|
|
(2,078 |
) |
|
|
|
|
|
|
|
|
|
|
|
Combined operating income
|
|
|
|
|
|
|
|
|
|
$ |
8,041 |
|
|
|
|
|
|
|
|
|
|
|
Other financial information:
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$ |
166,985 |
|
|
$ |
52,376 |
|
|
$ |
219,361 |
|
Equity method investments
|
|
|
147,281 |
|
|
|
|
|
|
|
147,281 |
|
Additions to long-lived assets
|
|
|
|
|
|
|
1,622 |
|
|
|
1,622 |
|
F-29
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering & | |
|
NGL | |
|
|
|
|
Processing | |
|
Services | |
|
Total | |
|
|
| |
|
| |
|
| |
|
|
(In thousands) | |
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues
|
|
$ |
3,515 |
|
|
$ |
48,254 |
|
|
$ |
51,769 |
|
Operating and maintenance expense
|
|
|
714 |
|
|
|
24,397 |
|
|
|
25,111 |
|
Product cost
|
|
|
|
|
|
|
11,821 |
|
|
|
11,821 |
|
Depreciation and accretion
|
|
|
1,200 |
|
|
|
2,419 |
|
|
|
3,619 |
|
Direct general and administrative expenses
|
|
|
2 |
|
|
|
1,068 |
|
|
|
1,070 |
|
Other, net
|
|
|
|
|
|
|
694 |
|
|
|
694 |
|
|
|
|
|
|
|
|
|
|
|
Segment operating income
|
|
|
1,599 |
|
|
|
7,855 |
|
|
|
9,454 |
|
Equity earnings
|
|
|
8,331 |
|
|
|
|
|
|
|
8,331 |
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$ |
9,930 |
|
|
$ |
7,855 |
|
|
$ |
17,785 |
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated Statement of Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income
|
|
|
|
|
|
|
|
|
|
$ |
9,454 |
|
|
General and administrative expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated affiliate
|
|
|
|
|
|
|
|
|
|
|
(3,194 |
) |
|
|
Third-party direct
|
|
|
|
|
|
|
|
|
|
|
(1,059 |
) |
|
|
|
|
|
|
|
|
|
|
|
Combined operating income
|
|
|
|
|
|
|
|
|
|
$ |
5,201 |
|
|
|
|
|
|
|
|
|
|
|
Other financial information:
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment assets
|
|
$ |
171,009 |
|
|
$ |
64,579 |
|
|
$ |
235,588 |
|
Other assets and eliminations
|
|
|
|
|
|
|
|
|
|
|
5,353 |
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
|
|
|
|
|
|
|
|
$ |
240,941 |
|
|
|
|
|
|
|
|
|
|
|
Equity method investments
|
|
$ |
150,260 |
|
|
$ |
|
|
|
$ |
150,260 |
|
Additions to long-lived assets
|
|
|
|
|
|
|
3,688 |
|
|
|
3,688 |
|
F-30
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering & | |
|
NGL | |
|
|
|
|
Processing | |
|
Services | |
|
Total | |
|
|
| |
|
| |
|
| |
|
|
(In thousands) | |
Three Months Ended March 31, 2005 (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues
|
|
$ |
880 |
|
|
$ |
10,489 |
|
|
$ |
11,369 |
|
|
Operating and maintenance expense
|
|
|
107 |
|
|
|
5,621 |
|
|
|
5,728 |
|
Product cost
|
|
|
|
|
|
|
2,735 |
|
|
|
2,735 |
|
Depreciation and accretion
|
|
|
300 |
|
|
|
605 |
|
|
|
905 |
|
Direct general and administrative expense
|
|
|
|
|
|
|
203 |
|
|
|
203 |
|
Taxes other than income
|
|
|
|
|
|
|
192 |
|
|
|
192 |
|
|
|
|
|
|
|
|
|
|
|
Segment operating income
|
|
|
473 |
|
|
|
1,133 |
|
|
|
1,606 |
|
Equity earnings
|
|
|
2,212 |
|
|
|
|
|
|
|
2,212 |
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$ |
2,685 |
|
|
$ |
1,133 |
|
|
$ |
3,818 |
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated Statements of Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income
|
|
|
|
|
|
|
|
|
|
$ |
1,606 |
|
|
Allocated general and administrative expense
|
|
|
|
|
|
|
|
|
|
|
(503 |
) |
|
|
|
|
|
|
|
|
|
|
|
Combined operating income
|
|
|
|
|
|
|
|
|
|
$ |
1,103 |
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2006 (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues
|
|
$ |
733 |
|
|
$ |
16,330 |
|
|
$ |
17,063 |
|
|
Operating and maintenance expense
|
|
|
242 |
|
|
|
7,449 |
|
|
|
7,691 |
|
Product cost
|
|
|
|
|
|
|
5,723 |
|
|
|
5,723 |
|
Depreciation and accretion
|
|
|
300 |
|
|
|
600 |
|
|
|
900 |
|
Direct general and administrative expense
|
|
|
2 |
|
|
|
301 |
|
|
|
303 |
|
Taxes other than income
|
|
|
|
|
|
|
207 |
|
|
|
207 |
|
|
|
|
|
|
|
|
|
|
|
Segment operating income
|
|
|
189 |
|
|
|
2,050 |
|
|
|
2,239 |
|
Equity earnings
|
|
|
3,781 |
|
|
|
|
|
|
|
3,781 |
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$ |
3,970 |
|
|
$ |
2,050 |
|
|
$ |
6,020 |
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated Statements of Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income
|
|
|
|
|
|
|
|
|
|
$ |
2,239 |
|
|
General and administrative expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated affiliate
|
|
|
|
|
|
|
|
|
|
|
(1,117 |
) |
|
|
Third party-direct
|
|
|
|
|
|
|
|
|
|
|
(528 |
) |
|
|
|
|
|
|
|
|
|
|
|
Combined operating income
|
|
|
|
|
|
|
|
|
|
$ |
594 |
|
|
|
|
|
|
|
|
|
|
|
F-31
WILLIAMS PARTNERS L.P.
QUARTERLY FINANCIAL DATA
(Unaudited)
Summarized quarterly financial data are as follows (thousands,
except per-unit amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First | |
|
Second | |
|
Third | |
|
Fourth | |
|
|
Quarter | |
|
Quarter | |
|
Quarter | |
|
Quarter | |
|
|
| |
|
| |
|
| |
|
| |
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
7,953 |
|
|
$ |
9,043 |
|
|
$ |
10,457 |
|
|
$ |
13,523 |
|
Costs and operating expenses
|
|
|
5,256 |
|
|
|
8,289 |
|
|
|
8,956 |
|
|
|
10,434 |
|
Income (loss) before cumulative effect of change in accounting
principle
|
|
|
1,569 |
|
|
|
(1,125 |
) |
|
|
(1,684 |
) |
|
|
(12,184 |
) |
Net income (loss)
|
|
|
1,569 |
|
|
|
(1,125 |
) |
|
|
(1,684 |
) |
|
|
(12,184 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First | |
|
Second | |
|
Third | |
|
Fourth | |
|
|
Quarter | |
|
Quarter | |
|
Quarter | |
|
Quarter | |
|
|
| |
|
| |
|
| |
|
| |
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
11,369 |
|
|
$ |
12,176 |
|
|
$ |
12,176 |
|
|
$ |
16,048 |
|
Costs and operating expenses
|
|
|
10,266 |
|
|
|
8,036 |
|
|
|
13,175 |
|
|
|
15,091 |
|
Income (loss) before cumulative effect of change in accounting
principle
|
|
|
311 |
|
|
|
1,849 |
|
|
|
(2,871 |
) |
|
|
6,170 |
|
Net income (loss)
|
|
|
311 |
|
|
|
1,849 |
|
|
|
(2,871 |
) |
|
|
5,542 |
|
Basic and diluted net income (loss) per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before cumulative effect of change in accounting
principle:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
|
NA |
|
|
|
NA |
|
|
$ |
(0.02 |
) |
|
$ |
0.51 |
|
|
|
Subordinated units
|
|
|
NA |
|
|
|
NA |
|
|
$ |
(0.02 |
) |
|
$ |
0.51 |
|
|
Cumulative effect of change in accounting principle:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
|
NA |
|
|
|
NA |
|
|
$ |
|
|
|
$ |
(0.05 |
) |
|
|
Subordinated units
|
|
|
NA |
|
|
|
NA |
|
|
$ |
|
|
|
$ |
(0.05 |
) |
|
Net income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
|
NA |
|
|
|
NA |
|
|
$ |
(0.02 |
) |
|
$ |
0.46 |
|
|
|
Subordinated units
|
|
|
NA |
|
|
|
NA |
|
|
$ |
(0.02 |
) |
|
$ |
0.46 |
|
|
|
|
|
|
Net income for fourth-quarter 2005 includes our 40 percent
share of Discoverys favorable adjustment of
$10.7 million related to amounts previously deferred for
net system gains from 2002 through 2004 that were reversed
following the acceptance in 2005 of a filing with the FERC. |
|
|
|
Net loss for third-quarter 2005 includes a $3.4 million
unfavorable product imbalance adjustments included in NGL
services. |
|
|
|
Net loss for fourth-quarter 2004 includes a $13.5 million
impairment of our investment in Discovery Producer Services (see
Note 6). |
F-32
REPORT OF INDEPENDENT AUDITORS
To the Management Committee of
Discovery Producer Services LLC
We have audited the accompanying consolidated balance sheets of
Discovery Producer Services LLC as of December 31, 2005 and
2004, and the related consolidated statements of income and
comprehensive income, members capital, and cash flows for
each of the three years in the period ended December 31,
2005. These financial statements are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with the auditing
standards generally accepted in the 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. We were not engaged to perform an
audit of the Companys internal control over financial
reporting. Our audits included consideration of internal control
over financial reporting as a basis for designing audit
procedures that are appropriate in the circumstances, but not
for the purpose of expressing an opinion on the effectiveness of
the Companys internal control over financial reporting.
Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by
management, and 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 consolidated
financial position of Discovery Producer Services LLC at
December 31, 2005 and 2004, and the consolidated results of
its operations and its cash flows for each of the three years in
the period ended December 31, 2005, in conformity with
accounting principles generally accepted in the
United States.
As described in Note 4, effective January 1, 2003,
Discovery Producer Services LLC adopted Statement of Financial
Accounting Standards No. 143, Accounting for Asset
Retirement Obligations.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
February 27, 2006
F-33
DISCOVERY PRODUCER SERVICES LLC
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, | |
|
March 31, | |
|
|
| |
|
| |
|
|
2004 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
|
|
|
(Unaudited) | |
|
|
(In thousands) | |
|
|
ASSETS |
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
55,222 |
|
|
$ |
21,378 |
|
|
$ |
34,286 |
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
4,399 |
|
|
|
31,448 |
|
|
|
8,759 |
|
|
|
Other
|
|
|
5,761 |
|
|
|
14,451 |
|
|
|
16,939 |
|
|
Inventory
|
|
|
840 |
|
|
|
924 |
|
|
|
867 |
|
|
Other current assets
|
|
|
1,312 |
|
|
|
2,324 |
|
|
|
1,849 |
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
67,534 |
|
|
|
70,525 |
|
|
|
62,700 |
|
Restricted cash
|
|
|
|
|
|
|
44,559 |
|
|
|
41,859 |
|
Property, plant and equipment, net
|
|
|
356,385 |
|
|
|
344,743 |
|
|
|
340,935 |
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$ |
423,919 |
|
|
$ |
459,827 |
|
|
$ |
445,494 |
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND MEMBERS CAPITAL |
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
$ |
682 |
|
|
$ |
9,334 |
|
|
$ |
5,875 |
|
|
|
Other
|
|
|
14,622 |
|
|
|
26,796 |
|
|
|
11,556 |
|
|
Accrued liabilities
|
|
|
14,197 |
|
|
|
6,205 |
|
|
|
6,726 |
|
|
Other current liabilities
|
|
|
2,071 |
|
|
|
2,735 |
|
|
|
3,318 |
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
31,572 |
|
|
|
45,070 |
|
|
|
27,475 |
|
Noncurrent accrued liabilities
|
|
|
702 |
|
|
|
1,121 |
|
|
|
1,146 |
|
Commitments and contingent liabilities (Note 7)
|
|
|
|
|
|
|
|
|
|
|
|
|
Members capital
|
|
|
391,645 |
|
|
|
413,636 |
|
|
|
416,873 |
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and members capital
|
|
$ |
423,919 |
|
|
$ |
459,827 |
|
|
$ |
445,494 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F-34
DISCOVERY PRODUCER SERVICES LLC
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended | |
|
|
Year Ended December 31, | |
|
March 31, | |
|
|
| |
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(In thousands) | |
|
(Unaudited) | |
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
$ |
54,145 |
|
|
$ |
57,838 |
|
|
$ |
70,848 |
|
|
$ |
14,909 |
|
|
$ |
44,259 |
|
|
|
Third-party
|
|
|
1,943 |
|
|
|
1,611 |
|
|
|
4,271 |
|
|
|
8 |
|
|
|
|
|
|
Gas and condensate transportation services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
4,611 |
|
|
|
3,966 |
|
|
|
1,908 |
|
|
|
930 |
|
|
|
2,641 |
|
|
|
Third-party
|
|
|
13,225 |
|
|
|
12,052 |
|
|
|
13,498 |
|
|
|
2,940 |
|
|
|
3,303 |
|
|
Gathering and processing services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
7,549 |
|
|
|
6,962 |
|
|
|
3,585 |
|
|
|
1,658 |
|
|
|
5,886 |
|
|
|
Third-party
|
|
|
16,974 |
|
|
|
14,168 |
|
|
|
26,133 |
|
|
|
6,202 |
|
|
|
5,258 |
|
|
Other revenues
|
|
|
4,731 |
|
|
|
3,279 |
|
|
|
2,502 |
|
|
|
642 |
|
|
|
773 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
103,178 |
|
|
|
99,876 |
|
|
|
122,745 |
|
|
|
27,289 |
|
|
|
62,120 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
7,832 |
|
|
|
423 |
|
|
|
7,911 |
|
|
|
4,685 |
|
|
|
2,307 |
|
|
|
Third-party
|
|
|
35,082 |
|
|
|
44,932 |
|
|
|
56,556 |
|
|
|
6,439 |
|
|
|
39,243 |
|
|
Operating and maintenance expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
3,035 |
|
|
|
3,098 |
|
|
|
3,355 |
|
|
|
780 |
|
|
|
918 |
|
|
|
Third-party
|
|
|
12,794 |
|
|
|
14,756 |
|
|
|
6,810 |
|
|
|
3,213 |
|
|
|
3,904 |
|
|
Depreciation and accretion
|
|
|
22,875 |
|
|
|
22,795 |
|
|
|
24,794 |
|
|
|
6,113 |
|
|
|
6,379 |
|
|
General and administrative expenses affiliate
|
|
|
1,400 |
|
|
|
1,424 |
|
|
|
2,053 |
|
|
|
500 |
|
|
|
690 |
|
|
Taxes other than income
|
|
|
1,602 |
|
|
|
1,382 |
|
|
|
1,151 |
|
|
|
314 |
|
|
|
287 |
|
|
Other net
|
|
|
(101 |
) |
|
|
(54 |
) |
|
|
(33 |
) |
|
|
(2 |
) |
|
|
(861 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
84,519 |
|
|
|
88,756 |
|
|
|
102,597 |
|
|
|
22,042 |
|
|
|
52,867 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
18,659 |
|
|
|
11,120 |
|
|
|
20,148 |
|
|
|
5,247 |
|
|
|
9,253 |
|
Interest expense
|
|
|
9,611 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
|
|
|
|
(550 |
) |
|
|
(1,685 |
) |
|
|
(284 |
) |
|
|
(626 |
) |
Foreign exchange loss
|
|
|
|
|
|
|
|
|
|
|
1,005 |
|
|
|
|
|
|
|
427 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle
|
|
|
9,048 |
|
|
|
11,670 |
|
|
|
20,828 |
|
|
|
5,531 |
|
|
|
9,452 |
|
Cumulative effect of change in accounting principle
|
|
|
(267 |
) |
|
|
|
|
|
|
(176 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
8,781 |
|
|
$ |
11,670 |
|
|
$ |
20,652 |
|
|
$ |
5,531 |
|
|
$ |
9,452 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow hedging activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Losses reclassified to earnings during year
|
|
$ |
5,196 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
Unrealized losses during year
|
|
|
(291 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income
|
|
|
4,905 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income
|
|
$ |
13,686 |
|
|
$ |
11,670 |
|
|
$ |
20,652 |
|
|
$ |
5,531 |
|
|
$ |
9,452 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F-35
DISCOVERY PRODUCER SERVICES LLC
CONSOLIDATED STATEMENT OF MEMBERS CAPITAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated | |
|
|
|
|
|
|
Williams | |
|
Duke Energy | |
|
|
|
Other | |
|
|
|
|
Williams | |
|
Operating | |
|
Field | |
|
Eni BB | |
|
Comprehensive | |
|
|
|
|
Energy LLC | |
|
Partners LLC | |
|
Services, LLC | |
|
Pipelines LLC | |
|
Income (Loss) | |
|
Total | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(In thousands) | |
Balance, December 31, 2002
|
|
$ |
58,541 |
|
|
$ |
|
|
|
$ |
39,028 |
|
|
$ |
19,515 |
|
|
$ |
(4,905 |
) |
|
$ |
112,179 |
|
|
Contributions
|
|
|
127,055 |
|
|
|
|
|
|
|
84,695 |
|
|
|
42,360 |
|
|
|
|
|
|
|
254,110 |
|
|
Net income 2003
|
|
|
4,391 |
|
|
|
|
|
|
|
2,927 |
|
|
|
1,463 |
|
|
|
|
|
|
|
8,781 |
|
|
Other comprehensive (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,905 |
|
|
|
4,905 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2003
|
|
|
189,987 |
|
|
|
|
|
|
|
126,650 |
|
|
|
63,338 |
|
|
|
|
|
|
|
379,975 |
|
|
Net income 2004
|
|
|
5,835 |
|
|
|
|
|
|
|
3,890 |
|
|
|
1,945 |
|
|
|
|
|
|
|
11,670 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2004
|
|
|
195,822 |
|
|
|
|
|
|
|
130,540 |
|
|
|
65,283 |
|
|
|
|
|
|
|
391,645 |
|
|
Contributions
|
|
|
16,269 |
|
|
|
24,400 |
|
|
|
7,634 |
|
|
|
|
|
|
|
|
|
|
|
48,303 |
|
|
Distributions
|
|
|
(30,030 |
) |
|
|
(1,280 |
) |
|
|
(15,654 |
) |
|
|
|
|
|
|
|
|
|
|
(46,964 |
) |
|
Net income 2005
|
|
|
8,063 |
|
|
|
4,651 |
|
|
|
6,909 |
|
|
|
1,029 |
|
|
|
|
|
|
|
20,652 |
|
|
Sale of Eni 16.67% interest to subsidiaries of Williams Energy
LLC
|
|
|
66,312 |
|
|
|
|
|
|
|
|
|
|
|
(66,312 |
) |
|
|
|
|
|
|
|
|
|
Sale of Williams Energy LLC and subsidiaries 40% interest to
Williams Operating Partners LLC
|
|
|
(142,761 |
) |
|
|
142,761 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sale of Williams Energy LLC 6.67% interest to Duke Energy Field
Services LLC
|
|
|
(25,869 |
) |
|
|
|
|
|
|
25,869 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2005
|
|
|
87,806 |
|
|
|
170,532 |
|
|
|
155,298 |
|
|
|
|
|
|
|
|
|
|
|
413,636 |
|
|
Contributions (unaudited)
|
|
|
|
|
|
|
|
|
|
|
7,383 |
|
|
|
|
|
|
|
|
|
|
|
7,383 |
|
|
Distributions (unaudited)
|
|
|
(4,798 |
) |
|
|
(4,400 |
) |
|
|
(4,400 |
) |
|
|
|
|
|
|
|
|
|
|
(13,598 |
) |
|
Net income three months ended March 31, 2006
(unaudited)
|
|
|
1,890 |
|
|
|
3,781 |
|
|
|
3,781 |
|
|
|
|
|
|
|
|
|
|
|
9,452 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, March 31, 2006 (unaudited)
|
|
$ |
84,898 |
|
|
$ |
169,913 |
|
|
$ |
162,062 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
416,873 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F-36
DISCOVERY PRODUCER SERVICES LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended | |
|
|
Year Ended December 31, | |
|
March 31, | |
|
|
| |
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(In thousands) | |
|
(Unaudited) | |
OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle
|
|
$ |
9,048 |
|
|
$ |
11,670 |
|
|
$ |
20,828 |
|
|
$ |
5,531 |
|
|
$ |
9,452 |
|
Adjustments to reconcile to cash provided by operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and accretion
|
|
|
22,875 |
|
|
|
22,795 |
|
|
|
24,794 |
|
|
|
6,113 |
|
|
|
6,379 |
|
|
Cash provided (used) by changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
7,860 |
|
|
|
(1,658 |
) |
|
|
(35,739 |
) |
|
|
(4,057 |
) |
|
|
20,201 |
|
|
|
Inventory
|
|
|
(229 |
) |
|
|
(240 |
) |
|
|
(84 |
) |
|
|
(138 |
) |
|
|
57 |
|
|
|
Other current assets
|
|
|
(761 |
) |
|
|
(1 |
) |
|
|
(1,012 |
) |
|
|
218 |
|
|
|
475 |
|
|
|
Accounts payable
|
|
|
(1,415 |
) |
|
|
1,256 |
|
|
|
29,355 |
|
|
|
(713 |
) |
|
|
(19,153 |
) |
|
|
Other current liabilities
|
|
|
2,223 |
|
|
|
(668 |
) |
|
|
664 |
|
|
|
443 |
|
|
|
583 |
|
|
|
Accrued liabilities
|
|
|
4,424 |
|
|
|
2,469 |
|
|
|
(7,992 |
) |
|
|
584 |
|
|
|
521 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
44,025 |
|
|
|
35,623 |
|
|
|
30,814 |
|
|
|
7,981 |
|
|
|
18,515 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(14,746 |
) |
|
|
(46,701 |
) |
|
|
(12,906 |
) |
|
|
(3,638 |
) |
|
|
(2,546 |
) |
|
Change in accounts payable capital expenditures
|
|
|
2,673 |
|
|
|
7,586 |
|
|
|
(8,532 |
) |
|
|
(3,459 |
) |
|
|
454 |
|
(Increase) decrease in restricted cash
|
|
|
|
|
|
|
|
|
|
|
(44,559 |
) |
|
|
|
|
|
|
2,700 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities
|
|
|
(12,073 |
) |
|
|
(39,115 |
) |
|
|
(65,997 |
) |
|
|
(7,097 |
) |
|
|
608 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments of long-term debt
|
|
|
(253,701 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions to members
|
|
|
|
|
|
|
|
|
|
|
(46,964 |
) |
|
|
|
|
|
|
(13,598 |
) |
|
Capital contributions
|
|
|
254,110 |
|
|
|
|
|
|
|
48,303 |
|
|
|
|
|
|
|
7,383 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
409 |
|
|
|
|
|
|
|
1,339 |
|
|
|
|
|
|
|
(6,215 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents
|
|
|
32,361 |
|
|
|
(3,492 |
) |
|
|
(33,844 |
) |
|
|
884 |
|
|
|
12,908 |
|
Cash and cash equivalents at beginning of period
|
|
|
26,353 |
|
|
|
58,714 |
|
|
|
55,222 |
|
|
|
55,222 |
|
|
|
21,378 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$ |
58,714 |
|
|
$ |
55,222 |
|
|
$ |
21,378 |
|
|
$ |
56,106 |
|
|
$ |
34,286 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Disclosure of Cash Flow Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid during the year for interest
|
|
$ |
9,855 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F-37
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
Note 1. |
Organization and Description of Business |
Our company consists of Discovery Producer Services LLC
(DPS), a Delaware limited liability company formed
on June 24, 1996, and its wholly owned subsidiary,
Discovery Gas Transmission LLC (DGT), a Delaware
limited liability company formed on June 24, 1996. DPS was
formed for the purpose of constructing and operating a
600 million cubic feet per day (MMcf/d)
cryogenic natural gas processing plant near Larose, Louisiana
and a 32,000 barrel per day (bpd) natural
gas liquids fractionator plant near Paradis, Louisiana. DGT was
formed for the purpose of constructing and operating a natural
gas pipeline from offshore deep water in the Gulf of Mexico to
DPSs gas processing plant in Larose, Louisiana. The
pipeline has a design capacity of 600 million cubic feet
per day and consists of approximately 173 miles of pipe.
DPS has since connected several laterals to the DGT pipeline to
expand its presence in the Gulf. Herein, DPS and DGT are
collectively referred to in the first person as we,
us or our and sometimes as the
Company.
Until April 14, 2005, we were owned 50 percent by
Williams Energy, L.L.C. (a wholly owned subsidiary of The
Williams Companies, Inc.), 33.33 percent by Duke Energy
Field Services, LP (Duke) and 16.67 percent by
Eni BB Pipeline, LLC (Eni) (formerly British-Borneo
Pipeline LLC). Williams Energy is our operator. Herein, The
Williams Companies, Inc. and its subsidiaries are collectively
referred to as Williams.
On April 14, 2005, Williams acquired the 16.67 percent
ownership interest in us previously held by Eni. As a result we
became 66.67 percent owned by Williams and
33.33 percent owned by Duke.
On August 22, 2005, we distributed cash of $44 million
to the members based on 66.67 percent ownership by Williams
and 33.33 percent ownership by Duke.
On August 23, 2005, Williams Partners Operating LLC (a
wholly owned subsidiary of Williams Partners L.P.)
(WPZ) acquired a 40 percent interest in us
previously held by Williams Energy. As a result we became
40 percent owned by WPZ, 26.67 percent owned by
Williams and 33.33 percent owned by Duke. In connection
with this Williams, Duke and WPZ amended our limited liability
company agreement including provisions for (1) quarterly
distributions of available cash, as defined in the amended
agreement and (2) pursuit of capital projects for the
benefit of one or more of our members when there is not
unanimous consent.
On December 22, 2005, Duke acquired 6.67 percent
interest in us previously held by Williams Energy. As a result
we became 40 percent owned by WPZ, 20 percent owned by
Williams and 40 percent owned by Duke.
|
|
Note 2. |
Summary of Significant Accounting Policies |
Basis of Presentation. The consolidated financial
statements have been prepared based upon accounting principles
generally accepted in the United States and include the accounts
of DPS and its wholly owned subsidiary, DGT. Intercompany
accounts and transactions have been eliminated.
The accompanying unaudited interim consolidated financial
statements include all normal recurring adjustments that, in the
opinion of our management, are necessary to present fairly our
financial position at March 31, 2006, and the results of
operations and cash flows for the three months ended
March 31, 2005 and 2006.
Reclassifications. Certain prior years amounts have been
reclassified to conform with the current year presentation.
These include the reclassification of certain costs charged by
Williams under operation and maintenance agreements. We have
reclassified these costs, which relate to accounting services,
computer systems and management services, to General and
administrative expenses affiliate on the
Consolidated Statements of Income.
F-38
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Use of Estimates. The preparation of consolidated
financial statements in conformity with accounting principles
generally accepted in the United States requires management to
make estimates and assumptions that affect the amounts reported
in the consolidated financial statements and accompanying notes.
Actual results could differ from those estimates.
Cash and Cash Equivalents. Cash and cash equivalents
include demand and time deposits, certificates of deposit and
other marketable securities with maturities of three months or
less when acquired.
Accounts Receivable. Accounts receivable are carried on a
gross basis, with no discounting, less an allowance for doubtful
accounts. No allowance for doubtful accounts is recognized at
the time the revenue that generates the accounts receivable is
recognized. We estimate the allowance for doubtful accounts
based on existing economic conditions, the financial condition
of the customers and the amount and age of past due accounts.
Receivables are considered past due if full payment is not
received by the contractual due date. Past due accounts are
generally written off against the allowance for doubtful
accounts only after all collection attempts have been exhausted.
There was no allowance for doubtful accounts at
December 31, 2005, and 2004.
Gas Imbalances. In the course of providing transportation
services to customers, DGT may receive different quantities of
gas from shippers than the quantities delivered on behalf of
those shippers. This results in gas transportation imbalance
receivables and payables which are recovered or repaid in cash,
based on market-based prices, or through the receipt or delivery
of gas in the future and are recorded in the balance sheet.
Settlement of imbalances requires agreement between the
pipelines and shippers as to allocations of volumes to specific
transportation contracts and the timing of delivery of gas based
on operational conditions. In accordance with its tariff, DGT is
required to account for this imbalance (cash-out)
liability/receivable and refund or invoice the excess or
deficiency when the cumulative amount exceeds $400,000. To the
extent that this difference, at any year end, is less than
$400,000 such amount would carry forward and be included in the
cumulative computation of the difference evaluated at the
following year end.
Inventory. Inventory includes fractionated products at
our Paradis facility and is carried at the lower cost of market.
Restricted Cash. Restricted cash within non-current
assets relates to escrow funds contributed by our members for
the construction of the Tahiti pipeline lateral expansion. The
restricted cash is classified as non-current because the funds
will be used to construct a long-term asset. The restricted cash
is primarily invested in short-term money market accounts with
financials institutions.
Property, Plant and Equipment. Property, plant and
equipment are carried at cost. We base the carrying value of
these assets on estimates, assumptions and judgments relative to
capitalized costs, useful lives and salvage values. The natural
gas and natural gas liquids maintained in the pipeline
facilities necessary for their operation (line fill) are
included in property, plant and equipment.
Depreciation for DPSs facilities and equipment is computed
primarily using the straight-line method with
25-year lives.
Depreciation for DGTs facilities and equipment is computed
using the straight-line method with
15-year lives.
We record an asset and a liability equal to the present value of
each expected future asset retirement obligation
(ARO). The ARO asset is depreciated in a manner
consistent with the depreciation of the underlying physical
asset. We measure changes in the liability due to passage of
time by applying an interest method of allocation. This amount
is recognized as an increase in the carrying amount of the
liability and as a corresponding accretion expense included in
operating income.
Revenue Recognition. Revenue for sales of products are
recognized in the period of delivery and revenues from the
gathering, transportation and processing of gas are recognized
in the period the service is provided based on contractual terms
and the related natural gas and liquid volumes. DGT is subject
to Federal
F-39
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Energy Regulatory Commission
(FERC) regulations, and accordingly, certain
revenues collected may be subject to possible refunds upon final
orders in pending cases. DGT records rate refund liabilities
considering regulatory proceedings by DGT and other third
parties, advice of counsel, and estimated total exposure as
discounted and risk weighted, as well as collection and other
risks. There were no rate refund liabilities accrued at
December 31, 2004 or 2005.
Derivative Instruments and Hedging Activities. The
accounting for changes in the fair value of a derivative depends
upon whether we have designated it in a hedging relationship
and, further, on the type of hedging relationship. To qualify
for designation in a hedging relationship, specific criteria
must be met and the appropriate documentation maintained in
accordance with Statement of Financial Accounting Standards
(SFAS) No. 133, Accounting for
Derivative Instruments and Hedging Activities, as amended.
We establish hedging relationships pursuant to our risk
management policies. We initially and regularly evaluate the
hedging relationships to determine whether they are expected to
be, and have been, highly effective hedges. If a derivative
ceases to be a highly effective hedge, hedge accounting is
discontinued prospectively, and future changes in the fair value
of the derivative are recognized in earnings each period.
We entered into interest rate swap agreements to reduce the
impact of changes in interest rates on our floating rate debt.
These instruments were designated as cash flow hedges under
SFAS No. 133. The effective portion of the change in
fair value of the derivatives is reported in other comprehensive
income and reclassified into earnings and included in interest
expense in the period in which the hedged item affects earnings.
There are no amounts excluded from the effectiveness
calculation, and there was no ineffective portion of the change
in fair value in 2003. The interest rate swap expired on
December 31, 2003, and we have no other derivative
instruments.
Impairment of Long-Lived Assets. We evaluate long-lived
assets for impairment on an individual asset or asset group
basis when events or changes in circumstances indicate, in our
managements judgment, that the carrying value of such
assets may not be recoverable. When such a determination has
been made, we compare our managements estimate of
undiscounted future cash flows attributable to the assets to the
carrying value of the assets to determine whether impairment has
occurred. If an impairment of the carrying value has occurred,
we determine the amount of the impairment recognized in the
financial statements by estimating the fair value of the assets
and recording a loss for the amount that the carrying value
exceeds the estimated fair value.
Judgments and assumptions are inherent in our managements
estimate of undiscounted future cash flows used to determine
recoverability of an asset and the estimate of an assets
fair value used to calculate the amount of impairment to
recognize. These judgments and assumptions include such matters
as the estimation of additional tie-ins of customers, strategic
value, rate adjustments, and capital expenditures. The use of
alternate judgments and/or assumptions could result in the
recognition of different levels of impairment charges in the
financial statements.
Accounting for Repair and Maintenance Costs. We expense
the cost of maintenance and repairs as incurred; significant
improvements are capitalized and depreciated over the remaining
useful life of the asset.
Capitalization of Interest. We capitalize interest on
major projects during construction. Interest is capitalized on
borrowed funds. Rates are based on the average interest rate on
debt.
Income Taxes. For federal tax purposes, we have elected
to be treated as a partnership with each member being separately
taxed on its ratable share of our taxable income. This election,
to be treated as a pass-through entity, also applies to our
wholly owned subsidiary, DGT. Therefore, no income taxes or
deferred income taxes are reflected in the consolidated
financial statements.
Foreign Currency Transactions. Transactions denominated
in currencies other than the functional currency are recorded
based on exchange rates at the time such transactions arise.
Subsequent changes in
F-40
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
exchange rates result in transaction gains or losses which are
reflected in the Consolidated Statements of Income.
Recent Accounting Standards. In December 2004, the
Financial Accounting Standards Board (FASB) issued
revised SFAS No. 123, Share-Based Payment.
The Statement requires that compensation costs for all
share-based awards to employees be recognized in the financial
statements at fair value. The Statement, as issued by the FASB,
was to be effective as of the beginning of the first interim or
annual reporting period that begins after June 15, 2005.
However, in April 2005, the Securities and Exchange Commission
(SEC) adopted a new rule that delayed the
effective date for revised SFAS No. 123 to the
beginning of the next fiscal year that begins after
June 15, 2005. We intend to adopt the revised Statement as
of January 1, 2006. Payroll costs directly charged to us by
Williams and general and administrative costs allocated to us by
Williams (see Note 3) will include such compensation costs
beginning January 1, 2006. Our adoption of this Statement
will not have a material impact on our Consolidated Financial
Statements.
In November 2004, the FASB issued SFAS No. 151,
Inventory Costs, an amendment of ARB No. 43,
Chapter 4, which will be applied prospectively for
inventory costs incurred in fiscal years beginning after
June 15, 2005. The Statement amends Accounting Research
Bulletin (ARB) No. 43, Chapter 4,
Inventory Pricing, to clarify that abnormal amounts
of certain costs should be recognized as current period charges
and that the allocation of overhead costs should be based on the
normal capacity of the production facility. The impact of this
Statement on our Consolidated Financial Statements will not be
material.
In December 2004, the FASB issued SFAS No. 153,
Exchanges of Nonmonetary Assets, an amendment of APB
Opinion No. 29, which is effective for nonmonetary
asset exchanges occurring in fiscal periods beginning after
June 15, 2005, and will be applied prospectively. The
Statement amends APB Opinion No. 29, Accounting for
Nonmonetary Transactions. The guidance in APB Opinion
No. 29 is based on the principle that exchanges of
nonmonetary assets should be measured based on the fair value of
the assets exchanged but includes certain exceptions to that
principle. SFAS No. 153 amends APB Opinion No. 29
to eliminate the exception for nonmonetary exchanges of similar
productive assets and replaces it with a general exception for
exchanges of nonmonetary assets that do not have commercial
substance. A nonmonetary exchange has commercial substance if
the future cash flows of the entity are expected to change
significantly as a result of the exchange.
In May 2005, the FASB issued SFAS No. 154,
Accounting Changes and Error Corrections a
replacement of APB Opinion No. 20 and FASB Statement
No. 3, which is effective prospectively for reporting
a change in accounting principle for fiscal years beginning
after December 15, 2005. The Statement changes the
reporting of a change in accounting principle to require
retrospective application to prior periods financial
statements, except for explicit transition provisions provided
for in any existing accounting pronouncements, including those
in the transition phase when SFAS No. 154 becomes
effective.
|
|
Note 3. |
Related Party Transactions |
We have no employees. Pipeline and plant operations were
performed under operation and maintenance agreements with
Williams. Under this agreement, we reimburse Williams for direct
payroll and employee benefit costs incurred on our behalf. Most
costs for materials, services and other charges are third-party
charges and are invoiced directly to us. Additionally, we
purchase a portion of the natural gas from Williams to meet our
fuel and shrink requirements at our processing plant. These
costs are presented as Operating and maintenance
expenses affiliate and Product costs and shrink
replacement affiliate on the Consolidated Statements
of Income.
We pay Williams a monthly operation and management fee to cover
the cost of accounting services, computer systems and management
services provided to us. This fee is presented as General and
administrative expenses affiliate on the
Consolidated Statements of Income.
F-41
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
We also pay Williams a project management fee to cover the cost
of managing capital projects. This fee is determined on a
project by project basis and is capitalized as part of the
construction costs.
A summary of the payroll costs and project fees charged to us by
Williams and capitalized are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, | |
|
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
|
| |
|
| |
|
| |
Capitalized labor
|
|
$ |
204 |
|
|
$ |
288 |
|
|
$ |
351 |
|
Capitalized project fee
|
|
|
147 |
|
|
|
854 |
|
|
|
115 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
351 |
|
|
$ |
1,142 |
|
|
$ |
466 |
|
|
|
|
|
|
|
|
|
|
|
We have various business transactions with our members and other
subsidiaries and affiliates of our members, including an
agreement with Williams pursuant to which Williams markets the
NGLs and natural gas to which we take title. Under the terms of
this agreement, Williams purchases the NGLs and excess natural
gas and resells it, for its own account, to end users. During
2005, we had transactions with Texas Eastern Corporation, a
subsidiary of Duke. These transactions primarily included
processing and sales of natural gas liquids and transportation
of gas and condensate. We have business transactions with Eni
that primarily include processing and transportation of gas and
condensate. The following table summarizes these related-party
revenues during 2003, 2004 and 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, | |
|
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
|
| |
|
| |
|
| |
|
|
(In thousands) | |
Eni*
|
|
$ |
12,160 |
|
|
$ |
10,928 |
|
|
$ |
2,830 |
|
Texas Eastern Corporation
|
|
|
|
|
|
|
|
|
|
|
2,663 |
|
Williams
|
|
|
54,145 |
|
|
|
57,838 |
|
|
|
70,848 |
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
66,305 |
|
|
$ |
68,766 |
|
|
$ |
76,341 |
|
|
|
|
|
|
|
|
|
|
|
Note 4. Property, Plant and
Equipment
Property, plant and equipment consisted of the following at
December 31, 2004 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2005 | |
|
|
| |
|
| |
|
|
(In thousands) | |
Property, plant and equipment:
|
|
|
|
|
|
|
|
|
|
Construction work in progress
|
|
$ |
11,739 |
|
|
$ |
5,444 |
|
|
Buildings
|
|
|
4,393 |
|
|
|
4,406 |
|
|
Land and land rights
|
|
|
1,165 |
|
|
|
1,530 |
|
|
Transportation lines
|
|
|
286,661 |
|
|
|
302,252 |
|
|
Plant and other equipment
|
|
|
195,429 |
|
|
|
198,837 |
|
|
|
|
|
|
|
|
|
|
|
499,387 |
|
|
|
512,469 |
|
Less accumulated depreciation and amortization
|
|
|
143,002 |
|
|
|
167,726 |
|
|
|
|
|
|
|
|
|
|
$ |
356,385 |
|
|
$ |
344,743 |
|
|
|
|
|
|
|
|
Commitments for construction and acquisition of property, plant
and equipment for Tahiti are approximately $64 million at
December 31, 2005.
F-42
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
We adopted SFAS No. 143, Accounting for Asset
Retirement Obligations on January 1, 2003. As a
result, we recorded a liability of $549,000 representing the
present value of expected future asset retirement obligations at
January 1, 2003, and a decrease to earnings of $267,000
reflected as a cumulative effect of a change in accounting
principle.
Effective December 31, 2005, we adopted Financial
Accounting Standards Board Interpretation (FIN)
No. 47, Accounting for Conditional Asset Retirement
Obligations. This Interpretation clarifies that an entity
is required to recognize a liability for the fair value of a
conditional ARO when incurred if the liabilitys fair value
can be reasonably estimated. The Interpretation clarifies when
an entity would have sufficient information to reasonably
estimate the fair value of an ARO. As required by the new
standard, we reassessed the estimated remaining life of all our
assets with a conditional ARO. We recorded additional
liabilities totaling $327,000 equal to the present value of
expected future asset retirement obligations at
December 31, 2005. The liabilities are slightly offset by a
$151,000 increase in property, plant and equipment, net of
accumulated depreciation, recorded as if the provisions of the
Interpretation had been in effect at the date the obligation was
incurred. The net $176,000 reduction to earnings is reflected as
a cumulative effect of a change in accounting principle for the
year ended 2005. If the Interpretation had been in effect at the
beginning of 2003, the impact to our income from continuing
operations and net income would have been immaterial.
The obligations relate to an offshore platform and our onshore
processing and fractionation facilities. At the end of the
useful life of each respective asset, we are legally or
contractually obligated to dismantle the offshore platform,
remove the onshore facilities and related surface equipment and
restore the surface of the property.
A rollforward of our asset retirement obligation for 2004 and
2005 is presented below.
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2005 | |
|
|
| |
|
| |
|
|
(In thousands) | |
Balance, January 1
|
|
$ |
621 |
|
|
$ |
702 |
|
Accretion expense
|
|
|
81 |
|
|
|
92 |
|
FIN No. 47 revisions
|
|
|
|
|
|
|
327 |
|
|
|
|
|
|
|
|
Balance, December 31
|
|
$ |
702 |
|
|
$ |
1,121 |
|
|
|
|
|
|
|
|
|
|
Note 5. |
Leasing Activities |
We lease the land on which the Paradis fractionator plant and
the Larose processing plant are located. The initial terms of
the leases are 20 years with renewal options for an
additional 30 years. We entered into a 10 year leasing
agreement for pipeline capacity from Texas Eastern Transmission,
LP, as part of our Market Expansion project which began in June
2005 (see Note 7). The lease includes renewal options and
options to increase capacity which would also increase rentals.
The future minimum annual rentals under these non-cancelable
leases as of December 31, 2005 are payable as follows:
|
|
|
|
|
|
|
(In thousands) | |
2006
|
|
$ |
854 |
|
2007
|
|
|
854 |
|
2008
|
|
|
858 |
|
2009
|
|
|
858 |
|
2010
|
|
|
858 |
|
Thereafter
|
|
|
4,109 |
|
|
|
|
|
|
|
$ |
8,391 |
|
|
|
|
|
F-43
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Total rent expense for 2003, 2004 and 2005, including a
cancelable platform space lease and
month-to-month leases,
was $1,050,000, $866,000 and $994,610, respectively.
|
|
Note 6. |
Financial Instruments and Concentrations of Credit Risk |
|
|
|
Financial Instruments Fair Value |
We used the following methods and assumptions to estimate the
fair value of financial instruments:
Cash and cash equivalents. The carrying amounts reported
in the balance sheets approximate fair value due to the
short-term maturity of these instruments.
Restricted cash. The carrying amounts reported in the
balance sheets approximate fair value as these instruments have
interest rates approximating market.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2005 | |
|
|
| |
|
| |
|
|
Carrying | |
|
Fair | |
|
Carrying | |
|
Fair | |
Asset |
|
Amount | |
|
Value | |
|
Amount | |
|
Value | |
|
|
| |
|
| |
|
| |
|
| |
|
|
(In thousands) | |
Cash and cash equivalents
|
|
$ |
55,222 |
|
|
$ |
55,222 |
|
|
$ |
21,378 |
|
|
$ |
21,378 |
|
Restricted cash
|
|
|
|
|
|
|
|
|
|
|
44,559 |
|
|
|
44,559 |
|
|
|
|
Concentrations of Credit Risk |
Our cash equivalents and restricted cash consist of high-quality
securities placed with various major financial institutions with
credit ratings at or above AA by Standard & Poors
or Aa by Moodys Investors Service.
Substantially all of our accounts receivable result from gas
transmission services for and natural gas liquids sales to our
two largest customers at December 31, 2005 and 2004. This
concentration of customers may impact our overall credit risk
either positively or negatively, in that these entities may be
similarly affected by industry-wide changes in economic or other
conditions. As a general policy, collateral is not required for
receivables, but customers financial condition and credit
worthiness are evaluated regularly. Our credit policy and the
relatively short duration of receivables mitigate the risk of
uncollected receivables. We did not incur any credit losses on
receivables during 2005 and 2004.
Major Customers. Three customers, Williams, Eni and Pogo
Producing Company accounted for approximately $54 million
(52 percent), $12.2 million (12 percent) and
$12 million (12 percent), respectively, of our total
revenues in 2003. Williams and Eni accounted for approximately
$57.8 million (58 percent) and $10.9 million
(11 percent), respectively, of our total revenues in 2004,
and $70.8 million (58 percent) and $8.5 million
(7 percent), respectively, of our total revenues in 2005.
F-44
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
Note 7. |
Rate and Regulatory Matters and Contingent Liabilities |
Rate and Regulatory Matters. In 2002, DGT filed a request
with the FERC to change the lost and unaccounted-for gas
percentage to be allocated to shippers from 0.5 percent to
0.1 percent to be effective for the period from
July 1, 2002 to June 30, 2003. On June 26, 2002,
the FERC approved DGTs request. Additionally, DGT filed to
reduce the lost and unaccounted-for gas percentage to zero to be
effective for the period from July 1, 2003 to June 30,
2004. On June 19, 2003, the FERC approved this request. On
June 1, 2004, DGT filed to maintain a lost and
unaccounted-for percentage of zero for the period from
July 1, 2004 to June 30, 2005 due to the continued
absence of system gas losses. On June 22, 2004, the FERC
approved this request. In this filing, DGT explained that
management determined the reasons for the gas gains and
established new procedures in July 2003 that significantly
reduced the amount of gains occurring thereafter. On
April 28, 2005, DGT filed to maintain a lost and
unaccounted-for gas percentage of zero for the period from
July 1, 2005 to June 30, 2006. DGT also filed to
retain net system gains that are unrelated to the lost and
unaccounted-for gas over-recovered from its shippers. These
system gas gains totaled approximately $0.4 million at
March 31, 2006 (unaudited) and $2.5 million,
$2.5 million and $5.5 million respectively in 2005,
2004, and 2003. Certain shippers protested the net system gains
filing and the FERC requested additional information in a
May 27, 2005 Letter Order. DGT responded to the information
request and on October 31, 2005, the FERC accepted the
filing and no requests for rehearing were filed. As a result, we
recognized system gains for 2002 2004 of
$10.7 million in 2005. As of March 31, 2006
(unaudited) December 31, 2005 and 2004, DGT has deferred
amounts of $6.4 million, $6 million and
$14.2 million, respectively, included in current accrued
liabilities in the accompanying Consolidated Balance Sheets
representing amounts collected from customers pursuant to prior
years lost and unaccounted for gas percentage and
unrecognized net system gains for 2005.
On July 23, 2003, DGT applied to the FERC for a Certificate
of Public Convenience and Necessity authorizing DGTs
market expansion to acquire, lease or construct and/or to own
and operate certain new delivery points, pipeline, compression
services and metering and appurtenant facilities to enable DGT
to deliver natural gas to four additional delivery points to new
markets in southern Louisiana. This application was amended on
December 30, 2003. On the same dates, DPS applied to the
FERC and amended its application for a Limited Jurisdiction
Certificate authorizing DPS to provide the compression services
to DGT to enable DGT to provide service through the Market
Expansion facilities. The capital cost of the expansion
facilities was approximately $11 million. On May 6,
2004, the FERC granted DGTs and DPSs applications.
On July 13, 2004, the FERC granted an additional approval
on a rate design issue requested by DGT. On January 6,
2005, the FERC granted DGT permission to commence construction
of the Market Expansion facilities. The Market Expansion
facilities became operational in June 2005.
On November 25, 2003, the FERC issued Order No. 2004
promulgating new standards of conduct applicable to natural gas
pipelines. On August 10, 2004, the FERC granted DGT a
partial exemption allowing the continuation of DGTs
current ownership structure and management subject to compliance
with many of the other standards of conduct. DGT continues to
evaluate the effect of the partial exemption and the compliance
with the remaining requirements. The effect of complying with
the new standards is not expected to have a material effect on
the consolidated financial statements.
On October 11, 2005, DGT applied to the FERC for permission
to construct and operate facilities to allow temporary
re-routing of gas to DGT from other facilities that were
impacted by Hurricane Katrina. The FERC granted emergency
exemptions and waivers permitting such actions the same day,
allowing emergency service for up to one year or until certain
third-party processing facilities were restored to service. DGT
conducted two open seasons for shippers wishing to take
advantage of the new service.
On January 16, 2006, DPS and DGT received notice of a claim
by POGO Producing Company (POGO) relating to the
results of a POGO audit performed in April 2004. POGO claims
that DPS and DGT overcharged POGO and its working interest
owners approximately $600,000 relating to condensate
F-45
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
transportation and handling during 2000 2004. The
underlying agreements limit audit claims to a two-year period
from the date of the audit, and DPS and DGT dispute the validity
of the claim. POGO dropped the condensate transportation claim
and has extended the audit period to 2005 on the condensate
handling claim which POGO is conducting now.
Environmental Matters. We are subject to extensive
federal, state and local environmental laws and regulations
which affect our operations related to the construction and
operation of our facilities. Appropriate governmental
authorities may enforce these laws and regulations with a
variety of civil and criminal enforcement measures, including
monetary penalties, assessment and remediation requirements and
injunctions as to future compliance. We have not been notified
and are not currently aware of any noncompliance under the
various environmental laws and regulations.
Other. We are party to various other claims, legal
actions and complaints arising in the ordinary course of
business. Litigation, arbitration and environmental matters are
subject to inherent uncertainties. Were an unfavorable ruling to
occur, there exists the possibility of a material adverse impact
on the results of operations in the period in which the ruling
occurs. Management, including internal counsel, currently
believes that the ultimate resolution of the foregoing matters,
taken as a whole, and after consideration of amounts accrued,
insurance coverage or other indemnification arrangements, will
not have a material adverse effect upon our future financial
position.
F-46
REPORT OF INDEPENDENT AUDITORS
The Board of Directors of
The Williams Companies, Inc.
We have audited the accompanying balance sheets of Williams Four
Corners Predecessor as of December 31, 2005 and 2004, and
the related statements of income, owners equity and cash
flows for each of the three years in the period ended
December 31, 2005. These financial statements are the
responsibility of The Williams Companies, Inc.s
management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards
generally accepted in the 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. We were not engaged to perform an audit
of the Williams Four Corners Predecessors internal control
over financial reporting. Our audits included consideration of
internal control over financial reporting as a basis for
designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion
on the effectiveness of the Williams Four Corners
Predecessors internal control over financial reporting.
Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by
management, and 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 Williams Four Corners Predecessor at December 31, 2005
and 2004, and the results of its operations and its cash flows
for each of the three years in the period ended
December 31, 2005, in conformity with accounting principles
generally accepted in the United States.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
March 31, 2006
F-47
WILLIAMS FOUR CORNERS PREDECESSOR
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, | |
|
|
|
|
| |
|
March 31, | |
|
|
2004 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
|
|
|
|
|
(Unaudited) | |
|
|
(In thousands) | |
ASSETS |
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trade, less allowance of $1,326 in 2004, $0 in 2005
|
|
$ |
15,599 |
|
|
$ |
15,855 |
|
|
$ |
16,356 |
|
|
|
Other
|
|
|
250 |
|
|
|
1,368 |
|
|
|
1,383 |
|
|
Product imbalance
|
|
|
7,548 |
|
|
|
|
|
|
|
|
|
|
Prepaid expenses current
|
|
|
1,530 |
|
|
|
1,609 |
|
|
|
1,609 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
24,927 |
|
|
|
18,832 |
|
|
|
19,348 |
|
Property, plant and equipment, net
|
|
|
601,710 |
|
|
|
591,034 |
|
|
|
585,470 |
|
Prepaid expenses noncurrent
|
|
|
18,657 |
|
|
|
25,228 |
|
|
|
24,825 |
|
Other noncurrent assets
|
|
|
|
|
|
|
|
|
|
|
595 |
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$ |
645,294 |
|
|
$ |
635,094 |
|
|
$ |
630,238 |
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND OWNERS EQUITY |
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable trade
|
|
$ |
17,080 |
|
|
$ |
21,666 |
|
|
$ |
13,942 |
|
|
Product imbalance
|
|
|
|
|
|
|
2,525 |
|
|
|
148 |
|
|
Accrued liabilities
|
|
|
7,058 |
|
|
|
3,787 |
|
|
|
4,239 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
24,138 |
|
|
|
27,978 |
|
|
|
18,329 |
|
Other noncurrent liabilities
|
|
|
626 |
|
|
|
1,526 |
|
|
|
1,118 |
|
Commitments and contingent liabilities (Note 10)
|
|
|
|
|
|
|
|
|
|
|
|
|
Owners equity
|
|
|
620,530 |
|
|
|
605,590 |
|
|
|
610,791 |
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and owners equity
|
|
$ |
645,294 |
|
|
$ |
635,094 |
|
|
$ |
630,238 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to financial statements.
F-48
WILLIAMS FOUR CORNERS PREDECESSOR
STATEMENTS OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended | |
|
|
Year Ended December 31, | |
|
March 31, | |
|
|
| |
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
|
|
|
|
|
|
(Unaudited) | |
|
|
(In thousands) | |
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
$ |
122,762 |
|
|
$ |
199,210 |
|
|
$ |
222,620 |
|
|
$ |
50,735 |
|
|
$ |
52,255 |
|
|
|
Third-party
|
|
|
1,611 |
|
|
|
5,658 |
|
|
|
8,665 |
|
|
|
1,210 |
|
|
|
2,792 |
|
|
Gathering and processing services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
24,839 |
|
|
|
30,990 |
|
|
|
36,755 |
|
|
|
8,728 |
|
|
|
9,933 |
|
|
|
Third-party
|
|
|
202,993 |
|
|
|
190,949 |
|
|
|
194,978 |
|
|
|
47,158 |
|
|
|
50,643 |
|
|
Other revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
1,488 |
|
|
|
924 |
|
|
|
15 |
|
|
|
7 |
|
|
|
|
|
|
|
Third-party
|
|
|
441 |
|
|
|
492 |
|
|
|
170 |
|
|
|
65 |
|
|
|
49 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
354,134 |
|
|
|
428,223 |
|
|
|
463,203 |
|
|
|
107,903 |
|
|
|
115,672 |
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
44,334 |
|
|
|
58,193 |
|
|
|
58,780 |
|
|
|
13,009 |
|
|
|
21,380 |
|
|
|
Third-party
|
|
|
46,994 |
|
|
|
88,135 |
|
|
|
106,926 |
|
|
|
23,425 |
|
|
|
16,897 |
|
|
Operating and maintenance expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
26,569 |
|
|
|
29,982 |
|
|
|
32,816 |
|
|
|
9,084 |
|
|
|
11,686 |
|
|
|
Third-party
|
|
|
63,214 |
|
|
|
67,088 |
|
|
|
71,832 |
|
|
|
16,562 |
|
|
|
17,409 |
|
|
Depreciation and amortization
|
|
|
41,552 |
|
|
|
40,675 |
|
|
|
38,960 |
|
|
|
9,726 |
|
|
|
9,814 |
|
|
General and administrative expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
23,105 |
|
|
|
27,414 |
|
|
|
29,579 |
|
|
|
7,154 |
|
|
|
5,866 |
|
|
|
Third-party
|
|
|
997 |
|
|
|
2,152 |
|
|
|
1,713 |
|
|
|
626 |
|
|
|
772 |
|
|
Taxes other than income
|
|
|
6,822 |
|
|
|
6,790 |
|
|
|
7,746 |
|
|
|
2,185 |
|
|
|
2,076 |
|
|
Other net
|
|
|
11,800 |
|
|
|
11,238 |
|
|
|
636 |
|
|
|
237 |
|
|
|
(3,643 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
265,387 |
|
|
|
331,667 |
|
|
|
348,988 |
|
|
|
82,008 |
|
|
|
82,257 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle
|
|
|
88,747 |
|
|
|
96,556 |
|
|
|
114,215 |
|
|
|
25,895 |
|
|
|
33,415 |
|
Cumulative effect of change in accounting principle
|
|
|
(330 |
) |
|
|
|
|
|
|
(694 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
88,417 |
|
|
$ |
96,556 |
|
|
$ |
113,521 |
|
|
$ |
25,895 |
|
|
$ |
33,415 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to financial statements.
F-49
WILLIAMS FOUR CORNERS PREDECESSOR
STATEMENT OF OWNERS EQUITY
(In thousands)
|
|
|
|
|
|
Balance, December 31, 2002.
|
|
$ |
671,709 |
|
|
Net income 2003.
|
|
|
88,417 |
|
|
Distributions to The Williams Companies, Inc. net
|
|
|
(115,685 |
) |
|
|
|
|
|
Balance, December 31, 2003.
|
|
|
644,441 |
|
|
Net income 2004.
|
|
|
96,556 |
|
|
Distributions to The Williams Companies, Inc. net
|
|
|
(120,467 |
) |
|
|
|
|
|
Balance, December 31, 2004.
|
|
|
620,530 |
|
|
Net income 2005.
|
|
|
113,521 |
|
|
Distributions to The Williams Companies, Inc. net
|
|
|
(128,461 |
) |
|
|
|
|
|
Balance, December 31, 2005.
|
|
|
605,590 |
|
|
|
|
|
|
Net income three months ended March 31, 2006
(unaudited)
|
|
|
33,415 |
|
|
Distributions to The Williams Companies, Inc. net
(unaudited)
|
|
|
(28,214 |
) |
|
|
|
|
|
Balance, March 31, 2006 (unaudited)
|
|
$ |
610,791 |
|
|
|
|
|
See accompanying notes to financial statements.
F-50
WILLIAMS FOUR CORNERS PREDECESSOR
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months | |
|
|
Year Ended December 31, | |
|
Ended March 31, | |
|
|
| |
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
|
|
|
|
|
|
(Unaudited) | |
|
|
(In thousands) | |
OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle
|
|
$ |
88,747 |
|
|
$ |
96,556 |
|
|
$ |
114,215 |
|
|
$ |
25,895 |
|
|
$ |
33,415 |
|
Adjustments to reconcile to cash provided by operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
41,552 |
|
|
|
40,675 |
|
|
|
38,960 |
|
|
|
9,726 |
|
|
|
9,814 |
|
|
Provision for loss on property, plant and equipment
|
|
|
7,598 |
|
|
|
7,636 |
|
|
|
917 |
|
|
|
|
|
|
|
|
|
|
(Gain)/loss on sale of property, plant and equipment
|
|
|
(1,151 |
) |
|
|
1,258 |
|
|
|
|
|
|
|
|
|
|
|
(3,319 |
) |
|
Cash provided (used) by changes in current assets and
liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(279 |
) |
|
|
1,298 |
|
|
|
(1,374 |
) |
|
|
2,463 |
|
|
|
(516 |
) |
|
|
Prepaid expenses
|
|
|
(1,530 |
) |
|
|
|
|
|
|
(79 |
) |
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
|
(3,266 |
) |
|
|
9,435 |
|
|
|
4,586 |
|
|
|
(5,758 |
) |
|
|
(7,724 |
) |
|
|
Product imbalance
|
|
|
(4,447 |
) |
|
|
(7,983 |
) |
|
|
10,073 |
|
|
|
4,483 |
|
|
|
(2,377 |
) |
|
|
Accrued liabilities
|
|
|
61 |
|
|
|
(5,047 |
) |
|
|
(3,271 |
) |
|
|
514 |
|
|
|
451 |
|
Other, including changes in other noncurrent assets and
liabilities
|
|
|
(5,019 |
) |
|
|
(9,441 |
) |
|
|
(7,988 |
) |
|
|
(296 |
) |
|
|
(280 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
122,266 |
|
|
|
134,387 |
|
|
|
156,039 |
|
|
|
37,027 |
|
|
|
29,464 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(8,079 |
) |
|
|
(14,069 |
) |
|
|
(27,578 |
) |
|
|
(2,540 |
) |
|
|
(8,450 |
) |
|
Proceeds from sales of property, plant and equipment
|
|
|
1,498 |
|
|
|
149 |
|
|
|
|
|
|
|
|
|
|
|
7,200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities
|
|
|
(6,581 |
) |
|
|
(13,920 |
) |
|
|
(27,578 |
) |
|
|
(2,540 |
) |
|
|
(1,250 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions to The Williams Companies, Inc. net
|
|
|
(115,685 |
) |
|
|
(120,467 |
) |
|
|
(128,461 |
) |
|
|
(34,487 |
) |
|
|
(28,214 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by financing activities
|
|
|
(115,685 |
) |
|
|
(120,467 |
) |
|
|
(128,461 |
) |
|
|
(34,487 |
) |
|
|
(28,214 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in cash and cash equivalents
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at beginning of year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to financial statements.
F-51
WILLIAMS FOUR CORNERS PREDECESSOR
NOTES TO FINANCIAL STATEMENTS
Note 1. Basis of Presentation
The accompanying financial statements and related notes present
the financial position, results of operations, cash flows and
owners equity of a natural gas gathering and processing
system in the Four Corners area of the United States held by
Williams Field Services Company (WFSC). This system
is collectively referred to as the Four Corners
system. WFSC is a wholly owned subsidiary of The Williams
Companies, Inc. (Williams). In February 2006, WFSC
was converted into a limited liability company and was renamed
Williams Field Services Company, LLC (WFSC LLC).
Also in November 2005, WFSC LLC formed a new entity, Williams
Four Corners LLC (WFC LLC), and in the second
quarter of 2006, WFSC conveyed the Four Corners assets to it.
These financial statements are prepared in connection with the
proposed acquisition of a 25.1 percent interest in WFC LLC
by Williams Partners L.P. (the Partnership). All
significant intercompany transactions have been eliminated.
The accompanying unaudited interim financial statements include
all normal recurring adjustments that, in the opinion of our
management, are necessary to present fairly our financial
position at March 31, 2006, and the results of operations
and cash flows for the three months ended March 31, 2005
and 2006.
Note 2. Description of
Business
We operate a natural gas gathering and processing system in New
Mexico and Colorado. This gathering and processing system
includes natural gas gathering pipelines, treating plants and
processing plants. WFC LLC includes 3,500 miles of natural gas
gathering pipelines with a capacity of approximately two billion
cubic feet per day (Bcfd). The system has total
compression of approximately 400,000 horsepower. The assets
include two natural gas treating plants (Milagro and Esperanza)
with a combined carbon dioxide treating capacity of
750 million cubic feet per day (MMcfd) and
three natural gas processing plants: Ignacio, Kutz, and Lybrook.
The Ignacio plant has an inlet capacity of 450 MMcfd and can
produce approximately 22,000 barrels per day (bpd)
of natural gas liquids (NGLs). The Kutz and Lybrook
plants have a combined capacity of 310 MMcfd and can produce
approximately 19,000 bpd of NGLs.
Note 3. Summary of Significant
Accounting Policies
Use of Estimates. The preparation of financial statements
in conformity with accounting principles generally accepted in
the United States requires management to make estimates and
assumptions that affect the amounts reported in the financial
statements and accompanying notes. Actual results could differ
from those estimates.
Estimates and assumptions which, in the opinion of management,
are significant to the underlying amounts included in the
financial statements and for which it would be reasonably
possible that future events or information could change those
estimates include:
|
|
|
|
|
impairment assessments of long-lived assets; |
|
|
|
loss contingencies; |
|
|
|
asset retirement obligations; and |
|
|
|
environmental remediation obligations. |
These estimates are discussed further throughout the
accompanying notes.
Accounts Receivable. Accounts receivable are carried on a
gross basis, with no discounting, less an allowance for doubtful
accounts. No allowance for doubtful accounts is recognized at
the time the revenue which generates the accounts receivable is
recognized. We estimate the allowance for doubtful accounts
based on existing economic conditions, the financial condition
of our customers and the amount and age of past due
F-52
WILLIAMS FOUR CORNERS PREDECESSOR
NOTES TO FINANCIAL STATEMENTS (Continued)
accounts. Receivables are considered past due if full payment is
not received by the contractual due date. Past due accounts are
generally written off against the allowance for doubtful
accounts only after all collection attempts have been
unsuccessful.
Product Imbalances. In the course of providing gathering,
processing and treating services to our customers, we realize
over and under deliveries of our customers products, and
over and under purchases of shrink replacement gas when our
purchases vary from operational requirements. In addition, we
realize gains and losses, which we believe are related to
inaccuracies inherent in the gas measurement process. These
gains and losses impact our results of operations and are
included in operating and maintenance expense in the Statement
of Operations. The sum of these items is reflected as product
imbalance receivables or payables on the Balance Sheets. These
product imbalances are valued based on the market value of the
products when the imbalance is identified and are evaluated for
the impact of changes in market prices at the balance sheet date.
Property, Plant and Equipment. Property, plant and
equipment is recorded at cost. We base the carrying value of
these assets on capitalized costs, useful lives and salvage
values. Depreciation of property, plant and equipment is
provided on a straight-line basis over estimated useful lives.
Expenditures for maintenance and repairs are expensed as
incurred. Expenditures that extend the useful lives of the
assets or increase their functionality are capitalized. The cost
of property, plant and equipment sold or retired and the related
accumulated depreciation is removed from the accounts in the
period of sale or disposition. Gains and losses on the disposal
of property, plant and equipment are recorded in net income.
We record an asset and a liability equal to the present value of
each expected future asset retirement obligation
(ARO). The ARO asset is depreciated in a manner
consistent with the depreciation of the underlying physical
asset. We measure changes in the liability due to passage of
time by applying an interest method of allocation. This amount
is recognized as an increase in the carrying amount of the
liability and as a corresponding accretion expense included in
operating income.
Revenue Recognition. Revenue for sales of products are
recognized when the product has been delivered, and revenues
from the gathering and processing of gas are recognized in the
period the service is provided based on contractual terms and
the related natural gas and liquid volumes.
Impairment of Long-Lived Assets. We evaluate our
long-lived assets of identifiable business activities for
impairment when events or changes in circumstances indicate, in
our managements judgment, that the carrying value of such
assets may not be recoverable. The impairment evaluation of
tangible long-lived assets is measured pursuant to the
guidelines of Statement of Financial Accounting Standards
(SFAS) No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets. When an
indicator of impairment has occurred, we compare our
managements estimate of undiscounted future cash flows
attributable to the assets to the carrying value of the assets
to determine whether the carrying value of the asset is
recoverable. We apply a probability-weighted approach to
consider the likelihood of different cash flow assumptions and
possible outcomes. If the carrying value is not recoverable, we
determine the amount of the impairment recognized in the
financial statements by estimating the fair value of the assets
and recording a loss for the amount that the carrying value
exceeds the estimated fair value.
Judgments and assumptions are inherent in our managements
estimate of undiscounted future cash flows used to determine
recoverability of an asset and the estimate of an assets
fair value used to calculate the amount of impairment to
recognize. The use of alternate judgments and/or assumptions
could result in the recognition of different levels of
impairment charges in the financial statements.
Environmental. Environmental expenditures that relate to
current or future revenues are expensed or capitalized based
upon the nature of the expenditures. Expenditures that relate to
an existing contamination caused by past operations that do not
contribute to current or future revenue generation are expensed.
Accruals related to environmental matters are generally
determined based on site-specific plans for
F-53
WILLIAMS FOUR CORNERS PREDECESSOR
NOTES TO FINANCIAL STATEMENTS (Continued)
remediation, taking into account our prior remediation
experience. Environmental contingencies are recorded
independently of any potential claim for recovery.
Prepaid expenses and leasing activities. Prepaid expenses
include the unamortized balance of minimum lease payments made
to date under a
right-of-way renewal
agreement. Land and
right-of-way lease
payments made at the time of initial construction or placement
of plant and equipment on leased land are capitalized as part of
the cost of the assets. Lease payments made in connection with
subsequent renewals or amendments of these leases are classified
as prepaid expenses. The minimum lease payments for the lease
term, including any renewal periods where the economic
disincentive to not renew provides reasonable assurance of
renewal, are expensed on a straight-line basis over the lease
term.
Income Taxes. Our operations are currently included in
the Williams consolidated federal income tax return.
However, prospectively for federal tax purposes, we have elected
to be treated as a partnership with each member being separately
taxed on its ratable share of our taxable income. Therefore, we
have excluded income taxes from these financial statements.
Earnings Per Share. During the periods presented, we were
wholly owned by Williams. Accordingly, we have not calculated
earnings per share.
Recent Accounting Standards. In December 2004, the
Financial Accounting Standards Board (FASB) issued
revised SFAS No. 123, Share-Based Payment. The
Statement requires that compensation costs for all share-based
awards to employees be recognized in the financial statements at
fair value. The Statement, as issued by the FASB, was to be
effective as of the beginning of the first interim or annual
reporting period that begins after June 15, 2005. However,
in April 2005, the Securities and Exchange Commission
(SEC) adopted a new rule that delayed the effective
date for revised SFAS No. 123 to the beginning of the next
fiscal year that begins after June 15, 2005. We intend to
adopt the revised Statement as of January 1, 2006. Payroll
costs directly charged to us by Williams and general and
administrative costs allocated to us by Williams (see Note 3)
will include such compensation costs beginning January 1,
2006. Our adoption of this Statement will not have a material
impact on our Financial Statements.
In November 2004, the FASB issued SFAS No. 151,
Inventory Costs, an amendment of ARB No. 43,
Chapter 4, which will be applied prospectively for
inventory costs incurred in fiscal years beginning after
June 15, 2005. The Statement amends Accounting Research
Bulletin (ARB) No. 43, Chapter 4,
Inventory Pricing, to clarify that abnormal amounts
of certain costs should be recognized as current period charges
and that the allocation of overhead costs should be based on the
normal capacity of the production facility. The impact of this
Statement on our Financial Statements will not be material.
In December 2004, the FASB issued SFAS No. 153,
Exchanges of Nonmonetary Assets, an amendment of APB
Opinion No. 29, which is effective for nonmonetary
asset exchanges occurring in fiscal periods beginning after
June 15, 2005, and will be applied prospectively. The
Statement amends Accounting Principles Board (APB)
Opinion No. 29, Accounting for Nonmonetary
Transactions. The guidance in APB Opinion No. 29 is
based on the principle that exchanges of nonmonetary assets
should be measured based on the fair value of the assets
exchanged but includes certain exceptions to that principle.
SFAS No. 153 amends APB Opinion No. 29 to eliminate
the exception for nonmonetary exchanges of similar productive
assets and replaces it with a general exception for exchanges of
nonmonetary assets that do not have commercial substance. A
nonmonetary exchange has commercial substance if the future cash
flows of the entity are expected to change significantly as a
result of the exchange.
In May 2005, the FASB issued SFAS No. 154, Accounting
Changes and Error Corrections a replacement of APB
Opinion No. 20 and FASB Statement No. 3, which
is effective prospectively for reporting a change in accounting
principle for fiscal years beginning after December 15,
2005. The Statement changes the reporting of a change in
accounting principle to require retrospective application to
prior periods,
F-54
WILLIAMS FOUR CORNERS PREDECESSOR
NOTES TO FINANCIAL STATEMENTS (Continued)
financial statements, except for explicit transition provisions
provided for in any existing accounting pronouncements,
including those in the transition phase when SFAS No. 154
becomes effective.
In January 2006, Williams adopted SFAS No. 123(R),
Share-Based Payment. Accordingly, payroll costs
charged to us by Williams reflect additional compensation costs
related to the adoption of this accounting standard. These costs
relate to Williams common stock equity awards made between
Williams and its employees. For the first quarter of 2006 there
is approximately $300,000 of cost related to Williams
share-based payment plan reflected in our general and
administrative expense on the Consolidated Statements of Income.
The cost is charged to us through specific allocations of
certain employees if they directly support our operations, and
through an allocation methodology among all Williams affiliates
if they provide indirect support. These allocated costs are
based on a three-factor formula, which considers revenues;
property, plant and equipment; and payroll.
Note 4. Related Party
Transactions
The employees supporting our operations are employees of
Williams. Their payroll costs are directly charged to us by
Williams. Williams carries the accruals for most
employee-related liabilities in its financial statements,
including the liabilities related to the employee retirement and
medical plans and paid time off accruals. Our share of these
costs are charged to us through a benefit load factor with the
payroll costs and are reflected in Operating and Maintenance
Expense Affiliate in the accompanying Statements of
Income.
We are charged for certain administrative expenses by Williams
and its Midstream segment of which we are a part. These charges
are either directly identifiable or allocated to our assets.
Direct charges are for goods and services provided by Williams
and Midstream at our request. Allocated charges are either
(1) charges allocated to the Midstream segment by Williams
and then reallocated from the Midstream segment to us or
(2) Midstream-level administrative costs that are allocated
to us. These expenses are allocated based on a three-factor
formula, which considers revenues, property, plant and equipment
and payroll. These costs are reflected in General and
Administrative Expenses Affiliate in the
accompanying Statements of Income. In managements
estimation, the allocation methodologies used are reasonable and
result in a reasonable allocation to us of our costs of doing
business incurred by Williams and its Midstream segment.
The operation of the Four Corners gathering system includes the
routine movement of gas across gathering systems. We refer to
this activity as crosshauling. Crosshauling
typically involves the movement of some natural gas between
gathering systems at established interconnect points to optimize
flow. As a result, we must purchase gas for delivery to
customers at certain plant outlets and we have excess volumes to
sell at other plant outlets. These purchase and sales
transactions are conducted for us by Williams Power Company
(Power), a wholly owned indirect subsidiary of
Williams, at current market prices and are included in Product
Sales Affiliate and Product Cost
Affiliate on the Statements of Income. Historically, Power has
not charged us a fee for providing this service, but has
occasionally benefited from price differentials that
historically existed from time to time between the plant outlets.
We also purchase natural gas for fuel and shrink replacement
from Power. These purchases are made at market rates at the time
of purchase. These costs are reflected in Operating and
Maintenance Expense Affiliate and Product
Cost-Affiliate in the accompanying Statements of Income.
Prior to April 2003, we purchased steam from Power for use at
our Milagro treating plant. The steam was produced from the
operation of the Milagro cogeneration facility owned by Power.
Beginning in April 2003, we purchased natural gas for steam
conversion services. The natural gas cost charged to us by Power
has been favorably impacted by Powers fixed price natural
gas fuel contracts. This impact was approximately
$9.0 million annually during the periods presented as
compared to estimated market prices. These agreements expire in
the fourth quarter of 2006. We are evaluating the means by which
we will obtain waste heat to
F-55
WILLIAMS FOUR CORNERS PREDECESSOR
NOTES TO FINANCIAL STATEMENTS (Continued)
generate steam beyond the life of this agreement and expect that
our Milagro natural gas fuel costs will increase due to our
expectation that future market prices will exceed prices
associated with these agreements.
We sell the NGLs to which we take title to Williams Midstream
Marketing and Risk Management, LLC (WMMRM), a wholly
owned indirect subsidiary of Williams. Revenues associated with
these activities are reflected as Product Sales
Affiliate revenues on the Statements of Income.
One of our major customers is Williams Production Company
(WPC), a wholly owned subsidiary of Williams. WPC is
one of the largest natural gas producers in the San Juan Basin
and we provide natural gas gathering, treating and processing
services to WPC under several contracts. Revenues associated
with these activities are reflected in the Gathering and
Processing Services Affiliate revenues on the
Statements of Income.
A summary of affiliate general and administrative expenses
directly charged and allocated to us, steam generation expenses
and other operating and maintenance expenses directly charged to
us for the periods stated is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003 | |
|
2004 | |
|
2005 | |
|
|
| |
|
| |
|
| |
|
|
(In thousands) | |
General and administrative expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated
|
|
$ |
18,578 |
|
|
$ |
22,215 |
|
|
$ |
25,964 |
|
|
Directly charged
|
|
|
4,527 |
|
|
|
5,199 |
|
|
|
3,615 |
|
Operating and maintenance expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other natural gas and steam expenses
|
|
|
9,003 |
|
|
|
11,798 |
|
|
|
14,518 |
|
|
Salaries and benefits and other
|
|
|
17,566 |
|
|
|
18,184 |
|
|
|
18,298 |
|
Prior to closing, we participated in Williams cash
management program; hence, we maintained no cash balances. As of
December 31, 2004 and December 31, 2005, our net
advances to Williams under an unsecured promissory note
agreement which allows for both advances to and from Williams
have been classified as a component of owners equity
because, although the advances are due on demand, Williams has
not historically required repayment or repaid amounts owed to
us. In addition, when our assets are conveyed to WFC LLC in
2006, the outstanding advances are expected to be distributed to
Williams. Changes in the advances to Williams are presented as
distributions to Williams in the Statement of Owners
Equity and Statements of Cash Flows.
Note 5. Other Costs and
Expenses Net
Other Net reflected on the Statements of Income
consists of the following items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended | |
|
|
Year Ended December 31, | |
|
March 31, | |
|
|
| |
|
| |
|
|
2003 | |
|
2004 | |
|
2005 | |
|
2005 | |
|
2006 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
|
|
|
|
|
|
(Unaudited) | |
|
|
(In thousands) | |
Impairment of LaMaquina carbon dioxide treating facility
|
|
$ |
4,128 |
|
|
$ |
7,636 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Impairment of membrane units
|
|
|
3,470 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on sale of LaMaquina carbon dioxide treating facility
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,319 |
) |
Other
|
|
|
4,202 |
|
|
|
3,602 |
|
|
|
636 |
|
|
|
237 |
|
|
|
(324 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
11,800 |
|
|
$ |
11,238 |
|
|
$ |
636 |
|
|
$ |
237 |
|
|
$ |
(3,643 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-56
WILLIAMS FOUR CORNERS PREDECESSOR
NOTES TO FINANCIAL STATEMENTS (Continued)
LaMaquina Carbon Dioxide Treating Facility. This facility
consisted of two amine trains and seven gas powered generator
sets. The facility was shut down in 2002 due to a reduced need
for treating. In 2003, management estimated that only one amine
train would be returned to service. As a result, we recognized
an impairment of the carrying value of the other train to its
estimated fair value based on estimated salvage values and sales
prices. Further developments in 2004 led management to conclude
that the facility would not return to service. Thus, we
recognized an additional impairment of the carrying value to its
estimated fair value. The facility was sold in the first quarter
of 2006 resulting in the recognition of a gain on the sale in
2006.
Membrane Units. In 2003, management conducted an
impairment assessment on several idle carbon dioxide removal
(membrane) units. The estimated fair value was based on the
proceeds from the sale of two similar units earlier in 2003. An
asset impairment was recognized to adjust the carrying value to
the estimated fair value.
Other. In 2003, other expense included $4.2 million
of bad debt expense and contingency accruals. In 2004, other
expense included losses on asset dispositions and materials and
supplies inventory adjustments.
Note 6. Property, Plant and
Equipment
Property, plant and equipment, at cost, as of December 31,
2004 and 2005 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31 | |
|
Estimated | |
|
|
| |
|
Depreciable | |
|
|
2004 | |
|
2005 | |
|
Lives | |
|
|
| |
|
| |
|
| |
|
|
(In thousands) | |
|
|
Land and right of way
|
|
$ |
39,367 |
|
|
$ |
41,990 |
|
|
|
|
|
Gathering pipelines and related equipment
|
|
|
761,837 |
|
|
|
777,701 |
|
|
|
30 years |
|
Processing plants and related equipment
|
|
|
163,227 |
|
|
|
164,257 |
|
|
|
30 years |
|
Buildings and other equipment
|
|
|
92,694 |
|
|
|
88,578 |
|
|
|
3-30 years |
|
Construction work in progress
|
|
|
9,728 |
|
|
|
18,437 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment
|
|
|
1,066,853 |
|
|
|
1,090,963 |
|
|
|
|
|
Accumulated depreciation
|
|
|
465,143 |
|
|
|
499,929 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
$ |
601,710 |
|
|
$ |
591,034 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We adopted SFAS No. 143, Accounting for Asset
Retirement Obligations on January 1, 2003. As a
result, we recorded a liability of $330,000 representing the
present value of expected future asset retirement obligations at
January 1, 2003, and a decrease to earnings of $330,000
reflected as a cumulative effect of a change in accounting
principle.
Effective December 31, 2005, we adopted FASB Interpretation
(FIN) No. 47, Accounting for Conditional
Asset Retirement Obligations. This Interpretation
clarifies that an entity is required to recognize a liability
for the fair value of a conditional ARO when incurred if the
liabilitys fair value can be reasonably estimated. The
Interpretation clarifies when an entity would have sufficient
information to reasonably estimate the fair value of an ARO. As
required by the new standard, we reassessed the estimated
remaining life of all our assets with a conditional ARO. We
recorded additional liabilities totaling $788,000 equal to the
present value of expected future asset retirement obligations at
December 31, 2005. The liabilities are slightly offset by a
$94,000 increase in property, plant and equipment, net of
accumulated depreciation, recorded as if the provisions of the
Interpretation had been in effect at the date the obligation was
incurred. The net $694,000 reduction to earnings is reflected as
a cumulative effect of a change in accounting principle for the
year ended 2005. If the Interpretation had been in effect at the
beginning of 2003, the impact to our income from continuing
operations and net income would have been immaterial.
F-57
WILLIAMS FOUR CORNERS PREDECESSOR
NOTES TO FINANCIAL STATEMENTS (Continued)
The ARO at December 31, 2004 and 2005 is $330,000 and
$1.1 million, respectively. The increase in the obligation
in 2005 is due primarily to the adoption of FIN No. 47. The
obligations relate to gas processing and compression facilities
located on leased land and wellhead connections on federal land.
At the end of the useful life of each respective asset, we are
legally or contractually obligated to remove certain surface
equipment and cap certain gathering pipelines at the wellhead
connection.
Note 7. Accrued Liabilities
Accrued liabilities as of December 31, 2004 and 2005 are as
follows:
|
|
|
|
|
|
|
|
|
|
|
December 31 | |
|
|
| |
|
|
2004 | |
|
2005 | |
|
|
| |
|
| |
|
|
(In thousands) | |
Taxes other than income
|
|
$ |
1,961 |
|
|
$ |
2,056 |
|
Environmental remediation current portion
|
|
|
1,484 |
|
|
|
328 |
|
Reserve for customer refunds current portion
|
|
|
2,583 |
|
|
|
|
|
Casualty loss accrual
|
|
|
676 |
|
|
|
435 |
|
Other
|
|
|
354 |
|
|
|
968 |
|
|
|
|
|
|
|
|
|
|
$ |
7,058 |
|
|
$ |
3,787 |
|
|
|
|
|
|
|
|
Note 8. Leasing Activities
We lease the land on which a significant portion of our pipeline
assets are located. The primary landowners are the Bureau of
Land Management (BLM) and several Indian tribes. The
BLM leases are for thirty years with renewal options. The most
significant of the Indian tribal leases will expire at the end
of 2022 and will then be subject to renegotiation. We lease
compression units under a lease agreement with Hanover
Compression, Inc. The initial term of this agreement expires on
June 30, 2006. Following the initial term, the agreement
can be continued on a month-to-month basis unless terminated by
either party upon thirty days advance written notice. We also
lease other minor office and warehouse equipment under
non-cancelable leases. The future minimum annual rentals under
these non-cancelable leases as of December 31, 2005 are
payable as follows:
|
|
|
|
|
|
|
(Thousands) | |
|
|
| |
2006
|
|
$ |
12,223 |
|
2007
|
|
|
1,169 |
|
2008
|
|
|
791 |
|
2009
|
|
|
421 |
|
2010
|
|
|
338 |
|
Thereafter
|
|
|
3,120 |
|
|
|
|
|
|
|
$ |
18,062 |
|
|
|
|
|
Total rent expense for the years ended 2003, 2004 and 2005 was
$15.8 million, $14.7 million and $18.8 million,
respectively.
Note 9. Major Customers and
Concentrations of Credit Risk
For the years ended December 31, 2004 and 2005,
substantially all of our accounts receivable result from product
sales and gathering and processing services provided to our five
largest customers. This concentration of customers may impact
our overall credit risk either positively or negatively, in that
these entities may be
F-58
WILLIAMS FOUR CORNERS PREDECESSOR
NOTES TO FINANCIAL STATEMENTS (Continued)
similarly affected by industry-wide changes in economic or other
conditions. As a general policy, collateral is not required for
receivables, but customers financial conditions and credit
worthiness are evaluated regularly. Our credit policy and the
relatively short duration of receivables mitigate the risk of
uncollected receivables.
Our largest customer, on a percentage of revenues basis, is
WMMRM, which purchases and resells substantially all of the NGLs
to which we take title. WMMRM accounted for 35 percent,
47 percent and 48 percent of revenues in 2003, 2004
and 2005, respectively. The percentages for the remaining three
largest customers are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003 | |
|
2004 | |
|
2005 | |
|
|
| |
|
| |
|
| |
Customer A
|
|
|
19 |
% |
|
|
15 |
% |
|
|
15 |
% |
Customer B
|
|
|
12 |
|
|
|
12 |
|
|
|
11 |
|
Customer C
|
|
|
10 |
|
|
|
5 |
|
|
|
4 |
|
Note 10. Commitments and
Contingent Liabilities
Environmental Matters. Current federal regulations
require that certain unlined liquid containment pits located
near named rivers and catchment areas be taken out of use, and
current state regulations required all unlined, earthen pits to
be either permitted or closed by December 31, 2005.
Operating under a New Mexico Oil Conservation Division-approved
work plan, we have physically closed all of our pits that were
slated for closure under those regulations. We are presently
awaiting agency approval of the closures for 40 to 50 of those
pits.
We are also a participant in certain environmental activities
associated with groundwater contamination at certain well sites
in New Mexico. Of nine remaining active sites, product removal
is ongoing at seven and groundwater monitoring is ongoing at
each site. As groundwater concentrations reach and sustain
closure criteria levels and state regulator approval is
received, the sites will be properly abandoned. We expect the
remaining sites will be closed within four to eight years.
At December 31, 2005 and March 31, 2006, we have
accrued liabilities totaling $735,000 and $603,000,
respectively, for these environmental activities. It is
reasonably possible that we will incur losses in excess of our
accrual for these matters. However, a reasonable estimate of
such amounts cannot be determined at this time because actual
costs incurred will depend on the actual number of contaminated
sites identified, the amount and extent of contamination
discovered, the final cleanup standards mandated by governmental
authorities and other factors.
We are subject to extensive federal, state and local
environmental laws and regulations which affect our operations
related to the construction and operation of our facilities.
Appropriate governmental authorities may enforce these laws and
regulations with a variety of civil and criminal enforcement
measures, including monetary penalties, assessment and
remediation requirements and injunctions as to future
compliance. We have not been notified and are not currently
aware of any material noncompliance under the various applicable
environmental laws and regulations.
Will Price. In 2001, we were named, along with other
subsidiaries of Williams, as defendants in a nationwide class
action lawsuit in Kansas state court that had been pending
against other defendants, generally pipeline and gathering
companies, since 2000. The plaintiffs alleged that the
defendants have engaged in mismeasurement techniques that
distort the heating content of natural gas, resulting in an
alleged underpayment of royalties to the class of producer
plaintiffs and sought an unspecified amount of damages. The
defendants have opposed class certification and a hearing on
plaintiffs second motion to certify the class was held on
April 1, 2005. We are awaiting a decision from the court.
Grynberg. In 1998, the Department of Justice informed
Williams that Jack Grynberg, an individual, had filed claims on
behalf of himself and the federal government, in the United
States District Court for the
F-59
WILLIAMS FOUR CORNERS PREDECESSOR
NOTES TO FINANCIAL STATEMENTS (Continued)
District of Colorado under the False Claims Act against Williams
and certain of its wholly owned subsidiaries, including us. The
claims sought an unspecified amount of royalties allegedly not
paid to the federal government, treble damages, a civil penalty,
attorneys fees, and costs. Grynberg has also filed claims
against approximately 300 other energy companies alleging that
the defendants violated the False Claims Act in connection with
the measurement, royalty valuation and purchase of hydrocarbons.
In 1999, the Department of Justice announced that it was
declining to intervene in any of the Grynberg cases, including
the action filed in federal court in Colorado against us. Also
in 1999, the Panel on Multi-District Litigation transferred all
of these cases, including those filed against us, to the federal
court in Wyoming for pre-trial purposes. Grynbergs
measurement claims remain pending against us and the other
defendants; the court previously dismissed Grynbergs
royalty valuation claims. In May 2005, the court-appointed
special master entered a report which recommended that the
claims against certain Williams subsidiaries, including
us, be dismissed. The District Court is considering whether to
affirm or reject the special masters recommendations and
heard oral arguments in December 2005.
Other. We are not currently a party to any other legal
proceedings but are a party to various administrative and
regulatory matters that have arisen in the ordinary course of
our business.
Summary. Litigation, arbitration, regulatory matters and
environmental matters are subject to inherent uncertainties.
Were an unfavorable ruling to occur, there exists the
possibility of a material adverse impact on the results of
operations in the period in which the ruling occurs. Management,
including internal counsel, currently believes that the ultimate
resolution of the foregoing matters, taken as a whole and after
consideration of amounts accrued, insurance coverage, recovery
from customers or other indemnification arrangements, will not
have a materially adverse effect upon our future financial
position.
F-60
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors of Williams Partners GP LLC
We have audited the accompanying consolidated balance sheet of
Williams Partners GP LLC as of December 31, 2005. The
consolidated balance sheet is the responsibility of the
Companys management. Our responsibility is to express an
opinion on the consolidated balance sheet 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. We were not engaged to perform an audit
of the Companys internal control over financial reporting.
Our audit included consideration of internal control over
financial reporting as a basis for designing audit procedures
that are appropriate in the circumstances, but not for the
purpose of expressing an opinion on the effectiveness of the
Companys internal control over financial reporting.
Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the balance sheet, assessing the accounting
principles used and significant estimates made by management,
and evaluating the overall balance sheet presentation. We
believe that our audit provides a reasonable basis for our
opinion.
In our opinion, the balance sheet referred to above presents
fairly, in all material respects, the financial position of
Williams Partners GP LLC, in conformity with U.S. generally
accepted accounting principles.
Tulsa, Oklahoma
February 27, 2006
F-61
WILLIAMS PARTNERS GP LLC
CONSOLIDATED BALANCE SHEET
December 31, 2005
(In thousands)
|
|
|
|
|
|
|
|
ASSETS |
|
Current assets:
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
6,839 |
|
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
Trade
|
|
|
1,840 |
|
|
|
|
Other
|
|
|
2,104 |
|
|
Product imbalance
|
|
|
760 |
|
|
Gas purchase contract affiliate
|
|
|
5,320 |
|
|
Prepaid expenses
|
|
|
1,133 |
|
|
|
|
|
|
Total current assets
|
|
|
17,996 |
|
Investment in Discovery Producer Services
|
|
|
150,260 |
|
Property, plant and equipment, net
|
|
|
67,931 |
|
Gas purchase contract noncurrent
affiliate
|
|
|
4,754 |
|
|
|
|
|
Total assets
|
|
$ |
240,941 |
|
|
|
|
|
LIABILITIES AND OWNERS EQUITY |
|
Current liabilities:
|
|
|
|
|
|
|
Accounts payable:
|
|
|
|
|
|
|
|
Trade
|
|
$ |
3,906 |
|
|
|
|
Affiliate
|
|
|
6,562 |
|
|
|
Deferred revenue
|
|
|
3,552 |
|
|
|
Accrued liabilities
|
|
|
2,373 |
|
|
|
|
|
|
Total current liabilities
|
|
|
16,393 |
|
Environmental remediation liabilities
|
|
|
3,964 |
|
Other noncurrent liabilities
|
|
|
762 |
|
Minority interest
|
|
|
112,160 |
|
Commitments and contingent liabilities (Note 11)
|
|
|
|
|
Owners equity
|
|
|
107,662 |
|
|
|
|
|
Total liabilities and owners equity
|
|
$ |
240,941 |
|
|
|
|
|
See accompanying notes to the consolidated balance sheet.
F-62
WILLIAMS PARTNERS GP LLC
NOTES TO CONSOLIDATED BALANCE SHEET
We are a Delaware limited liability company formed on
February 23, 2005, to become the general partner of
Williams Partners L.P. (the Partnership). We own a
2 percent general partner interest in the Partnership.
However, due to the substantive control granted to us by the
partnership agreement we consolidate our interest in the
Partnership. Unless the context clearly indicates otherwise,
references to we, our, and
us include the operations of the Partnership. We are
a wholly owned subsidiary of The Williams Companies, Inc.
(Williams).
The Partnership is a Delaware limited partnership formed in
February 2005, to acquire and own (1) a 40 percent
interest in Discovery; (2) the Carbonate Trend gathering
pipeline off the coast of Alabama; (3) three integrated
natural gas liquids (NGL) product storage facilities
near Conway, Kansas; and (4) a 50 percent undivided
ownership interest in a fractionator near Conway, Kansas. Prior
to the closing of the Partnerships initial public offering
(the IPO) in August 2005, the 40 percent
interest in Discovery was held by Williams Energy, L.L.C.
(Energy) and Williams Discovery Pipeline LLC; the
Carbonate Trend gathering pipeline was held in Carbonate Trend
Pipeline LLC (CTP), which was owned by Williams
Mobile Bay Producers Services, L.L.C.; and the NGL product
storage facilities and the interest in the fractionator were
owned by Mid-Continent Fractionation and Storage, LLC
(MCFS). All of these are wholly owned indirect
subsidiaries of The Williams Companies, Inc. (collectively
Williams). Additionally, Williams Partners Operating
LLC, an operating limited liability company (wholly owned by the
Partnership) through which all the Partnerships activities
are conducted, was formed.
|
|
|
Initial Public Offering and Related Transactions |
On August 23, 2005, the Partnership completed an IPO of
5,000,000 common units representing limited partner interests in
us at a price of $21.50 per unit. The proceeds of
$100.2 million, net of the underwriters discount and
a structuring fee totaling $7.3 million, were used to:
|
|
|
|
|
distribute $58.8 million to Williams, in part to reimburse
Williams for capital expenditures relating to the assets
contributed to us and for a gas purchase contract contributed to
us; |
|
|
|
provide $24.4 million to make a capital contribution to
Discovery to fund an escrow account required in connection with
the Tahiti pipeline lateral expansion project; |
|
|
|
provide $12.7 million of additional working
capital; and |
|
|
|
pay $4.3 million of expenses associated with the IPO and
related formation transactions. |
Concurrent with the closing of the IPO, the 40 percent
interest in Discovery and all of the interests in CTP and MCFS
were contributed to the Partnership by Williams
subsidiaries in exchange for an aggregate of 2,000,000 common
units and 7,000,000 subordinated units. The public, through the
underwriters of the offering, contributed $107.5 million
($100.2 million net of the underwriters discount and
a structuring fee) to the Partnership in exchange for 5,000,000
common units, representing a 35 percent limited partner
interest in the Partnership. Additionally, at the closing of the
IPO, the underwriters fully exercised their option to purchase
750,000 common units from Williams subsidiaries at the IPO
price of $21.50 per unit, less the underwriters
discount and a structuring fee.
|
|
Note 2. |
Description of Business |
We are principally engaged in the business of gathering,
transporting and processing natural gas and fractionating and
storing NGLs. Operations of our businesses are located in the
United States and are organized into two reporting segments:
(1) Gathering and Processing and (2) NGL Services. Our
Gathering and Processing segment includes our equity investment
in Discovery and the Carbonate Trend gathering pipeline. Our NGL
Services segment includes the Conway fractionation and storage
operations.
F-63
WILLIAMS PARTNERS GP LLC
NOTES TO CONSOLIDATED BALANCE
SHEET (Continued)
Gathering and Processing. We own a 40 percent
interest in Discovery, which includes a wholly owned subsidiary,
Discovery Gas Transmission LLC. Discovery owns (1) a
273-mile natural gas
gathering and transportation pipeline system, located primarily
off the coast of Louisiana in the Gulf of Mexico, (2) a
600 million cubic feet per day cryogenic natural gas
processing plant in Larose, Louisiana, (3) a
32,000 barrels per day (bpd) natural gas
liquids fractionator in Paradis, Louisiana and (4) two
onshore liquids pipelines, including a
22-mile mixed NGL
pipeline connecting the gas processing plant to the fractionator
and a 10-mile
condensate pipeline connecting the gas processing plant to a
third party oil gathering facility. Although Discovery includes
fractionation operations, which would normally fall within the
NGL Services segment, it is primarily engaged in gathering and
processing and is managed as such. Hence, this equity investment
is considered part of the Gathering and Processing segment.
Our Carbonate Trend gathering pipeline is an unregulated sour
gas gathering pipeline consisting of approximately 34 miles
of pipeline off the coast of Alabama.
NGL Services. Our Conway storage facilities include three
underground NGL storage facilities in the Conway, Kansas, area
with a storage capacity of approximately 20 million
barrels. The facilities are connected via a series of pipelines.
The storage facilities receive daily shipments of a variety of
products, including mixed NGLs and fractionated products. In
addition to pipeline connections, one facility offers truck and
rail service.
Our Conway fractionation facility is located near McPherson,
Kansas, and has a capacity of approximately 107,000 bpd. We
own a 50 percent undivided interest in these facilities
representing capacity of approximately 53,500 bpd.
ConocoPhillips and ONEOK Partners, L.P. are the other owners.
Williams operates the facility pursuant to an operating
agreement that extends until May 2011. The fractionator
separates mixed NGLs into five products: ethane, propane, normal
butane, isobutane and natural gasoline. Portions of these
products are then transported and stored at our Conway storage
facilities.
|
|
Note 3. |
Summary of Significant Accounting Policies |
Basis of Presentation. The consolidated balance sheet has
been prepared based upon accounting principles generally
accepted in the United States and include the accounts of the
parent and our controlled subsidiaries. Intercompany accounts
and transactions have been eliminated.
Use of Estimates. The preparation of financial statements
in conformity with accounting principles generally accepted in
the United States requires management to make estimates and
assumptions that affect the amounts reported in the consolidated
balance sheet and accompanying notes. Actual results could
differ from those estimates.
Estimates and assumptions which, in the opinion of management,
are significant to the underlying amounts included in the
balance sheet and for which it would be reasonably possible that
future events or information could change those estimates
include:
|
|
|
|
|
impairment assessments of investments and long-lived assets; |
|
|
|
loss contingencies; |
|
|
|
environmental remediation obligations; and |
|
|
|
asset retirement obligations. |
These estimates are discussed further throughout the
accompanying notes.
Proportional Accounting for the Conway Fractionator. No
separate legal entity exists for the fractionator. We hold a
50 percent undivided interest in the fractionator property,
plant and equipment, and we are responsible for our proportional
share of the costs and expenses of the fractionator. As operator
of the
F-64
WILLIAMS PARTNERS GP LLC
NOTES TO CONSOLIDATED BALANCE
SHEET (Continued)
facility, we incur the liabilities of the fractionator (except
for certain fuel costs purchased directly by one of the
co-owners) and are reimbursed by the co-owners for their
proportional share of the total costs and expenses. Each
co-owner is responsible for the marketing of their proportional
share of the fractionators capacity. Accordingly, we
reflect our proportionate share of the fractionator property,
plant and equipment in the Consolidated Balance Sheet.
Liabilities in the Consolidated Balance Sheet include those
incurred on behalf of the co-owners with corresponding
receivables from the co-owners. Accounts receivable also
includes receivables from our customers for fractionation
services.
Cash and Cash Equivalents. Cash and cash equivalents
include demand and time deposits, certificates of deposit and
other marketable securities with maturities of three months or
less when acquired.
Accounts Receivable. Accounts receivable are carried on a
gross basis, with no discounting, less an allowance for doubtful
accounts. No allowance for doubtful accounts is recognized at
the time the revenue which generates the accounts receivable is
recognized. We estimate the allowance for doubtful accounts
based on existing economic conditions, the financial condition
of our customers, and the amount and age of past due accounts.
Receivables are considered past due if full payment is not
received by the contractual due date. Past due accounts are
generally written off against the allowance for doubtful
accounts only after all collection attempts have been
unsuccessful.
Investments. The voting rights under Discoverys
limited liability company agreement are such that our
40 percent interest combined with the additional interest
held by Williams do not control Discovery. Hence, we account for
our investment in Discovery under the equity method. In 2004, we
recognized an other-than-temporary impairment of our investment
in Discovery. As a result, Discoverys underlying equity
exceeds the carrying value of our investment at
December 31, 2005.
Property, Plant and Equipment. Property, plant and
equipment is recorded at cost. We base the carrying value of
these assets on capitalized costs, useful lives and salvage
values. Depreciation of property, plant and equipment is
provided on the straight-line basis over estimated useful lives.
Expenditures for maintenance and repairs are expensed as
incurred. Expenditures that enhance the functionality or extend
the useful lives of the assets are capitalized. The cost of
property, plant and equipment sold or retired and the related
accumulated depreciation is removed from the accounts in the
period of sale or disposition. Gains and losses on the disposal
of property, plant and equipment are recorded in the
Consolidated Statement of Operations.
We record an asset and a liability equal to the present value of
each expected future asset retirement obligation
(ARO). The ARO asset is depreciated in a manner
consistent with the depreciation of the underlying physical
asset. We measure changes in the liability due to passage of
time by applying an interest method of allocation. This amount
is recognized as an increase in the carrying amount of the
liability and as a corresponding accretion expense included in
operating income.
Revenue Recognition. The nature of our businesses result
in various forms of revenue recognition. Our Gathering and
Processing segment recognizes revenue from gathering services
when the services have been performed. Our NGL Services segment
recognizes (1) fractionation revenues when services have
been performed and product has been delivered, (2) storage
revenues under prepaid contracted storage capacity evenly over
the life of the contract as services are provided and
(3) product sales revenue when the product has been
delivered.
Gas purchase contract. In connection with the
Partnerships IPO, Williams transferred to us a gas
purchase contract for the purchase of a portion of our fuel
requirements at the Conway fractionator at a market price not to
exceed a specified level. The gas purchase contract is for the
purchase of 80,000 MMBtu per month and terminates on
December 31, 2007. The initial value of this contract is
being amortized to expense over the contract life.
F-65
WILLIAMS PARTNERS GP LLC
NOTES TO CONSOLIDATED BALANCE
SHEET (Continued)
Product Imbalances. In the course of providing
fractionation and storage services to our customers, we realize
product gains and losses that are reflected as product imbalance
receivables or payables on the Consolidated Balance Sheet. These
imbalances are valued based on the market price of the products
when the imbalance is identified and are evaluated for the
impact of a change in market prices at the balance sheet date.
Certain of these product gains and losses arise due to the
product blending process at the fractionator. Others are
realized when storage caverns are emptied. Storage caverns are
emptied periodically to determine whether any product gains or
losses have occurred, and as these caverns are emptied, it is
possible that the resulting product gains or losses could have a
material impact to the results of operations for the period
during which the cavern drain is performed.
Impairment of Long-Lived Assets and Investments. We
evaluate our long-lived assets of identifiable business
activities for impairment when events or changes in
circumstances indicate the carrying value of such assets may not
be recoverable. The impairment evaluation of tangible long-lived
assets is measured pursuant to the guidelines of Statement of
Financial Accounting Standards (SFAS) No. 144,
Accounting for the Impairment or Disposal of Long-Lived
Assets. When an indicator of impairment has occurred, we
compare our managements estimate of undiscounted future
cash flows attributable to the assets to the carrying value of
the assets to determine whether the carrying value of the assets
is recoverable. We apply a probability weighted approach to
consider the likelihood of different cash flow assumptions and
possible outcomes. If the carrying value is not recoverable, we
determine the amount of the impairment recognized in the
financial statements by estimating the fair value of the assets
and recording a loss for the amount that the carrying value
exceeds the estimated fair value.
We evaluate our investments for impairment when events or
changes in circumstances indicate, in our managements
judgment, that the carrying value of such investments may have
experienced an other-than-temporary decline in value. When
evidence of loss in value has occurred, we compare our estimate
of fair value of the investment to the carrying value of the
investment to determine whether an impairment has occurred. If
the estimated fair value is less than the carrying value and we
consider the decline in value to be other than temporary, the
excess of the carrying value over the estimated fair value is
recognized in the financial statements as an impairment.
Judgments and assumptions are inherent in our managements
estimate of undiscounted future cash flows used to determine
recoverability of an asset and the estimate of an assets
fair value used to calculate the amount of impairment to
recognize. The use of alternate judgments and/or assumptions
could result in the recognition of different levels of
impairment charges in the financial statements.
Income Taxes. We are not a taxable entity for federal and
state income tax purposes. The tax on our net income is borne by
our owner, The Williams Companies, Inc.
Environmental. Environmental expenditures that relate to
current or future revenues are expensed or capitalized based
upon the nature of the expenditures. Expenditures that relate to
an existing contamination caused by past operations that do not
contribute to current or future revenue generation are expensed.
Accruals related to environmental matters are generally
determined based on site-specific plans for remediation, taking
into account our prior remediation experience. Environmental
contingencies are recorded independently of any potential claim
for recovery.
Capitalized Interest. We capitalize interest on major
projects during construction to the extent we incur interest
expense. Historically, Williams provided the financing for
capital expenditures; hence, the rates used to calculate the
interest were based on Williams average interest rate on
debt during the applicable period in time.
Owners Equity. Because we are part of a controlled
group that includes other wholly owned subsidiaries of Williams,
the ownership interests that the other entities in this
controlled group have in the Partnership are classified as
Owners equity on the Consolidated Balance Sheet.
F-66
WILLIAMS PARTNERS GP LLC
NOTES TO CONSOLIDATED BALANCE
SHEET (Continued)
Recent Accounting Standards. In December 2004, the
Financial Accounting Standards Board (FASB) issued
revised SFAS No. 123, Share-Based Payment.
The Statement requires that compensation costs for all
share-based awards to employees be recognized in the financial
statements at fair value. The Statement, as issued by the FASB,
was to be effective as of the beginning of the first interim or
annual reporting period that begins after June 15, 2005.
However, in April 2005, the Securities and Exchange Commission
(SEC) adopted a new rule that delayed the effective
date for revised SFAS No. 123 to the beginning of the
next fiscal year that begins after June 15, 2005. We intend
to adopt the revised Statement as of January 1, 2006.
Payroll costs directly charged to us by Williams and general and
administrative costs allocated to us by Williams (see
Note 5) will include such compensation costs beginning
January 1, 2006. Our and Williams adoption of this
Statement will not have a material impact on our Consolidated
Balance Sheet.
In November 2004, the FASB issued SFAS No. 151,
Inventory Costs, an amendment of ARB No. 43,
Chapter 4, which will be applied prospectively for
inventory costs incurred in fiscal years beginning after
June 15, 2005. The Statement amends Accounting Research
Bulletin (ARB) No. 43, Chapter 4, Inventory
Pricing, to clarify that abnormal amounts of certain costs
should be recognized as current period charges and that the
allocation of overhead costs should be based on the normal
capacity of the production facility. The impact of this
Statement on our Consolidated Balance Sheet will not be material.
In December 2004, the FASB issued SFAS No. 153,
Exchanges of Nonmonetary Assets, an amendment of APB
Opinion No. 29, which is effective for nonmonetary
asset exchanges occurring in fiscal periods beginning after
June 15, 2005, and will be applied prospectively. The
Statement amends APB Opinion No. 29, Accounting for
Nonmonetary Transactions. The guidance in APB Opinion
No. 29 is based on the principle that exchanges of
nonmonetary assets should be measured based on the fair value of
the assets exchanged but includes certain exceptions to that
principle. SFAS No. 153 amends APB Opinion No. 29
to eliminate the exception for nonmonetary exchanges of similar
productive assets and replaces it with a general exception for
exchanges of nonmonetary assets that do not have commercial
substance. A nonmonetary exchange has commercial substance if
the future cash flows of the entity are expected to change
significantly as a result of the exchange.
In May 2005, the FASB issued SFAS No. 154,
Accounting Changes and Error Corrections a
replacement of APB Opinion No. 20 and FASB Statement
No. 3, which is effective prospectively for reporting
a change in accounting principle for fiscal years beginning
after December 15, 2005. The Statement changes the
reporting of a change in accounting principle to require
retrospective application to prior periods financial
statements, except for explicit transition provisions provided
for in any existing accounting pronouncements, including those
in the transition phase when SFAS No. 154 becomes
effective.
|
|
Note 4. |
Related Party Transactions |
The employees of our operated assets and all of our general and
administrative employees are employees of Williams. Williams
directly charges us for the payroll costs associated with the
operations employees and certain general and administrative
employees. Williams carries the obligations for most
employee-related benefits in its financial statements, including
the liabilities related to the employee retirement and medical
plans and paid time off. Certain of these costs are charged back
to the other Conway fractionator co-owners.
Williams charges its affiliates, including us and its Midstream
segment, of which we are a part, for certain corporate
administrative expenses that are directly identifiable or
allocable to the affiliates. Direct costs charged from Williams
represent the direct costs of services provided by Williams on
our behalf. Prior to the IPO, a portion of the charges allocated
to the Midstream segment were then reallocated to us. These
allocated corporate administrative expenses are based on a
three-factor formula, which considered revenues; property, plant
and equipment; and payroll. Certain of these costs are charged
back to the other Conway fractionator co-owners. In
managements estimation, the allocation methodologies used
are reasonable and result in a reasonable allocation to us of
our costs of doing business incurred by Williams.
F-67
WILLIAMS PARTNERS GP LLC
NOTES TO CONSOLIDATED BALANCE
SHEET (Continued)
We purchase fuel for the Conway fractionator, including fuel on
behalf of the co-owners, from Williams Power Company
(Power), a wholly owned subsidiary of Williams.
These purchases are made at market rates at the time of
purchase. In connection with the IPO, Williams transferred to us
a gas purchase contract for the purchase of a portion of our
fuel requirements at the Conway fractionator at a market price
not to exceed a specified level. The initial value of this
contract is being amortized to expense over the contract life.
The carrying value of this contract is reflected as Gas purchase
contract affiliate and Gas purchase
contract noncurrent affiliate on the
Consolidated Balance Sheet.
We sell surplus propane and other NGLs to Power, which takes
title to the product and resells it, for its own account, to end
users. Correspondingly, we purchase ethane and other NGLs from
Power to replenish deficit product positions. The transactions
conducted between us and Power are transacted at current market
prices for the products.
The per-unit gathering fee associated with two of our Carbonate
Trend gathering contracts was negotiated on a bundled basis that
includes transportation along a segment of a pipeline system
owned by Transcontinental Gas Pipe Line Company
(Transco), a wholly owned subsidiary of Williams.
The fees we realize are dependent upon whether our customer
elects to utilize this Transco capacity. When they make this
election, our gathering fee is determined by subtracting the
Transco tariff from the total negotiated fee. The rate
associated with the capacity agreement is based on a Federal
Energy Regulatory Commission tariff that is subject to change.
Accordingly, if the Transco rate increases, our net gathering
fees for these two contracts may be reduced. The customers with
these bundled contracts must make an annual election to receive
this capacity. For 2005 and 2006, only one of our customers has
elected to utilize this capacity.
Note 5. Investment in Discovery Producer Services
Our 40 percent investment in Discovery is accounted for
using the equity method of accounting. At December 31,
2005, Williams owned an additional 20 percent ownership
interest in Discovery through Energy. Although we and Williams
hold a 60 percent interest in Discovery on a combined
basis, the voting provisions of Discoverys limited
liability company agreement give the other member of Discovery
significant participatory rights such that we and Williams do
not control Discovery.
Of the total ownership interest owned by Williams prior to the
transfer of 40 percent to us, a portion was acquired by
Williams in April 2005 resulting in a revised basis used for the
calculation of the 40 percent interest transferred to us in
connection with the Partnerships IPO. As a result, the
carrying value of our 40 percent interest in Discovery and
Owners equity decreased $11.0 million during the
second quarter of 2005.
On August 22, 2005, Discovery made a distribution of
approximately $43.8 million to Williams and the other
member of Discovery at that date. This distribution was
associated with Discoverys operations prior to the
Partnerships IPO; hence, we did not receive any portion of
this distribution. The distribution resulted in a revised basis
used for the calculation of the 40 percent interest
transferred to us in connection with the Partnerships IPO.
As a result, the carrying value of our 40 percent interest
in Discovery and Owners equity decreased
$17.5 million during the third quarter of 2005.
In September 2005, we made a $24.4 million capital
contribution to Discovery for a substantial portion of our share
of the estimated future capital expenditures for the Tahiti
pipeline lateral expansion project.
Williams is the operator of Discovery. Discovery reimburses
Williams for actual payroll and employee benefit costs incurred
on its behalf. In addition, Discovery pays Williams a monthly
operations and management fee to cover the cost of accounting
services, computer systems and management services provided to
it. Discovery also has an agreement with Williams pursuant to
which Williams markets the NGLs and excess natural gas to which
Discovery takes title.
F-68
WILLIAMS PARTNERS GP LLC
NOTES TO CONSOLIDATED BALANCE
SHEET (Continued)
Due to the significance of Discoverys equity earnings to
our financial position, the summarized financial position for
100 percent of Discovery at December 31, 2005 is
presented below (in thousands).
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|
|
|
|
|
|
December 31, | |
|
|
2005 | |
|
|
| |
Current assets
|
|
$ |
70,525 |
|
Non-current restricted cash
|
|
|
44,559 |
|
Property, plant and equipment
|
|
|
344,743 |
|
Current liabilities
|
|
|
(45,070 |
) |
Non-current liabilities
|
|
|
(1,121 |
) |
|
|
|
|
Members capital
|
|
$ |
413,636 |
|
|
|
|
|
|
|
Note 6. |
Property, Plant and Equipment |
Property, plant and equipment, at cost, as of December 31,
2005 is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated | |
|
|
|
|
Depreciable | |
|
|
|
|
Lives | |
|
|
|
|
| |
Land and right of way
|
|
$ |
2,373 |
|
|
|
|
|
Fractionation plant and equipment
|
|
|
16,646 |
|
|
|
30 years |
|
Storage plant and equipment
|
|
|
65,892 |
|
|
|
30 years |
|
Pipeline plant and equipment
|
|
|
23,684 |
|
|
|
20-30 years |
|
Construction work in progress
|
|
|
1,886 |
|
|
|
|
|
Other
|
|
|
1,492 |
|
|
|
5-45 years |
|
|
|
|
|
|
|
|
|
Total property, plant and equipment
|
|
|
111,973 |
|
|
|
|
|
Accumulated depreciation
|
|
|
44,042 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
$ |
67,931 |
|
|
|
|
|
|
|
|
|
|
|
|
Effective December 31, 2005, we adopted FASB Interpretation
(FIN) No. 47, Accounting for Conditional
Asset Retirement Obligations. This Interpretation
clarifies that an entity is required to recognize a liability
for the fair value of a conditional ARO when incurred if the
liabilitys fair value can be reasonably estimated. The
Interpretation clarifies when an entity would have sufficient
information to reasonably estimate the fair value of an ARO. As
required by the new standard, we reassessed the estimated
remaining life of all our assets with a conditional ARO. We
recorded additional liabilities totaling $573,000 equal to the
present value of expected future asset retirement obligations at
December 31, 2005. The liabilities are slightly offset by a
$16,000 increase in property, plant and equipment, net of
accumulated depreciation, recorded as if the provisions of the
Interpretation had been in effect at the date the obligation was
incurred, and the net $557,000 reduced earnings in 2005. If the
Interpretation had been in effect at the beginning of 2005, the
impact to our balance sheet would have been immaterial.
The obligations relate to underground storage caverns and the
associated brine ponds. At the end of the useful life of each
respective asset, we are legally obligated to properly abandon
the storage caverns, empty the brine ponds and restore the
surface, and remove any related surface equipment.
F-69
WILLIAMS PARTNERS GP LLC
NOTES TO CONSOLIDATED BALANCE
SHEET (Continued)
A rollforward of our asset retirement obligation for 2005 is
presented below (in thousands).
|
|
|
|
|
Balance, January 1
|
|
$ |
760 |
|
Liabilities incurred during the period
|
|
|
91 |
|
Liabilities settled during the period
|
|
|
(204 |
) |
Accretion expense
|
|
|
1 |
|
Estimate revisions
|
|
|
(460 |
) |
FIN No. 47 revisions
|
|
|
574 |
|
|
|
|
|
Balance, December 31
|
|
$ |
762 |
|
|
|
|
|
|
|
Note 7. |
Accrued Liabilities |
Accrued liabilities as of December 31, 2005 are as follows
(in thousands):
|
|
|
|
|
Environmental remediation current portion
|
|
$ |
1,424 |
|
Employee costs affiliate
|
|
|
387 |
|
Taxes other than income
|
|
|
375 |
|
Other
|
|
|
187 |
|
|
|
|
|
|
|
$ |
2,373 |
|
|
|
|
|
|
|
Note 8. |
Long-Term Incentive Plan |
In November 2005, we adopted the Williams Partners GP LLC
Long-Term Incentive Plan (the Plan) for employees,
consultants, and directors who perform services for us. The Plan
permits the grant of awards covering an aggregate of 700,000
common units. These awards may be in the form of options,
restricted units, phantom units or unit appreciation rights. Our
Board of Directors Compensation Committee administers the Plan.
During November and December 2005, our we granted 6,146
restricted units pursuant to the Plan to members of our Board of
Directors who are not officers or employees. These restricted
units vest six months from grant date.
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|
Note 9. |
Major Customers, Concentration of Credit Risk and Financial
Instruments |
In 2005, four customers, Williams Power Company (an affiliate
company), SemStream, L.P., Enterprise and BP Products North
America, Inc. (BP) accounted for approximately
25.9 percent, 17.1 percent, 14.1 percent and
13.5 percent, respectively, of our total revenues.
SemStream, L.P., BP, Enterprise and Williams Power Company are
customers of the NGL Services segment. Chevron is a customer of
the Gathering and Processing segment.
Our Carbonate Trend gathering pipeline has only two customers.
The loss of either of these customers, unless replaced, would
have a significant impact on the Gathering and Processing
segment.
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|
|
Concentration of Credit Risk |
Our cash equivalents consist of high-quality securities placed
with various major financial institutions with credit ratings at
or above AA by Standard & Poors or Aa by Moodys
Investors Service.
F-70
WILLIAMS PARTNERS GP LLC
NOTES TO CONSOLIDATED BALANCE
SHEET (Continued)
The following table summarizes the concentration of accounts
receivable by service and segment as of December 31, 2005
(in thousands).
|
|
|
|
|
|
Gathering and Processing:
|
|
|
|
|
|
Natural gas gathering
|
|
$ |
525 |
|
NGL Services:
|
|
|
|
|
|
Fractionation services
|
|
|
532 |
|
|
Amounts due from fractionator partners
|
|
|
1,834 |
|
|
Storage
|
|
|
793 |
|
|
Other
|
|
|
260 |
|
|
|
|
|
|
|
$ |
3,944 |
|
|
|
|
|
Our fractionation and storage customers include crude refiners;
propane wholesalers and retailers; gas producers; natural gas
plant, fractionator and storage operators; and NGL traders and
pipeline operators. Our two Carbonate Trend natural gas
gathering customers are oil and gas producers. While sales to
our customers are unsecured, we routinely evaluate their
financial condition and creditworthiness.
The carrying amount of cash and cash equivalents reported in the
balance sheet approximates fair value due to the short-term
maturity of these instruments.
The following table summarizes our financial instruments as of
December 31, 2005 (in thousands).
|
|
|
|
|
|
|
|
|
|
|
Carrying | |
|
Fair | |
|
|
Amount | |
|
Value | |
|
|
| |
|
| |
Cash and cash equivalents
|
|
$ |
6,839 |
|
|
$ |
6,839 |
|
|
|
Note 10. |
Credit Facilities |
On May 20, 2005, Williams amended its $1.275 billion
revolving credit facility (Williams facility), which
is available for borrowings and letters of credit, to allow us
to borrow up to $75 million under the Williams facility.
Borrowings under the Williams facility mature on May 3,
2007. Our $75 million borrowing limit under the Williams
facility is available for general partnership purposes,
including acquisitions, but only to the extent that sufficient
amounts remain unborrowed by Williams and its other
subsidiaries. At December 31, 2005, letters of credit
totaling $378 million had been issued on behalf of Williams
by the participating institutions under the Williams facility
and no revolving credit loans were outstanding.
Interest on any borrowings under the Williams facility is
calculated based on our choice of two methods: (i) a
fluctuating rate equal to the facilitating banks base rate
plus an applicable margin or (ii) a periodic fixed rate
equal to LIBOR plus an applicable margin. We are also required
to pay or reimburse Williams for a commitment fee based on the
unused portion of its $75 million borrowing limit under the
Williams facility, currently 0.325 percent annually. The
applicable margin, currently 1.75 percent, and the
commitment fee are based on Williams senior unsecured
long-term debt rating. Under the Williams facility, Williams and
certain of its subsidiaries, other than us, are required to
comply with certain financial and other covenants. Significant
financial covenants under the Williams facility to which
Williams is subject include the following:
|
|
|
|
|
ratio of debt to net worth no greater than
(i) 70 percent through December 31, 2005, and
(ii) 65 percent for the remaining term of the
agreement; |
|
|
|
ratio of debt to net worth no greater than 55 percent for
Northwest Pipeline Corporation, a wholly owned subsidiary of
Williams, and Transco; and |
F-71
WILLIAMS PARTNERS GP LLC
NOTES TO CONSOLIDATED BALANCE
SHEET (Continued)
|
|
|
|
|
ratio of EBITDA to interest, on a rolling four quarter basis, no
less than (i) 2.0 for any period after March 31, 2005
through December 31, 2005, and (ii) 2.5 for the
remaining term of the agreement. |
In August 2005, we entered into a $20 million revolving
credit facility (the credit facility) with Williams
as the lender. The credit facility is available exclusively to
fund working capital requirements. Borrowings under the credit
facility mature on May 3, 2007 and bear interest at the
same rate as for borrowings under the Williams facility
described above. We pay a commitment fee to Williams on the
unused portion of the credit facility of 0.30 percent
annually. We are required to reduce all borrowings under the
credit facility to zero for a period of at least 15 consecutive
days once each 12-month
period prior to the maturity date of the credit facility. No
amounts have been drawn on this facility.
In May 2006, Williams replaced its $1.275 billion secured
credit facility with a $1.5 billion unsecured credit
facility. The new facility contains similar terms and covenants
applicable to us. This revolving credit facility is available
for borrowings and letters of credit and will continue to allow
us to borrow up to $75 million for general partnership
purposes, including acquisitions, but only to the extent that
sufficient amounts remain unborrowed by Williams and its other
subsidiaries.
We lease automobiles for use in our NGL Services segment. We
account for these leases as operating leases. Future minimum
annual rentals under non-cancelable operating leases as of
December 31, 2005 are as follows (in thousands):
|
|
|
|
|
2006
|
|
$ |
30 |
|
2007
|
|
|
29 |
|
2008
|
|
|
27 |
|
2009
|
|
|
10 |
|
2010
|
|
|
|
|
|
|
|
|
|
|
$ |
96 |
|
|
|
|
|
|
|
Note 11. |
Commitments and Contingencies |
Environmental Matters. We are a participant in certain
environmental remediation activities associated with soil and
groundwater contamination at our Conway storage facilities.
These activities relate to four projects that are in various
remediation stages including assessment studies, cleanups and/or
remedial operations and monitoring. We continue to coordinate
with the Kansas Department of Health and Environment
(KDHE) to develop screening, sampling, cleanup and
monitoring programs. The costs of such activities will depend
upon the program scope ultimately agreed to by the KDHE and are
expected to be paid over the next two to nine years.
In 2004, we purchased an insurance policy that covers up to
$5 million of remediation costs until an active remediation
system is in place or April 30, 2008, whichever is earlier,
excluding operation and maintenance costs and ongoing monitoring
costs, for these projects to the extent such costs exceed a
$4.2 million deductible. The policy also covers costs
incurred as a result of third party claims associated with then
existing but unknown contamination related to the storage
facilities. The aggregate limit under the policy for all claims
is $25 million. In addition, under an omnibus agreement
with Williams entered into at the closing of the IPO, Williams
has agreed to indemnify us for the $4.2 million deductible
(less amounts expended prior to the closing of the IPO) of
remediation expenditures not covered by the insurance policy,
excluding costs of project management and soil and groundwater
monitoring. There is a $14 million cap on the total amount
of indemnity coverage under the omnibus agreement, which will be
reduced by actual recoveries under the environmental insurance
policy. There is also a three-year time limitation from the IPO
F-72
WILLIAMS PARTNERS GP LLC
NOTES TO CONSOLIDATED BALANCE
SHEET (Continued)
closing date, August 23, 2005. The benefit of this
indemnification will be accounted for as a capital contribution
to us by Williams as the costs are reimbursed. We estimate that
the approximate cost of this project management and soil and
groundwater monitoring associated with the four remediation
projects at the Conway storage facilities and for which we will
not be indemnified will be approximately $200,000 to
$400,000 per year following the completion of the
remediation work.
At December 31, 2005, we had accrued liabilities totaling
$5.4 million for these costs. It is reasonably possible
that we will incur losses in excess of our accrual for these
matters. However, a reasonable estimate of such amounts cannot
be determined at this time because actual costs incurred will
depend on the actual number of contaminated sites identified,
the amount and extent of contamination discovered, the final
cleanup standards mandated by KDHE and other governmental
authorities and other factors.
Other. We are not currently a party to any legal
proceedings but are a party to various administrative and
regulatory proceedings that have arisen in the ordinary course
of our business. Management, including internal counsel,
currently believes that the ultimate resolution of the foregoing
matters, taken as a whole, and after consideration of amounts
accrued, insurance coverage or other indemnification
arrangements, will not have a material adverse effect upon our
future financial position.
|
|
Note 12. |
Segment Disclosures |
Our reportable segments are strategic business units that offer
different products and services. The Segments are managed
separately because each segment requires different industry
knowledge, technology and marketing strategies. The accounting
policies of the segments are the same as those described in
Note 3, Summary of Significant Accounting Policies.
Long-lived assets are comprised of property, plant and equipment.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering & | |
|
NGL | |
|
|
|
|
Processing | |
|
Services | |
|
Total | |
|
|
| |
|
| |
|
| |
|
|
(In thousands) | |
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment Assets
|
|
$ |
171,009 |
|
|
$ |
64,579 |
|
|
$ |
235,588 |
|
Other assets and eliminations
|
|
|
|
|
|
|
|
|
|
|
5,353 |
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
|
|
|
|
|
|
|
|
$ |
240,941 |
|
|
|
|
|
|
|
|
|
|
|
Equity method investments
|
|
$ |
150,260 |
|
|
$ |
|
|
|
$ |
150,260 |
|
Additions to long-lived assets
|
|
|
|
|
|
|
3,688 |
|
|
|
3,688 |
|
F-73
APPENDIX A
GLOSSARY OF TERMS
Adjusted EBITDA: For Discovery and Four Corners, net
income plus interest (income) expense, depreciation,
amortization and accretion, further adjusted for certain
non-cash, non-recurring items.
Adjusted EBITDA Excluding Equity Investments: For
Williams Partners L.P., net income (loss) plus interest (income)
expense, depreciation and accretion and the amortization of a
natural gas contract, less our equity earnings in Discovery and
Four Corners, further adjusted for certain non-cash,
non-recurring items.
Adjusted operating surplus: For any period, operating
surplus generated during that period is adjusted to:
(a) decrease operating surplus by:
|
|
|
(1) any net increase in working capital borrowings with
respect to that period; and |
|
|
(2) any net reduction in cash reserves for operating
expenditures with respect to that period not relating to an
operating expenditure made with respect to that period; and |
(b) increase operating surplus by:
|
|
|
(1) any net decrease in working capital borrowings with
respect to that period; and |
|
|
(2) 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. |
Adjusted operating surplus does not include that portion of
operating surplus included in clauses (a)(1) and (a)(2) of
the definition of operating surplus.
Available cash: For any quarter ending prior to
liquidation:
(a) the sum of:
|
|
|
(1) all cash and cash equivalents of Williams Partners L.P.
and its subsidiaries on hand at the end of that quarter; and |
|
|
(2) all additional cash and cash equivalents of Williams
Partners L.P. and its subsidiaries on hand on the date of
determination of available cash for that quarter resulting from
working capital borrowings made after the end of 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
Williams Partners L.P. and its subsidiaries (including reserves
for future capital expenditures and for future credit needs of
Williams Partners L.P. and its subsidiaries) after that quarter; |
|
|
(2) comply with applicable law or any debt instrument or
other agreement or obligation to which Williams Partners L.P. 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 for distributions on the subordinated
units unless our general partner has determined that the
establishment of reserves will not prevent Williams Partners
L.P. from distributing the minimum quarterly distribution on all
common units and any cumulative common unit arrearages thereon
with respect to that quarter; and
provided, further, that disbursements made by Williams
Partners L.P. or any of its subsidiaries or cash reserves
established, increased or reduced after the end of that quarter
but on or before the date of
A-1
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.
Barrel: One barrel of petroleum products equals 42
U.S. gallons.
Bcf/d: One billion cubic feet of natural gas per day.
bpd: Barrels per day.
Btu: When used in terms of volumes, Btu is used to refer
to the amount of natural gas required to raise the temperature
of one pound of water by one degree Fahrenheit at one
atmospheric pressure.
Capital account: The capital account maintained for a
partner under the partnership agreement. The capital account in
respect of a general partner interest, a common unit, a
subordinated unit, an incentive distribution right or other
partnership interest will be the amount which that capital
account would be if that general partner interest, common unit,
subordinated unit, incentive distribution right or other
partnership interest were the only interest in Williams Partners
L.P. held by a partner.
Capital surplus: All available cash distributed by us
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 as of the end of the quarter before that distribution.
Any excess available cash will be deemed to be capital surplus.
¢/ MMBtu: Cents per one million British Thermal
Units.
Current market price: For any class of units listed 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.
Distributable Cash Flow: For Discovery and Four Corners,
net income (loss) plus depreciation, amortization and accretion
and less maintenance capital expenditures.
Distributable Cash Flow Excluding Equity Investments: For
Williams Partners L.P., net income (loss) plus the non-cash
affiliate interest expense associated with the advances from
affiliate to our predecessor that were forgiven by Williams,
depreciation and accretion, the amortization of a natural gas
contract, and reimbursements from Williams under our omnibus
agreement, less our equity earnings in Discovery and Four
Corners and maintenance capital expenditures, further adjusted
for certain non-cash, non-recurring items.
Fractionation: The process by which a mixed stream of
natural gas liquids is separated into its constituent products.
GAAP: Generally accepted accounting principles in the
United States.
General and administrative expenses: General and
administrative expenses consist of employment costs, cost of
facilities, as well as legal, information technology, audit and
other administrative costs.
Incentive distribution right: A non-voting limited
partner partnership interest issued to our general partner. The
partnership interest will confer upon its holder only the rights
and obligations specifically provided in the partnership
agreement for incentive distribution rights.
Incentive distributions: The distributions of available
cash from operating surplus initially made to our general
partner that are in excess of our general partners
aggregate 2% general partner interest.
(a) borrowings, refinancings or refundings of indebtedness
(other than for working capital borrowings and other than for
items purchased on open account in the ordinary course of
business) by Williams Partners L.P. or any of its subsidiaries
and sales of any debt securities of Williams Partners L.P. or
any of its subsidiaries;
(b) sales of equity interests by Williams Partners L.P. or
any of its subsidiaries; or
(c) sales or other voluntary or involuntary dispositions of
any assets of Williams Partners L.P. or any of its subsidiaries
(other than sales or other dispositions of inventory, accounts
receivable and other assets in the
A-2
ordinary course of business, and sales or other dispositions of
assets as a part of normal retirements or replacements).
Long-haul natural gas pipelines: Generally, interstate
natural gas pipelines that serve end markets.
LNG: Liquefied natural gas.
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 of natural gas per day.
NGLs: Natural gas liquids.
Operating expenditures: All expenditures of Williams
Partners L.P. and its subsidiaries, including, but not limited
to, taxes, reimbursements of our general partner, repayment of
working capital borrowings, debt service payments and capital
expenditures, subject to the following:
(a) Payments (including prepayments) of principal of and
premium on indebtedness, other than working capital borrowings
will not constitute operating expenditures.
(b) Operating expenditures will not include:
|
|
|
(1) capital expenditures made for acquisitions or for
capital improvements; |
|
|
(2) payment of transaction expenses relating to interim
capital transactions; or |
|
|
(3) distributions to partners. |
Where capital expenditures are made in part for acquisitions or
for capital improvements and in part for other purposes, our
general partner, with the concurrence of the conflicts
committee, shall determine the allocation between the amounts
paid for each and, with respect to the part of such capital
expenditures made for other purposes, the period over which the
capital expenditures made for other purposes will be deducted as
an operating expenditure in calculating operating surplus.
Operating surplus: For any period prior to liquidation,
on a cumulative basis and without duplication:
(a) the sum of
|
|
|
(1) $10.0 million; |
|
|
(2) all the cash of Williams Partners L.P. and its
subsidiaries on hand as of the closing date of its initial
public offering, excluding amounts retained from the proceeds of
its initial public offering to make a capital contribution to
Discovery to fund an escrow account required in connection with
the Tahiti pipeline lateral expansion project; |
|
|
(3) all cash receipts of Williams Partners L.P. and its
subsidiaries for the period beginning on the closing date of the
initial public offering and ending with the last day of that
period, other than cash receipts from interim capital
transactions; and |
|
|
(4) all cash receipts of Williams Partners L.P. and its
subsidiaries after the end of that period but on or before the
date of determination of operating surplus for the period
resulting from working capital borrowings; less |
(b) the sum of:
|
|
|
(1) operating expenditures for the period beginning on the
closing date of the initial public offering and ending with the
last day of that period (other than operating expenditures
funded with cash reserves established pursuant to
clause (2) below); and |
A-3
|
|
|
(2) the amount of cash reserves established by our general
partner to provide funds for future operating expenditures;
provided however, that disbursements made (including
contributions to a member of Williams Partners L.P. and its
subsidiaries or disbursements on behalf of a member of Williams
Partners L.P. and its subsidiaries) or cash reserves
established, increased or reduced after the end of that period
but on or before the date of determination of available cash for
that period shall be deemed to have been made, established,
increased or reduced for purposes of determining operating
surplus, within that period if our general partner so determines. |
Recompletions: After the initial completion of a well,
the action and techniques of reentering the well and redoing or
repairing the original completion to restore the wells
productivity.
Subordination period: The subordination period will
generally extend from the closing of the initial public offering
until the first to occur of:
(a) the first day of any quarter beginning after
June 30, 2008 for which:
|
|
|
(1) distributions of available cash from operating surplus
on each of the outstanding common units and subordinated units
equaled or exceeded the sum of the minimum quarterly
distributions on all of the outstanding common units and
subordinated units for each of the three consecutive,
non-overlapping four-quarter periods immediately preceding that
date; |
|
|
(2) the adjusted operating surplus 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 common units
and subordinated units that were outstanding during those
periods on a fully diluted basis, and the related distribution
on the general partner interest in Williams Partners
L.P.; and |
|
|
(3) there are no outstanding cumulative common units
arrearages. |
(b) the date on which our general partner is removed as
general partner of Williams Partners L.P. upon the requisite
vote by the limited partners under circumstances where cause
does not exist and units held by our general partner and its
affiliates are not voted in favor of the removal
provided, however, subordinated units may convert into
common units as described in How We Make Cash
Distributions Subordination Period Early
Termination of Subordinated Units.
Throughput: The volume of product transported or passing
through a pipeline, plant, terminal or other facility.
Units: Refers to both common units and subordinated units.
Working capital borrowings: Borrowings used exclusively
for working capital purposes or to pay distributions to partners
made pursuant to a credit facility or other arrangement to the
extent such borrowings are required to be reduced to a
relatively small amount each year for an economically meaningful
period of time.
Workover: Operations on a completed production well to
clean, repair and maintain the well for the purposes of
increasing or restoring production.
A-4
6,600,000 Common Units
Representing Limited Partner Interests
PROSPECTUS
,
2006
Joint Book-Running Managers
Lehman
Brothers
Citigroup
A.G. Edwards
Merrill Lynch &
Co.
Wachovia
Securities
RBC Capital
Markets
Raymond James
PART II
INFORMATION NOT REQUIRED IN THE PROSPECTUS
|
|
Item 13. |
Other Expenses of Issuance and Distribution. |
Set forth below are the expenses (other than underwriting
discounts and commissions) expected to be incurred in connection
with the issuance and distribution of the securities registered
hereby. With the exception of the Securities and Exchange
Commission registration fee, the NASD filing fee and the NYSE
filing fee, the amounts set forth below are estimates.
|
|
|
|
|
|
SEC registration fee
|
|
$ |
28,028 |
|
NASD filing fee
|
|
|
28,816 |
|
NYSE listing fee
|
|
|
38,640 |
|
Printing and engraving expenses
|
|
|
300,000 |
|
Accounting fees and expenses
|
|
|
1,050,000 |
|
Legal fees and expenses
|
|
|
675,000 |
|
Transfer agent and registrar fees
|
|
|
5,000 |
|
Miscellaneous
|
|
|
224,516 |
|
|
|
|
|
|
Total
|
|
$ |
2,350,000 |
|
|
|
|
|
|
|
Item 14. |
Indemnification of Directors and Officers. |
The section of the prospectus entitled The Partnership
Agreement Indemnification discloses that we
will generally indemnify officers, directors and affiliates of
our 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 8 of the form of Underwriting Agreement to be filed
as an exhibit to this registration statement in which we and our
affiliates 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 person from and against all claims and demands
whatsoever.
|
|
Item 15. |
Recent Sales of Unregistered Securities. |
On February 28, 2005, in connection with the formation of
the partnership, Williams Partners L.P. issued to Williams
Energy Services, LLC the 98% limited partner interest in the
partnership for $980 in an offering exempt from registration
under Section 4(2) of the Securities Act.
On August 23, 2005, in connection with the consummation of
the transactions contemplated by a Contribution Agreement
entered into at the closing of the initial public offering,
Williams Partners L.P. issued (i) an aggregate 2,000,000
Common Units and 7,000,000 Subordinated Units to Williams
Energy, L.L.C., Williams Energy Services, LLC, Williams Partners
Holdings LLC and Williams Discovery Pipeline LLC in exchange for
certain member interests and (ii) the continuation of a
2.0% general partner interest in Williams Partners L.P. and
incentive distribution rights (which represent the right to
receive increasing percentages of quarterly distributions in
excess of specified amounts) to Williams Partners GP LLC in
exchange for certain member interests. Each subordinated unit
will convert into one common unit at the end of the
subordination period. Unless earlier terminated pursuant to the
terms of the partnership agreement of Williams Partners L.P.,
the subordination period will extend until the first day of any
quarter beginning after June 30, 2008 that Williams
Partners L.P. meets the financial tests set forth in its
partnership agreement. The foregoing transactions were
undertaken in reliance upon the exemption from the registration
requirements of the
II-1
Securities Act afforded by Section 4(2). Williams Partners
L.P. believes that exemptions other than the foregoing exemption
may exist for these transactions.
There have been no other sales of unregistered securities within
the past three years.
|
|
Item 16. |
Exhibits and Financial Statement Schedules. |
(a) The following documents are filed as exhibits to this
registration statement:
|
|
|
|
|
|
|
Exhibit |
|
|
|
|
Number |
|
|
|
Description |
|
|
|
|
|
|
1 |
.1** |
|
|
|
Form of Underwriting Agreement. |
|
2 |
.1+ |
|
|
|
Purchase and Sale Agreement, dated April 6, 2006, by and
among Williams Energy Services, LLC, Williams Field Services
Group, LLC, Williams Field Services Company, LLC, Williams
Partners GP LLC, Williams Partners L.P. and Williams
Partners Operating LLC (incorporated by reference to
Exhibit 2.1 to Williams Partners L.P.s current
report on Form 8-K filed on April 7, 2006 (File
No. 001-32599)). |
|
3 |
.1+ |
|
|
|
Certificate of Limited Partnership of Williams Partners L.P.
(incorporated by reference to Exhibit 3.1 to Williams
Partners L.P.s registration statement on Form S-1
filed on May 2, 2005 (File No. 333-124517)). |
|
3 |
.2+ |
|
|
|
Amended and Restated Agreement of Limited Partnership of
Williams Partners L.P. (including form of common unit
certificate) (incorporated by reference to Exhibit 3.1 to
Williams Partners L.P.s current report on Form 8-K
filed on August 26, 2005 (File No. 001-32599)). |
|
3 |
.3+ |
|
|
|
Certificate of Formation of Williams Partners GP LLC
(incorporated by reference to Exhibit 3.3 to Williams
Partners L.P.s registration statement on Form S-1
filed on May 2, 2005 (File No. 333-124517)). |
|
3 |
.4+ |
|
|
|
Amended and Restated Limited Liability Company Agreement of
Williams Partners GP LLC (incorporated by reference to
Exhibit 3.2 to Williams Partners L.P.s current report
on Form 8-K filed on August 26, 2005
(File No. 001-32599)). |
|
5 |
.1* |
|
|
|
Opinion of Andrews Kurth LLP as to the legality of the
securities being registered. |
|
8 |
.1** |
|
|
|
Opinion of Andrews Kurth LLP relating to tax matters. |
|
10 |
.1+ |
|
|
|
Credit Agreement dated as of May 1, 2006 among The Williams
Companies, Inc., Williams Partners L.P., Northwest Pipeline
Corporation, Transcontinental Gas Pipe Line Corporation, and the
Banks named therein, Citibank, N.A., as administrative
agent, and the other parties thereto (incorporated by reference
to Exhibit 10.1 to The Williams Companies, Inc.s
current report on Form 8-K filed May 1, 2006
(File No. 001-04174)). |
|
10 |
.2+ |
|
|
|
Contribution, Conveyance and Assumption Agreement, dated
August 23, 2005, by and among Williams Partners L.P.,
Williams Energy, L.L.C., Williams Partners GP LLC, Williams
Partners Operating LLC, Williams Energy Services, LLC, Williams
Discovery Pipeline LLC, Williams Partners Holdings LLC and
Williams Natural Gas Liquids, Inc. (incorporated by reference to
Exhibit 10.3 to Williams Partners L.P.s current
report on Form 8-K filed on August 26, 2005
(File No. 001-32599)). |
|
10 |
.3+ |
|
|
|
Omnibus Agreement among Williams Partners L.P., Williams Energy
Services, LLC, Williams Energy, L.L.C., Williams Partners
Holdings LLC, Williams Discovery Pipeline LLC, Williams Partners
GP LLC, Williams Partners Operating LLC and (for purposes of
Articles V and VI thereof only) The Williams Companies,
Inc. (incorporated by reference to Exhibit 10.1 to Williams
Partners L.P.s current report on Form 8-K filed on
August 26, 2005 (File No. 001-32599)). |
|
10 |
.4+ |
|
|
|
Williams Partners GP LLC Long-Term Incentive Plan (incorporated
by reference to Exhibit 10.2 to Williams Partners
L.P.s current report on Form 8-K filed on
August 26, 2005 (File No. 001-32599)). |
|
10 |
.5+ |
|
|
|
Working Capital Loan Agreement, dated August 23, 2005,
between The Williams Companies, Inc. and Williams Partners L.P.
(incorporated by reference to Exhibit 10.4 to Williams
Partners L.P.s current report on Form 8-K filed on
August 26, 2005 (File No. 001-32599)). |
II-2
|
|
|
|
|
|
|
Exhibit |
|
|
|
|
Number |
|
|
|
Description |
|
|
|
|
|
|
10 |
.6+ |
|
|
|
Fractionation Agreement, dated as of July 18, 1997, by and
between MAPCO Natural Gas Liquids Inc. and Amoco Oil Company
(incorporated by reference to Exhibit 10.6 to Amendment
No. 3 to Williams Partners L.P.s registration
statement on Form S-1 filed on August 3, 2005
(File No. 333-124517)). |
|
10 |
.7+ |
|
|
|
Third Amended and Restated Limited Liability Company Agreement
for Discovery Producer Services LLC (incorporated by reference
to Exhibit 10.7 to Amendment No. 1 to Williams
Partners L.P.s registration statement on Form S-1
filed on June 24, 2005 (File No. 333-124517)). |
|
10 |
.8+ |
|
|
|
Director Compensation Policy (incorporated by reference to
Exhibit 10.1 to Williams Partners L.P.s current
report on Form 8-K filed December 1, 2005
(File No. 001-32599)). |
|
10 |
.9+ |
|
|
|
Form of Grant Agreement for Restricted Units under Williams
Partners GP LLC Long-Term Incentive Plan (incorporated by
reference to Exhibit 10.2 to Williams Partners L.P.s
current report on Form 8-K filed December 1, 2005
(File No. 001-32599)). |
|
10 |
.10+ |
|
|
|
Base Contract for Sale and Purchase of Natural Gas between
Williams Natural Gas Liquids, Inc. and Williams Power Company,
Inc., dated August 15, 2005 (incorporated by reference to
Exhibit 10.7 to Williams Partners L.P.s quarterly
report on Form 10-Q filed on September 22, 2005
(File No. 001-32599)). |
|
10 |
.11+ |
|
|
|
Form of Contribution, Conveyance and Assumption Agreement by and
among Williams Energy Services, LLC, Williams Field Services
Company, LLC, Williams Field Services Group, LLC, Williams
Partners GP LLC, Williams Partners L.P. and Williams Partners
Operating LLC (included as Exhibit A to Exhibit 2.1) |
|
10 |
.12+ |
|
|
|
Form of Amended and Restated Limited Liability Company Agreement
of Williams Four Corners LLC (included as Exhibit B to
Exhibit 2.1) |
|
10 |
.13+ |
|
|
|
Form of Loan Agreement between The Williams Companies, Inc. and
Williams Four Corners LLC (included as Exhibit A to
Exhibit B to Exhibit 2.1) |
|
10 |
.14+ |
|
|
|
Form of Contribution, Conveyance and Assumption Agreement by and
among Williams Field Services Company, LLC and Williams Four
Corners LLC (included as Exhibit C to Exhibit 2.1) |
|
21 |
.1+ |
|
|
|
List of subsidiaries of Williams Partners L.P. (incorporated by
reference to Exhibit 21.1 to Amendment No. 1 to
Williams Partners L.P.s registration statement on
Form S-1 filed on June 24, 2005
(File No. 333-124517)). |
|
23 |
.1** |
|
|
|
Consent of Ernst & Young LLP. |
|
23 |
.2** |
|
|
|
Consent of Ernst & Young LLP. |
|
23 |
.3* |
|
|
|
Consent of Andrews Kurth LLP (contained in Exhibit 5.1). |
|
23 |
.4** |
|
|
|
Consent of Andrews Kurth LLP (contained in Exhibit 8.1). |
|
24 |
.1* |
|
|
|
Powers of Attorney (included on the signature page). |
|
99 |
.1+ |
|
|
|
Pre-approval Policy with respect to audit and non-audit services
of the audit committee of the board of directors of Williams
Partners GP LLC (incorporated by reference to Exhibit 99.1
to Williams Partners L.P.s annual report on Form 10-K
filed on March 3, 2006 (File No. 001-32599)). |
+ Incorporated by reference.
|
|
|
|
|
Confidential treatment granted for omitted portions. |
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.
II-3
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 of 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 registrant undertakes to send to each limited partner at
least on an annual basis a detailed statement of any
transactions with Williams Partners GP LLC, our general partner,
or its affiliates, and of fees, commissions, compensation and
other benefits paid, or accrued to Williams Partners GP LLC or
its affiliates 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 limited partners the
financial statements required by
Form 10-K for the
first full fiscal year of operations of the partnership.
II-4
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as
amended, the registrant has duly caused this Registration
Statement to be signed on its behalf by the undersigned,
thereunto duly authorized, in the City of Tulsa, State of
Oklahoma, on May 22, 2006.
|
|
|
|
By: |
Williams Partners GP LLC,
its General Partner |
|
|
|
|
By: |
/s/ Steven J. Malcolm |
|
|
|
|
|
Steven J. Malcolm |
|
Chairman of the Board and |
|
Chief Executive Officer |
POWER OF ATTORNEY
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 on the dates
indicated.
|
|
|
|
|
|
|
Name |
|
Title |
|
Date |
|
|
|
|
|
|
*
Steven
J. Malcolm |
|
Chairman of the Board
and Chief Executive Officer
(Principal Executive Officer) |
|
May 22, 2006 |
|
*
Donald
R. Chappel |
|
Chief Financial Officer and Director
(Principal Financial Officer) |
|
May 22, 2006 |
|
*
Ted
T. Timmermans |
|
Vice President, Chief Accounting Officer and Controller
(Principal Accounting Officer) |
|
May 22, 2006 |
|
*
Alan
S. Armstrong |
|
Chief Operating Officer and Director |
|
May 22, 2006 |
|
*
Thomas
C. Knudson |
|
Director |
|
May 22, 2006 |
|
*
Bill
Z. Parker |
|
Director |
|
May 22, 2006 |
|
*
Alice
M. Peterson |
|
Director |
|
May 22, 2006 |
II-5
|
|
|
|
|
|
|
Name |
|
Title |
|
Date |
|
|
|
|
|
|
*
Phillip
D. Wright |
|
Director |
|
May 22, 2006 |
|
*By: |
|
/s/ Richard M. Carson
Richard
M. Carson
Attorney-in-fact |
|
|
|
|
II-6
EXHIBIT INDEX
|
|
|
|
|
|
|
Exhibit |
|
|
|
|
Number |
|
|
|
Description |
|
|
|
|
|
|
1 |
.1** |
|
|
|
Form of Underwriting Agreement. |
|
2 |
.1+ |
|
|
|
Purchase and Sale Agreement, dated April 6, 2006, by and
among Williams Energy Services, LLC, Williams Field Services
Group, LLC, Williams Field Services Company, LLC, Williams
Partners GP LLC, Williams Partners L.P. and Williams Partners
Operating LLC (incorporated by reference to Exhibit 2.1 to
Williams Partners L.P.s current report on
Form 8-K filed on April 7, 2006 (File
No. 001-32599)). |
|
3 |
.1+ |
|
|
|
Certificate of Limited Partnership of Williams Partners L.P.
(incorporated by reference to Exhibit 3.1 to Williams
Partners L.P.s registration statement on Form S-1
filed on May 2, 2005 (File No. 333-124517)). |
|
3 |
.2+ |
|
|
|
Amended and Restated Agreement of Limited Partnership of
Williams Partners L.P. (including form of common unit
certificate) (incorporated by reference to Exhibit 3.1 to
Williams Partners L.P.s current report on Form 8-K
filed on August 26, 2005 (File No. 001-32599)). |
|
3 |
.3+ |
|
|
|
Certificate of Formation of Williams Partners GP LLC
(incorporated by reference to Exhibit 3.3 to Williams
Partners L.P.s registration statement on Form S-1
filed on May 2, 2005 (File No. 333-124517)). |
|
3 |
.4+ |
|
|
|
Amended and Restated Limited Liability Company Agreement of
Williams Partners GP LLC (incorporated by reference to
Exhibit 3.2 to Williams Partners L.P.s current report
on Form 8-K filed on August 26, 2005 (File
No. 001-32599)). |
|
5 |
.1* |
|
|
|
Opinion of Andrews Kurth LLP as to the legality of the
securities being registered. |
|
8 |
.1** |
|
|
|
Opinion of Andrews Kurth LLP relating to tax matters. |
|
10 |
.1+ |
|
|
|
Credit Agreement dated as of May 1, 2006 among The Williams
Companies, Inc., Williams Partners L.P., Northwest Pipeline
Corporation, Transcontinental Gas Pipe Line Corporation, and the
Banks named therein, Citibank, N.A., as administrative agent,
and the other parties thereto (incorporated by reference to
Exhibit 10.1 to The Williams Companies, Inc.s current
report on Form 8-K filed May 1, 2006
(File No. 001-04174)). |
|
10 |
.2+ |
|
|
|
Contribution, Conveyance and Assumption Agreement, dated
August 23, 2005, by and among Williams Partners L.P.,
Williams Energy, L.L.C., Williams Partners GP LLC, Williams
Partners Operating LLC, Williams Energy Services, LLC, Williams
Discovery Pipeline LLC, Williams Partners Holdings LLC and
Williams Natural Gas Liquids, Inc. (incorporated by reference to
Exhibit 10.3 to Williams Partners L.P.s current
report on Form 8-K filed on August 26, 2005
(File No. 001-32599)). |
|
10 |
.3+ |
|
|
|
Omnibus Agreement among Williams Partners L.P., Williams Energy
Services, LLC, Williams Energy, L.L.C., Williams Partners
Holdings LLC, Williams Discovery Pipeline LLC, Williams Partners
GP LLC, Williams Partners Operating LLC and (for purposes of
Articles V and VI thereof only) The Williams Companies,
Inc. (incorporated by reference to Exhibit 10.1 to Williams
Partners L.P.s current report on Form 8-K filed on
August 26, 2005 (File No. 001-32599)). |
|
10 |
.4+ |
|
|
|
Williams Partners GP LLC Long-Term Incentive Plan (incorporated
by reference to Exhibit 10.2 to Williams Partners
L.P.s current report on Form 8-K filed on
August 26, 2005 (File No. 001-32599)). |
|
10 |
.5+ |
|
|
|
Working Capital Loan Agreement, dated August 23, 2005,
between The Williams Companies, Inc. and Williams Partners L.P.
(incorporated by reference to Exhibit 10.4 to Williams
Partners L.P.s current report on Form 8-K filed on
August 26, 2005 (File No. 001-32599)). |
|
10 |
.6+ |
|
|
|
Fractionation Agreement, dated as of July 18, 1997, by and
between MAPCO Natural Gas Liquids Inc. and Amoco Oil Company
(incorporated by reference to Exhibit 10.6 to Amendment
No. 3 to Williams Partners L.P.s registration
statement on Form S-1 filed on August 3, 2005
(File No. 333-124517)). |
|
10 |
.7+ |
|
|
|
Third Amended and Restated Limited Liability Company Agreement
for Discovery Producer Services LLC (incorporated by reference
to Exhibit 10.7 to Amendment No. 1 to Williams
Partners L.P.s registration statement on Form S-1
filed on June 24, 2005 (File No. 333-124517)). |
|
10 |
.8+ |
|
|
|
Director Compensation Policy (incorporated by reference to
Exhibit 10.1 to Williams Partners L.P.s current
report on Form 8-K filed December 1, 2005 (File
No. 001-32599)). |
|
|
|
|
|
|
|
Exhibit |
|
|
|
|
Number |
|
|
|
Description |
|
|
|
|
|
|
10 |
.9+ |
|
|
|
Form of Grant Agreement for Restricted Units under Williams
Partners GP LLC Long-Term Incentive Plan (incorporated by
reference to Exhibit 10.2 to Williams Partners L.P.s
current report on Form 8-K filed December 1, 2005
(File No. 001-32599)). |
|
10 |
.10+ |
|
|
|
Base Contract for Sale and Purchase of Natural Gas between
Williams Natural Gas Liquids, Inc. and Williams Power Company,
Inc., dated August 15, 2005 (incorporated by reference to
Exhibit 10.7 to Williams Partners L.P.s quarterly
report on Form 10-Q filed on September 22, 2005 (File
No. 001-32599)). |
|
10 |
.11+ |
|
|
|
Form of Contribution, Conveyance and Assumption Agreement by and
among Williams Energy Services, LLC, Williams Field Services
Company, LLC, Williams Field Services Group, LLC, Williams
Partners GP LLC, Williams Partners L.P. and Williams Partners
Operating LLC (included as Exhibit A to Exhibit 2.1) |
|
10 |
.12+ |
|
|
|
Form of Amended and Restated Limited Liability Company Agreement
of Williams Four Corners LLC (included as Exhibit B to
Exhibit 2.1) |
|
10 |
.13+ |
|
|
|
Form of Loan Agreement between The Williams Companies, Inc. and
Williams Four Corners LLC (included as Exhibit A to
Exhibit B to Exhibit 2.1) |
|
10 |
.14+ |
|
|
|
Form of Contribution, Conveyance and Assumption Agreement by and
among Williams Field Services Company, LLC and Williams Four
Corners LLC (included as Exhibit C to Exhibit 2.1) |
|
21 |
.1+ |
|
|
|
List of subsidiaries of Williams Partners L.P. (incorporated by
reference to Exhibit 21.1 to Amendment No. 1 to
Williams Partners L.P.s registration statement on
Form S-1 filed on June 24, 2005 (File
No. 333-124517)). |
|
23 |
.1** |
|
|
|
Consent of Ernst & Young LLP. |
|
23 |
.2** |
|
|
|
Consent of Ernst & Young LLP. |
|
23 |
.3* |
|
|
|
Consent of Andrews Kurth LLP (contained in Exhibit 5.1). |
|
23 |
.4** |
|
|
|
Consent of Andrews Kurth LLP (contained in Exhibit 8.1). |
|
24 |
.1* |
|
|
|
Powers of Attorney (included on the signature page). |
|
99 |
.1+ |
|
|
|
Pre-approval Policy with respect to audit and non-audit services
of the audit committee of the board of directors of
Williams Partners GP LLC (incorporated by reference to
Exhibit 99.1 to Williams Partners L.P.s annual report
on Form 10-K filed on March 3, 2006 (File
No. 001-32599)). |
+ Incorporated by reference.
|
|
|
|
|
Confidential treatment granted for omitted portions. |